SEC Filing - Evolve Transition Infrastructure LP

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Amendment No. 2 to Form S-1

Index to Financial Statements

As filed with the Securities and Exchange Commission on September 29, 2006

Registration No. 333-134995

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 2 TO

FORM S-1

REGISTRATION STATEMENT

UNDER THE SECURITIES ACT OF 1933

Constellation Energy Partners LLC

(Exact name of registrant as specified in its charter)


Delaware	1311	11-3742489
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

111 Market Place

Baltimore, Maryland 21202

(410) 468-3500

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Felix J. Dawson

Chief Executive Officer

Constellation Energy Partners LLC

111 Market Place

Baltimore, Maryland 21202

(410) 468-3500

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

G. Michael O’Leary

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200

Alan P. Baden

Catherine S. Gallagher

Vinson & Elkins L.L.P.

666 Fifth Avenue, 26^th Floor

New York, New York 10103

(212) 237-0000

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

Index to Financial Statements

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED SEPTEMBER 29, 2006

P R O S P E C T U S

6,275,000 Common Units

Representing Class B Limited Liability Company Interests

We are offering 6,275,000 common units representing Class B limited liability company interests in us. This is our initial public offering and no public market currently exists for our common units. We have granted the underwriters an option to purchase up to 941,250 additional common units to cover over-allotments. We currently estimate that the initial public offering price will be between $ and $ per common unit. We have applied to list our common units on NYSE Arca under the symbol “CEP.”

Investing in our common units involves risks. See “ Risk Factors” beginning on page 23.

These risks include the following:

•

We may not have sufficient cash from operations to pay our initial quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to affiliates of Constellation Energy Group, Inc., or Constellation.

•

If commodity prices decline significantly, our cash from operations will decline, and we may have to reduce our quarterly cash distributions or may not be able to pay cash distributions at all.

•

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our cash from operations and our ability to make cash distributions to you.

•

We will rely on an affiliate of Constellation to identify and evaluate for us prospective oil and natural gas properties for acquisition. Constellation and its affiliates have no obligation to present us with such potential acquisitions, and, if they fail to do so, we may not be able to replace or increase our reserves, which would adversely affect our cash from operations and our ability to make cash distributions to you.

•

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves and production.

•

Constellation and its affiliates will own a controlling interest in us through their ownership of all of our Class A limited liability company interests and 57% of our outstanding common units. Constellation and its affiliates have conflicts of interest with us and no fiduciary duties to us. The ultimate resolution of these conflicts of interest may result in favoring the interests of Constellation and its other affiliates over yours and may be to our detriment.

•

We benefit from a gas purchase contract that will be terminated if a third-party royalty trust is terminated. The termination of the royalty trust is an event that is beyond our control.

•

You will experience immediate and substantial dilution of $10.59 per common unit.

•

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.


	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to Constellation Energy Partners LLC (before expenses)	$	$

(1)

Excludes a structuring fee of $ to be paid to Citigroup Global Markets Inc. and Lehman Brothers Inc.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units to purchasers on or about , 2006.


Citigroup		Lehman Brothers


UBS Investment Bank		Wachovia Securities
Scotia Capital

, 2006

Index to Financial Statements

LOGO

Index to Financial Statements

TABLE OF CONTENTS


SUMMARY		1
Constellation Energy Partners LLC		1
The Offering		8
Summary Historical and Pro Forma Consolidated Financial Data		16
Non-GAAP Financial Measure—Adjusted EBITDA		19
Summary Reserve and Operating Data		21
RISK FACTORS		23
Risks Related to Our Business		23
Risks Related to Our Structure		39
Tax Risks to Unitholders		44
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		47
USE OF PROCEEDS		48
CAPITALIZATION		49
DILUTION		50
HOW WE MAKE CASH DISTRIBUTIONS		51
Initial Quarterly Distributions		51
Distributions of Available Cash		51
Operating Surplus and Capital Surplus		51
Distributions of Available Cash from Operating Surplus		54
Management Incentive Interests		55
Percentage Allocations of Available Cash from Operating Surplus		57
Distributions from Capital Surplus		57
Quarterly Cash Distributions on our Class D Interests		58
Distributions of Cash Upon Liquidation		59
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS		61
General		61
Our Initial Quarterly Distribution Rate		63
Financial Forecast		65
Our Estimated Cash Available to Pay Distributions		66
Sensitivity Analysis		73
Unaudited Pro Forma Available Cash to Pay Distributions		74
SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA		77
Non-GAAP Financial Measure—Adjusted EBITDA		80
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		82
Overview		82
Comparability of Financial Statements		84
Outlook		86
Results of Operations		87
Revenue		89
Mark-to-Market Activities		89
Expenses		89
Other Income (Expenses)		92
Capital Resources and Liquidity		93
Cash Flow from Operations		95
Investing Activities—Acquisitions and Capital Expenditures		96
Financing Activities		97
Impact of Inflation		98
Contingencies and Contractual Obligations		98
Quantitative and Qualitative Disclosure About Market Risk		98

Index to Financial Statements


Critical Accounting Policies and Estimates		99
Natural Gas Properties		99
Natural Gas Reserve Quantities		100
Net Profits Interest		101
Revenue Recognition		101
Hedging Activities		101
Accounting Standards Adopted		102
Accounting Standards Issued But Not Effective		102
BUSINESS		103
Overview		103
Business Strategies		103
Competitive Strengths		104
Our Relationship With Constellation		105
Description of Our Properties and Projects		106
Natural Gas Data		109
Operations		115
Marketing and Major Customers		116
Hedging Activity		117
Competition		117
Title to Properties		117
Environmental Matters and Regulation		118
Employees		120
Offices		121
Legal Proceedings		121
MANAGEMENT		122
Management of Constellation Energy Partners LLC		122
Governance Matters		123
Compensation Committee Interlocks and Insider Participation		124
Meetings of Board of Managers		124
Our Board of Managers and Executive Officers		124
Executive Compensation		125
Employment Agreements		126
Compensation of Managers		126
Reimbursement of Expenses of CEPM		126
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		127
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		128
Distributions and Payments to CCG, CEPH, CEP Equity II LLC, CHI and CEPM		128
Agreements Governing the Transactions		130
Trademark License		132
Gas Purchase Contract		132
Cash Pool Arrangement		133
Transactions with Executive Officers, Managers and Principal Unitholders		133
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		134
Conflicts of Interests		134
Fiduciary Duties		136
DESCRIPTION OF THE COMMON UNITS		137
The Common Units		137
Transfer Agent and Registrar		137
Transfer of Common Units		137
THE LIMITED LIABILITY COMPANY AGREEMENT		138
Organization		138
Purpose		138
Fiduciary Duties		138

Index to Financial Statements


Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney		138
Capital Contributions		138
Limited Liability		139
Voting Rights		139
Issuance of Additional Securities		140
Election of Members of Our Board of Managers		140
Amendment of Our Limited Liability Company Agreement		141
Merger, Sale or Other Disposition of Assets		143
Termination and Dissolution		143
Liquidation and Distribution of Proceeds		144
Anti-Takeover Provisions		144
Limited Call Right		145
Meetings; Voting		145
Non-Citizen Assignees; Redemption		146
Indemnification		146
Books and Reports		146
Right To Inspect Our Books and Records		147
Registration Rights		147
UNITS ELIGIBLE FOR FUTURE SALE		148
MATERIAL TAX CONSEQUENCES		149
INVESTMENT IN OUR COMPANY BY EMPLOYEE BENEFIT PLANS		167
UNDERWRITING		168
VALIDITY OF THE UNITS		170
EXPERTS		170
WHERE YOU CAN FIND MORE INFORMATION		171
INDEX TO FINANCIAL STATEMENTS		F-1



APPENDIX A –	Form of Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC	A-1

APPENDIX B –	Glossary of Terms	B-1

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2006 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

iii

Index to Financial Statements

SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements. The information presented in this prospectus assumes an initial public offering price of $ per common unit (the mid-point of the price range on the cover of this prospectus), and that the underwriters’ option to purchase additional common units is not exercised, in each case unless otherwise noted. You should read “Risk Factors” for information about important factors to consider before buying the common units. We include a glossary of some of the terms used in this prospectus in Appendix B. We have prepared the estimates of proved natural gas reserves described in this prospectus, including the reserve estimates contained in the financial statements included elsewhere in this prospectus. As described in more detail under the caption “Summary Reserve and Operating Data,” in preparing the estimates as of December 31, 2005 included in the financial statements for the year ended December 31, 2005 and the estimates included elsewhere in this prospectus, we made certain downward adjustments to the reserve estimates as of December 31, 2005 prepared by Netherland, Sewell & Associates, Inc., or NSAI. In preparing the reserve estimates as of December 31, 2004 and 2003 used to prepare the financial statements of our predecessor for 2004 and 2003, we made other adjustments to the reserve estimates as of December 31, 2005 prepared by NSAI to rollback those estimates for actual production, prices and development as described in more detail under the caption “Business—Natural Gas Data—Proved Reserves.” We have removed from our reserve and Standardized Measure estimates in this prospectus estimated amounts attributable to the Torch Royalty NPI by treating the NPI as an overriding royalty interest. The number of common units referred to in this prospectus are after giving pro forma effect to a split of the outstanding limited liability company interests in us into 295,690 Class A units, 8,214,010 common units and the management incentive interests to be effected prior to the closing of this offering.

References in this prospectus to “Constellation Energy Partners,” “we,” “our,” “us,” “CEP” or like terms refer to Constellation Energy Partners LLC and its subsidiaries. References in this prospectus to “CEPM” are to Constellation Energy Partners Management, LLC, a newly formed Delaware limited liability company. References in this prospectus to “CCG” are to Constellation Energy Commodities Group, Inc., a Delaware corporation. References in this prospectus to “CEPH” are to Constellation Energy Partners Holdings, LLC, a newly formed Delaware limited liability company. References to “CHI” are to Constellation Holdings, Inc., a Delaware corporation. References in this prospectus to “Constellation” are to Constellation Energy Group, Inc., a Maryland corporation. We refer to our Class A limited liability company interests as the Class A units, our Class B limited liability company interests as the common units, our Class C limited liability company interests as the management incentive interests and our Class D limited liability company interests as the Class D interests.

Constellation Energy Partners LLC

We are a limited liability company that was formed by Constellation in February 2005 to acquire coalbed methane reserves and production. We are focused on the acquisition, development and exploitation of oil and natural gas properties, or E&P properties, as well as related midstream assets. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions. Currently, our estimated proved reserves are 100% natural gas and are located in the Robinson’s Bend Field, which we acquired in June 2005. The Robinson’s Bend Field is located in Alabama’s Black Warrior Basin. Our estimated proved reserves at December 31, 2005 were approximately 112.0 Bcf, approximately 80% of which were classified as proved developed producing. Our estimated proved reserves at December 31, 2005 had estimated future net revenues discounted at 10%, which we refer to as the Standardized Measure, of approximately $295.4 million. Standardized Measure is an accounting term that should not be confused with fair market value. Our average proved reserve-to-production ratio is approximately 25 years

Index to Financial Statements

based on our estimated proved reserves at December 31, 2005 and annualized production for the six months ended December 31, 2005. We currently own a 100% working interest (an approximate 75% average net revenue interest, calculated before the Torch Royalty NPI described below) in our Robinson’s Bend Field producing properties, which had 436 producing natural gas wells as of December 31, 2005.

The Black Warrior Basin is one of the oldest and most prolific coalbed methane basins in the country, with over 2,750 producing coalbed methane wells. These multi-seam vertical wells range from 500 to 3,700 feet deep, with coal seams averaging a total of 25 to 30 feet of thickness, or net pay, per well. Coalbed methane wells are generally more shallow than other natural gas wells, require pumping units to remove the water from the wells, which we refer to as dewatering, and require fracturing to enhance production. These wells also tend to start producing gas and water immediately upon completion, and production increases as the well is dewatered. However, production rates from newly drilled and completed wells in the Robinson’s Bend Field do not always increase as the formation dewaters. Once dewatered, coalbed methane wells often demonstrate fairly constant production rates for up to five years and then start on a decline to a final decline rate of as low as 5% to 6% per year. A typical well produces over a period of 20 to over 50 years. For a further description of the characteristics of coalbed methane production, please read “Business—Description of Our Properties and Projects—Characteristics of Coalbed Methane.”

On June 20, 2006, we executed part of a commodity price risk management program that is intended to reduce the volatility in our revenues due to commodity price changes, which in turn should provide greater stability to our future cash flows. Pursuant to this program, we have hedged the future prices of approximately 78% of our expected production from October 2006 through December 2009 from currently producing wells. Under our broader hedge program, we plan to adopt a policy that contemplates hedging the sales prices for approximately 80% of our expected production from currently producing wells for a period of up to five years, as appropriate, based primarily on our intent to stabilize cash flows and our view of prevailing and expected market conditions for natural gas. In determining our initial quarterly distribution, or IQD, we have taken into account the resulting impact of these hedges. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Business Strategies

Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase the amount of our future quarterly distributions by executing our business strategy, which is to:

•

make accretive acquisitions of E&P properties characterized by a high percentage of proved producing reserves with long-lived, stable production and step-out development opportunities, which may include associated midstream assets such as gathering systems, compression, dehydrating and treating facilities and other similar facilities;

•

identify and work with third-party operators who have experience in regions in which we seek to acquire an ownership interest and who will hold an ownership interest in our properties;

•

increase reserves and production through what we believe to be low-risk development and exploitation drilling; and

•

reduce the volatility in our revenues resulting from changes in oil and natural gas commodity prices through hedging.

Competitive Strengths

We believe we are positioned to successfully execute our business strategies because of the following competitive strengths from which we benefit:

•

our relationship with Constellation;

Index to Financial Statements

•

operational and technical support from Constellation;

•

low-risk development drilling operations;

•

predictable, long-lived reserves;

•

control of operations; and

•

large undeveloped acreage base;

Our Relationship With Constellation

We believe that one of our principal strengths is our relationship with Constellation, an integrated energy company with 2005 revenues of approximately $17.1 billion and total assets of approximately $19.2 billion as of June 30, 2006. Constellation’s common stock trades on The New York Stock Exchange under the symbol “CEG.” Constellation is engaged in numerous aspects of the energy industry, including, through CCG, oil and natural gas exploration and production, or E&P, natural gas transportation, natural gas storage and physical and financial natural gas trading.

A principal component of our business strategy is to grow our asset base and production through the acquisition of E&P properties characterized by long-lived, stable production. Constellation, through CCG, has a track record of successfully acquiring developed and undeveloped E&P properties. CCG is currently developing several other E&P projects in various locations with unconventional production, including coalbed methane, tight sands and shale. As CCG continues to develop the E&P properties that comprise these projects, and potentially other undeveloped E&P properties that it may acquire in the future, it is possible these projects will have characteristics of properties suitable for us and our business strategies. Constellation views us as an integral component of the growth strategy for its upstream oil and natural gas business and intends to use us as its primary vehicle to develop a portfolio of long-lived, proved producing E&P properties. However, Constellation has no obligation or commitment to do so, and may act in a manner that is beneficial to its interests and detrimental to ours.

We will enter into a management services agreement with CEPM, an indirect wholly owned subsidiary of Constellation. Pursuant to that agreement, CEPM will provide us with legal, accounting, finance, tax, property management, engineering and risk management services and may provide us with acquisition services in respect of opportunities for us to acquire long-lived, stable and proved oil and natural gas reserves. While neither Constellation nor CEPM has any obligation to provide us with acquisition services under the management services agreement, we expect that their ownership of our Class A units, common units and management incentive interests will provide them with an incentive to grow our business by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash.

We will reimburse CEPM for the reasonable costs of the services it provides to us. Our board of managers has the right and the duty to review the services provided, and the costs charged, by CEPM under the management services agreement. Our board of managers may in the future cause us to hire additional personnel to supplement or replace some or all of the services provided by CEPM, as well as employ third-party service providers. If we were to take such actions, they could increase the overall costs of our operations. For a description of the services that CEPM will provide to us and our obligation to reimburse CEPM for the costs it incurs in providing those services, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management Services Agreement.”

Index to Financial Statements

in those assets. The ultimate resolution of the conflicts of interest that exist or arise as a result of either our relationship with Constellation and its other affiliates or the status of our executive officers or our Class A managers as managers, directors, officers or employees of Constellation or its other affiliates may result in the interests of Constellation or its affiliates being favored over your interests and may be to our detriment. Please read “Conflicts of Interest and Fiduciary Duties.”

In December 2005, Constellation entered into an Agreement and Plan of Merger with FPL Group, Inc., a Florida corporation whose common stock trades on The New York Stock Exchange under the symbol “FPL.” FPL Group, Inc. is also an integrated energy company with 2005 revenues of $11.8 billion and total assets of $33.8 billion as of June 30, 2006.

Cash Distribution Policy

Our board of managers has adopted a cash distribution policy to pay a regular quarterly distribution of $0.425 per unit on our outstanding common and Class A units while reinvesting in our business a portion of our operating cash flow. We intend to pay our first cash distribution on or about February 14, 2007 for the period from the closing of this offering through December 31, 2006. We will adjust our first distribution based on the actual length of that period. Thereafter, we intend to pay a distribution on a quarterly basis. Declaration and payment of distributions is at the discretion of our board of managers, and we cannot assure you that we will not reduce or eliminate our distributions.

In general, it is our policy to distribute all of our available cash after paying our operating expenses and retaining an amount of funds that our board of managers estimates is adequate for the proper conduct of our business, including the maintenance of our asset base. If we continue this policy, we will be dependent on our ability to raise debt and equity from the capital markets to grow our asset base, and we cannot assure you of our ability to access such markets. If our board of managers underestimates the amounts necessary to maintain our asset base or we fail to invest those funds effectively, our board of managers will likely need to reduce the amount of our distributions. In an effort to reduce the uncertainty regarding our distributions, our board of managers intends to increase our distributions per unit only if it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such increased distribution level for a sustained period.

You may not receive distributions in the intended amounts described above, or at all. Please read “Risk Factors—Risks Related to Our Business.” If we had completed the transactions contemplated in this prospectus on January 1, 2005, pro forma available cash generated during the year ended December 31, 2005 would have been approximately $8.6 million. If we had completed the transactions contemplated in this prospectus on July 1, 2005, pro forma available cash generated during the twelve months ended June 30, 2006 would have been approximately $8.3 million. These amounts of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 34% and 33%, respectively, of the initial quarterly distribution, or IQD, on our Class A and common units for these periods. For a calculation of our ability to make distributions based on our pro forma results for the year ended December 31, 2005 and the twelve months ended June 30, 2006, please read the information included under the caption “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Available Cash to Pay Distributions.”

Pursuant to the terms of our limited liability company agreement, our board of managers has the discretionary authority to cause us to borrow funds from our reserve-based credit facility to make up a shortfall in cash available for distribution such as the estimated shortfall amounts discussed above. Under our reserve-based credit facility that we expect to enter into prior to or at the closing of this offering, we expect to be able to incur debt to pursue our business plan and to pay distributions to our unitholders, provided that our borrowings do not reach or exceed 90% of the borrowing base and that we are not then in default. For a description of our borrowing parameters and covenants, please read “Cash Distribution Policy and Restrictions on Distributions.”

Index to Financial Statements

Torch Royalty NPI

The majority of our properties in the Robinson’s Bend Field are subject to a non-operating net profits interest, or NPI, held by Torch Energy Royalty Trust, or the Trust. Through the NPI, the Trust is entitled to a royalty payment, calculated as a percentage of the net revenue, that is, specified revenues reduced by associated expenditures, from specified wells in the Robinson’s Bend Field, or Trust Wells. As of December 31, 2005, we owned a working interest in 436 producing wells in the Robinson’s Bend Field, of which 404 wells were subject to the NPI. We estimate that, as of December 31, 2005, approximately 5.8 Bcf of proved reserves were attributable to the NPI on the Trust Wells, which we have excluded from our estimate of proved reserves attributable to our interests in the Robinson’s Bend Field.

Under the terms of the NPI and related contractual arrangements, the royalty payment we are required to make to the Trust under the NPI is calculated using a sharing arrangement with a pricing formula that has resulted in below-market prices and has had the effect of keeping our payments to the Trust significantly lower than if such payments had been calculated based on then prevailing market prices. No amounts were due to the Trust in 2005 in respect of the NPI. We paid the Trust approximately $0.2 million in the aggregate for January 2006 through August 2006 production from the Trust Wells in respect of the NPI.

The sharing arrangement may be terminated under specified circumstances that are beyond our control. If we lose the benefit of the sharing arrangement in respect of calculating payments under the NPI, our payments to the Trust will increase and our revenues will decrease. For a further description of the NPI and the related contractual arrangements, as well as the circumstances under which the sharing arrangement may be terminated, please read “Business—Natural Gas Data—Torch Royalty NPI.”

In order to address to a limited extent the risks of the potential adverse impact on our operating results from early termination, without the prior consent of our board of managers, of the sharing arrangement in respect of the calculation of amounts payable to the Trust for the NPI, CHI will contribute to us at the closing of this offering $8.0 million for all of our Class D interests. This contribution will be returned to CHI in 24 special quarterly distributions over a period of approximately six years if the sharing arrangement remains in effect during that period. If the amounts payable by us to the Trust are not calculated based on the continued applicability of the sharing arrangement through December 31, 2012, unless such change is approved in advance by our board of managers and our conflicts committee, the following will occur: the Class D interests will cease receiving the special quarterly cash distributions; and the Class D interests will only be returned the remaining undistributed amount of the $8.0 million contribution under certain circumstances upon our liquidation. The effect of our retention and use of the unreturned portion of the $8.0 million is to provide us with cash that will reduce, but not eliminate, the adverse impact of our reduced revenues from the termination of the sharing arrangement. For a further description of this special distribution right, please read “Cash Distribution Policy and Restrictions on Distributions” and “Certain Relationships and Related Party Transactions—Distributions and Payments to CCG, CEPH, CEP Equity II LLC, CHI and CEPM—Operational Stage.”

Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our common units. Please read carefully the risks under the caption “Risk Factors” immediately following this Summary beginning on page 23.

The Transactions and Limited Liability Company Structure

General. We are a Delaware limited liability company formed in February 2005 to own natural gas properties that were acquired in June 2005 in the Black Warrior Basin of Alabama.

Conversion of Interests and Formation of CEPM. Immediately prior to the closing of this offering, the limited liability company interests in us held by CEPH will be converted into 295,690 Class A units, 8,214,010

Index to Financial Statements

common units and the management incentive interests. Immediately after such conversion, CEPH will contribute the 295,690 Class A units and the management incentive interests to CEPM in exchange for all of the limited liability company interests in CEPM.

Class D Interests Contribution. For a description of the Class D interests, the special cash distribution rights associated with those interests and the effects thereon of termination of the sharing arrangement without the prior consent of our board of managers, please read “Cash Distribution Policy and Restrictions on Distributions” and “Certain Relationships and Related Party Transactions—Distributions and Payments to CCG, CEPH, CEP Equity II LLC, CHI and CEPM—Operational Stage.”

Distribution of Floyd Shale Rights. In connection with this offering, we will distribute to an affiliate of Constellation, CEP Equity II, LLC, an undivided mineral interest in our properties in the Robinson’s Bend Field for depths generally below 100 feet below the base of the lowest producing coal seam. We refer to this mineral interest as the Floyd Shale Rights. The Floyd Shale Rights are not material to our business and no value has been assigned to them in our historical financial statements included elsewhere in this prospectus. The Floyd Shale Rights do not fit our investment strategy, given the uncertainty of encountering commercial quantities of oil or natural gas. We will receive $475,000 in return for this distribution of the Floyd Shale Rights.

Reserve-Based Credit Facility. Prior to this offering, we plan to enter into a new reserve-based credit facility under which we expect our initial borrowing base will be $100.0 million. At the closing of this offering, we plan to borrow $30.0 million under that facility to fund part of a distribution currently estimated to be $136.0 million to CEPH as reimbursement for capital expenditures made by CCG prior to this offering.

Management of Constellation Energy Partners LLC. Our board of managers will manage our operations and activities, and CEPM, through its affiliates and employees, will carry out the directions of our board of managers pursuant to a management services agreement. This agreement is not terminable by us while we are consolidated with Constellation for accounting purposes. Thereafter, the management services agreement is terminable by either us or CEPM upon six months’ notice. CEPM will be reimbursed for its costs in providing services to us and will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. Constellation and its affiliates will also be entitled to distributions on our Class A units, common units they own, management incentive interests and Class D interests. For more information about our management, please read “Management—Our Board of Managers and Executive Officers” and “Certain Relationships and Related Party Transactions.”

Elimination of Special Voting Rights of Class A Units; Conversion of Class A Units and Management Incentive Interests Into Common Units. The holders of our Class A units have the right, voting as a separate class, to elect two of the five members of our board of managers, and any replacement of either of such members. This right can be eliminated upon a vote of the holders of not less than 66²/3% of our outstanding common units. If such elimination is so approved and Constellation and its affiliates do not vote their common units in favor of such elimination, the Class A units will be converted into common units on a one-for-one basis and CEPM will have the right to convert its management incentive interests into common units at the then fair market value of such interests. For a further description of the right of common unitholders to eliminate the voting rights of the Class A units and the conversion of Class A units and management incentive interests into common units, please read “The Limited Liability Company Agreement—Election of Members of Our Board of Managers—Elimination of Special Voting Rights of Class A Units.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 111 Market Place, Baltimore, Maryland 21202, and our telephone number is (410) 468-3500. Our website is located at http://www.constellationenergypartners.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those

Index to Financial Statements

reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Organizational Chart

The following diagram depicts our organizational structure after giving effect to this offering and the related transactions.

LOGO

Index to Financial Statements

The Offering

Units offered by us

6,275,000 common units; or 7,216,250 common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering

14,489,010 common units.

295,690 Class A units, all of which will be owned by CEPM.

Use of proceeds

The following table sets forth the estimated sources and uses of the funds we expect to receive from the sale of common units in this offering and related transactions. The actual sources and uses of these funds may differ from those set forth below. Please read “Use of Proceeds.”


Sources of Funds:

Estimated proceeds, net of estimated underwriting discounts and commissions and offering expenses, received from this offering^(a)	$	113.8 million

Contribution for the Class D interests	$	8.0 million

Borrowings under our new reserve-based credit facility	$	30.0 million

Uses of Funds:

Distribution to CEPH^(a)(b)	$	136.0 million

Reduction of borrowings under our new reserve-based credit facility	$	8.0 million

Working capital	$	7.8 million
(a) Assumes an initial public offering price of $20.00 per common unit, the mid-point of the price range set forth on the cover page of this prospectus and after deducting estimated underwriting discounts and commissions of $8.5 million and estimated offering expenses of $3.2 million. (b) If the price exceeds the mid-point of the price range, we will distribute the excess net proceeds to CEPH. If the price is less than the mid-point of the price range, we will reduce the size of the special distribution to CEPH in an amount equal to the reduction in net proceeds.

We intend to use the net proceeds from any exercise of the underwriters’ option to purchase additional units from us to purchase an equivalent number of common units from CEPH.

Cash distributions

We intend to make an IQD of $0.425 per common unit to the extent we have sufficient available cash from operations after we establish appropriate cash reserves and pay fees and expenses, including

Index to Financial Statements

payments to CEPM for reimbursement of costs and expenses it incurs on our behalf. We refer to this cash as “available cash,” and we define its meaning in more detail in our limited liability company agreement, in “How We Make Cash Distributions—Distributions of Available Cash—Definition of Available Cash” and in the glossary of terms found in Appendix B. Our board of managers has broad discretion in establishing cash reserves. The cash reserves that our board of managers may establish in its discretion include reserves for future cash distributions on the common units, Class A units and management incentive interests and to pay special cash distributions to the holders of our Class D interests. These reserves, which could be substantial, will reduce the amount of cash available for distribution to you.

Our board of managers has adopted a policy that it will raise our quarterly cash distribution only when it believes that we (i) have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) can maintain such increased distribution level for a sustained period. While this is our current policy, our board of managers may alter such policy in the future when and if it determines such alteration to be appropriate. Our limited liability company agreement requires that, within 45 days after the end of each calendar quarter beginning with the quarter ending December 31, 2006, we distribute all of our available cash to holders of record of our limited liability company interests on the applicable record date.

We will adjust the IQD for the period from the closing of this offering through December 31, 2006, based on the actual length of the period.

The amount of available cash in any quarter may be greater or less than the aggregate amount associated with payment of the IQD on all of our common units and Class A units. In general, we will pay any cash distributions we make in the following manner:

•

first, 98% to the holders of our common units and 2% to the holders of our Class A units, pro rata, until each unitholder has received $0.48875 (that is, the $0.425 IQD plus $0.06375), which aggregate amount we refer to as the “Target Distribution;” and

•

thereafter, any amount distributed in respect of any quarter in excess of the Target Distribution will be distributed 98% to the holders of our common units, pro rata, and 2% to the holder of our Class A units until distributions become payable in respect of our management incentive interests as described under “Management incentive interests” below.

The holder of our Class A units will be entitled to 2% of our cash distributions without any obligation to make future capital contributions to us.

Index to Financial Statements

Management incentive interests

We refer to a distribution in respect of the management incentive interests as a “management incentive distribution.” CEPM will initially hold all of the management incentive interests.

Payments to the holder of our management incentive interests will be subject to the satisfaction of certain requirements. The first

requirement is the “12-Quarter Test.” The 12-Quarter Test requires that, for the 12 full, consecutive, non-overlapping calendar quarters that begin with the first calendar quarter in respect of which we pay per unit cash distributions from operating surplus to holders of Class A and common units in an amount equal to or greater than the Target Distribution (we refer to such 12-quarter period as the “First MII Earnings Period”):

•

we pay cash distributions from operating surplus to holders of our outstanding Class A and common units in an amount that on average exceeds the Target Distribution on all of the outstanding Class A and common units over the First MII Earnings Period;

•

we generate adjusted operating surplus (which is defined in “How We Make Cash Distributions” and in the glossary included as Appendix B) during the First MII Earnings Period that on average is in an amount at least equal to 100% of all distributions on the outstanding Class A and common units up to the Target Distribution plus 117.65% of all such distributions in excess of the Target Distribution; and

•

we do not reduce the amount distributed per unit in respect of any such 12 quarters.

The second requirement is the “4-Quarter Test.” The 4-Quarter Test requires that, for each of the last four full, consecutive, non-overlapping calendar quarters in the First MII Earnings Period:

•

we pay cash distributions from operating surplus to the holders of our outstanding Class A and common units that exceed the Target Distribution on all of the outstanding Class A and common units;

•

we generate adjusted operating surplus in an amount at least equal to 100% of all distributions on the outstanding Class A and common units up to the Target Distribution plus 117.65% of all such distributions in excess of the Target Distribution; and

•

we do not reduce the amount distributed per unit in respect of any of such four quarters.

If the 12-Quarter Test and the 4-Quarter Test have been met, then: (i) we will make a one-time management incentive distribution (contemporaneously with the distribution paid in respect of the Class A and common units for the twelfth calendar quarter in the First MII Earnings Period) to the holder of our management incentive

Index to Financial Statements

interests equal to 17.65% of the sum of the cumulative amounts, if any, by which quarterly cash distributions per unit paid on the outstanding Class A and common units during the First MII Earnings Period exceeded the Target Distribution on all of the outstanding Class A and common units (we refer to this one-time management incentive distribution as an “EP MID”); and (ii) for each calendar quarter after the First MII Earnings Period, the holders of our Class A units, common units and management incentive interests will receive 2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay for such quarter in excess of the Target Distribution.

If the 12-Quarter Test is not met, management incentive distributions will not be payable in respect of the First MII Earnings Period. An EP MID may become payable, however, with respect to a subsequent period, which we refer to as the Later MII Earnings Period, if the 12-Quarter Test and the 4-Quarter Test are met in respect of such Later MII Earnings Period. If both tests are met with respect to a Later MII Earnings Period, then for each calendar quarter after the Later MII Earnings Period, the holders of the Class A units, common units and management incentive interests will receive 2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay for such quarter in excess of the Target Distribution.

However, if (a) the 12-Quarter Test has been met in respect of the First MII Earnings Period or any Later MII Earnings Period, but not the 4-Quarter Test; (b) the 4-Quarter Test has been met in any period of four full, consecutive and non-overlapping quarters occurring after the end of the First MII Earnings Period or Later MII Earnings Period, as the case may be, up to three of which quarters can fall within the First MII Earnings Period or Later MII Earnings Period, as the case may be, (we refer to such four-quarter period as the “MII 4-Quarter Earnings Period”); and (c) we have paid at least the IQD in each calendar quarter occurring between the end of the First MII Earnings Period or Later MII Earnings Period, as the case may be, and the beginning of the MII 4-Quarter Earnings Period:

•

the holders of our Class A units, common units and management incentive interests will receive 2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay in excess of the Target Distribution for each calendar quarter after the MII 4-Quarter Earnings Period; and

•

the holder of our management incentive interests will receive an EP MID with respect to the First MII Earnings Period or Later MII Earnings Period, as the case may be.

We are not able to predict whether or when we will be required to make distributions in respect of the management incentive interests,

Index to Financial Statements

or if we do make such distributions, how much they will be. For a further discussion of the management incentive interests, please read the information set forth under the caption “How We Make Cash Distributions–Management Incentive Interests.”

Special Class D interests distribution

2012 that the sharing arrangement remains in effect, we will distribute to the holder of the Class D interests $333,333, as a partial return of the $8.0 million capital contribution made for the Class D interests, which payment will be made concurrently with the quarterly cash distribution to our unitholders for that quarter. The Class D interests will be cancelled upon the payment of the final distribution of $333,341 to CHI for the quarter ending December 31, 2012, unless the special distribution right has been terminated earlier. If the amounts payable by us to the Trust are not calculated based on the sharing arrangement through December 31, 2012, unless such change is approved in advance by our board of managers and our conflicts committee, the special distribution right for future quarters will terminate and the remaining portion of the $8.0 million contribution not so returned in special cash distributions will be retained by us to partially offset the reduction in our revenues resulting from termination of the sharing arrangement in respect of the Trust. In the case of such termination of the special distribution right, CHI will have the right only under specific circumstances upon our liquidation to receive the unpaid portion of the $8.0 million capital contribution that has not then been distributed to CHI in such special distributions. If the distribution right is terminated during a quarter, the special distribution to the holder of the Class D interests will be pro rated for that quarter based upon the ratio of the number of days in such quarter prior to the effective date of such termination to 90.

Based upon our estimated production for the twelve months ending September 30, 2007 and the weighted average net realized sales price for our production used in calculating our Estimated Adjusted EBITDA for that twelve-month period under the caption “Cash Distribution Policy and Restrictions on Distributions,” we estimate that, if the sharing arrangement in respect of the Trust was terminated as of October 1, 2006, our revenues would be reduced by approximately $5.6 million during such twelve-month period and the $8.0 million contributed to us for the Class D interests would offset such a shortfall for approximately 1.4 years, if the production and prices set forth under “Cash Distribution Policy and Restrictions on Distributions—Our Estimated Cash Available to Pay Distributions” were to remain constant throughout such period.

Index to Financial Statements

Pro forma and expected ability to pay the IQD

We believe, based on the assumptions and considerations included under the caption “Cash Distribution Policy and Restrictions on Distributions” of this prospectus, that we will have sufficient cash flow from operations to enable us to pay the IQD of $0.425 on all Class A and common units for each quarter in the twelve-month period ending September 30, 2007. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2005 and the twelve months ended June 30, 2006, please read the information included under the caption “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Available Cash to Pay Distributions.”

Issuance of additional units

We can issue an unlimited number of additional limited liability company interests without the consent of our unitholders. Please read “Risk Factors—Risks Related to Our Structure—We may issue an unlimited number of additional units without your approval, which would dilute your existing ownership interests,” “Units Eligible for Future Sale” and “The Limited Liability Company Agreement—Issuance of Additional Securities.”

Agreement to be bound by limited liability agreement; common unit voting rights

By purchasing a common unit, you will be admitted as a member of our limited liability company and be deemed to have agreed to be bound by all of the terms of our limited liability company agreement. Our board of managers will manage us and will rely on personnel from CEPM and its affiliates to oversee our operations. Pursuant to our limited liability company agreement, as a common unitholder you will be entitled to vote on the following matters:

•

annual election of three members of our five-member board of managers;

•

specified amendments to our limited liability company agreement;

•

merger of our company or the sale of all or substantially all of our assets; and

•

dissolution of our company.

Please read “The Limited Liability Company Agreement—Voting Rights.”

Board of Managers

Our board of managers will initially be comprised of five members, two of whom will be elected by the holders of the Class A units and the remainder of whom will be elected by the holders of the common units. Because Constellation will own more than a majority of our outstanding common units immediately after the closing of this offering, Constellation, in combination with CEPM as owner of the

Index to Financial Statements

Class A units, will be able to elect a majority of the members of our board of managers. In addition, as the removal of a manager elected by our common unitholders requires the approval of the holders of not less than 66²/3% of our outstanding common units, our public common unitholders will not be able to remove a member of our board of managers unless Constellation votes its common units in favor of such a removal.

Limitations on common unitholder actions

Our limited liability company agreement (i) prohibits common unitholders from taking unitholder action by written consent and (ii) nullifies the common unitholder voting rights of any person other than Constellation or its affiliates that holds 20% or more of our outstanding common units.

Limited call right

If at any time any person and its affiliates own more than 80% of the outstanding common units, such person will have the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then–current market price of the common units.

Fiduciary duties

Our limited liability company agreement provides that the fiduciary duties of our managers and officers are generally to act in good faith in acting on our behalf in such capacity.

As a result of our relationship with Constellation and its affiliates, as well as the fact that our executive officers and Class A managers also serve as managers, directors, officers or employees of Constellation or its other affiliates, conflicts of interest exist and will arise in the future. The ultimate resolution of these conflicts of interest may result in the interests of Constellation or its affiliates being favored over your interests, may be to our detriment and could adversely affect the market price of the common units. If in resolving these conflicts of interest our board of managers or officers, as the case may be, satisfy the applicable standards set forth in our limited liability company agreement for resolving conflicts of interest, you will not be able to assert that such resolution constituted a breach of fiduciary duty owed to us or to you by our board of managers and officers. For example, our limited liability company agreement establishes a conflicts committee of our board of managers, consisting solely of independent managers, which will be responsible for reviewing transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, you will not be able to assert that such approval or the consummation of such transaction constituted a breach of fiduciary duties owed to you by our managers and officers. Please read “Management—Our Board of Managers—Conflicts Committee.”

Estimated ratio of taxable income to distributions

We estimate that, if you own the common units that you purchase in this offering through the record date for distributions for the period

Index to Financial Statements

ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 20% of the cash distributed to you with respect to that period. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Exchange listing and trading symbol

We have applied to list our common units on NYSE Arca under the trading symbol “CEP.”

Index to Financial Statements

Summary Historical and Pro Forma

Consolidated Financial Data

Set forth below is our summary historical and unaudited pro forma consolidated financial data for the periods indicated. We were formed in February 2005 and had no operations prior to the completion of a $161.1 million acquisition of natural gas reserves and equipment in the Robinson’s Bend Field from Everlast Energy LLC, or Everlast, on June 13, 2005. We applied the purchase method of accounting to the separable assets and liabilities of the natural gas properties and equipment acquired from Everlast. The summary historical consolidated financial data of Everlast for the period from January 1, 2005 through June 12, 2005 and as of and for the years ended December 31, 2004 and 2003 have been derived from Everlast’s audited historical financial statements. The summary historical financial data of Constellation Energy Partners LLC as of December 31, 2005 and for the period from February 7, 2005 (inception) through December 31, 2005, have been derived from our audited historical consolidated financial statements. The summary historical consolidated financial data of Constellation Energy Partners LLC as of and for the six months ended June 30, 2006 and for the period from February 7, 2005 (inception) to June 30, 2005 have been derived from our unaudited historical consolidated financial statements. The summary unaudited pro forma consolidated financial data as of and for the six months ended June 30, 2006 and for the year ended December 31, 2005 have been derived from our unaudited pro forma consolidated financial statements. For a description of the adjustments made in the unaudited pro forma consolidated financial statements, please read the notes to those financial statements.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to net income and net cash flow provided by operating activities, the most directly comparable financial measures calculated and presented in accordance with GAAP in “—Non-GAAP Financial Measure—Adjusted EBITDA” below.

You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the financial statements of Everlast and related notes appearing elsewhere in this prospectus. You should also read the pro forma information, together with the unaudited pro forma consolidated financial statements and related notes included in this prospectus.

Our only operations are in the Robinson’s Bend Field, as were Everlast’s. During each of the last three years, our properties in the Robinson’s Bend Field were wholly owned by us or Everlast. Our acquisition from Everlast resulted in a new basis in our properties in the Robinson’s Bend Field for accounting purposes. In addition, new management, operating and accounting policies, and estimates were put into place after our acquisition from Everlast. Though the financial statements represent the operation of the same properties in the Robinson’s Bend Field, due to these differences, the financial statements for the periods prior to and after our purchase of our properties in the Robinson’s Bend Field are not comparable. For that purpose, a black line has been placed between our and Everlast’s financial statements. Our historical results of operations and period-to-period comparisons of results and certain financial data prior to and after our acquisition of our properties in the Robinson’s Bend Field from Everlast may not be indicative of future results.

Index to Financial Statements


	Predecessor									Successor
	Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005^(b)		For the period from February 7, 2005 (inception) to June 30, 2005^(b)			For the six months ended June 30, 2006			Pro Forma
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005								For the six months ended June 30, 2006			For the year ended December 31, 2005			For the six months ended June 30, 2006
	As Restated^(a)			As Restated^(a)								Unaudited			Unaudited			Unaudited			Unaudited
	(In ‘000’s)									(In ‘000’s)
Statement of Operations Data:

Revenues:
Gas sales	$	22,320		$	27,494		$	12,882		$	25,957	$	1,377		$	17,605		$	38,839		$	17,605
Loss from mark-to-market activities		(3,664	)		(9,107	)		(15,313	)		—		—			—			(15,313	)		—

Total revenues		18,656			18,387			(2,431	)		25,957		1,377			17,605			23,526			17,605

Operating expenses:
Lease operating expenses		4,428			5,270			2,769			4,175		357			3,495			6,944			3,495
Production taxes		1,279			1,479			676			1,400		72			909			2,076			909
General and administrative		1,945			2,706			594			4,184		3,275			2,731			4,778			2,731
Depreciation, depletion and amortization		3,684			3,719			1,683			4,176		350			3,811			7,281			3,811
Accretion expense		73			86			46			78		7			71			141			71

Total operating expenses		11,409			13,260			5,768			14,013		4,061			11,017			21,220			11,017

Other expenses/(income):
Interest expense/(income), net		1,961			3,028			2,437			3		—			(197	)		1,546			573
Organization costs		299			—			—			—		—			—			—			—

Total other expenses/(income)		2,260			3,028			2,437			3		—			(197	)		1,546			573

Total expenses/(income)		13,669			16,288			8,205			14,016		4,061			10,820			22,766			11,590

Net income (loss)	$	4,987		$	2,099		$	(10,636	)	$	11,941	$	(2,684	)	$	6,785		$	760		$	6,015

Other Financial Information (unaudited)
Adjusted EBITDA	$	10,193		$	14,738		$	8,795		$	16,198	$	(2,327	)	$	10,470		$	24,993		$	10,470

(a)

The financial statements of Everlast for 2003 and 2004 have been restated. Please read Note 2 to the historical consolidated financial statements included elsewhere in this prospectus.

(b)

Until our acquisition of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005, we did not conduct any operations.

Index to Financial Statements


	Predecessor									Successor
	Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005^(b)			For the period from February 7, 2005 (inception) to June 30, 2005^(b)			For the six months ended June 30, 2006			Pro Forma
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005									For the six months ended June 30, 2006			For the six months ended June 30, 2006
	As Restated^(a)			As Restated^(a)									Unaudited			Unaudited			Unaudited
	(In ‘000’s)									(In ‘000’s)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	2,563		$	2,012					$	14,831					$	3,880		$	7,827
Other current assets		1,812			4,562						6,097						17,912			5,713
Natural gas properties, net of accumulated depreciation, depletion and amortization		49,252			52,531						165,211						169,282			169,282
Other assets		590			1,579						—						311			311

Total assets	$	54,217		$	60,684					$	186,139					$	191,385		$	183,133

Current liabilities	$	4,403		$	4,482					$	13,895					$	10,797		$	10,797
Debt		26,000			67,500						63						52			22,052
Preferred units subject to mandatory redemption		16,752			—						—						—			8,000
Other long-term liabilities		2,671			3,314						3,014						3,099			3,099
Members equity
Common members equity (deficit)		4,391			(14,612	)					169,167						176,523			138,271
Accumulated other comprehensive income		—			—						—						914			914

Total members’ equity (deficit)		4,391			(14,612	)					169,167						177,437			139,185

Total liabilities and members’ equity (deficit)	$	54,217		$	60,684					$	186,139					$	191,385		$	183,133

Cash Flow Data:
Net cash provided by operating activities	$	9,773		$	4,906		$	6,639		$	23,313		$	2,931		$	8,805
Net cash used in investing activities		(47,832	)		(6,997	)		(4,203	)		(147,237	)		(139,357	)		(19,745	)
Net cash provided by (used in) financing activities		40,622			1,540			(2,500	)		138,755			138,770			(11	)
Development of natural gas properties		(2,040	)		(5,680	)		(4,000	)		(8,286	)		(406	)		(7,285	)

(a)

The financial statements of Everlast for 2003 and 2004 have been restated. Please read Note 2 to the historical consolidated financial statements included elsewhere in this prospectus.

(b)

Until our acquisition of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005, we did not conduct any operations.

Index to Financial Statements

Non–GAAP Financial Measure—Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus:

•

interest (income) expense;

•

depreciation, depletion and amortization;

•

write-off of deferred financing fees;

•

impairment of long-lived assets;

•

(gain) loss on sale of assets;

•

(gain) loss from equity investment;

•

accretion of asset retirement obligation;

•

unrealized (gain) loss on natural gas derivatives; and

•

realized loss (gain) on cancelled natural gas derivatives.

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our board of managers) the cash distributions we can pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and

•

our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Index to Financial Statements

The following table presents a reconciliation of Adjusted EBITDA to net income and net cash flow provided by operating activities, our most directly comparable GAAP performance and liquidity measures, for each of the periods presented:


	Predecessor									Successor
	Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005			For the period from February 7, 2005 (inception) to June 30, 2005			For the six months ended June 30, 2006			Pro Forma
	For the year ended December 31, 2003			For the year ended December 31, 2004												For the six months ended June 30, 2006			For the year ended December 31, 2005		For the six months ended June 30, 2006
													Unaudited			Unaudited			Unaudited		Unaudited
	(In ‘000’s)									(In ‘000’s)
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net income/(loss)	$	4,987		$	2,099		$	(10,636	)	$	11,941		$	(2,684	)	$	6,785		$	760	$	6,015
Add:
Interest expense/(income), net		1,961			3,028			2,437			3			—			(197	)		1,546		573
Depreciation, depletion and amortization		3,684			3,719			1,683			4,176			350			3,811			7,281		3,811
Accretion of asset retirement obligation		73			86			46			78			7			71			141		71
Unrealized loss/(gain) on natural gas derivatives		(512	)		(2,156	)		15,265			—			—			—			15,265		—
Realized loss/(gain) on cancelled natural gas derivatives		—			7,962			—			—			—			—			—		—

Adjusted EBITDA	$	10,193		$	14,738		$	8,795		$	16,198		$	(2,327	)	$	10,470		$	24,993	$	10,470

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	9,773		$	4,906		$	6,639		$	23,313		$	2,931		$	8,805
Add:
Interest expense/(income), net^(a)		1,305			2,596			2,437			3			—			(197	)
Expenses paid by CCG on behalf of CEP		—			—			—			(64	)		—			(571	)
Realized loss on cancelled natural gas derivatives		—			7,962			—			—			—			—
Changes in working capital:
Accounts receivable		1,547			2,278			707			1,289			(1,535	)		(1,869	)
Prepaid expenses		265			(246	)		131			62			21			75
Other assets		—			—			10			211			—			807
Loan amortization cost		(288	)		(685	)		(237	)		—			—			—
Accounts payable		(908	)		(993	)		(807	)		(1,703	)		863			2,187
Royalty payable		(1,321	)		(708	)		(110	)		(1,859	)		(364	)		1,240
Accrued liabilities		(180	)		(372	)		25			(5,054	)		(4,243	)		(7	)

Adjusted EBITDA	$	10,193		$	14,738		$	8,795		$	16,198		$	(2,327	)	$	10,470

(a)

For the years ended December 31, 2004 and 2003, the return on the preferred units subject to mandatory redemption totaled approximately $0.4 million and $0.7 million, respectively. These amounts are included in interest expense in the accompanying income statements and were also treated as non-cash additions to net income when calculating the net cash provided by operating activities. As these amounts are already included in both interest expense and net cash provided by operating activities, they are not included in this line of the reconciliation.

Index to Financial Statements

Summary Reserve and Operating Data

The following is a summary of our estimated net proved reserves attributable to our properties in the Robinson’s Bend Field and summary unaudited information with respect to our production and sales of natural gas, all as of the dates indicated. We have prepared the estimates of proved natural gas reserves described in this prospectus. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business—Oil and Natural Gas Data—Proved Reserves” and our historical consolidated financial statements in evaluating the material presented below.

The following table reflects our internal estimates of proved natural gas reserves based on SEC definitions that were used to prepare our financial statements for the following periods:


	Predecessor						Successor
	Everlast Energy LLC						Constellation Energy Partners LLC
	As of December 31,
Reserve data:	2003			2004			2005
Estimated net proved reserves:
Natural gas (Bcf)		163.7			162.2			112.0
Proved developed reserves (Bcf)		100.7			101.4			89.3
Proved undeveloped reserves (Bcf)		63.0			60.8			22.7
Proved developed reserves as a percent of total reserves		62	%		62	%		80	%
Standardized Measure (in millions) (a)	$	194.2		$	206.8		$	295.4
Natural gas price—SONAT Gas Daily (price per Mmbtu) (b)	$	5.92		$	6.05		$	10.06

(a)

Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income taxes because we are not subject to income taxes. Standardized Measure does not give effect to derivative transactions and excludes reserves attributable to the NPI. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Cash Flow from Operations.”

(b)

Natural gas prices as of each period end were based on the Southern Natural Gas—Louisiana mid-point price, as published in Platts Gas Daily, which we refer to as the SONAT Gas Daily Price, on the last business day of the relevant period.

The data presented in the table above is based on our own internal estimates prepared for the predecessor and successor companies at the corresponding year ends and was used to prepare the financial statements presented elsewhere in this prospectus. Our 2005 estimates of proved reserves are lower than the 2004 and 2003 estimates for Everlast, the predecessor company, because of the decision of our current management to (i) reduce our future drilling program to 20 wells per year over the next six years, (ii) reflect our interpretation of well performance data from new wells drilled in the Robinson’s Bend Field in 2004 and 2005, and (iii) reflect the impact of a revised refracture program. There was no drilling in the Robinson’s Bend Field between 1994 and late 2003. While the performance data from new wells in the Robinson’s Bend Field at December 31, 2005 was limited, we believe it provides relevant information for the purposes of estimating reserves. The revised 20-well drilling program reflects our current intention of how we plan to develop the properties in the future. Our estimate of reserves at December 31, 2005 is also approximately 5.8 Bcf lower than the December 31, 2004

Index to Financial Statements

estimates of proved reserves due to a reduction for estimated reserves attributed to the NPI. No corresponding adjustment was made to the December 31, 2004 estimate of reserves because no amounts were due or paid in respect of the NPI at that time.

Our 2005 proved reserve estimate is 112.0 Bcf. At December 31, 2005, NSAI, an independent petroleum engineering firm, prepared an estimate of our proved reserves. NSAI also prepared an updated report at our request to provide a sensitivity of the estimates of the NSAI December 31, 2005 reserves based on our reduced drilling program, our revised refracture program and the elimination of estimated reserves attributable to the NPI. NSAI’s estimate of our 2005 proved reserves is materially consistent with our internal estimate.

Our 2004 and 2003 proved reserve estimates are 162.2 Bcf and 163.7 Bcf, respectively. These are our internal estimates of proved reserves that were used in the 2004 and 2003 Everlast financial statements included elsewhere in this prospectus. We prepared the estimates of 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 net proved reserve estimate, which was prepared based upon a continuation of the assumptions used by Everlast, including the prior accelerated drilling program and reserve assumptions, and rolling back the estimate to December 31, 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back approach was necessary because the reserve report prepared by NSAI for Everlast as of December 31, 2004 was not based on the SEC definition of proved reserves, while the reserve report prepared by NSAI for Everlast as of December 31, 2003, which was based on the SEC definition of proved reserves, included different assumptions than those used by NSAI in preparing the December 31, 2005 proved reserves estimate. To prepare reserve estimates for these periods in compliance with the SEC definitions, we adopted the roll back approach described above and in Note 2 and Note 17 to the historical financial statements. Everlast’s previous non-SEC compliant reserve estimates were 173.4 Bcf at December 31, 2004 and 166.2 Bcf at December 31, 2003.

Index to Financial Statements

RISK FACTORS

Limited liability company interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors, together with all of the other information included in this prospectus, in evaluating an investment in our common units.

The following risks could materially and adversely affect our business, financial condition or results of operations. If any of the events described below were to occur, we may not be able to pay quarterly distributions on our common units, the trading price of our common units could decline and you could lose part or all of your investment in our company.

Risks Related to Our Business

We may not have sufficient cash from operations to pay the IQD following establishment of cash reserves and payment of fees and expenses, including payments to CEPM.

We may not have sufficient cash flow from operations each quarter to pay the IQD of $0.425 per common unit following establishment of cash reserves and payment of fees and expenses, including payments to CEPM. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on numerous factors generally described in this caption ”Risk Factors”, including, among other things: the amount of natural gas we produce; the demand for and the price at which we are able to sell our natural gas production; the results of our hedging activity; the level of our operating costs, including reimbursements to CEPM under the management services agreement; the costs we incur to acquire E&P properties; whether we are able to continue our development and exploitation activities at economically attractive costs; the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon; and the level of our capital expenditures.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including: our ability to make working capital borrowings under our reserve-based credit facility to pay distributions; our debt service requirements and restrictions on distributions contained in our reserve-based credit facility; fluctuations in our working capital needs; timing and collectibility of receivables; prevailing economic conditions; the amount of our estimated maintenance capital expenditures; and the amount of cash reserves established by our board of managers for the proper conduct of our business, including the maintenance of our asset base and the payment of future cash distributions on our Class A and common units, management incentive interests and Class D interests. As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter and may be significantly less than the initial quarterly distribution amount that we expect to distribute. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

The amount of cash that we have available for distribution to our unitholders depends primarily upon our cash flow and not our profitability.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our profitability, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may pay distributions during periods when we incur net losses.

If we are unable to achieve the Estimated Adjusted EBITDA set forth in “Cash Distribution Policy and Restrictions on Distributions” and cannot borrow the required amounts, we may be unable to pay the full, or any, amount of the IQD on the common units, in which event the market price of our common units may decline substantially.

The calculation of Estimated Adjusted EBITDA for the twelve months ending September 30, 2007 set forth in “Cash Distribution Policy and Restrictions on Distributions” has been prepared by our management and we

Index to Financial Statements

have not received an opinion or report on it from any independent accountants. The assumptions underlying this calculation are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those expected. If we do not achieve the expected results or cannot borrow the amounts needed, we may not be able to pay the full, or any, amount of the IQD, in which event the market price of our common units may decline substantially.

We would not have generated sufficient available cash on a pro forma basis to have paid the IQD on all of our outstanding common units and Class A units for the year ended December 31, 2005 or the six months ended June 30, 2006.

The amount of available cash we will need to pay the IQD for four quarters on the common units and the Class A units to be outstanding immediately after this offering is approximately $25.1 million. If we had completed the transactions contemplated in this prospectus on January 1, 2005, pro forma available cash generated during the year ended December 31, 2005 would have been approximately $8.6 million. If we had completed the transactions contemplated in this prospectus on July 1, 2005, pro forma available cash generated during the twelve months ended June 30, 2006 would have been approximately $8.3 million. These amounts of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 34% and 33%, respectively, of the $0.425 per quarter IQD on our common units and Class A units during these periods. For a calculation of our ability to make distributions to you based on our pro forma results for the year ended December 31, 2005 and the twelve months ended June 30, 2006, please read “Cash Distribution Policy and Restrictions on Distributions.”

Natural gas prices are very volatile, and if commodity prices decline significantly for a temporary or prolonged period, our cash from operations will decline and we may have to lower our quarterly distribution or may not be able to pay distributions at all.

Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. In particular, declines in commodity prices will reduce the value of our reserves, our cash flow, our ability to borrow money or raise capital and our ability to pay distributions. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as: the domestic and foreign supply of and demand for natural gas; the price and level of foreign imports of oil and natural gas; the level of consumer product demand; weather conditions; overall domestic and global economic conditions; political and economic conditions in natural gas and oil producing countries, including those in West Africa, Middle East and South America; the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; the impact of the U.S. dollar exchange rates on natural gas and oil prices; technological advances affecting energy consumption; domestic and foreign governmental regulations and taxation; the impact of energy conservation efforts; the costs, proximity and capacity of natural gas pipelines and other transportation facilities; and the price and availability of alternative fuels.

In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2005, the SONAT Gas Daily Price ranged from a high of $19.79 per MMBtu to a low of $5.55 per MMBtu. If we raise our cash distribution level in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during periods of sustained lower commodity prices.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Coalbed methane production generally declines at a

Index to Financial Statements

shallow rate after initial increases in production as a consequence of the dewatering process. However, production rates from newly drilled and completed wells in the Robinson’s Bend Field do not typically increase as the formation dewaters.

We estimate that, as of December 31, 2005, our average annual decline rate for proved developed producing reserves is approximately 5% during the next fifteen years. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, we expect that production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline of our reserves and production reflected in our reserve report of December 31, 2005, will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of natural gas in an exact way. Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels and operating and development costs. In addition, in the early stages of a coalbed methane project, it is difficult to predict the production curve of a coalbed methane field. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may prove to be inaccurate. We have prepared the estimates of proved natural gas reserves included in this prospectus, and such estimates are different from the estimates that may be determined by an independent petroleum engineering firm. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which estimates are less reliable than those based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the Standardized Measure of our proved reserves as of December 31, 2005 would decrease from approximately $295.4 million to approximately $262.0 million. Our Standardized Measure is calculated using unhedged natural gas prices and is determined in accordance with the rules and regulations of the SEC (except for the impact of income taxes as we are not a taxable entity). Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves.

We base the estimated discounted future net cash flows from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our natural gas properties also will be affected by factors such as:

•

supply of and demand for natural gas;

•

actual prices we receive for natural gas;

•

our actual operating costs in providing natural gas;

Index to Financial Statements

•

the amount and timing of our capital expenditures;

•

the amount and timing of actual production; and

•

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to you.

Future price declines may result in a write-down of our asset carrying values.

Lower natural gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. Substantial decreases in natural gas prices would render a significant number of our planned exploitation projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a writedown of such carrying value. We may incur impairment charges in the future, which could result in a material reduction in our results of operations in the period taken and materially limit our ability to borrow funds under our reserve-based credit facility and our ability to make cash distributions to our unitholders.

We rely on third parties, including CEPM, for our management. If CEPM or these third parties fail to or inadequately perform, or if we cannot enter into other management contracts on satisfactory terms, our costs will increase and reduce our cash from operations and our ability to make cash distributions to you.

We rely on third parties for our management. While our board of managers will have the right and responsibility to manage our affairs, we expect to rely on third parties to manage the day-to-day aspects of our business. We will enter into a management services agreement with CEPM, a wholly owned subsidiary of Constellation. Pursuant to that agreement, we will be required to use CEPM or its designee for legal, accounting, finance, tax and risk management services while we are consolidated with Constellation for accounting purposes. We also expect that CEPM will provide us with assistance in hedging our production and acquisition services in respect of opportunities for us to acquire long-lived, stable and proved oil and natural gas reserves. Constellation and its affiliates have no obligation to present us with potential acquisitions, and, if they fail to do so, we will need to either seek acquisitions on our own or retain a third party to seek acquisitions on our behalf. In the long term, without further acquisitions, we will not be able to replace or grow our reserves, which would reduce our cash from operations and our ability to make cash distributions to you.

In addition, we plan to target acquisitions in areas where we can work with third-party operators who have technical development expertise and experience in the particular natural gas field in which we are acquiring an interest and who will hold a working interest in such properties. If we cannot find suitable third-party operators or our operators fail to perform under their contracts, we will need to hire additional personnel to operate our properties. Doing so will increase our costs and could adversely affect our cash from operations and our ability to make cash distributions to you.

Index to Financial Statements

Our operations require substantial capital expenditures, which will reduce our cash available for distribution.

We will need to make substantial capital expenditures to maintain our asset base over the long term. These maintenance capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:

•

changes in our reserves;

•

changes in natural gas prices;

•

changes in labor and drilling costs;

•

our ability to acquire, locate and produce reserves;

•

changes in leasehold acquisition costs; and

•

government regulations relating to safety and the environment.

Our significant maintenance capital expenditures will reduce the amount of cash we have available for distribution to our unitholders. In addition, our actual maintenance capital expenditures will vary from quarter to quarter.

Each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

Our limited liability company agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.

We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.

In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other securities. Such uses of cash from operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional

Index to Financial Statements

limited liability company interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

Furthermore, if our revenues or the borrowing base under our reserve-based credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to increase or sustain our asset base. Our reserve-based credit facility will restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our reserve-based credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves, and could diminish our results of operations, financial condition and our ability to make cash distributions to you.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to sustain or increase distributions will be limited.

Our ability to grow and to increase distributions to unitholders is partially dependent on our ability to make acquisitions that result in an increase in available cash per unit. We may be unable to make such acquisitions because we are:

•

unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•

unable to obtain financing for these acquisitions on economically acceptable terms; or

•

outbid by competitors.

In any of these cases, our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit.

Our anticipated acquisition activities will subject us to certain risks.

Any acquisition involves potential risks, including, among other things: the validity of our assumptions about reserves, future production, revenues and costs, including synergies; an inability to integrate successfully the businesses we acquire; a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; the diversion of management’s attention to other business concerns; an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; the incurrences of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; unforeseen difficulties encountered in operating in new geographic areas; and customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Index to Financial Statements

If our acquisitions do not generate increases in available cash per unit, our ability to make cash distributions to our unitholders could materially decrease.

We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions to our unitholders.

Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may borrow significant amounts under our reserve-based credit facility in the future to enable us to pay quarterly distributions. Significant declines in our production or significant declines in realized natural gas prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

When we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our reserve-based credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our reserve-based credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.

Our reserve-based credit facility will have substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations and our ability to pay distributions to our unitholders.

We will depend on our reserve-based credit facility for future capital needs and to fund a portion of our distributions. The reserve-based credit facility will restrict our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We will also be required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the reserve-based credit facility could result in a default under our reserve-based credit facility, which could cause all of our existing indebtedness to be immediately due and payable. Each of the following is expected to be an event of default:

•

failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

•

a representation or warranty made under the loan documents or in any report or other instrument furnished thereunder is incorrect when made;

•

failure to perform or otherwise comply with the covenants, including a covenant requiring that Constellation and its affiliates shall maintain the right to elect our Class A managers, in the credit facility or other loan documents, subject, in certain instances, to certain grace periods;

•

any event occurs that permits or causes the acceleration of the indebtedness;

•

bankruptcy or insolvency events involving us or our subsidiaries;

•

the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

Index to Financial Statements

•

specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any year; and

•

a change of control, generally defined as the first date on which the following two conditions occur: (i) a decrease by CEPH and CEPM of their combined voting power of our outstanding voting securities to less than 10%, and (ii) the ownership by any person (other than a wholly-owned subsidiary of Constellation) of our outstanding voting securities with a combined voting power of more than 35%.

The reserve-based credit facility will limit the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the reserve-based credit facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. Upon the closing of our reserve-based credit facility, we will not have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the reserve-based credit facility.

Our reserve-based credit facility may restrict us from borrowing to pay distributions on our outstanding units.

We will be prohibited from borrowing under our reserve-based credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our reserve-based credit facility reaches or exceeds 90% of the borrowing base. Our borrowing base is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas reserves, which will take into account the prevailing natural gas prices at such time. We anticipate that if, at the time of any distribution, our borrowings equal or exceed 90% of the then-specified borrowing base, our ability to pay distributions to our unitholders in any such quarter will be solely dependent on our ability to generate sufficient cash from our operations. Giving effect to the use of the net proceeds from this offering, we estimate our borrowings under the credit facility will be $22.0 million, or approximately 22% of our estimated initial borrowing base of $100.0 million upon the closing of the offering.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

We estimate that we will have $22.0 million of indebtedness outstanding immediately after the closing of this offering. Following this offering, we estimate that will have the ability to incur additional debt, including the capacity to borrow up to an additional $78.0 million under our new reserve-based credit facility, subject to borrowing base limitations in the credit agreement. Our future indebtedness could have important consequences to us, including:

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

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covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

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we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

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our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Index to Financial Statements

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Expense reimbursements due to CEPM under our management services agreement will reduce cash available for distribution to our unitholders.

Prior to making any distribution on the common units, we will reimburse CEPM for all expenses that it incurs on our behalf pursuant to the management services agreement. These expenses will include all costs incurred on our behalf in performing accounting and financial, risk management and acquisition services, including costs for providing corporate staff and support services to us. CEPM will charge on a fully allocated cost basis for services provided to us. This fully allocated cost basis is based on the percentage of time spent by personnel of CEPM and its affiliates on our matters and includes the compensation paid by CEPM and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on our business and affairs, subject to the periodic review and approval of our audit or conflicts committee. The reimbursement of expenses to CEPM could adversely affect our ability to pay cash distributions to our unitholders.

If the Trust is terminated, the gas purchase contract with the Trust will be terminated and payment by us to the Trust in respect of the NPI may cease being calculated by the sharing arrangement. As a result, our royalty obligations under the NPI could increase, which could adversely affect our results of operations and our ability to pay cash distributions.

The gas purchase contract with the Trust terminates on the earlier to occur of December 31, 2012 and the termination of the Trust. The Trust will terminate upon the first to occur of (i) an affirmative vote of the holders of not less than 66²/3% of the outstanding Trust units to liquidate the Trust, and (ii) such time as the ratio of the cash amounts received by the Trust from the NPI to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters. The Trust will also terminate on March 1 of any year if it is determined that the pre-tax future net cash flows, discounted at 10%, attributable to the estimated net proved reserves of the NPI on the preceding December 31 are less than $25.0 million. Based on natural gas reserve estimates at December 31, 2005 prepared by independent reserve engineers, the Trust has advised its investors that, unless the Henry Hub spot price for natural gas on December 31, 2006 exceeds approximately $6.25 per MMBtu, the Trust will terminate on March 1, 2007. The Henry Hub spot price for natural gas on December 31, 2005 and September 1, 2006 was $10.08 per MMBtu and $5.815 per MMBtu, respectively. Upon termination of the Trust, the gas purchase contract with Torch Energy Marketing, Inc., an affiliate of the original sponsor of the Trust, or TEMI, including the portion assigned to us, will terminate. Based upon our estimated production for the twelve months ending September 30, 2007 and the weighted average net realized sales price for our production used in calculating our Estimated Adjusted EBITDA for that twelve-month period under the caption “Cash Distribution Policy and Restrictions on Distributions,” we estimate that, if the sharing arrangement in respect of the Trust was terminated as of October 1, 2006, our revenues would be reduced by approximately $5.6 million during such twelve-month period and the $8.0 million contributed to us for the Class D interests would offset such a shortfall for approximately 1.4 years, if the production and prices set forth under “Cash Distribution Policy and Restrictions on Distributions—Our Estimated Cash Available to Pay Distributions” were to remain constant throughout such period.

The royalty payment owed by us under the NPI is calculated based in part on gross proceeds as that term is defined in the gas purchase contract. Under the gas purchase contract, there is a sharing arrangement that permits us, as gas purchaser, to retain any excess of the market price we receive for production from the Trust Wells over

Index to Financial Statements

the price under the sharing arrangement. This price under the sharing arrangement is equal to the sum of the sharing price set forth in the gas purchase contract, plus 50% of the amount by which 97% of the applicable spot index price exceeds the sharing price. Despite increases in recent years in the spot price for natural gas, this sharing arrangement has had the effect of keeping the royalty payments to the Trust in respect of the NPI significantly lower than the prevailing market price. If our payments to the Trust for the NPI ceased being calculated under the sharing arrangement, our royalty obligations under the NPI would be significantly higher based on current natural gas prices, which would reduce our revenues and could adversely affect our results of operations and our ability to pay cash distributions.

A group of investors in the Trust may seek to terminate the Trust, which termination could reduce our future revenues and adversely affect our results of operations and our ability to pay cash distributions.

In a filing with the SEC by a group that as of December 23, 2005 reported that it owned approximately 6.34% of the trust units then outstanding, such group reported that, among other actions it may take in the future, such group may “. . . call a meeting of Unitholders to vote on . . . termination of the Trust . . . .” If the trust unitholders were to approve a termination of the Trust, whether upon a resolution submitted by such group or otherwise, the Trust would be terminated, which in turn would terminate the gas purchase contract.

The gas purchase contract on which the NPI is based contains a minimum price arrangement, which could have the effect of requiring a higher royalty payment in respect of the NPI than would be the case if the gas purchase contract did not have the minimum price arrangement. If the applicable index price falls below the minimum price, it could adversely affect our financial condition and results of operations and, as a result, our ability to pay cash distributions.

Pursuant to the gas purchase contract on which the NPI is based, we are required to pay at least $1.70 (adjusted for inflation annually, or approximately $1.80 during 2006) per MMBtu, which we refer to as the minimum price, for gas purchased from production in respect of the Trust Wells. If the applicable index price is less than the minimum price in any month, amounts payable under the gas purchase contract could be higher than the gross proceeds we would receive for the gas at market prices. As a result, the royalty obligation payable by us in respect of the NPI could exceed the gross proceeds we have received for the gas produced in respect of the NPI. If we have to pay a royalty under the NPI based upon the minimum price that exceeds the actual revenue received by us for the sale of such gas, based upon market prices, it could adversely affect our financial condition and results of operations and, as a result, our ability to pay cash distributions. The index price for the Trust Wells is the price reported in Inside FERC’s Gas Market Report for the Southern Natural Gas Co., Louisiana hub, which we refer to as the SONAT Inside FERC Price. For the years ended December 31, 2005 and 2004, the monthly index price varied between a low of $6.12 and a high of $14.01, and a low of $5.05 and a high of $7.74, respectively. For the eight months ended August 31, 2006, the monthly index price varied between a low of $5.87 and a high of $11.67.

The gas purchase contract on which the NPI is based contains a sharing arrangement in the event the applicable spot index price for natural gas exceeds the sharing price, as calculated under the gas purchase contract. If the applicable spot index price for natural gas falls below the sharing price, it would have the effect of reducing the revenue we retain upon resale of the gas produced from the Trust Wells and could adversely affect our financial condition and results of operations and, as a result, our ability to pay cash distributions.

The gas purchase contract on which the NPI is based provides for a sharing arrangement in the event the index price in any month exceeds a price of $2.10 (adjusted for inflation annually, or approximately $2.22 during 2006) per MMBtu, which we refer to as the sharing price. If 97% of the applicable spot index price is equal to or less than the sharing price, gas is purchased at the greater of (i) 97% of the index price per MMBtu and (ii) the minimum price described in the immediately preceding risk factor. If the index price exceeds the sharing price in any month, however, gas is purchased at the sharing price plus 50% of the excess of 97% of the applicable spot index price over the sharing price per MMBtu. In that case, gross proceeds payable under the gas purchase

Index to Financial Statements

contract could be substantially less than the gross proceeds at market prices, as a result of which the royalty obligation payable by us in respect of the NPI could be substantially less than the gross proceeds we have received for the produced gas. For example, during 2005 and the seven months ended July 31, 2006, the amount payable under the gas purchase contract was, on average, approximately $3.37 MMBtu and $2.82 MMBtu, respectively, less than the net average market price realized for the sale of such gas. If during the term of the gas purchase contract, the index price is equal to or less than the sharing price, it could adversely affect our financial condition and results of operations and, as a result, our ability to pay cash distributions.

While TEMI’s interest in the gas purchase contract was assigned to one of our subsidiaries in June 2005, TEMI remains a nominal party to that contract and has obligations thereunder and the potential ability to make elections or even breach its obligations, both of which could adversely affect our rights and interests.

TEMI is an original party to the gas purchase contract. In connection with our acquisition of the Robinson’s Bend Field properties from Everlast in June 2005, one of our subsidiaries assumed from TEMI all of its rights in respect of the Trust Wells under the gas purchase contract. As TEMI remains a nominal party to the gas purchase contract, it may still have the ability to make elections or even breach its obligations under the contract in a manner that affects our rights in respect of the Robinson’s Bend Field. Any such action by TEMI could adversely impact our rights and interests. If TEMI breaches its obligations under the gas purchase contract, the gas purchase contract may terminate, which could similarly result in a termination of the rights assigned to us. Also, if TEMI elects to terminate the minimum price commitment, we could be required to use the applicable spot index price without the sharing arrangement to calculate the amounts payable by us to the Trust for the NPI, which could cause the royalty obligation in respect of the NPI to increase. Any such increase in our royalty obligation under the NPI could reduce our revenues and adversely affect our financial condition and results of operations and, as a result, our ability to pay cash distributions.

We depend on certain key customers for sales of our natural gas. To the extent these and other customers reduce the volumes of natural gas they purchase from us and are not replaced by new customers, our revenues and cash available for distribution could decline.

For the six months ended June 30, 2006, five customers accounted for 100% of our total sales volumes. Specifically, Interconn Resources Inc., BP Energy Company, Enterprise Alabama, ConocoPhillips and Coral Energy Resources, L.P. accounted for approximately 31%, 27%, 18%, 13% and 11%, respectively, of our total sales volumes. To the extent these and other customers reduce the volumes of natural gas that they purchase from us and are not replaced by new customers, our revenues and cash available for distribution could decline.

Our hedging activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of natural gas, we have adopted a policy that contemplates hedging approximately 80% of our expected production volumes for up to five years. As a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we intend to utilize are generally based on posted market prices, which may differ significantly from the actual natural gas prices we realize in our operations. If we had implemented this hedging strategy on June 30, 2005 for the twelve months ended June 30, 2006, we estimate that we would have realized approximately $5.9 million less revenue for that period. On June 20, 2006, we entered into derivative transactions that hedge the future prices of approximately 78% of the expected production from our currently producing wells from October 2006 to December 2009. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure about Market Risk.”

Our actual future production may be significantly higher or lower than we estimate at the time we enter into hedging transactions for such period. If the actual amount is higher than we estimate, we will have greater

Index to Financial Statements

commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the following risks:

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a counterparty may not perform its obligation under the applicable derivative instrument;

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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

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the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties to our hedging arrangements. Some of our customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties could reduce our ability to make distributions to our unitholders.

Certain of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

We hold natural gas leases on approximately 17,100 net acres in the Robinson’s Bend Field that are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases, most of these leases will expire between September 2006 and October 2010. Leases covering approximately 7,614 net acres are scheduled to expire before September 30, 2007. If our leases expire, we will lose our right to develop the related properties.

Our business is difficult to evaluate because we have a limited operating history.

We were formed in February 2005 by Constellation to acquire natural gas properties located in the Robinson’s Bend Field from Everlast in June 2005. Our assembled management team may not be able to successfully oversee our business and effectively implement our operating and growth strategies. Our financial results cover periods during which the natural gas properties that we acquired were not under the control or management of our current management team and therefore may not be indicative of our future financial or operating results. Our success will depend upon management’s ability to manage, operate and develop the properties that we currently own and those we may acquire in the future. Our failure to successfully manage, operate and develop these properties may have a significant adverse effect on our financial condition and results of operations.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.

Our management has specifically identified and scheduled drilling locations for our future multi-year drilling activities on our existing acreage. As of December 31, 2005, we had identified 120 gross proved undeveloped drilling locations and approximately 244 additional gross potential drilling locations. These identified drilling locations represent a significant part of our future development drilling program for the Robinson’s Bend Field. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results.

Index to Financial Statements

In addition, no proved reserves are assigned to any of the approximately 244 potential drilling locations we have identified and therefore, there may exist greater uncertainty with respect to the likelihood of drilling and completing successful commercial wells at these potential drilling locations. Our final determination of whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified, which could have a significant adverse effect on our financial condition and results of operations.

Locations that we decide to drill may not yield natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drilling success rate would decline, and may materially harm our business.

Drilling for and producing natural gas are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including: the high cost, shortages or delivery delays of drilling rigs, equipment, labor and other services; unexpected operational events and drilling conditions; reductions in oil and natural gas prices; limitations in the market for oil and natural gas; adverse weather conditions; facility or equipment malfunctions; accidents; title problems; piping, casing or cement failures; compliance with environmental and other governmental requirements; unusual or unexpected geological formations; lost or damaged oilfield drillings and service tools; loss of drilling fluid circulation; formations with abnormal pressures; environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; fires or natural disasters; blowouts, craterings and explosions; and uncontrollable flows of natural gas or well fluids.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could adversely affect our business activities, financial condition, results of operations and our ability to make cash distributions to you.

Because we handle natural gas and other petroleum products in our business, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations.

The operations of our wells, gathering systems, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

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the federal Clean Air Act, related federal regulations, and comparable state laws and regulations that impose obligations related to air emissions;

Index to Financial Statements

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the federal Clean Water Act, related federal regulations, and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated waters;

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the federal Resource Conservation and Recovery Act, or RCRA, related federal regulations, and comparable state laws and regulations that impose requirements for the handling and disposal of waste from our facilities; and

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the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance. Please read “Business—Environmental Matters and Regulation.”

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act, and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released into the environment.

We may incur significant costs and liabilities in the future resulting from an accidental release of hazardous substances into the environment.

There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example:

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there is the potential for an accidental release from one of our wells or gathering pipelines;

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certain of our operations are known to bring to the surface naturally occurring radioactive material, or NORM, that is accumulated at our facilities and is subject to permitting and controls for storage, as well as requirements for proper disposal; and

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several treatment ponds associated with the treatment and storage of produced waters and similar wastewaters have leaked into the subsurface and we are in the process of replacing the liners beneath these treatment ponds and, under the supervision of the Alabama Department of Environmental Management, monitoring for the presence of contaminants in the subsurface to better determine what cleanup, if any, may be required.

If a problem occurs with respect to any one of these, it could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations.

Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.

We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our natural gas exploration, production and transportation operations. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the

Index to Financial Statements

substances that we handle. For instance, we must maintain permits and adhere to certain controls related to the storage and proper disposal of naturally occurring radioactive material, or NORM, that is produced periodically in connection with our natural gas drilling operations. In addition, as a result of leaks from ponds used for the treatment and storage of produced waters and similar wastewaters from our operations, we are in the process of replacing pond liners and are also conducting subsurface monitoring for chlorides under the supervision of the Alabama Department of Environmental Management. We may incur additional expenses, which could be material, in the future if our monitoring activities reveal that any contaminants exist in the subsurface beneath the ponds, and the agency requires cleanup of any such contaminants.

Failure to comply with environmental laws and regulations could result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of orders to limit or cease certain operations. In addition, certain environmental laws impose strict, joint and several liability, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for damages as a result of environmental and other impacts. Please read “Business—Environmental Matters and Regulation” for more information.

Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher natural gas prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Over the past three years, we (and Everlast) and other oil and natural gas companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

The coalbeds from which we produce natural gas frequently contain water that may hamper our ability to produce natural gas in commercial quantities or adversely affect our profitability.

Unlike conventional natural gas production, coalbeds frequently contain water that must be removed in order for the gas to desorb from the coal and flow to the wellbore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce natural gas in commercial quantities. In addition, the cost of water disposal may be significant and may reduce our profitability.

We may face unanticipated water disposal costs.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies or our wells produce water in excess of the applicable volumetric permit limit, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

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we cannot obtain future permits from applicable regulatory agencies;

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water of lesser quality or requiring additional treatment is produced;

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our wells produce excess water; or

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new laws and regulations require water to be disposed of in a different manner.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our

Index to Financial Statements

reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon CEPM’s willingness and ability to evaluate and select suitable properties and our ability to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations, which could reduce the amount of cash we have available to pay distributions to you.

Due to our lack of asset and geographic diversification, adverse developments in our operating area would reduce our ability to make distributions to our unitholders.

We rely exclusively on sales of the natural gas that we produce. Furthermore, all of our assets are located in the Black Warrior Basin in Alabama. Due to our lack of diversification in asset type and location, an adverse development in the oil and gas business or this geographic area, would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

Seasonal weather conditions adversely affect our ability to conduct production activities in the Robinson’s Bend Field.

Natural gas operations in the Robinson’s Bend Field are adversely affected by seasonal weather conditions, primarily during hurricane season. We face the risk that power outages resulting from hurricanes and other strong storms will prevent us from operating our wells in an optimal manner.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of natural gas we may produce and sell.

Index to Financial Statements

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of natural gas. The possibility exists that these new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to our unitholders could be adversely affected. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry who can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business—Environmental Matters and Regulation” for more information on the laws and regulations that affect us.

We will incur increased costs as a result of being a public company.

We have no history operating as a public company. As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the NYSE Arca, have required changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a public company, we are required to have three independent managers, create board committees and adopt polices regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our public company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified persons to serve on our board of managers or as executive officers. The costs we incur as a result of being a public company will decrease the amount of cash available to pay distributions to you.

Risks Related to Our Structure

Constellation and its affiliates will own a controlling interest in us through their ownership of our Class A units and a majority of our common units.

Upon completion of this offering, Constellation will indirectly own approximately 57% of the outstanding common units, or approximately 50% if the underwriters’ option to purchase additional common units is exercised in full, and 100% of the outstanding Class A units. Accordingly, Constellation and its affiliates will be able to assert great influence in any vote of common unitholders, including the election of the three members of our board of managers that are elected by the common unitholders. As long as Constellation and its affiliates beneficially own a controlling interest in us, they will have the ability to control our management and affairs. In addition, CEPM, as the holder of all our Class A units, will have the exclusive right to elect two members of our board of managers. Affiliates of Constellation may thus be able to cause a change of control of our company. This concentration of ownership may have the effect of preventing or discouraging transactions involving an actual or a potential change of control of our company, regardless of whether a premium is offered over then-current market prices.

Members of our board of managers, our executive officers and Constellation and its affiliates, including CEPH and CEPM, may have conflicts of interest with us. Our limited liability company agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest or the resolution of such a conflict of interest.

Following the offering, two of the members of our board of managers who will be appointed by CEPM, the holder of our Class A units, and are officers of, and will be affiliated with, Constellation. In addition, our executive officers also serve as managers, directors, officers or employees of Constellation or its other affiliates. Conflicts of interest may arise between us and our unitholders and members of our board of managers or our executive officers and Constellation and its affiliates, including CEPH and CEPM. These potential conflicts may relate to the divergent interests of these parties. Situations in which the interests of members of our board of

Index to Financial Statements

managers or our executive officers and Constellation and its affiliates, including CEPH and CEPM, may differ from interests of owners of common units include, among others, the following situations:

•

our limited liability company agreement gives our board of managers broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our board of managers will use its reasonable discretion to establish and maintain cash reserves sufficient to maintain our asset base;

•

none of our limited liability agreement, management services agreement nor any other agreement requires Constellation, CEPM or any of their affiliates to pursue a business strategy that favors us. Directors and officers of Constellation, CEPM and their subsidiaries (other than us) have a fiduciary duty while acting in the capacity as such a director or officer of Constellation, CEPM or such subsidiary to make decisions in the best interests of the Constellation stockholders, which may be contrary to our best interests;

•

upon our request, CEPM, under the management services agreement, will recommend to our board of managers the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, and financing alternatives (whether borrowings, issuances of additional limited liability company interests or a combination of the foregoing) and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders;

•

we intend to rely on CEPM to provide us with opportunities for the acquisition of oil and natural gas reserves, however, neither Constellation nor CEPM has any obligation to provide us with such opportunities;

•

in some instances our board of managers may cause us to borrow funds in order to permit us to pay cash distributions to our unitholders, even if the purpose or effect of the borrowing is to make management incentive distributions;

•

each of our executive officers and our Class A managers also serve as a manager, director, officer or employee of Constellation or its affiliates (other than us) and (i) while acting in such person’s capacity as such a manager, director, officer or employee of Constellation or such affiliates, as opposed to such person’s capacity as our executive officer or Class A manager, such person will not owe any fiduciary duty to us or our security holders and (ii) in making decisions in such person’s capacity as such a manager, director, officer or employee of Constellation or such affiliates may favor the interests of Constellation or such affiliate over your interests and may be to our detriment;

•

following the closing of this offering, our executive officers will not be compensated by us; instead, they will be compensated by CCG for serving as officers or employees of CCG;

•

we intend to rely on CEPM and its affiliates to assist us in implementing our hedging policy;

•

none of our executive officers or the members of our board of managers and Constellation and its affiliates, including CEPH and CEPM, are prohibited from investing or engaging in other businesses or activities that compete with us; and

•

our board of managers is allowed to take into account the interests of parties other than us, such as Constellation or CEPM, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

If in resolving conflicts of interest that exist or arise in the future our board of managers or officers, as the case may be, satisfy the applicable standards set forth in our limited liability company agreement for resolving conflicts of interest, you will not be able to assert that such resolution constituted a breach of fiduciary duty owed to us or to you by our board of managers and officers.

Our limited liability company agreement prohibits a unitholder (other than CEPM, CEPH and their affiliates) who acquires 15% or more of our common units without the approval of our board of managers from engaging in a business combination with us for three years. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.

Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Laws, or the DGCL. Section 203 of the DGCL as it applies to us prevents an interested unitholder,

Index to Financial Statements

defined as a person who owns 15% or more of our outstanding common units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our limited liability company agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of managers, including discouraging takeover attempts that might result in a premium over the market price for our common units.

Our common unitholders will not have the right to vote for two of our managers, and the common units that will be indirectly owned by Constellation immediately after this offering will give Constellation the ability to elect a majority of our managers.

CEPM, as the sole holder of our Class A units, will have the sole right, voting as a separate class, to elect two of the five members of our board of managers and to fill any vacancy created by the death, resignation or removal of either of such managers. Each of the three remaining members of our board of managers will be subject to annual election at a meeting of our common unitholders.

Since Constellation will own more than a majority of our outstanding common units immediately after the closing of this offering, Constellation, in combination with CEPM as owner of the Class A units, will be able to elect a majority of the members of our board of managers. In addition, since the removal of a manager elected by our common unitholders requires the approval of the holders of not less than a majority of our outstanding common units, our public common unitholders will not be able to remove a member of our board of managers unless Constellation votes its common units in favor of such a removal.

Our limited liability agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our limited liability agreement restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Constellation, CEPM, their affiliates or transferees and persons who acquire such units with the prior approval of the board of managers, cannot vote on any matter. Our limited liability agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting common unitholders’ ability to influence the manner or direction of management.

If the holders of our common units vote to eliminate the special voting rights of the holders of our Class A units, our Class A units will convert into common units on a one-for-one basis and CEPM will have the option of converting the management incentive interests into common units at their fair market value, which may be dilutive to you.

The holders of our Class A units have the right, voting as a separate class, to elect two of the five members of our board of managers, and any replacement of either of such members. This right can be eliminated upon a vote of the holders of not less than a 66²/3% of our outstanding common units. If such elimination is so approved and Constellation and its affiliates do not vote their common units in favor of such elimination, the Class A units will be converted into common units on a one-for-one basis and CEPM will have the right to convert its management incentive interests into common units based on the then fair market value of such interests, which may be dilutive to you.

You will experience immediate and substantial dilution of $10.59 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $9.41 per common unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $10.59 per common unit. Please read “Dilution.”

Index to Financial Statements

We may issue additional units without your approval, which would dilute your existing ownership interests.

We may issue an unlimited number of limited liability company interests of any type, including common units and units with rights to cash distributions or in liquidation that are senior in order of priority to common units, without the approval of our unitholders.

The issuance of additional units or other equity securities may have the following effects:

•

your proportionate ownership interest in us may decrease;

•

the amount of cash distributed on each common unit may decrease;

•

the relative voting strength of each previously outstanding common unit may be diminished;

•

the market price of the common units may decline; and

•

the ratio of taxable income to distributions may increase.

Our limited liability company agreement provides for a limited call right that may require you to sell your common units at an undesirable time or price.

If, at any time, any person owns more than 80% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, you may be required to sell your common units at an undesirable time or price and therefore may receive a lower or no return on your investment. You may also incur tax liability upon a sale of your common units. For additional information about the call right, please read “The Limited Liability Company Agreement—Limited Call Right.”

Unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and you may not be able to resell your common units at the initial public offering price.

Prior to the offering, there has been no public market for the common units. After the offering, there will be 6,275,000 publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

If our common unit price declines after the initial public offering, you could lose a significant part of your investment.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

•

changes in securities analysts’ recommendations and their estimates of our financial performance;

•

the public’s reaction to our press releases, announcements and our filings with the Securities and Exchange Commission;

•

fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies and securities of publicly traded limited partnerships and limited liability companies;

•

changes in market valuations of similar companies;

•

departures of key personnel;

•

commencement of or involvement in litigation;

Index to Financial Statements

•

variations in our quarterly results of operations or those of other natural gas and oil companies;

•

variations in the amount of our quarterly cash distributions;

•

future issuances and sales of our common units; and

•

changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

In recent years, the securities markets have experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act (the “Delaware Act”), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, members or unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a member or unitholder is liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.

Constellation’s interests in us may be transferred to a third party without common unitholder consent.

Constellation’s affiliates may transfer their Class A units, common units, management incentive interests and Class D interests to a third party in a merger or in a sale of all or substantially all of their respective assets without the consent of our common unitholders. Furthermore, there is no restriction in our limited liability company agreement on the ability of Constellation to cause a transfer to a third party of its affiliates’ equity interest in CEPM, CEPH, CCG or CHI. The new owner of the Class A units and common units formerly owned by Constellation would then be in a position to replace a majority of our board of managers with its own choice, which could then replace some or all of our officers.

CEPH may sell common units in the future, which could reduce the market price of our outstanding common units.

Following the completion of this offering, CEPH will control an aggregate of 8,214,010 common units. In addition, we have agreed to register for sale common units held by CEPH. These registration rights allow CEPH to request registration of its common units and to include any of those common units in a registration of other securities by us. If CEPH were to sell a substantial portion of its common units, it could reduce the market price of our outstanding common units. Please also read “Units Eligible for Future Resale” and “Material Tax Consequences—Disposition of Units—Constructive Termination.”

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable

Index to Financial Statements

from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited liability company interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Tax Risks to Unitholders

You should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the initial quarterly distribution amount and the Target Distribution amounts will be adjusted to reflect the impact of that law on us.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the costs of any contest will reduce cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may

Index to Financial Statements

materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material Tax Consequences—Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your common units.

If you sell any of your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period.

You may be subject to state and local taxes and return filing requirements.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various

Index to Financial Statements

jurisdictions in which we do business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially do business and own assets in Alabama and Maryland. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Index to Financial Statements

CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This prospectus contains forward–looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

•

the volatility of realized natural gas prices;

•

discovery, estimation, development and replacement of oil and natural gas reserves;

•

business and financial strategy;

•

drilling locations;

•

technology;

•

cash flow, liquidity and financial position;

•

the impact on us of termination of the sharing arrangement before December 31, 2012;

•

production volumes;

•

lease operating expenses, general and administrative costs and finding and development costs;

•

availability of drilling and production equipment, labor and other services;

•

future operating results;

•

prospect development and property acquisitions;

•

marketing of oil and natural gas;

•

competition in the oil and natural gas industry;

•

the impact of weather and the occurrence of natural disasters such as fires, floods and other catastrophic events and natural disasters;

•

governmental regulation of the oil and natural gas industry;

•

developments in oil-producing and natural gas producing countries; and

•

strategic plans, objectives, expectations and intentions for future operations.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward–looking statements. These forward–looking statements may be found in the “Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Cash Distribution Policy and Restrictions on Distributions,” “Business” and other sections of this prospectus. In some cases, you can identify forward–looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward–looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward–looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward–looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward–looking statements due to factors listed in the “Risk Factors” section and elsewhere in this prospectus. All forward–looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward–looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward–looking statements attributable to us or persons acting on our behalf.

Index to Financial Statements

USE OF PROCEEDS


Sources of Funds		Uses of Funds

Sale of 6,275,000 common units^(a)	$113.8 million	Distribution to CEPH^(c)(d)	$136.0 million

Contribution by CHI for the Class D interests^(b)	$ 8.0 million	Retained for working capital^(d)^(e)	$ 7.8 million

Borrowings under our new reserve-based credit facility^(b)	$ 30.0 million	Reduction of borrowings under our new reserve-based credit facility	$ 8.0 million



Total	$151.8 million	Total	$151.8 million

(a)

We estimate that we will receive net proceeds of approximately $113.8 million from the sale of the 6,275,000 common units offered by this prospectus, assuming an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) and after deducting underwriting discounts and commissions of $8.5 million and estimated offering expenses of $3.2 million.

(b)

Will be consummated immediately prior to the closing of this offering.

(c)

Reimbursement for capital expenditures incurred by CCG prior to this offering.

(d)

If the initial public offering price exceeds the mid-point of the price range, we will distribute the excess net proceeds to CEPH. If the initial public offering price is less than the mid-point of the price range, we will reduce the size of the special distribution to CEPH in an amount equal to the reduction in net proceeds.

(e)

Includes cash to be retained by us, of which at least $5.0 million will exceed the amounts we expect to be necessary for our working capital purposes. As a result, at least $5.0 million of the net proceeds from our initial public offering will be available for future distributions to our unitholders.

If the underwriters’ option to purchase additional common units is exercised, we will use the additional net proceeds to purchase a number of common units from CEPH equal to the number of common units issued upon exercise of that option. If the underwriters’ option is exercised in full, CEPH’s ownership of common units will be reduced from 8,214,010 common units to 7,272,760 common units, reducing CEPH’s and CEPM’s combined limited liability company interest in us from approximately 58% to approximately 51%.

Index to Financial Statements

CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of June 30, 2006:

•

on a historical basis; and

•

on a pro forma basis to reflect the offering of the common units (assuming we price this offering at $20.00 per common unit, the mid-point of the price range reflected on the cover page of this prospectus), the $8.0 million cash contribution to be made to us in respect of the Class D interests, our borrowing of $30.0 million under our reserve-based credit facility and the application of the net proceeds from these transactions and this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read together with and is qualified in its entirety by reference to, our historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Summary—Constellation Energy Partners LLC—The Transactions and Limited Liability Company Structure,” “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.


	As of June 30, 2006
	Historical		Pro Forma
	(In ‘000’s)
Cash and cash equivalents	$	3,880	$	7,827

Debt
Note payable	$	52	$	52
Reserve-based credit facility^(a)		—		22,000
Class D interests^(a)(b)		—		8,000

Total debt		52		30,052
Equity
Members’ equity		177,437		—
Common units held by public:		—		58,457
Common units held by CEPH:		—		77,944
Class A units held by CEPM:		—		2,784

Total equity^(c)		177,437		139,185

Total capitalization	$	177,489	$	169,237

(a)

Prior to the closing of this offering, we will borrow $30.0 million under our reserve-based credit facility. The proceeds are included in the distribution to CEPH described in “Use of Proceeds.” The proceeds of $8.0 million contributed to us by CHI for the Class D interests will be used to reduce the borrowing under our reserve-based credit facility from $30.0 million to $22.0 million immediately following the offering.

(b)

Due to their mandatory redemption feature, the Class D interests will be treated as a liability under SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.

(c)

Includes $0.9 million of unrealized gains on our cash flow hedges.

Index to Financial Statements

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of June 30, 2006, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value would be $139.2 million, or $9.41 per common unit. Thus, purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit				$	20.00
Net tangible book value per common unit before the offering^(a)	$	20.85
Decrease in net tangible book value per common unit attributable to purchasers in the offering		(11.44	)

Less: Pro forma net tangible book value per common unit after the offering^(b)					9.41

Immediate dilution in net tangible book value per common unit to new investors				$	10.59

(a)

Determined by dividing the total number of common units and Class A units to be issued to CEPM and its affiliates (8,214,010 common units and 295,690 Class A units) into our net tangible book value of the contributed assets and liabilities of $177.4 million as of June 30, 2006.

(b)

Determined by dividing the total number of common units and Class A units to be outstanding after this offering (14,489,010 common units and 295,690 Class A units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds we receive from this offering, of $139.2 million as of June 30, 2006.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by CEPM and its affiliates in respect of their Class A units and common units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:


	Class A and Common Units Acquired			Total Consideration
	Class	Number	Percent	Amount (In ‘000’s)		Percent
CEPM and its affiliates⁽¹⁾⁽²⁾	Class A units	295,690	2%	$	862	0.6%
CEPM and its affiliates⁽¹⁾⁽²⁾	Common units	8,214,010	56%		23,938	15.9
New investors	Common units	6,275,000	42%		125,500	83.5

Total		14,784,700	100%	$	150,300	100%

(1)

Upon the consummation of the transactions contemplated by this prospectus, CEPM and its affiliates will own 8,214,010 common units and 295,690 Class A units, the management incentive interests and the Class D interests.

(2)

Book value of the consideration provided by CEPM and its affiliates, as of June 30, 2006, after giving effect to the application of the net proceeds of this offering and distribution of the excess cash in the cash pool and related transactions is as follows:


	(In millions)
Net tangible book value	$	177.4
Less: Distribution to CEPH		(136.0	)
Distribution of excess cash and cash pool		(16.6	)

	$	24.8

Index to Financial Statements

HOW WE MAKE CASH DISTRIBUTIONS

Initial Quarterly Distributions

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our board of managers, taking into consideration the terms of our limited liability company agreement. We intend to distribute to the holders of common units and Class A units on a quarterly basis at least the IQD of $0.425 per unit, or $1.70 per unit per year to the extent we have sufficient available cash after we establish appropriate reserves and pay fees and expenses, including payments to CEPM in reimbursement of costs and expenses it incurs on our behalf. Our IQD is intended to reflect the level of cash that we expect to be available for distribution per common unit and Class A unit each quarter from our productive assets. There is no guarantee we will pay the IQD in any quarter and we will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default is existing under our credit agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our board of managers has adopted a policy that it will raise our quarterly cash distribution only when it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such an increased distribution level for a sustained period. While this is our current policy, our board of managers may alter such policy in the future when and if it determines such alteration to be appropriate.

Distributions of Available Cash

Overview

Our limited liability company agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2006, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

We define available cash in the glossary, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

•

less the amount of cash reserves established by our board of managers to:

•

provide for the proper conduct of our business (including reserves for future capital expenditures and credit needs);

•

comply with applicable law, any of our debt instruments, or other agreements; or

•

provide funds for distributions (1) to our unitholders for any one or more of the next four quarters or (2) in respect of our Class D interests or management incentive interests;

•

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our reserve-based credit facility or another arrangement and in all cases are used solely for working capital purposes or to pay distributions to unitholders.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our limited liability company agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Index to Financial Statements

Definition of Operating Surplus

We define operating surplus in the glossary, and for any period, it generally means:

•

$20.0 million (as described below); plus

•

all of our cash receipts after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

•

working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

•

cash distributions paid on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset is placed into service or the date that it is abandoned or disposed of; plus

•

if the right to receive distributions (other than distributions in liquidation) on the Class D interests terminates before December 31, 2012, the excess of the amount of the $8.0 million contribution by CHI for the Class D interests over the cumulative cash distributions paid on the Class D interests before such termination shall be included in operating surplus, such inclusion to occur over a series of quarters with the amount included in each quarter to be equal to the amount of the payment we make to the Trust in respect of the NPI for such quarter that would not have been paid but for termination of the sharing arrangement; less

•

our operating expenditures (as defined below) after the closing of this offering; less

•

the amount of cash reserves established by our board of managers to provide funds for future operating expenditures; less

•

all working capital borrowings not repaid within twelve months after having been incurred.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $20.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity securities in operating surplus would be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash distributions we receive from non-operating sources.

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in the glossary, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to CEPM for services under the management services agreement, payments made in the ordinary course of business under commodity hedge contracts, manager and officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures, provided that operating expenditures will not include:

•

repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus when such repayment actually occurs;

•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

•

expansion capital expenditures;

Index to Financial Statements

•

actual maintenance capital expenditures;

•

investment capital expenditures;

•

payment of transaction expenses relating to interim capital transactions; or

•

distributions to our members (including distributions in respect of our Class D interests and management incentive interests).

Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain, including over the long term, our asset base, and expansion capital expenditures are those capital expenditures that we expect will increase our asset base over the long term. Examples of maintenance capital expenditures include capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a replacement asset during the period from such financing until the earlier to occur of the date any such replacement asset is placed into service or the date that it is abandoned or disposed of. Plugging and abandonment costs will also constitute maintenance capital expenditures. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus. As a result, to eliminate the effect on operating surplus of these fluctuations, our limited liability company agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our board of managers at least once a year, provided that any change is approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

•

it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the initial quarterly distribution to be paid on all the units for that quarter and subsequent quarters;

•

it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

•

it will be more difficult for us to raise our distribution above the IQD and pay management incentive distributions on our management incentive interests; and

•

it will reduce the likelihood that a large maintenance capital expenditure during the First MII Earnings Period or Later MII Earnings Period will prevent the payment of a management incentive distribution in respect of the First MII Earnings Period or Later MII Earnings Period since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Index to Financial Statements

Expansion capital expenditures are those capital expenditures that we expect will increase our asset base. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interest, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase our asset base. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

As described above, none of actual maintenance capital expenditures, investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures, investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from such financing until the earlier to occur of the date any such capital asset is placed into service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of maintenance capital expenditures, but which are not expected to expand for more than the short term our asset base.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our board of managers, based upon its good faith determination, subject to approval by our conflicts committee.

Definition of Capital Surplus

We also define capital surplus in the glossary, and it will generally be generated only by:

•

borrowings other than working capital borrowings;

•

sales of debt and equity securities; and

•

sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of Cash Distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Distributions of Available Cash from Operating Surplus

We will make distributions of available cash from operating surplus for any quarter in the following manner:

•

first, 98% to the common unitholders, pro rata, and 2% to the holder(s) of our Class A units, pro rata, until we distribute for each outstanding unit an amount equal to the Target Distribution for that quarter; and

Index to Financial Statements

•

thereafter, any amount distributed in respect of such quarter in excess of the Target Distribution per unit will be distributed 98% to the holders of the common units, pro rata, and 2% to the holder(s) of our Class A units until distributions become payable in respect of our management incentive interests as described in “—Management Incentive Interests” below.

The Class A units will be entitled to 2% of all cash distributions from operating surplus, without any requirement for future capital contributions by the holders of such Class A units, even if we issue additional common units or other senior or subordinated equity securities in the future. The percentage interests shown above for the Class A units assume they have not been converted into common units. If the Class A units have been converted, the common units will receive the 2% of distributions originally allocated to the Class A units.

Management Incentive Interests

Management incentive interests represent the right to receive 15% of quarterly distributions of available cash from operating surplus after the Target Distribution has been achieved and certain other tests have been met. CEPM currently holds the management incentive interests, which are evidenced by the Class C limited liability company interests, but may transfer these rights separately from its Class A units, subject to restrictions in our limited liability company agreement. The earliest that we could be required to make distributions in respect of the management incentive interests is after a period of 12 consecutive quarters after this offering. We are not able to predict whether or when we will be required to make distributions in respect of the management incentive interests or, if we do make such distributions in the future, how much they will be.

Prior to the end of the First MII Earnings Period or Later MII Earnings Period, which are defined below, we will not pay any management incentive distributions. To the extent, however, that during the First MII Earnings Period or Later MII Earnings Period we distribute available cash from operating surplus in excess of the Target Distribution, our board of managers intends to cause us to reserve an amount for payment of the EP MID, which is defined below, earned during the First MII Earnings Period or Later MII Earnings Period, as the case may be, after such period ends. If during the First MII Earnings Period or Later MII Earnings Period we fail to satisfy a condition specified in the next paragraph, our board of managers will cause any such reserved amount to be released from that reserve and restored to available cash.

Payments to the holder of our management incentive interests will be subject to the satisfaction of certain requirements. The first requirement is the 12-Quarter Test, which requires that for the 12 full, consecutive, non-overlapping calendar quarters that begin with the first calendar quarter in respect of which we pay per unit cash distributions from operating surplus to holders of Class A and common units in an amount equal to or greater than the Target Distribution (that is, our $0.425 IQD plus $0.06375) (we refer to such 12-quarter period as the “First MII Earnings Period”):

•

we pay cash distributions from operating surplus to holders of our outstanding Class A and common units in an amount that on average exceeds the Target Distribution on all of the outstanding Class A units and common units over the First MII Earnings Period;

•

we generate adjusted operating surplus (which is summarized below and is defined in the glossary included as Appendix B) during the First MII Earnings Period that on average is in an amount at least equal to 100% of all distributions on the outstanding Class A and common units up to the Target Distribution plus 117.65% of all such distributions in excess of the Target Distribution; and

•

we do not reduce the amount distributed per unit in respect of any such 12 quarters.

The second requirement is the 4-Quarter Test, which requires that for each of the last four full, consecutive, non-overlapping calendar quarters in the First MII Earnings Period:

•

we pay cash distributions from operating surplus to the holders of our outstanding Class A and common units that exceed the Target Distribution on all of the outstanding Class A and common units;

Index to Financial Statements

•

We generate adjusted operating surplus in an amount at least equal to 100% of all distributions on the outstanding Class A and common units up to the Target Distribution plus 117.65% of all such distributions in excess of the Target Distribution; and

•

we do not reduce the amount distributed per unit in respect of any such four quarters.

If both the 12-Quarter Test and the 4-Quarter Test have been met, then: (i) we will make a one-time management incentive distribution (contemporaneously with the distribution paid in respect of the Class A and common units for the twelfth calendar quarter in the First MII Earnings Period) to the holder of our management incentive interests equal to 17.65% of the sum of the cumulative amounts, if any, by which quarterly cash distributions per unit part on the outstanding Class A and common units during the First MII Earnings Period exceeded the Target Distribution on all of the outstanding Class A and common units (we refer to this one-time management incentive distribution as an “EP MID”); and (ii) for each calendar quarter after the First MII Earnings Period, the holders of our Class A units, common units and management incentive interests will receive 2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay for such quarter in excess of the Target Distribution.

If the 12-Quarter Test is not met and except as described below, management incentive distributions will not be payable in respect of the First MII Earnings Period and the holder of the management incentive interests will forfeit any and all rights to any management incentive distributions in respect of the First MII Earnings Period. An EP MID may become payable, however, with respect to a Later MII Earnings Period, if the 12-Quarter Test and the 4-Quarter Test are met in respect of such Later MII Earnings Period. A Later MII Earnings Period may begin with the first quarter following the quarter in which the 12-Quarter Test is not met, or, where we do not meet the 12-Quarter Test because we reduced our cash distribution in a particular quarter, the Later MII Earnings Period may begin with the quarter in which such reduction is made. If both tests are met with respect to a Later MII Earnings Period, then for each calendar quarter after the Later MII Earnings Period, the holders of the Class A units, common units and management incentive interests will receive 2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay for such quarter in excess of the Target Distribution.

However, if (a) the 12-Quarter Test has been met in respect of the First MII Earnings Period or any Later MII Earnings Period, but not the 4-Quarter Test; (b) the 4-Quarter Test has been met in any period of four full, consecutive and non-overlapping quarters occurring after the end of the First MII Earnings Period or Later MII Earnings Period, as the case may be, up to three of which quarters can fall within the First MII Earnings Period or Later MII Earnings Period, as the case may be (we refer to such four-quarter period as the “MII 4-Quarter Earnings Period”); and (c) we have paid at least the IQD in each calendar quarter occurring between the end of the First MII Earnings Period or Later MII Earnings Period, as the case may be, and the beginning of the MII 4-Quarter Earnings Period:

•

the holder of our management incentive interests will receive an EP MID with respect to the First MII Earnings Period or Later MII Earnings Period, as the case may be.

Our board of managers has adopted a policy that it will raise our quarterly cash distribution only when it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such increased distribution level for a sustained period. While this is our current policy, our board of managers may alter such policy in the future when and if it determines such alteration to be appropriate.

Index to Financial Statements

Definition of Adjusted Operating Surplus

We define adjusted operating surplus in the glossary and for any period it generally means:

•

operating surplus generated with respect to that period less any amounts described in the fifth bullet point under “—Definition of Operating Surplus” above; less

•

any net increase in working capital borrowings with respect to that period (excluding any such borrowings to the extent the proceeds are distributed to the record holder of our Class D interests); less

•

any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

•

any net decrease in working capital borrowings with respect to that period; plus

•

any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from our operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and CEPM as the owner of our management incentive interests up to various distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our Class A unitholders and common unitholders and the holders of our management incentive interests in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Quarterly Distribution Level,” until available cash from operating surplus we distribute reaches the next distribution level, if any. The percentage interests shown for the IQD are also applicable to quarterly distribution amounts that are less than the IQD. The percentage interests shown in the table below assume that the Class A units have not been converted into common units as described herein.


	Quarterly Distribution Level	Marginal Percentage Interest in Distributions
	Quarterly Distribution Level	Class A Unitholders		Common Unitholders		Management Incentive Interests
IQD	$0.425	2	%	98	%	0	%
Target Distribution	above $0.425 up to $0.48875	2	%	98	%	0	%
Thereafter*	above $0.48875	2	%	83	%	15	%

Assumes the management incentive interests have met the 12-Quarter Test and the 4-Quarter Test. Until the 12-Quarter Test and the 4-Quarter Test are met and distributions in respect of the management incentive interests become payable, quarterly distributions in excess of the $0.48875 Target Distribution will be made 2% to the holder of the Class A units and 98% to the holders of common units, pro rata.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

•

First, 2% to the holder of our Class A units and 98% to all common unitholders, pro rata, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price; and

Index to Financial Statements

•

Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus

Our limited liability company agreement treats a distribution of capital surplus as the repayment of the initial common unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per common unit is referred to as the “unrecovered initial common unit price.” Each time a distribution of capital surplus is made, the IQD and the Target Distribution will be reduced in the same proportion as the corresponding reduction in the unrecovered initial common unit price. Because distributions of capital surplus will reduce the IQD, after any of these distributions are made, it may be easier for CEPM to receive management incentive distributions. However, any distribution of capital surplus before the unrecovered initial common unit price is reduced to zero cannot be applied to the payment of the IQD.

Once we distribute capital surplus on a common unit issued in this offering in an amount equal to the initial common unit price, we will reduce the IQD and the Target Distribution to zero. We will then make all future distributions from operating surplus, with 2% being distributed to the holder of our Class A units, 83% being distributed to our common unitholders, pro rata, and 15% being distributed to the holder of our management incentive interests. The percentage interests shown above for the Class A units assume they have not been converted into common units. If the Class A units have been converted, the common units will receive the 2% of distributions originally allocated to the Class A units.

Adjustment to the IQD and Target Distribution

In addition to adjusting the IQD and Target Distribution to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, we will proportionately adjust:

•

the IQD;

•

the Target Distribution; and

•

the unrecovered initial common unit price.

For example, if a two-for-one split of the common units should occur, the Target Distribution and the unrecovered initial common unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the IQD and the Target Distribution for each quarter by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our board of manager’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus our board of managers’ estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Quarterly Cash Distributions on our Class D Interests

In order to address the risk of early termination, without the prior consent of board of managers, prior to December 31, 2012, of the sharing arrangement under the gas purchase contract pertaining to the calculation of amounts payable to the Trust for the NPI, and the potential reduction in our revenues resulting therefrom, at the closing of this offering CHI will contribute $8.0 million to us for all of our Class D interests. For each full

Index to Financial Statements

calendar quarter during the period commencing January 1, 2007 and ending on December 31, 2012 that the sharing arrangement remains in effect, we will distribute to the holder of the Class D interests $333,333, as a partial return of the $8.0 million capital contribution made for the Class D interests, which payment will be made concurrently with the quarterly cash distribution to our unitholders for that quarter. The Class D interests will be cancelled upon the payment of the final distribution of $333,341 to CHI for the quarter ending December 31, 2012, unless the special distribution right has been terminated earlier. Such special quarterly cash distributions will be made 45 days after the end of each calendar quarter, commencing with the quarter ending March 31, 2007.

If the amounts payable by us to the Trust are not calculated based on the sharing arrangement through December 31, 2012, unless such change is approved in advance by our board of managers and our conflicts committee, the special distribution right for future quarters will terminate and the remaining portion of the $8.0 million original contribution not so returned in special cash distributions will be retained by us to partially offset the reduction in our revenues resulting from termination of the sharing arrangement. In the case of such termination of the special distribution right, CHI will have the right only under specific circumstances upon our liquidation to receive the unpaid portion of the $8.0 million capital contribution that has not then been distributed to CHI in such special distributions. See “—Distributions of Cash Upon Liquidation” below. If the gas purchase contract in respect of the Trust Wells is terminated during a quarter, the special distribution to CHI as the holder of our Class D interests will be prorated for that quarter based on the ratio of the number of days in such quarter prior to the effective date of such termination to 90. If we and any of the Trust, the trustee of the Trust or any subsequent holder of the NPI become involved in a dispute or proceeding in which such person asserts that prior to December 31, 2012 the sharing arrangement ceased to be applicable in calculating amounts payable in respect of production from the Trust Wells, special cash distributions in respect of the Class D interests for periods commencing at the inception of such dispute will be suspended, and such suspended amounts will only be paid to the holder of the Class D interests to the extent it is finally determined that the sharing arrangement remained applicable during some or all of the suspension period.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our limited liability company agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders, to CHI, the entity that will contribute $8.0 million to us in exchange for the Class D interests, CEPH and CEPM in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our limited liability company agreement, and requires that we will allocate any gain to the unitholders and holders of the Class A units in the following manner:

•

First, to the holders of common units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

•

Second, 2% to the holder of our Class A units and 98% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

(1)

the unrecovered initial common unit price; and

(2)

the amount of the IQD for the quarter during which our liquidation occurs; and

•

Third, 100% to the holder of our Class D interests, until the capital account of the Class D interests equals, in the aggregate, the excess, if any, of (i) the $8.0 million capital contribution made to us by CHI

Index to Financial Statements

at the closing of this offering for all of our Class D interests over (ii) the cumulative amount distributed as a special distribution to the holder of the Class D interests in accordance with the description under “Quarterly Cash Distributions On Our Class D interests” above;

•

Fourth, 2% to the holder of our Class A units and 98% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

(1)

the amount described above under the second bullet point of this paragraph; and

(2)

the excess of (I) over (II), where

(I)

equals the sum of the excess of the Target Distribution per common unit over the IQD for each quarter of our existence; and

(II)

equals the cumulative amount per common unit of any distributions of available cash from operating surplus in excess of the IQD per common unit that we distributed 98% to our common unitholders, pro rata, for each quarter of our existence; and

•

Thereafter, 2% to the holder of our Class A units, 83% to all common unitholders, pro rata, and 15% to the holder of our management incentive interests.

Manner of Adjustments for Losses

Upon our liquidation, we will generally allocate any loss 2% to the holder of the Class A units and 98% to the holders of the outstanding common units, pro rata.

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the holder of the Class A units, the common unitholders, the holders of Class D interests and the holders of the management incentive interests in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional common units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional common units or upon our liquidation in a manner which results, to the extent possible, in the capital account balances of the holders of the management incentive interests equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

Index to Financial Statements

CASH DISTRIBUTION POLICY AND

RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “—Our Estimated Cash Available to Pay Distributions—Our Estimated Adjusted EBITDA” below. In addition, you should read “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, you should refer to our historical and pro forma consolidated financial statements for the six months ended June 30, 2006 and the year ended December 31, 2005, included elsewhere in this prospectus as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

General

Rationale for our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash (after deducting expenses, estimated maintenance capital expenditures and reserves) rather than our retaining it. Moreover, it is the current policy of our board of managers that we should increase our level of quarterly cash distributions per unit only when, in its judgment, it believes that (i) we have sufficient reserves and liquidity for the conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such an increased distribution level for a sustained period. The amount of available cash will be determined by our board of managers for each calendar quarter after the closing of the offering and will be based upon recommendations from our management. Because we believe we will generally finance any expansion capital expenditures and investment capital expenditures from external financing sources, we also believe that our investors are best served by our distributing all of our available cash. In addition, since we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to federal income tax. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash quarterly (and our available cash is determined after deducting expenses, estimated maintenance capital expenditures and reserves). Under that policy, we will pay an initial quarterly distribution, or IQD, of $0.425 per Class A unit and common unit for each complete quarter. These distributions will not be cumulative. Consequently, if distributions on our common units and Class A units are not paid with respect to any fiscal quarter at the anticipated IQD rate, our unitholders will not be entitled to receive such payments in the future. We are a recently formed limited liability company and have not historically made any cash distributions. For a more detailed discussion, please read “How We Make Cash Distributions” elsewhere in this prospectus.

Restrictions and Limitations on Our Ability to Make Quarterly Distributions

There is no guarantee that unitholders will receive quarterly cash distributions from us or that any increases in our quarterly cash distributions can or will be maintained. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

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Other than the obligation under our limited liability company agreement to distribute available cash on a quarterly basis, which is subject to our board of managers’ authority to establish reserves and other limitations, our unitholders have no contractual or other legal right to receive distributions.

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Our board of managers will have broad discretion to establish reserves for the prudent conduct of our business and for the payments to the holders of our Class D interests and for future cash distributions, including, during the First MII Earnings Period or any Later MII Earnings Period, payment of the EP

Index to Financial Statements

MID, and the establishment of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy.

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Our ability to make distributions of available cash will depend primarily on our cash flow from operations, which primarily depends on our level of production and our realized natural gas prices. Although our limited liability company agreement provides for quarterly distributions of available cash, we have no prior history of making distributions to our members.

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Our distribution policy will be subject to restrictions on distributions under our new reserve-based credit agreement. Specifically, our credit agreement requires us to maintain a ratio of total borrowings outstanding under our reserve-based credit facility to our Borrowing Base (as defined in our credit agreement) measured at the time of the distribution of not more than 0.90 to 1.0. In addition, the credit facility contains covenants requiring us to maintain, as of the last day of each fiscal quarter, a ratio of our Adjusted EBITDA (as defined in our credit agreement) to our cash interest expense, each measured for the preceding quarter, of not less than 4.5 to 1.0; a ratio of total indebtedness to Adjusted EBITDA of not more than 3.5 to 1.0; and a ratio of current assets to current liabilities of not less than 1.0 to 1.0. In addition, a default that results in or could result in acceleration of any of our indebtedness in excess of $1.0 million will constitute an event of default under our credit agreement that would prohibit us from making distributions. Should we be unable to satisfy these restrictions or another default or event of default occurs and is continuing under our credit agreements, we would be prohibited from making a distribution to you notwithstanding our stated distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Reserve-Based Credit Facility.”

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Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay and the decision to make any distribution is determined by our board of managers, taking into consideration the terms of our limited liability company agreement.

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We have a limited operating history and therefore we have a limited historical basis upon which to rely in our determination as to whether we will have sufficient available cash to pay the initial quarterly distribution.

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Under Section 18-607 of the Delaware Limited Liability Company Act, or Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

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We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reduced production from our wells, lower prices for the natural gas we sell, increases in our operating or selling, general and administrative expense, principal and interest payments on our outstanding debt, tax expenses, capital expenditures, working capital requirements or other anticipated cash needs. See “Risk Factors” for information regarding the factors.

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Although our limited liability company agreement requires us to distribute our available cash, our limited liability company agreement may be amended with the approval of our board of managers and both a common unit majority and a Class A unit majority. At the closing of this offering, CEPH will own approximately 57% of the outstanding common units (approximately 50% if the underwriters exercise their option to purchase additional common units in full) and CEPM will own 100% of the outstanding Class A units.

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state limited liability company laws and other laws and regulations, including state laws and policies affecting our oil and natural gas production, gathering and marketing operations.

Index to Financial Statements

Our Cash Distribution Policy Limits Our Ability to Grow

Because we distribute all of our available cash, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. If we issue additional common units or incur debt to fund acquisitions and expansion capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

We expect that we will distribute our available cash from operations to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any investment capital expenditures and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow our asset base. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. To the extent we issue additional units in connection with any maintenance, expansion or investment capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may affect the available cash that we have to distribute on each unit. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Initial Quarterly Distribution Rate

Our Cash Distribution Policy

Upon completion of this offering, our board of managers will adopt a policy pursuant to which we will pay an initial quarterly distribution, or IQD, of $0.425 per Class A unit and common unit for each complete quarter. Beginning with the quarter ending December 31, 2006, we will pay our distributions within 45 days after the end of each quarter ending March, June, September and December to holders of record on the record date established for such distribution. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust our first distribution for the period from the closing of the offering through December 31, 2006 based on the actual length of the period. These distributions will not be cumulative. Consequently, if distributions on our common units and Class A units are not paid with respect to any fiscal quarter at the anticipated IQD rate, our unitholders will not be entitled to receive such payments in the future.

If the underwriters exercise their option to purchase additional common units from us, we will use the additional net proceeds from such exercise to redeem from CEPM an equivalent number of common units. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the initial quarterly distribution rate on all units. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “—Restrictions and Limitations on Our Ability to Make Quarterly Distributions.”

Index to Financial Statements

The following table sets forth the estimated aggregate amount of available cash from operating surplus, which we also refer to as cash available for distributions, needed to pay the IQD on all of the common units and the Class A units to be outstanding immediately after this offering for one full quarter (at the initial rate of $0.425 per unit per quarter) and for four full quarters (at the initial rate of $1.70 per unit for four quarters):


		Initial Quarterly Distribution
	Number of Units	One Quarter		Four Quarters
		(In ‘000’s)
Common units	14,489,010	$	6,158	$	24,631
Class A units	295,690		126		503

Total	14,784,700	$	6,284	$	25,134

The Class A units will be entitled to 2% of all distributions that we make prior to our liquidation. The 2% sharing ratio of the Class A units will not be reduced if we issue additional equity securities in the future.

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our limited liability company agreement. Our distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash quarterly. Under our limited liability company agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount our board of managers determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for payment of the EP MID to the holder of our management incentive interests or for future distributions to the holder of our Class D interests or to our unitholders for any one or more of the upcoming four quarters. Holders of our common units may pursue judicial action to enforce provisions of our limited liability company agreement, including those related to requirements to make cash distributions as described above; however, our limited liability company agreement provides that any determination made by our board of managers must be made in good faith and that any such determination will not be subject to any other standard imposed by our limited liability company agreement, the Delaware Act or any other law, rule or regulation or at equity. Our limited liability company agreement also provides that, in order for a determination by our board of managers to be made in “good faith,” our board of managers must believe that the determination is in our best interests.

The requirement in our limited liability company agreement to distribute all of our available cash quarterly may not be modified or repealed without amending our limited liability company agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuation based on the amount of cash we generate from our business and the amount of reserves our board of managers establishes in accordance with our limited liability company agreement as described above. Our limited liability company agreement may be amended with the approval of our board of managers and holders of a majority of our outstanding common units.

In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash from operating surplus to pay the IQD on all outstanding Class A units and common units for each full calendar quarter through September 30, 2007. In those sections, we present the following two tables:

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“Our Estimated Cash Available to Pay Distributions,” in which we present our Estimated Adjusted EBITDA for the twelve months ending September 30, 2007. In the footnotes to this first table, we present the significant assumptions and considerations underlying our belief that we will generate sufficient Estimated Adjusted EBITDA to pay the IQD on all outstanding Class A units and common units for each quarter through September 30, 2007; and

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“Unaudited Pro Forma Cash Available to Pay Distributions,” in which we present our estimate of the amount of available cash we would have had on a pro forma basis in 2005 and for the twelve months

Index to Financial Statements

ended June 30, 2006, based on our pro forma financial statements that are included elsewhere in this prospectus.

Financial Forecast

For the purpose of this offering, our management has prepared the prospective financial information set forth in “—Our Estimated Cash Available to Pay Distributions” below, and such information is the responsibility of our management. Our forecast information presents, to our best knowledge and belief, our expected results of operations and cash flows for the twelve-month period ending September 30, 2007. Our forecast financial information reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending September 30, 2007. The assumptions disclosed in the footnotes to the table under the caption “—Our Estimated Cash Available to Pay Distributions—Our Estimated Adjusted EBITDA” below are those that we believe are significant to our forecasted information, but we can give you no assurance that our forecast results will be achieved. There will likely be differences between our forecast and actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay the full IQD or any amount on our outstanding common units.

Our forecast financial information is a forward-looking statement and should be read together with the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus and together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In the view of our management, however, such information was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the Estimated Adjusted EBITDA necessary for us to have sufficient available cash for distribution to pay a distribution on the common units and Class A units at the initial quarterly distribution rate. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained in this section, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for the prospective financial information. Such independent registered public accounting firms’ reports included elsewhere in this prospectus relate to the appropriately described historical financial information contained in this section. Such reports do not extend to the tables and related information contained in this section and should not be read to do so. In addition, such tables and information were not prepared:

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with a view toward compliance with published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information; or

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in accordance with GAAP.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date in this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

As a result of the factors described in “—Our Estimated Cash Available to Pay Distributions” and in the footnotes to the table in that section, we believe we will be able to pay distributions at the initial quarterly distribution rate of $0.425 per unit on all outstanding common units and Class A units for each full calendar quarter in the twelve-month period ending September 30, 2007.

Index to Financial Statements

Our Estimated Cash Available to Pay Distributions

In order to pay the IQD to our unitholders of $0.425 per unit per quarter over the four full calendar quarters ending September 30, 2007, our cumulative available cash to pay distributions must be at least approximately $25.1 million over that period. We have calculated that the minimum amount of our Estimated Adjusted EBITDA for the twelve-month period ending September 30, 2007 that we estimate will be necessary to generate cash available to pay aggregate distributions of approximately $25.1 million over that period is approximately $31.6 million. Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance or liquidity.

Adjusted EBITDA is a significant liquidity metric to be used by our management to indicate (prior to the establishment of any reserves by our board of managers) the cash distributions we expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. As used in this prospectus, the term “Adjusted EBITDA” means the sum of net income (loss) plus:

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interest (income) expense;

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depreciation, depletion and amortization;

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write-off of deferred financing fees;

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impairment of long-lived assets;

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(gain) loss on sale of assets;

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(gain) loss from equity investment;

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accretion of asset retirement obligation;

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unrealized (gain) loss on natural gas derivatives; and

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realized loss (gain) on cancelled natural gas derivatives.

In the table below entitled “Our Estimated Adjusted EBITDA,” we calculate that our Estimated Adjusted EBITDA will be approximately $31.6 million for the four full calendar quarters ending September 30, 2007, which is sufficient for us to be able to generate cash available to pay aggregate distributions of approximately $25.1 million to the holders of our common units and Class A units, assuming borrowings of $5.3 million to fund our investment capital expenditures and distributions on our Class D interests. If we do not borrow funds to finance such expenditures, we would experience a shortfall in the amount of cash generated from our operations to both pay the aggregate cash distributions on our common units and Class A units and make the investment capital expenditures we expect to make and pay cash distributions on our Class D interests.

In calculating the Estimated Adjusted EBITDA that we will need to pay cash distributions, we have included estimates of estimated maintenance capital expenditures, investment capital expenditures and expansion capital expenditures for the twelve-month period ending September 30, 2007. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our asset base (including our undeveloped leasehold acreage) at a steady level over the long term. These expenditures include the drilling and completion of additional development wells to offset the expected production decline during such period from our producing properties, as well as additions to our inventory of unproved properties or proved reserves required to maintain our asset base.

Investment capital expenditures are capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Our estimated investment capital expenditures for the twelve months ending September 30, 2007 consist of capital expenditures we expect to make to drill and complete additional development wells and to refracture the formations of specified existing wells in excess of the level of such

Index to Financial Statements

operations that are necessary to offset our expected depletion rate of our producing properties and replace reserves.

Expansion capital expenditures consist of capital expenditures we expect to make to expand the size of our asset base for longer than the short term. These expenditures would include amounts expended to increase the rate of development and production of our existing properties at a rate in excess of that necessary to offset our expected depletion rate decline of existing producing properties and which excess production or operating capacity we expect to extend for longer than the short term. Expansion capital expenditures also consist of capital expenditures that increase our inventory of unproved properties or our proved reserves to the extent such increases exceed those necessary to maintain our asset base. Expansion capital expenditures may include expenditures for additional producing properties, undeveloped leasehold acreage, gathering, treating or processing facilities, new drilling, workovers, recompletions, completion and other production enhancement technologies that we expect will increase our asset base over the long term. For the twelve months ending September 30, 2007, we have not estimated any expansion capital expenditures since we do not have any acquisitions pending or planned and the capital expenditures we expect to incur on our existing properties do not include any that would constitute expansion capital expenditures.

You should read the footnotes to the table under the caption “—Our Estimated Adjusted EBITDA” below for a discussion of the material assumptions underlying our belief that we will be able to generate the Estimated Adjusted EBITDA of approximately $31.6 million. Our belief is based on those assumptions and reflects our judgment, as of the date of this prospectus, regarding the conditions we expect to exist and the course of action we expect to take over the twelve-month period ending September 30, 2007. The assumptions we disclose below are those that we believe are significant to our ability to generate the necessary Estimated Adjusted EBITDA. If our estimates prove to be materially incorrect, we may not be able to pay the IQD or any amount on our outstanding units during the four calendar quarters ending September 30, 2007.

When considering our Estimated Adjusted EBITDA, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these risk factors or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the table below.

Our Estimated Adjusted EBITDA

The following table illustrates (i) our Estimated Adjusted EBITDA that we expect to generate for the twelve months ending September 30, 2007 based on the assumptions and considerations described in the footnotes to the table and (ii) the estimated cash available to pay distributions for the twelve-month period ending September 30, 2007, assuming that the offering was consummated on October 1, 2006. We explain each of the adjustments presented below in the footnotes to the table. All of the amounts for the twelve-month period ending September 30, 2007 in the table and footnotes below are estimates.


	Twelve-Month Period Ending September 30, 2007
	(In ‘000’s, except per unit data and ratios)
Estimated Adjusted EBITDA^(a)	$	31,624
Less:
Estimated maintenance capital expenditures^(b)		(4,950	)
Estimated interest expense^(c)		(1,540	)
Estimated investment capital expenditures^(d)		(4,272	)
Cash required to pay Class D special cash distributions^(e)		(1,029	)
Add:
Borrowings to finance investment capital expenditures and Class D distributions^(c)(d)(e)		5,301
Excess proceeds from initial public offering available for distribution^(f)		5,027

Estimated cash available to pay distributions	$	30,161

Index to Financial Statements


	Twelve-Month Period Ending September 30, 2007
	(In ‘000’s, except per unit data and ratios)
Estimated cash distributions
Annualized initial quarterly distribution per unit	$	1.70

Estimated total cash distributions to common unitholders and Class A unitholder^(g)	$	25,134

Borrowing base ratio^(h)		0.2x
Interest coverage ratio^(h)		18.6x
Total debt/Adjusted EBITDA ratio^(h)		0.7x

(a)

As reflected in the table below, to generate our Estimated Adjusted EBITDA for the twelve months ending September 30, 2007, we have assumed the following regarding our operations, revenues and expenses:


Net sales volumes⁽¹⁾		5.0 Bcf
Average Henry Hub Price (NYMEX) (hedged volumes)⁽²⁾		$9.22 per MMBtu
Average SONAT Inside FERC Price (unhedged volumes)⁽²⁾		$8.82 per MMBtu
Percentage of net production hedged		78%
Weighted average net realized natural gas sales price⁽²⁾		$9.11 per MMBtu
Estimated adjusted EBITDA (in thousands):
Total revenues⁽³⁾		$43,980
Field operating expenses⁽⁴⁾		(8,717)
Torch NPI Payment⁽⁵⁾		(291)
General and administrative expenses⁽⁶⁾		(4,803)
Hedge gains⁽³⁾		1,455

Estimated Adjusted EBITDA		$31,624

(1)

Our forecasted net sales volumes for the twelve months ending September 30, 2007 are based on our estimated proved reserves as of December 31, 2005, which were prepared using a price of $10.06 per MMBtu, based on the SONAT Gas Daily Price on December 30, 2005. The price used in preparing our proved reserve estimates, which price is consistent with SEC rules and regulations, differs from the price of $9.11 per MMBtu used to compile our net forecasted revenues, which reflects pricing as of September 1, 2006. For the twelve months ended June 30, 2006, our sales volumes were approximately 4.5 Bcf. We are forecasting our sales volumes to be approximately 5.0 Bcf for the period from October 1, 2006 through September 30, 2007, which is consistent with the forecasted production in our internal reserve estimates. We expect to be able to add the additional 0.5 Bcf from our drilling and refracture program in combination with compression and other production enhancing techniques.

Our estimates of approximately 5.0 Bcf net to our interest include production attributable to the 20 gross (20 net) development wells on proved undeveloped drilling locations that we intend to drill and complete and are assumed to be placed on production during the twelve months ending September 30, 2007. We have assumed that each of the 20 gross (20 net) new wells is completed as a commercial well at an initial production rate of 50-75 Mcf/d, which is consistent with the average initial production rate for the gross development wells drilled by Everlast in the first half of 2005 and the 9 gross (9 net) development wells that we drilled and completed in the second half of 2005. It is also consistent with the 25 wells drilled and completed in the first nine months of 2006. During the nine months ended September 30, 2006, we drilled and completed 25 gross (25 net) wells and spudded an additional 6 gross (6 net) wells that are in the process of completion. We commenced drilling on 10 of the 25 wells in 2005 and brought them onto production in 2006. Based on our experience and that of Everlast with drilling and completing development wells in the Black Warrior Basin, we have assumed that these development wells are drilled at an average rate of 1.7 gross wells per month and are placed on production approximately 40 days after the first wells are spudded.

Index to Financial Statements

During the nine months ended September 30, 2006, we refractured the formations of 2 gross (2 net) well locations. We also assumed that we will refracture 7 gross (7 net) additional wells during the twelve months ending September 30, 2007.

(2)

Our weighted average net natural gas sales price of $9.11 per MMBtu is calculated taking into account our executed hedges of 3.7 Bcf (or approximately 78% of our forecasted proved developed production volume from currently producing wells) at a weighted average NYMEX natural gas sales price of approximately $9.22 per MMBtu, and unhedged production volumes at an assumed price based on the SONAT Inside FERC Price, of $8.82 per MMBtu (based on forward curves as of September 1, 2006).

Our weighted average NYMEX hedge price of $9.22 per MMBtu was derived from our contractual fixed price contracts that were executed on June 20, 2006. Under these contracts, we have hedged approximately 0.9 Bcf of fourth quarter 2006 production at $8.83 per MMBtu and approximately 3.7 Bcf of 2007 production at $9.345 per MMBtu (2.8 Bcf of which is attributable to the nine months ending September 30, 2007). This results in our weighted average hedge price of $9.22 per MMBtu for the twelve months ending September 30, 2007.

The unhedged price for SONAT Inside FERC was derived from the weighted average forward market for NYMEX less our internal basis differential from NYMEX for SONAT as of September 1, 2006. The basis differential to NYMEX was zero on September 1, 2006. On September 1, 2006, the NYMEX weighted average forward price was approximately $8.824 per MMBtu and SONAT was approximately $8.826 per MMBtu.

The weighted average sales price has been calculated as the sum of the forecasted sales revenues from all production plus any gains or losses from executed hedges divided by the sales volumes forecasted for the period.

We initiated our hedging policy on June 20, 2006 and we intend to actively monitor and manage any further commodity price risk based upon our hedging policy.

On a pro forma basis, for the twelve months ended June 30, 2006, our average net realized sales price was approximately $8.00 per MMBtu as compared to approximately $9.11 per MMBtu forecast for the twelve-month period ending September 30, 2007.

(3)

In calculating our Estimated Adjusted EBITDA, we have netted from our total revenues estimated gains that we expect to incur of approximately $1.5 million due to hedges of the forecasted production.

(4)

Our forecasted field operating expenses consist of lease operating expenses, production expenses, “minor” maintenance, tools and supplies, production taxes (including severance and ad valorem taxes) and other customary charges. We believe that the amount reflected in the forecast for field operating expenses is sufficient to cover the expenses we will incur during the twelve months ending September 30, 2007 assuming production at the forecast level. If our actual field operating expenses are higher than we estimate, we believe that we will have sufficient capacity under our reserve-based credit facility to fund such incremental expenditures.

Our production taxes are calculated as a percentage of our revenues. As prices or volumes increase, our production taxes increase and as prices and volumes decrease, our production taxes decrease. Our forecasted production tax rate of approximately 5.3% is consistent with our historical production taxes of 5.4% and 5.2% for the year ended December 31, 2005 and the six months ended June 30, 2006, respectively.

Our forecasted lease operating expenses of approximately $6.4 million are $0.5 million lower than 2005 lease operating expenses, which were approximately $6.9 million. The $0.5 million difference is due to specific non-recurring costs such as costs incurred for transition services in connection with the purchase of our properties in the Robinson’s Bend Field, that, in many cases, were duplicative. In addition, we have adjusted for charges that were non-recurring, discretionary in nature.

Index to Financial Statements

(5)

We have assumed that the gas purchase contract in respect of production from the Trust Wells attributable to the NPI remains in effect. We do not directly hedge the NPI related production volumes. Based upon the assumptions set forth in notes (1) and (2) above, we have assumed that the forecasted net payment to the Trust would be approximately $0.3 million during such twelve-month period after consideration of all deductible estimated NPI related expenses. If the gas purchase contract or the sharing arrangement provided thereunder were terminated as of October 1, 2006, we estimate that our revenues would decline by $5.6 million during the twelve-month period ending September 30, 2007 based on forecast production from the Trust Wells for such twelve-month period and assuming the weighted average net realized sales price of $9.11 per MMBtu.

We made no payments to the Trust in respect of the NPI in 2005. For the eight months ended August 31, 2006, we paid the Trust approximately $0.2 million, which is comprised of actual calculations through June 30, 2006 and estimates for July and August 2006. We have not made a payment for production since February 2006 and, based upon our forward prices as of the forecast date, do not expect any further payments to the Trust in respect of the NPI until at least January 2007. However, changes in forward prices from our forecast date may change when our next payment with respect to the NPI will occur.

(6)

Our forecasted general and administrative expenses include the following:

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approximately $1.0 million in estimated expenses attributable to operations on the Robinson’s Bend Field properties, accounting and other similar administrative costs;

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approximately $2.0 million in estimated expenses associated with being a publicly traded entity, including, among other things, incremental accounting and audit fees, director and officer liability insurance, tax return preparation, investor relations, registrar and transfer agent fees and reports to our unitholders; and

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approximately $1.8 million of estimated expenses associated with financial, portfolio management and hedging services performed on our behalf by CEPM under the management services agreement, as well as officer compensation and other third-party consulting fees.

We have further assumed that we do not make any acquisitions during the twelve-month period ending September 30, 2007, and that we do not reimburse CEPM under the management services agreement for any acquisition services during such period. Our total forecasted general and administrative expenses of $4.8 million for the twelve months ending September 30, 2007, compares to approximately $1.7 million of pro forma general and administrative expenses, excluding $3.1 million attributable to the consulting fee payable to The Investment Company, for the year ended December 31, 2005. The pro forma general and administrative expenses do not include some costs associated with being a public entity, which we estimate will be approximately $3.1 million per year. These costs are $2.0 million of expenses associated with being a public entity and $1.1 million of costs not already reflected in the pro forma period such as officer and other employee compensation and other fees that will be required.

(b)

Our limited liability company agreement requires that we deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuations in our actual maintenance capital expenditures. Because of the substantial capital expenditures we are required to make to maintain our production and asset base, we estimate that our initial annual estimated maintenance capital expenditures for purposes of calculating operating surplus will be approximately $5.0 million per year as described in the next paragraph. Our board of managers, with the approval of our conflicts committee, may determine to increase the annual amount of our estimated maintenance capital expenditures. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus.

Index to Financial Statements

We expect to invest approximately $30.0 million in capital over the next six years (an average of approximately $5.0 million per year) related to maintenance capital expenditure projects. As a result, we expect that our estimated maintenance capital expenditures for the twelve-month period ending September 30, 2007, will be approximately $5.0 million. Our drilling program assumes that we will drill a total of 20 gross (20 net) development wells during the twelve months ending September 30, 2007. Of these wells, 12 gross (12 net) wells will constitute maintenance capital projects required to maintain our production volumes and on which we assume we will spend $4.8 million of the $5.0 million. We currently plan to continue that drilling program to develop our proved undeveloped drilling locations over the next six years. We also have included in estimated maintenance capital expenditures approximately $150,000 per year for potential costs that we may incur for lease renewals and acquisitions that will enable us to maintain our asset base.

Our forecasted average costs for drilling and refracturing wells are consistent with our actual results for the six months ended June 30, 2006. Of the 17 wells that were drilled and completed, our average costs were approximately $410,000 per well. We are forecasting approximately $400,000 per well to drill and complete during October 1, 2006 through September 30, 2007. Of the two wells that we refractured during the six months ended June 30, 2006, our average cost per refracture was approximately $110,000 as compared to our forecast of $137,500 per refracture for our forecast period October 1, 2006 through September 30, 2007.

(c)

We have assumed that our interest expense (excluding fees) for the twelve-month period ending September 30, 2007 will be approximately $1.5 million. We intend to borrow under our reserved-based credit facility amounts sufficient to pay interest during acquisition and development of any investment capital expenditures or any expansion capital expenditures before production, transportation or gathering, as the case may be, begins. For this reason, interest expense associated with our expected investment capital expenditures is capitalized and included in estimated investment capital expenditures, rather than estimated interest expense. Prior to the offering, we intend to borrow $30.0 million under our reserve-based credit facility. We also intend to use the $8.0 million in funds from the Class D interests to reduce the $30.0 million balance of the reserve-based credit facility to $22.0 million. For the twelve-month period ending September 30, 2007, we have assumed that our estimated investment capital expenditures consist of approximately $4.1 million (before interest expense), all of which we expect to fund with borrowings under our reserve-based credit facility. We have assumed that we pay 7% annualized interest on the end of month balance of the credit facility, which includes the $22.0 million initial net debt and cumulative borrowings of $4.1 million for investment capital. Our actual interest expense from February 7, 2005 (inception) through December 31, 2005 was approximately $3,000. If we do not borrow funds to pay our investment capital expenditures and distributions on our Class D interests, we would experience a shortfall in the cash available to allow us, together with cash generated from operations to pay our investment capital expenditures and distributions on our Class D interests and to pay our annualized initial quarterly distribution on our outstanding common units and Class A units. We do not expect that any of our expected development drilling or formation refracture operations to be conducted during the twelve months ending September 30, 2007 will constitute expansion capital expenditures. Our limited liability company agreement does not restrict us from borrowing to pay distributions on our Class A units, common units and other limited liability company interests, such as the management incentive interests and Class D interests. However, we may borrow funds under our reserve based credit facility (i) as long as there has not been a default or event of default under our credit agreement and if the amount of borrowings outstanding under our credit facility is less than 90% of our borrowing base, and (ii) under our limited liability company agreement working capital borrowings constitute operating surplus only if we repay such borrowings within one year. Please read “Management’s Discussion and Analysis—Capital Resources and Liquidity—Reserve-Based Credit Facility.” Furthermore, we assume that all of our debt incurred for other than working capital purposes will be refinanced as it comes due, although we have the right to establish cash reserves, including reserves for debt repayments, before determining the amount of cash available for distribution.

(d)

We have assumed that our estimated drilling and other production enhancement expenditures that are in excess of those necessary to replace our asset base during the twelve-month period ending September 30, 2007, including our unproven properties, and to offset over the long-term the expected production decline

Index to Financial Statements

from our properties will constitute investment capital expenditures. If we do make any such investment capital or expansion capital expenditures, we expect to fund those expenditures with borrowings under our reserve-based credit facility, the issuance of debt or equity securities or a combination thereof until production or other operations commence, after which we intend to refinance any short-term indebtedness incurred to fund such expenditures with the issuance of long-term debt, equity securities or a combination thereof. As a result, we do not expect any such investment capital expenditures or expansion capital expenditures and related borrowings to have an immediate impact on available cash. Our investment capital expenditures projected for the twelve-month period ending September 30, 2007 of approximately $4.3 million, including interest expense related to expansion capital borrowings, is expected to be incurred to drill, develop and place on production 8 gross (8 net) wells during such period. These 8 newly drilled gross wells would be in excess of the 12 gross wells that we project need to be drilled, completed and placed on production in the twelve months ending September 30, 2007 to offset the expected production decline rate from our existing producing wells. The estimated $4.3 million also includes capital required for the refracturing of the formations of approximately 7 gross (7 net) of our existing proved developed non-producing wells that we plan to complete during the twelve months ending September 30, 2007. Approximately $0.2 million of the $4.3 million is interest expense related to borrowings of investment capital, which we have assumed we will fund with borrowings and not pay out of available cash.

(e)

We will be required to pay special cash distributions in respect of the Class D interests totaling $1.0 million for the twelve months ending September 30, 2007 unless the gas purchase contract or, without the prior consent of our board of managers, the sharing arrangement provided thereunder is terminated before September 30, 2007. For purposes of this estimate, we have assumed that we deploy in our business the $8.0 million contributed to us for the Class D interests and that we borrow the amounts necessary to fund such special cash distributions under our reserve-based credit facility (payment of such special cash distributions would be made on or about May 15, 2007, August 14, 2007 and November 14, 2007, each in the amount of $333,333). We will generally be required to make four quarterly payments in any given year, assuming the sharing arrangement has not been terminated without the prior consent of our board of managers, but the first payment is not required to be made until May 15, 2007 for the first quarter of 2007.

(f)

$7.8 million of the proceeds from this offering will be retained in working capital. Of the $7.8 million, $5.0 million will be retained for the purposes of providing cash available for coverage of the initial quarterly distribution amounts and is thus included in the estimated cash available to pay distributions. While this $5.0 million will be available to pay distributions, we do not currently expect to use such cash to pay distributions for the forecast period. The remaining $2.8 million of the $7.8 million retained in working capital will be used for working capital purposes and is not expected to be used for distribution to the unitholders and is therefore not included in estimated cash available to pay distributions.

(g)

The table below sets forth the assumed number of outstanding common units and Class A units upon the closing of this offering and the full IQD payable on the outstanding common units and Class A units for the twelve-month period ending September 30, 2007.


	Number of Units	Distributions Per Unit		Aggregate Distributions
				(in ‘000’s)
Estimated distributions on common units	14,489,010	$	1.70	$	24,631
Estimated distributions on Class A units	295,690		1.70		503

Total	14,784,700	$	1.70	$	25,134

(h)

Our new reserve-based credit facility contains a covenant requiring us to have, as of the date of any distribution, a ratio of total borrowings outstanding under our reserve-based credit facility to our Borrowing Base (as defined in our credit agreement), of not more than 0.90 to 1.0. In addition, it contains a covenant requiring us to maintain, as of the last day of each fiscal quarter, a ratio of our Adjusted EBITDA (as defined in our credit agreement) to our cash interest expense, each measured for the preceding quarter, of not less than 4.5 to 1.0, a ratio of total indebtedness to Adjusted EBITDA of not more than 3.5 to 1.0 and a

Index to Financial Statements

ratio of current assets to current liabilities of not less than 1.0 to 1.0. We believe that we will be in compliance with these covenants for the twelve-month period ending September 30, 2007. A default by us that results in or could result in acceleration of any of our indebtedness in excess of $1.0 million constitutes an event of default under our credit agreement that would prohibit us from making distributions.

In preparing the estimates above, we have assumed that there will be no material change in the following matters, and thus they will have no impact on our Estimated Adjusted EBITDA:

•

There will not be any material expenditures related to new federal, state or local regulations or interpretations.

•

There will not be any material change in the natural gas industry or in market, regulatory and general economic conditions that would affect our cash flow.

•

We will not undertake any extraordinary transactions that would materially affect our cash flow.

•

There will be no material nonperformance or credit-related defaults by suppliers, customers or vendors.

•

The gas purchase contract (including the sharing arrangement provided thereunder) remains in effect.

While we believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full IQD or any amount on all our outstanding common units in respect of the four calendar quarters ending September 30, 2007 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from our operations to pay distributions to our unitholders of not less than the IQD per unit for the twelve months ending September 30, 2007 is a function of two primary variables: production volumes and natural gas prices. In the paragraphs below, we discuss the impact that changes in either of these variables, while holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the IQD on our outstanding units.

Production volume changes

For purposes of our estimates set forth above, we have assumed that our net production attributable to the Robinson’s Bend Field totals 5.0 Bcf during the twelve months ending September 30, 2007. If our actual net production realized during such twelve-month period is 5% more (or 5% less) than such estimate (that is, if actual net realized production is 5.25 Bcf or 4.75 Bcf), we estimate that our estimated cash available to pay distributions would increase (decrease) by approximately $2.1 million, assuming no other changes in any other variables.

Natural gas price changes

For purposes of our estimates set forth above, we have assumed that our weighted average net realized natural gas sales price for our net production volumes is $9.11 per MMBtu. If the average realized natural gas sales price for our net production volumes were to increase (decrease) by $1.00 per MMBtu, we estimate that our estimated cash available to pay distributions would increase (decrease) by approximately $1.2 million, assuming we maintain hedges of approximately 78% of our expected production from currently producing wells from October 1, 2006 through September 30, 2007 and no other changes in any other variables.

In order to address, in part, volatility in natural gas prices, we have implemented a commodity price risk management program that is intended to reduce the volatility in our revenues due to short-term changes in natural

Index to Financial Statements

gas prices. Under that program, we have adopted a policy that contemplates hedging the prices for approximately 80% of our expected production for a period of up to five years as appropriate. Implementation of such policy will mitigate, but will not eliminate, our sensitivity to short-term changes in prevailing natural gas prices.

Unaudited Pro Forma Available Cash to Pay Distributions

If we had completed the transactions contemplated in this prospectus on January 1, 2005, our pro forma available cash to pay distributions generated during 2005 would have been approximately $8.6 million. This amount would have been sufficient to pay approximately 34% of our $0.425 per quarter IQD ($1.70 on an annualized basis) on our outstanding common units and Class A units. If we had completed the transactions contemplated in this prospectus on July 1, 2005, our pro forma available cash to pay distributions generated during the twelve months ended June 30, 2006 would have been approximately $8.3 million. This amount would have been sufficient to pay approximately 33% of our $0.425 per quarter IQD ($1.70 on an annualized basis) on our outstanding common units and Class A units. Pro forma cash available to pay distributions also excludes any cash from working capital or other borrowings. As described in “How We Make Cash Distributions—Operating Surplus and Capital Surplus,” cash from these sources may also be used to pay distributions. Pursuant to the terms of our limited liability company agreement, our board of managers would have had the discretionary authority to cause us to borrow funds under our reserve-based credit facility to make up some or all of this estimated shortfall. For purposes of the calculation in the table below, however, we have assumed that we did not borrow any amounts to fund such estimated shortfall and that we paid out 100% of our pro forma available cash for distributions, which represented $8.6 million for 2005 and $8.3 million for the twelve months ended June 30, 2006.

In the future, it is management’s intent to borrow to the extent prudent and feasible to fund any short-term shortfall in cash available for distribution. Under the reserve-based credit facility that we plan to enter into prior to or at the closing of this offering, we expect to be able to incur debt to pursue our business plan and to pay distributions to our unitholders. However, we are prohibited from borrowing under our reserve-based credit facility to pay distributions to unitholders if the amount of borrowings outstanding under our reserve-based credit facility reaches or exceeds 90% of the borrowing base, which is estimated to be $100 million upon the closing of the offering, or if we are then in default under such facility. Giving effect to the use of the proceeds from this offering, we estimate our borrowing under the credit facility immediately after this offering will be $22.0 million.

The following table illustrates, on a pro forma basis for 2005 and the twelve months ended June 30, 2006, cash available to pay distributions, assuming, in each case, that the following transactions had occurred on January 1, 2005 and July 1, 2005, respectively:

•

the acquisition of our properties in the Robinson’s Bend Field from Everlast;

•

the indebtedness associated with our reserve-based credit facility;

•

aggregate payments (payable quarterly) to CHI of approximately $1.0 million in respect of the Class D interests, which we assume to be funded with borrowings under our reserve-based credit facility; and

•

this offering and the application of the net proceeds thereof, together with the $30.0 million assumed to be drawn under our reserve-based credit facility and $8.0 million from issuance of the Class D interests, as described under the caption “Use of Proceeds.”

Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

The pro forma financial statements, from which pro forma available cash is derived, do not purport to present our results of operations had the transactions contemplated above actually been completed as of the dates indicated. Furthermore, available cash is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma available cash stated above in the manner described in the table below. As a result, the amount of pro forma available cash should only be viewed

Index to Financial Statements

as a general indication of the amount of available cash that we might have generated had we been formed and completed the transactions contemplated below in earlier periods.


	Pro Forma Year Ended December 31, 2005			Pro Forma 12 Months Ended June 30, 2006
	(In ‘000’s, except ratios) (unaudited)
Net income^(a)	$	760		$	16,986
Plus:
Interest expense^(b)		1,546			1,546
Depreciation, depletion and amortization		7,281			7,987
Accretion of asset retirement obligation		141			149
Unrealized loss on natural gas derivatives		15,265			—

Adjusted EBITDA	$	24,993		$	26,668
Less:
Estimated incremental general and administrative expenses^(c)		3,100			3,100

Pro forma cash flow from operations		21,893			23,568
Less:
Cash necessary to pay initial quarterly distributions on Class A units and common units		25,134			25,134

Pro forma cash flow from operations after distributions		(3,241	)		(1,566	)
Less:
Pro forma capital expenditures^(d)		(12,286	)		(14,233	)
Cash required to pay Class D special cash distributions^(e⁾		(1,000	)		(1,000	)

Shortfall	$	(16,524	)	$	(16,799	)

Borrowing base ratio^(f)		0.2x			0.2x
Interest coverage ratio^(f)		16.2x			17.2x
Total debt/Adjusted EBITDA ratio^(f)		0.9x			0.8x

(a)

Excludes any adjustment for estimated incremental ongoing expenses we expect to incur as a result of being a publicly traded entity, including, among other things, incremental accounting and audit fees, director and officer liability insurance, tax return preparation, investor relations, registrar and transfer agent fees and reports to unitholders. We estimate that these incremental general and administrative expenses will be approximately $3.1 million annually.

(b)

Gives effect to interest on net borrowings of $22.0 million under our reserve-based credit facility as of the beginning of each period presented. The interest rate on these amounts is 7%.

(c)

Gives effect to $3.1 million in incremental general and administrative expenses we estimate that we would incur as a result of being a public company.

(d)

Gives effect to the capital expenditures for the drilling and completion of new wells and wells that were in the process of being drilled. It also gives effect to other capital expenditures such as facilities, pipelines, and other support equipment. During the year ended December 31, 2005, CEP and Everlast drilled and completed a total of 18 gross (18 net) development wells and commenced drilling on an additional 9 gross (9 net) wells. During the twelve months ended June 30, 2006, we drilled and completed 29 gross (29 net) wells and commenced drilling on an additional 7 gross (7 net) wells. During such periods, neither we nor Everlast characterized capital expenditures as maintenance, investment or expansion and, during such periods, neither we nor Everlast planned capital expenditures in a manner intended to maintain or expand the production or asset base of the Robinson’s Bend Field. As a result, we have not attempted to characterize the pro forma capital expenditures reflected herein as maintenance, investment or expansion. The capital expenditures that we and Everlast incurred during 2005 and for the twelve months ended June 30, 2006 were all funded from cash generated by our and Everlast’s operations, respectively.

Index to Financial Statements

(e)

Gives effect to the assumed payment of approximately $1.0 million in special distributions in respect of the Class D interests, assuming that payment of such special distributions was required to be made commencing with the quarter ended June 30, 2005 (for the year ended December 31, 2005) and December 31, 2005 (for the twelve months ended June 30, 2006). We will generally be required to make four quarterly payments in any given year, assuming the sharing arrangement has not been terminated without the prior consent of our board of managers.

(f)

Our reserve-based credit facility contains covenants requiring us to have, as of the date of any distribution, a ratio of total borrowings outstanding under our reserve-based credit facility to our Borrowing Base (as defined in our credit agreement) of not more than 0.90 to 1.0. In addition, the credit facility contains covenants requiring us to maintain, as of the last day of each fiscal quarter, a ratio of our Adjusted EBITDA (as defined in our credit agreement) to our cash interest expense, each measured for the preceding quarter, of not less than 4.5 to 1.0; a ratio of total indebtedness to Adjusted EBITDA of not more than 3.5 to 1.0; and a ratio of current assets to current liabilities of not less than 1.0 to 1.0. We would have been in compliance on a pro forma basis with these covenants for the year ended December 31, 2005 and the twelve months ended June 30, 2006. In addition, a default by us that results in or could result in an acceleration of any of our indebtedness in excess of $1.0 million will constitute an event of default under our credit agreement that would prohibit us from making distributions.

Index to Financial Statements

SELECTED HISTORICAL AND PRO FORMA

CONSOLIDATED FINANCIAL DATA

Set forth below is our selected historical and unaudited pro forma consolidated financial data for the periods indicated. We were formed in February 2005 and had no principal operations prior to the completion of a $161.1 million acquisition of natural gas reserves and equipment from Everlast Energy LLC, or Everlast, on June 13, 2005. We applied the purchase method of accounting to the separable assets and liabilities of the natural gas properties and equipment acquired from Everlast. The selected historical consolidated financial data of Everlast for the period from January 1, 2005 through June 12, 2005 and as of and for the years ended December 31, 2004 and 2003 have been derived from Everlast’s audited historical financial statements. The historical financial data as of and for the years ended December 31, 2002 and December 31, 2001 have been derived from unaudited financial data of Torch Energy, the predecessor to Everlast. The historical financial data of Constellation Energy Partners LLC as of December 31, 2005 and for the period from February 7, 2005 (inception) to December 31, 2005, have been derived from our audited historical consolidated financial statements. The historical consolidated financial data of Constellation Energy Partners, LLC as of and for the six months ended June 30, 2006 and for the period from February 7, 2005 (inception) to June 30, 2005 have been derived from our unaudited historical consolidated financial statements. The selected unaudited pro forma consolidated financial data as of and for the six months ended June 30, 2006 and for the year ended December 31, 2005 have been derived from our unaudited pro forma consolidated financial statements. For a description of the adjustments made in the unaudited pro forma consolidated financial statements, please read the notes to those financial statements.

You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the financial statements of Everlast and related notes appearing elsewhere in this prospectus. You should also read the pro forma information together with the unaudited pro forma consolidated financial statements and related notes included in this prospectus.

Our only operations are in the Robinson’s Bend Field, as were Everlast’s. During each of the last three years, our properties in the Robinson’s Bend Field were wholly owned by us or Everlast. Our acquisition from Everlast resulted in a new basis for our properties in the Robinson’s Bend Field for accounting purposes. In addition, new management, operating and accounting policies, and estimates were put into place after our acquisition from Everlast. Though the financial statements represent the operation of the same properties in the Robinson’s Bend Field, due to these differences, the financial statements for the periods prior to and after our purchase of our properties in the Robinson’s Bend Field are not comparable. For that purpose, a black line has been placed between our and Everlast’s financial statements. Our historical results of operations and period-to-period comparisons of results and certain financial data prior to and after our acquisition of our properties in the Robinson’s Bend Field from Everlast may not be indicative of future results.

Index to Financial Statements


	Predecessor															Successor
	Torch Energy						Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2001			For the year ended December 31, 2002			For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005^(b)		For the period from February 7, 2005 (inception) to June 30, 2005^(b)			For the six months ended June 30, 2006			Pro Forma
	For the year ended December 31, 2001			For the year ended December 31, 2002			For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005								For the six months ended June 30, 2006			For the year ended December 31, 2005			For the six months ended June 30, 2006
	Unaudited			Unaudited			As Restated^(a)			As Restated^(a)								Unaudited			Unaudited			Unaudited			Unaudited
	(In ‘000’s)						(In ‘000’s)									(In ‘000’s)
Statement of Operations Data:
Revenues:
Gas sales	$	9,216		$	8,710		$	22,320		$	27,494		$	12,882		$	25,957	$	1,377		$	17,605		$	38,839		$	17,605
Loss from mark-to-market activities		—			—			(3,664	)		(9,107	)		(15,313	)		—		—			—			(15,313	)		—

Total revenues		9,216			8,710			18,656			18,387			(2,431	)		25,957		1,377			17,605			23,526			17,605

Operating Expenses:
Lease operating expenses		9,254			7,763			4,428			5,270			2,769			4,175		357			3,495			6,944			3,495
Production taxes		592			368			1,279			1,479			676			1,400		72			909			2,076			909
General and administrative		162			92			1,945			2,706			594			4,184		3,275			2,731			4,778			2,731
Depreciation, depletion and amortization		199			77			3,684			3,719			1,683			4,176		350			3,811			7,281			3,811
Accretion expense		—			—			73			86			46			78		7			71			141			71
(Gain) loss on asset sale		(193	)		(4	)		—			—			—			—		—			—			—			—

Total operating expenses		10,014			8,296			11,409			13,260			5,768			14,013		4,061			11,017			21,220			11,017

Other expenses/(income):
Interest expense/(income), net		—			—			1,961			3,028			2,437			3		—			(197	)		1,546			573
Organization costs		—			—			299			—			—			—		—			—			—

Total other expenses (income)		—			—			2,260			3,028			2,437			3		—			(197	)		1,546			573

Total expenses		—			—			13,669			16,288			8,205			14,016		4,061			10,820			22,766			11,590

Net income (loss)	$	(798	)	$	414		$	4,987		$	2,099		$	(10,636	)	$	11,941	$	(2,684	)	$	6,785		$	760		$	6,015

Other Financial Information (unaudited)
Adjusted EBITDA							$	10,193		$	14,738		$	8,795		$	16,198	$	(2,327	)	$	10,470		$	24,993		$	10,470

(a)

The financial statements of Everlast for 2003 and 2004 have been restated. Please read Note 2 to the historical consolidated financial statements included elsewhere in this prospectus.

(b)

Until our acquisition of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005, we did not conduct any operations.

Index to Financial Statements


	Predecessor															Successor
	Torch Energy						Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2001			For the year ended December 31, 2002			For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005(b)			For the period from February 7, 2005 (inception) to June 30, 2005(b)			For the six months ended June 30, 2006			Pro Forma
	For the year ended December 31, 2001			For the year ended December 31, 2002			For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005									For the six months ended June 30, 2006			For the six months ended June 30, 2006
	Unaudited			Unaudited			As Restated^(a)			As Restated^(a)									Unaudited			Unaudited			Unaudited
	(In ‘000’s)						(In ‘000’s)									(In ‘000’s)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	—		$	—		$	2,563		$	2,012					$	14,831					$	3,880		$	7,827
Other current assets		32,762			39,014			1,812			4,562						6,097						17,912			5,713
Natural gas properties, net of accumulated depreciation, depletion and amortization		1,555			1,587			49,252			52,531						165,211						169,282			169,282
Other assets		—			—			590			1,579						—						311			311

Total assets	$	34,317		$	40,601		$	54,217		$	60,684					$	186,139					$	191,385		$	183,133

Current liabilities	$	37,941		$	43,812		$	4,403		$	4,482					$	13,895					$	10,797		$	10,797
Debt		—			—			26,000			67,500						63						52			22,052
Preferred units subject to mandatory redemption		—			—			16,752			—						—						—			8,000
Other long-term liabilities		—			—			2,671			3,314						3,014						3,099			3,099
Members Equity
Common members equity (deficit)		(3,624	)		(3,211	)		4,391			(14,612	)					169,167						176,523			138,271
Accumulated other comprehensive income		—			—			—			—						—						914			914

Total members’ equity (deficit)		(3,624	)		(3,211	)		4,391			(14,612	)					169,167						177,437			139,185

Total liabilities and members’ equity (deficit)	$	34,317		$	40,601		$	54,217		$	60,684					$	186,139					$	191,385		$	183,133

Cash Flow Data:
Net cash provided by operating activities	$	(219	)	$	109		$	9,773		$	4,906		$	6,639		$	23,313		$	2,931		$	8,805
Net cash provided by (used in) investing activities		219			(109	)		(47,832	)		(6,997	)		(4,203	)		(147,237	)		(139,357	)		(19,745	)
Net cash provided by (used in) financing activities		—			—			40,622			1,540			(2,500	)		138,755			138,770			(11	)
Development of natural gas properties		(61	)		(109	)		(2,040	)		(5,680	)		(4,000	)		(8,286	)		(406	)		(7,285	)

(a)

The financial statements of Everlast for 2003 and 2004 have been restated. Please read Note 2 to the historical consolidated financial statements included elsewhere in this prospectus.

(b)

Until our acquisition of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005, we did not conduct any operations.

Index to Financial Statements

Non–GAAP Financial Measure—Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) plus:

•

interest (income) expense;

•

depreciation, depletion and amortization;

•

write-off of deferred financing fees;

•

impairment of long-lived assets;

•

(gain) loss on sale of assets;

•

(gain) loss from equity investment;

•

accretion of asset retirement obligation;

•

unrealized (gain) loss on natural gas derivatives; and

•

realized loss (gain) on cancelled natural gas derivatives.

Adjusted EBITDA is a significant performance metric to be used by our management to indicate (prior to the establishment of any reserves by our board of managers) the cash distributions we expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:

•

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and

•

our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Index to Financial Statements

The following table presents a reconciliation of net income (loss) and net cash flow provided by operating activities to Adjusted EBITDA, our most directly comparable GAAP performance and liquidity measures, for each of the periods presented:


	Predecessor									Successor
	Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005			For the period from February 7, 2005 (inception) to June 30, 2005			For the six months ended June 30, 2006			Pro Forma
	For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005									For the six months ended June 30, 2006			For the year ended December 31, 2005		For the six months ended June 30, 2006
	(In ‘000’s)												(Unaudited)			(Unaudited)			(Unaudited)		(Unaudited)
										(In ‘000’s)
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net income/(loss)	$	4,987		$	2,099		$	(10,636	)	$	11,941		$	(2,684	)	$	6,785		$	760	$	6,015
Add:
Interest expense/(income), net^(a)		1,961			3,028			2,437			3			—			(197	)		1,546		573
Depreciation, depletion and amortization		3,684			3,719			1,683			4,176			350			3,811			7,281		3,811
Accretion of asset retirement obligation		73			86			46			78			7			71			141		71
Unrealized loss/(gain) on natural gas derivatives		(512	)		(2,156	)		15,265			—			—			—			15,265		—
Realized loss on cancelled natural gas derivatives		—			7,962			—			—			—			—			—		—

Adjusted EBITDA	$	10,193		$	14,738		$	8,795		$	16,198		$	(2,327	)	$	10,470		$	24,993	$	10,470

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	9,773		$	4,906		$	6,639		$	23,313		$	2,931		$	8,805
Add:
Interest expense/(income), net^(a)		1,305			2,596			2,437			3			—			(197	)
Expenses paid by CCG on behalf of CEP		—			—			—			(64	)		—			(571	)
Realized loss on cancelled natural gas derivatives		—			7,962			—			—			—			—
Changes in working capital:
Accounts receivable		1,547			2,278			707			1,289			(1,535	)		(1,869	)
Prepaid expenses		265			(246	)		131			62			21			75
Other assets		—			—			10			211			—			807
Loan amortization cost		(288	)		(685	)		(237	)		—			—			—
Accounts payable		(908	)		(993	)		(807	)		(1,703	)		863			2,187
Royalty payable		(1,321	)		(708	)		(110	)		(1,859	)		(364	)		1,240
Accrued liabilities		(180	)		(372	)		25			(5,054	)		(4,243	)		(7	)

Adjusted EBITDA	$	10,193		$	14,738		$	8,795		$	16,198		$	(2,327	)	$	10,470

(a)

Index to Financial Statements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical and Pro Forma Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a limited liability company formed by Constellation on February 7, 2005 to acquire coalbed methane reserves and production in the Robinson’s Bend Field in June 2005. These reserves were acquired from Everlast and included working interests in 424 coalbed methane producing wells at the time of the acquisition. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase the amount of our future quarterly distributions. Our strategies for achieving this objective are to:

•

make accretive acquisitions of E&P properties characterized by a high percentage of proved producing reserves with long-lived, stable production and step-out development opportunities. Such properties may include associated midstream assets such as gathering systems, compression, dehydrating and treating facilities and other similar facilities;

•

identify and work with third-party operators who have experience in regions in which we seek to acquire an ownership interest and who will hold an ownership interest in our properties;

•

increase reserves and production through what we believe to be low-risk development and exploitation drilling; and

•

reduce the volatility in our revenues resulting from changes in oil and natural gas commodity prices through hedging.

Our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations and our ability to pay quarterly cash distributions to our unitholders.

Our estimated proved reserves at December 31, 2005 were approximately 112.0 Bcf, approximately 80% of which were classified as proved developed producing. Our estimated proved reserves at December 31, 2005 had a Standardized Measure of approximately $295.4 million, which excluded the impact of taxes because we are not a taxable entity. Our average proved reserve-to-production ratio is approximately 25 years, based on our estimated proved reserves at December 31, 2005 and annualized production for the six months ended December 31, 2005. We currently own a 100% working interest (an approximate 75% average net revenue interest, calculated before the Torch Royalty NPI) in our Robinson’s Bend Field producing properties, which had 436 producing natural gas wells as of December 31, 2005.

Index to Financial Statements

calculated as a percentage of the net revenue, that is, specified revenues reduced by specified associated expenditures, from certain wells in the Robinson’s Bend Field, or the Trust Wells. Under the terms of the NPI and related contractual arrangements, the royalty payment we are required to make to the Trust under the NPI is calculated using a sharing arrangement with a pricing formula that has been below market and has had the effect of keeping the payments to the Trust significantly lower than if such payments had been calculated based on then prevailing market prices. Reserves attributable to the NPI are not included in our estimate of proved reserves. The sharing arrangement may be terminated under specified circumstances that are beyond our control. If we lose the benefit of the sharing arrangement in respect of calculating payments under the NPI, the payments to the Trust will increase and our revenues will decrease in each case compared to the amounts if the sharing arrangement remained in effect. For a further description of the NPI and the related contractual arrangement, as well as the circumstances under which the sharing arrangement may be terminated, please read “Business—Natural Gas Data—Torch Royalty NPI.”

Daily field operations are performed by employees of our wholly owned subsidiary, Robinson’s Bend Operating II, LLC, whose employees operate under the direct supervision of Ironhorse Energy, LP, or Ironhorse. We entered into a professional services agreement with Ironhorse to provide us with these project management services for the Robinson’s Bend Field. Other support services, including geology, engineering, land administration and revenue accounting, will be provided to us by CEPM and its affiliates.

We will enter into a management services agreement with CEPM, an indirect wholly owned subsidiary of Constellation. Pursuant to that agreement, CEPM will provide us with legal, accounting, finance and tax services. We also expect that CEPM will provide us with property management, engineering and other services and with assistance in hedging our production as well as acquisition services in respect of opportunities for us to acquire long-lived, stable and proved oil and natural gas reserves. While we are consolidated with Constellation for accounting purposes, we will be required under the management services agreement to use CEPM or its designee for legal, accounting, finance, tax and risk management services. While neither Constellation nor CEPM has any obligation to provide us with acquisition services under the management services agreement, we expect that their ownership of our Class A units, common units and management incentive interests will provide them with an incentive to grow our business by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash.

Following this offering we will be dependent on CEPM for management of our operations and, pursuant to the management services agreement, we will reimburse CEPM for the reasonable costs of the services it provides to us. Our board of managers has the right and the duty to review the services provided, and the costs charged, by CEPM under that agreement. Our board of managers may in the future cause us to hire additional personnel to supplement or replace some or all of the services provided by CEPM, as well as employ third-party service providers. If we were to take such actions, they could increase the overall costs of our operations. For a description of the services that CEPM will provide to us under the management services agreement and our obligation to reimburse CEPM for the costs it incurs in providing those services, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management Services Agreement.”

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of these goods and services. To date, our higher realized sales prices for natural gas have more than offset the higher drilling and operating costs we have

Index to Financial Statements

incurred since our acquisition. Given the inherent volatility of natural gas prices, which are influenced by many factors beyond our control, we plan our activities and budgets based on sales price assumptions that reflect our forward price curve. We focus our efforts on increasing natural gas reserves and maintaining natural gas production levels while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations is dependent on our ability to manage our overall cost structure.

We face the challenge of natural gas production declines. As a given well’s initial reservoir pressures are depleted, natural gas production decreases. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on costs to add reserves through drilling and acquisitions, as well as the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. In accordance with our business plan, we intend to invest the capital necessary to maintain our production or operating capacity and our asset base over the long term.

Comparability of Financial Statements

Because of our limited operating history, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be indicative of future results.

Our only operations are in the Robinson’s Bend Field, as were Everlast’s. During each of the last three years, our properties in the Robinson’s Bend Field were wholly owned by us or Everlast. Our acquisition from Everlast resulted in a new basis in the Robinson’s Bend Field for accounting purposes. In addition, new management, operating and accounting policies, and reserve estimates were put into place after our acquisition from Everlast. Though the financial statements represent the operation of the same properties in the Robinson’s Bend Field, due to these differences, the financial statements for the periods prior to and after our purchase of the Robinson’s Bend Field are not comparable. Our historical results of operations and period-to-period comparisons of results and certain financial data prior to and after our acquisition from Everlast may not be indicative of future results.

Some of the differences include:

•

Reserves and related estimates: Our estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our 2005 proved reserve estimate is 112.0 Bcf which is lower than our 2004 estimates of proved reserves primarily because of the following factors:

–

A Reduction of 24.5 Bcf Based on Interpretation of Well Performance: The information on which we based this adjustment includes our interpretation of well performance data that was available at December 31, 2005 for new wells drilled and completed in the Robinson’s Bend Field in 2004 and 2005. There was no drilling in the field between 1994 and late 2003. While the performance data at December 31, 2005 is from a limited number of new wells drilled in the field in 2004 and in 2005, we believe it provides relevant information for the purposes of estimating reserves and we have interpreted the data and reflected the results of that analysis in our reserve estimates and assumptions. The majority of the 24.5 Bcf reduction in the reserve estimate at December 31, 2005 associated with our interpretation of the recent well performance data is in the proved developed non-producing (PDNP) category and the proved undeveloped (PUD) categories of reserves.

–

A Reduction of 15.4 Bcf Based on CEP’s Planned Drilling Program: The 112.0 Bcf estimate also reflects our planned drilling program of 20 gross wells per year for the next six years. We use a six year time horizon for drilling program and reserves estimation purposes because it is consistent with what we use for internal capital expenditure planning purposes and because we

Index to Financial Statements

believe that using a longer time horizon would create additional uncertainty with regard to capital budgeting, therefore potentially reducing our ability to prepare a reliable estimate of reserves. Everlast’s drilling program, which was designed to provide maximum returns in a relatively short time period, was to drill and complete 197 gross wells within a five-year period. Our planned drilling program is designed to provide a steady and constant return by drilling an average of 20 wells per year over a six year period. Due to this difference in drilling programs, certain proved undeveloped reserves that were based on Everlast’s accelerated drilling program and using NSAI’s reserve assumptions cannot be included in our proved reserve estimates because under our current drilling program those reserves are scheduled to be drilled more than six years after the date of the reserve report and as such are outside the time horizon we use to prepare our internal estimates of proved reserves.

–

A Reduction of 5.8 Bcf for Reserves Attributed to the NPI: Our December 31, 2005 reserve estimates removed 5.8 Bcf of reserves that are attributed to the NPI using an overriding royalty interest approach. The estimated reserves attributed to the NPI at December 31, 2004 were zero due to the lower gas prices compared to December 31, 2005 prices.

We used our 112.0 Bcf proved reserve estimate to prepare our 2005 financial statements. The reserve estimates of 162.2 Bcf at December 31, 2004 and 163.7 Bcf at December 31, 2003 used to prepare the 2004 and 2003 financial statements of our predecessor, Everlast, were also prepared by us using internal estimates.

We prepared the estimates of the 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 proved reserve estimate, which was based upon Everlast’s drilling program and reserve assumptions, and rolling that estimate back to December 31, 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll-back process was necessary because the reserve report prepared by NSAI for Everlast for December 31, 2004 was not based on the SEC definition of proved reserves, which we use for financial statement preparation purposes. The reserve report prepared by NSAI for Everlast for December 31, 2003, while based on the SEC definition of proved reserves, included different assumptions than those used by NSAI in preparing the December 31, 2005 estimate.

Due to this inconsistency in the preparation of reserve reports for the periods presented, we have rolled back the estimate of reserves at December 31, 2005 to December 31, 2004 and 2003 in preparing the financial statements of our predecessor for the years ended December 31, 2004 and 2003. In preparing the roll-back to December 31, 2004 and 2003, we did not adjust the estimated proved reserve volumes to reflect our reserve assumptions based upon our interpretation of recent well performance in the Robinson’s Bend Field because these assumptions, were based on recent information that was not available to Everlast when it was preparing the 2004 and 2003 financials statements. In addition, we did not adjust the volumes to reflect our current drilling program of 20 gross wells per year for the next six years because this drilling program was not the drilling program adopted by Everlast in 2004 and 2003. The previous reserve estimates were 173.4 Bcf at December 31, 2004 and 166.2 Bcf at December 31, 2003.

•

Derivatives: Everlast’s economic hedges did not qualify for hedge accounting treatment under Statement of Financial Accounting Standard (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities and are thus classified as losses on a mark-to-market basis in its statement of operations. From the acquisition of our properties in the Robinson’s Bend Field until June 20, 2006, we did not, enter into hedges in our own name. During that period, hedges were executed by CCG, which hedged its exposure to the variability in revenues from the forecasted sale of natural gas due to changes in natural gas prices by entering into hedges for its entire portfolio of natural gas properties, including our properties in the Robinson’s Bend Field. Therefore, hedging gains and losses are not reflected in our financial statements included elsewhere in this prospectus. These gains and losses are reported in the financial statements of CCG. On June 20, 2006, we executed hedges for approximately 78% of our expected production from currently producing wells for October 2006 through December 2009.

Index to Financial Statements

•

Depletion: Everlast used the full-cost method of accounting for natural gas properties, whereas we use the successful efforts method. Under the full-cost method used by Everlast, all costs related to the acquisition, exploration or development of natural gas properties are capitalized and depleted based on the production of proved reserves. Under the successful efforts method that we use, costs relating to the development of proved areas are capitalized when incurred and are depleted based on the production of either proved developed reserves or proved reserves, depending on the asset classification. Exploration costs, however, are expensed as incurred. Under both methods, capitalized costs are depleted on a units-of-production method.

Outlook

We expect that, during the remainder of 2006 and for our forecast period, our business will continue to be affected by the risks described in “Risk Factors”, as well as the following key industry and economic trends. Our expectation is based upon key assumptions and information currently available to us. To the extent that our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Production and Drilling

Our net production for August 2006 was approximately 0.41 Bcf, or about 4.9 Bcf on an annualized basis. We have determined, based upon internal reserve and production analysis, that drilling approximately 12 new wells per year on our properties in the Robinson’s Bend Field would maintain those production levels for approximately five years. For the twelve months ending September 30, 2007, we expect net production of approximately 5.0 Bcf. This is based upon our current drilling and refracture plan, which includes a total of 20 newly drilled wells and 7 refractures during that twelve-month period.

Natural Gas Prices

Natural gas prices have been extremely volatile over the past three years and even more so in the past nine to twelve months. We believe that this trend has been significantly affected by the hurricanes in the late summer and fall of 2005, threats and existence of wars and terrorism in the Middle East and elsewhere, OPEC’s management of oil reserves (given the correlation between natural gas and oil) and growth in domestic natural gas demand. The currently high levels of natural gas in storage, resulting at least in part from a relatively mild winter of 2005 in the United States, have caused natural gas prices to decline substantially from the higher levels prevailing during the later part of 2005.

Hedging Activities

As of June 30, 2006, we had hedges for approximately 78% of our expected production from currently producing wells from October 2006 through December 2009. Previously, hedges for natural gas production by CCG and its subsidiaries were generally held by CCG and maintained on CCG’s books on a portfolio basis. However, we expect our hedging policy will be to hedge approximately 80% of our total forecasted proved developed production from currently producing wells for a five-year period. These hedges are required by our lender under the terms of our reserve-based credit facility. However, our management may modify the hedging percentages and strategies as it deems appropriate for market conditions and our business strategy. For accounting purposes, these hedges are being treated as cash flow hedges.

Field Operating Expenses

Our field operating expenses include, without limitation, such items as lease operating expenses, labor, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, as well as production and ad valorem taxes. Due to the current environment of relatively high commodity prices, we anticipate that during

Index to Financial Statements

the twelve months ending September 30, 2007, service and labor costs, as well as costs of equipment and raw materials, will remain at or exceed the levels we experienced in 2005 and the six months ended June 30, 2006. We expect our future field operating costs will be correlated to the price of natural gas, although the cost changes generally lag and are less volatile than natural gas price changes. When natural gas prices are higher, demand for these services is higher, resulting in increased costs for such services. We intend to monitor and manage these costs in an effort to mitigate their adverse impact on our results of operations. Our production taxes are directly correlated to our revenues, as they are calculated as a percentage of sales revenue. We will consider the effect of production taxes on hedged revenues and quantities when we execute and manage our hedges.

General and Administrative Expenses

We expect that our general and administrative expenses will be approximately $4.8 million for the twelve months ending September 30, 2007. There are three main components of these estimated costs:

•

operational general and administrative expenses will comprise approximately $1.0 million of our forecasted general and administrative costs. These costs include third-party well-level accounting charges, Ironhorse and other consultant fees, accounting, annual reserve reports and other similar administrative expenses;

•

costs associated with annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, fees of independent managers, accounting fees and legal fees will comprise approximately $2.0 million of our estimated total general and administrative expenses;

•

other overhead charges, including financial, portfolio management and hedging services performed on our behalf by CEPM under the management services agreement, other third-party consulting fees and reimbursement of affiliate employee expense will comprise approximately $1.8 million of our estimated total general and administrative expenses.

These estimated general and administrative costs assume that we do not make any acquisitions during the twelve-month period ending September 30, 2007, and that we do not reimburse CEPM under the management services agreement for any acquisition services during such period.

Results of Operations

We acquired the Robinson’s Bend Field from Everlast on June 13, 2005. From February 7, 2005, the date of our formation, to June 12, 2005, we did not conduct any operations and had no production, therefore we had no revenues or operating expenses.

Index to Financial Statements

The following table sets forth selected financial and operating data for the periods indicated.


	Predecessor									Successor
	Everlast Energy LLC									Constellation Energy Partners LLC
	For the year ended December 31, 2003^(a)			For the year ended December 31, 2004^(a)			For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005^(b)			For the period from February 7, 2005 (inception) to June 30, 2005^(b)			For the six months ended June 30, 2006
													Unaudited			Unaudited
	(In ‘000’s, except production, cost and price data)									(In ‘000’s, except production, cost and price data)
Statement of Operations Data:
Revenues:
Gas sales	$	22,320		$	27,494		$	12,882		$	25,957		$	1,377		$	17,605
Loss from mark-to-market activities		(3,664	)		(9,107	)		(15,313	)		—			—			—

Total revenues		18,656			18,387			(2,431	)		25,957			1,377			17,605

Operating expenses:
Lease operating expenses		4,428			5,270			2,769			4,175			357			3,495
Production taxes		1,279			1,479			676			1,400			72			909
General and administrative expenses		1,945			2,706			594			4,184			3,275			2,731
Depreciation, depletion and amortization		3,684			3,719			1,683			4,176			350			3,811
Accretion expense		73			86			46			78			7			71

Total operating expenses		11,409			13,260			5,768			14,013			4,061			11,017

Other expenses/(income):
Interest expense/(income)		1,961			3,028			2,437			3			—			(197	)
Organizational costs		299			—			—			—			—			—

Total other expenses/(income)		2,260			3,028			2,437			3			—			(197	)

Net income (loss)	$	4,987		$	2,099		$	(10,636	)	$	11,941		$	(2,684	)	$	6,785

Net production:
Total production (MMcf)		4,566			4,527			1,970			2,525			217			2,200
Average daily production (Mcf/d)		12,500			12,400			12,100			12,500			12,053			12,156
Average sales prices:
Price per Mcf including economic hedges	$	4.09		$	4.06		$	(1.23	)^(c)	$	10.28	^(d)	$	6.35	^(d)	$	8.00	^(d)
Price per Mcf excluding economic hedges	$	4.89		$	6.07		$	6.54		$	10.28		$	6.35		$	8.00
Average unit costs per Mcf:
Field operating expenses	$	1.25		$	1.49		$	1.75		$	2.21		$	1.98		$	2.00
General and administrative expenses	$	0.43		$	0.60		$	0.30		$	1.66		$	15.10		$	1.24
Depreciation, depletion and amortization	$	0.81		$	0.82		$	0.85		$	1.65		$	1.61		$	1.73

(a)

The financial statements of Everlast for 2003 and 2004 have been restated. Please read Note 2 to the historical consolidated financial statements included elsewhere in this prospectus.

(b)

Until our acquisition of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005, we did not conduct any operations and, therefore, had no production.

(c)

Price per Mcf including economic hedges includes mark-to-market losses of approximately $15.3 million on derivative transactions that did not qualify for hedge accounting treatment.

(d)

We had no derivatives at June 30, 2005 and December 31, 2005. On June 20, 2006, we entered into derivative transactions that hedge the future prices of approximately 78% of our expected production from October 2006 through December 2009 from currently producing wells.

Index to Financial Statements

Revenue

Gas Sales

Our natural gas sales for the six months ended June 30, 2006 were $17.6 million, which were driven by average prices of $8.00 per Mcf. Production for that period was 2.2 Bcf.

Our natural gas sales for the period from February 7, 2005 (inception) to June 30, 2005 were $1.4 million. For the period from February 7, 2005 (inception) to June 30, 2005, our total production was 0.2 Bcf, with an average sales price of $6.35 per Mcf.

Our natural gas sales for the period from February 7, 2005 (inception) to December 31, 2005 were $26.0 million. For the period from February 7, 2005 (inception) to December 31, 2005, our total production was 2.5 Bcf, with an average sales price of $10.28 per Mcf. For the period from June 13, 2005 to December 31, 2005, gas prices increased substantially, particularly in October and November, due to natural gas shortages caused by hurricanes Katrina and Rita. The average realized sales price for those two months was $13.79 Mcf/d, which was 49% higher than the prior two months.

Everlast’s natural gas sales were $12.9 million for the period from January 1, 2005 to June 12, 2005. For the period from January 1, 2005 to June 12, 2005, Everlast’s production was 2.0 Bcf, with an average realized sales price of $6.54 per Mcf. Everlast’s natural gas sales increased by $4.9 million, or 22%, to $27.5 million for the year ended December 31, 2004 compared to gas sales of $22.3 million for 2003. This was due to a 24% increase in the average natural gas price, which was $6.07 per Mcf for the year ended December 31, 2004, compared to $4.89 per Mcf for the year ended December 31, 2003, as total production remained relatively stable at approximately 4.5 Bcf.

Mark-to-Market Activities

We did not have any mark-to-market derivatives for the six months ended June 30, 2006.

We did not have any mark-to-market derivatives from February 7, 2005 (inception) to December 31, 2005. During such period, CCG utilized hedges to mitigate its natural gas price exposure across its portfolio of gas producing assets including our properties in the Robinson’s Bend Field. Accordingly, the results of these hedges are not reflected on our financial statements. CCG also assumed certain of Everlast’s hedges at the time of our acquisition from Everlast and managed such hedges as part of its portfolio of hedges.

Everlast entered into derivative instruments to economically hedge the market price fluctuations of its natural gas. Everlast’s losses on its mark-to-market derivatives were $15.3 million for the period from January 1, 2005 to June 12, 2005, and $9.1 million and $3.7 million for the years ended December 31, 2004 and 2003, respectively. These losses were caused by the movement of market prices above the fixed price under the derivatives maintained by Everlast.

Expenses

Field Operating Expenses

Our field operating expenses generally consist of lease operating expenses, labor, vehicle expenses, supervision, transportation, minor maintenance, tools and supplies, as well as production and ad valorem taxes. Production taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by county and are based on the value of our reserves. All of our current reserves are located in Tuscaloosa County in the State of Alabama. We assess our field operating expenses by monitoring the expenses in relation to the volume of production and the number of wells under operation.

Index to Financial Statements

For the six months ended June 30, 2006, field operating expenses were $4.4 million, or $2.00 per Mcf. Significant field operating expenses during this period included:

•

Production taxes of $0.9 million, or $0.41 per Mcf (the current production tax rate is approximately 5% of gas sales);

•

Field salaries and operating supervision costs of $0.9 million, or $0.43 per Mcf;

•

Well servicing and work-over costs $1.0 million, or $0.45 per Mcf;

•

Power and fuel costs of $0.4 million, or $0.19 per Mcf;

•

Maintenance and repair costs of $0.3 million, or $0.16 per Mcf;

•

Gas marketing costs of $0.2 million, or $0.08 per Mcf;

•

Insurance and bond costs of $0.1 million, or $0.07 per Mcf; and

•

Miscellaneous operating costs of $0.5 million, or $0.24 per Mcf.

Our field operating expenses were $0.4 million for the period from February 7, 2005 (inception) to June 30, 2005, or an average of approximately $1.98 per Mcf of production during that period.

For the period from February 7, 2005 (inception) to June 30, 2005, significant field operating expenses included:

•

Production taxes of $0.1 million, or $0.33 per Mcf; and

•

Miscellaneous operating costs of $0.3 million, or $1.65 per Mcf.

Our field operating expenses were $5.6 million for the period from February 7, 2005 (inception) to December 31, 2005, or an average of approximately $2.21 per Mcf of production during that period. Our field operating expenses increased during such period as a result of the effects of generally higher prevailing natural gas prices, which affected our production taxes and fuel costs.

For the period from February 7, 2005 (inception) to December 31, 2005, significant field operating expenses included:

•

Production taxes of $1.4 million, or $0.55 per Mcf (the current production tax rate is approximately 5% of gas sales);

•

Field salary costs and operating supervision costs of $1.3 million, or $0.52 per Mcf;

•

Well servicing costs of $0.7 million, or $0.29 per Mcf;

•

Power and fuel costs of $0.6 million, or $0.24 per Mcf;

•

Maintenance and repair costs of $0.3 million, or $0.14 per Mcf;

•

Gas marketing costs of $0.4 million, or $0.16 per Mcf;

•

Insurance and bond costs of $0.2 million, or $0.07 per Mcf; and

•

Miscellaneous operating costs of $0.6 million, or $0.25 per Mcf.

Everlast’s field operating expenses were $3.4 million, or $1.75 per Mcf, for the period from January 1, 2005 to June 12, 2005, and $6.7 million, or $1.49 per Mcf, and $5.7 million, or $1.25 per Mcf, for the years ended December 31, 2004 and 2003, respectively.

For the period from January 1, 2005 to June 12, 2005, significant field operating expenses included:

•

Production taxes of $0.7 million, or $0.30 per Mcf;

•

Field salary costs of $0.6 million, or $0.29 per Mcf;

Index to Financial Statements

•

Well servicing and workover costs of $0.5 million, or $0.24 per Mcf;

•

Power and fuel costs of $0.4 million, or $0.19 per Mcf;

•

Maintenance and repair costs of $0.3 million, or $0.13 per Mcf;

•

Insurance and bond costs of $0.1 million, or $0.04 per Mcf; and

•

Miscellaneous operating expenses of $0.3 million, or $0.15 per Mcf.

Field operating expenses for the year ended December 31, 2004 were $6.7 million, an increase of $1.0 million, or 18%, over field operating expenses of $5.7 for the year ended December 31, 2003. Production taxes increased by $0.2 million from 2003 to 2004. The production tax rate was consistent for both years, and the increase was due to an increase in gas prices. In 2004, three recompletions were performed that refractured seven more productive zones than in 2003. Power and fuel costs for the year ended December 31, 2004 were $0.8 million, an increase of $0.2 million, or 24%, over power and fuel costs for the year ended December 31, 2003, due to higher energy prices.

General and Administrative Expenses

General and administrative expenses include the costs of our employees, related benefits, field office lease, professional fees and other costs not directly associated with field operations. We monitor general and administrative expenses in relation to the volume of production and the number of wells under operation.

Our general and administrative expenses were $2.7 million, or $1.24 per Mcf, for the six months ended June 30, 2006. Significant general and administrative costs during this period were:

•

Audit fees of $1.0 million, or $0.45 per Mcf;

•

Professional services and consulting fees of $0.7 million, or $0.31 per Mcf;

•

Consulting fees of $0.7 million, or $0.32 per Mcf; and

•

Landman consulting fees of $0.2 million, or $0.09 per Mcf, related to lease acquisition efforts.

Our general and administrative expenses were $3.3 million, or $15.08 per Mcf, for the period of February 7, 2005 (inception) to June 30, 2005. For the period from February 7, 2005 (inception) to June 30, 2005, significant general and administrative costs were:

•

Consulting fees of $3.1 million, or $14.40 per Mcf, to be paid by CCG pursuant to an agreement with The Investment Company for consulting services associated with the acquisition of our properties in the Robinson’s Bend Field; and

•

Professional services of $0.1 million, or $0.07 per Mcf.

Our general and administrative expenses were $4.2 million, or $1.66 per Mcf, for the period February 7, 2005 (inception) to December 31, 2005. For the period from February 7, 2005 (inception) to December 31, 2005, significant general and administrative costs were:

•

Professional service and consulting fees of $3.7 million, or $1.45 per Mcf. $3.1 million, or $1.24 per Mcf, of this balance relates to the agreement with The Investment Company described above; and

•

Fees incurred by CCG on our behalf of $0.4 million, or $0.15 per Mcf, for salaries and benefit costs of CCG employees dedicated to our operations.

Everlast’s general and administrative expenses were $0.6 million for the period from January 1, 2005 to June 12, 2005.

Index to Financial Statements

For the period from January 1, 2005 to June 12, 2005, Everlast’s significant general and administrative costs were:

•

Corporate salaries of $0.3 million, or $0.13 per Mcf; and

•

Professional service and consulting fees of $0.2 million, or $0.09 per Mcf.

General and administrative expenses for the year ended December 31, 2004 were $2.7 million, an increase of $0.8 million, or 50%, over general and administrative expenses of $1.9 million for the year ended December 31, 2003. The increase resulted primarily from an increase in corporate salaries of $1.0 million.

Depreciation, Depletion and Amortization Expense

Depreciation, depletion and amortization expenses include the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated using units-of-production. Assuming everything else remains unchanged, as natural gas production changes, depletion would change in the same direction.

Our depreciation, depletion and amortization expense for the six months ended June 30, 2006 was $3.8 million, or $1.73 per Mcf. This reflects our basis in the assets as of June 2006 of $177.3 million, gross of accumulated depletion. As described above, we calculate depletion using units-of-production under the successful efforts method of accounting.

Our depreciation, depletion and amortization for the period from February 7, 2005 (inception) to June 30, 2005 was $0.3 million, or $1.61 per Mcf.

Our depreciation, depletion and amortization expense for the period from February 7, 2005 (inception) to December 31, 2005, was $4.2 million and reflects the $161.1 million purchase price of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005. The combined effect of a higher basis and lower reserve estimates resulted in higher depreciation, depletion and amortization expense.

Everlast’s depreciation, depletion and amortization expense was $1.7 million for the period from January 1, 2005 to June 12, 2005 and $3.7 million for each of the years ended December 31, 2004 and December 31, 2003. As described above, Everlast calculated depletion based on units-of-production under the full cost method of accounting applied to capital costs of $63.8 million, $59.7 million and $52.7 million as of June 12, 2005, December 31, 2004 and 2003, respectively. Production was constant for 2003, 2004 and the period from January 1, 2005 to June 12, 2005, which is why Everlast’s depletion was relatively consistent for such periods.

Other Income (Expenses)

Our other income (expenses) for the six months ended June 30, 2006 was $0.2 million, or $0.09 per Mcf. Interest income was earned on the cash pool agreement with CCG. As of June 2006, we had a receivable from CCG of $12.2 million. The interest rate as of June 30, 2006 was 5.25%.

During the period from February 7, 2005 (inception) through December 31, 2005, our only debt outstanding was a $0.1 million note payable associated with an equipment lease. Our interest expense on the note payable was approximately $3,000 for this period.

For Everlast, interest expense includes all interest on notes payable, short-term and long-term debt, and accretion of the preferred return on Everlast’s Series A and Series B Preferred Member units. Everlast’s interest expense was $2.4 million for the period from January 1, 2005 to June 12, 2005, $3.0 million for the year ended December 31, 2004 and $1.9 million for the year ended December 31, 2003. For 2003, $1.3 million of the total annual interest expense related to the interest charged on Everlast’s notes payable, short-term debt and long-term debt. At December 31, 2003, the weighted average interest rate on Everlast’s floating rate debt was 3.8% and debt outstanding was $26.0 million. For 2003, the remaining $0.7 million of interest expense related to the accretion of the preferred rate of return of 8% on Everlast’s Series A and Series B Preferred Member units. For

Index to Financial Statements

2004, $2.6 million of the total annual interest expense related to the interest charged on Everlast’s notes payable, short-term and long-term debt. At December 31, 2004, the weighted average interest rate on Everlast’s floating rate debt was 6.1% and debt outstanding was $67.5 million. For 2004, the remaining $0.4 million of total annual interest expense related to the accretion of the preferred rate of return of 8% on Everlast’s Series A and Series B Preferred Member units. The Series A and Series B Preferred Member units were redeemed by Everlast in April 2004. At June 12, 2005, the weighted average interest rate on Everlast’s floating rate debt was 7.3% and debt outstanding was $65.0 million.

Capital Resources and Liquidity

Our primary source of capital for the six months ended June 30, 2006 was our cash flow from operations. Net cash provided by operating activities for the six months was $8.8 million. We expect to continue to generate cash flow sufficient to support our projected maintenance capital expenditures for the remainder of 2006.

Our primary source of capital since February 7, 2005 (inception) has been our cash flow from operations. Net cash provided by operating activities was $23.3 million for the period from February 7, 2005 (inception) to December 31, 2005. Net cash provided by operating activities was $2.9 million for the period from February 7, 2005 (inception) to June 30, 2005. We expect to continue to generate cash flow sufficient to support our projected maintenance capital expenditures. In addition, immediately prior to the closing of this offering, we expect to establish a reserve-based credit facility to allow us to help finance future expansion capital expenses, such as incremental drilling and recompletions, as well acquisitions. Upon completion of the offering and application of the net proceeds therefrom, we expect to have $22.0 million of debt outstanding under the reserve-based credit facility and $88.0 million in unused borrowing capacity.

We expect to fund our 2006 and 2007 maintenance capital expenditures with cash flow from operations, while funding our investment capital expenditures and any expansion capital expenditures that we might incur with borrowings under our reserve-based credit facility. We do not expect to incur expansion capital expenditures through the twelve-month period ending September 30, 2007, although that may change if expansion opportunities are available to us in that period. We also estimate that we will have sufficient cash flow from operations after funding our maintenance capital expenditures to enable us to make our quarterly cash distributions to unitholders through September 30, 2007. CEPM currently holds management incentive interests in us that represent the right to receive 15% of quarterly distributions of available cash from operating surplus after the Target Distribution has been achieved and certain other tests have been met. The earliest that we could be required to make distributions in respect of the management incentive interests is after a period of twelve consecutive quarters following this offering. We are not able to predict whether or when we will be required to make distributions in respect of the management incentive interests or, if we do make such distributions in the future, how much they will be. See “Cash Distribution Policy and Restrictions on Distributions.”

In the event that we acquire additional gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities and, if necessary, new equity issuances. The ratio of debt and equity issued will be determined by our management and our board of managers as deemed appropriate for our unitholders.

Reserve-Based Credit Facility

Prior to or at the closing of this offering, we plan to enter into a $200.0 million secured revolving credit facility with a syndicate of commercial and investment banks, including The Royal Bank of Scotland plc, as administrative agent. We expect that the credit facility will mature on , 2010. The amount available for borrowing at any one time is expected to be limited to the borrowing base, which will be set at $100.0 million at the closing of the credit facility. The borrowing base is expected to be re-determined semi-annually by the lenders in their sole discretion based on reserve reports prepared by reserve engineers, together with, among

Index to Financial Statements

other things, the natural gas and oil prices at such time. We expect that any increase in the borrowing base will have to be approved by all of the lenders in the syndicate and any decrease in the borrowing base will have to be approved by lenders holding 66²/3% of the commitments.

Our obligations under the credit facility are expected to be secured by mortgages on our natural gas properties, as well as a pledge of all ownership interests in our subsidiaries. We expect to be required to maintain the mortgages on properties representing at least 85% of our natural gas properties. Additionally, the obligations under the credit facility are expected to be guaranteed by all of our operating subsidiaries and any future subsidiaries.

Borrowings under the credit facility are expected to be available to us for acquisition, exploration, operation and maintenance of natural gas and oil properties, payment of expenses incurred in connection with the credit facility, working capital and general limited liability company purposes. A sub-limit of $20.0 million of the facility is expected to apply for letters of credit.

At our election, interest is expected to be determined by reference to:

•

the London interbank offered rate, or LIBOR, plus an applicable margin between 1.25% and 2.00% per annum based on utilization; or

•

a domestic bank rate plus an applicable margin between 0.25% and 1.00% per annum based on utilization.

We expect that interest will generally be payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.

The new credit facility is expected to contain various covenants that will limit our ability to:

•

incur indebtedness;

•

grant certain liens;

•

make certain loans, acquisitions, capital expenditures and investments;

•

make distributions other than from available cash;

•

merge or consolidate; or

•

engage in certain asset dispositions, including a sale of all or substantially all of our assets.

We also expect the credit facility to contain covenants that, among other things, require us to maintain specified ratios or conditions as follows:

•

debt to Adjusted EBITDA (defined as, for any period, the sum of consolidated net income for such period plus the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on natural gas derivatives and realized (gain) loss on cancelled natural gas derivatives, and other similar charges) of not more than 3.5 to 1.0; and

•

Adjusted EBITDA to cash interest expense of not less than 4.5 to 1.0; and

•

consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities, of not less than 1.0 to 1.0, all calculated pursuant to the requirements under SFAS No. 133 and 143 (including the current liabilities in respect of the termination of natural gas and interest rate swaps).

Upon completion of this offering, we expect that we will have the ability to borrow under the credit facility to pay distributions to unitholders as long as there has not been a default or event of default and if the amount of borrowings outstanding under our credit facility is less than 90% of the borrowing base.

Index to Financial Statements

If an event of default exists under the credit facility, we expect that the lenders will be able to accelerate the maturity of the credit facility and exercise other customary rights and remedies. Each of the following is expected to be an event of default:

•

failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

•

a representation or warranty made under the loan documents or in any report or other instrument furnished thereunder is incorrect when made;

•

any event occurs that permits or causes the acceleration of the indebtedness;

•

bankruptcy or insolvency events involving us or our subsidiaries;

•

specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any year; and

•

Off-Balance Sheet Arrangements

We have no guarantees or off-balance-sheet debt to third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.

Cash Flow from Operations

Our net cash flow provided by operating activities was $8.8 million for the six months ended June 30, 2006. The major component of our cash flow for that period was net income of $6.8 million.

Net cash provided by operating activities was $23.3 million for the period from February 7, 2005 (inception) to December 31, 2005 and $2.9 million for the period from February 7, 2005 (inception) to June 30, 2005. This cash flow is a result of relatively steady production in a rising natural gas price environment. As discussed above, CCG utilized portfolio hedges to mitigate its natural gas price exposure across its portfolio of gas producing assets. Therefore, we did not hedge the revenue from our production for the period from June 13, 2005 to December 31, 2005. If we had hedged 80% of our production for the period from June 13, 2005 through December 31, 2005, we estimate that our cash provided by operating activities would have been reduced by approximately $6.1 million, resulting in net cash provided by operating activities for that period of $17.2 million. The major component of our cash flow for the period from February 7, 2005 (inception) to December 31, 2005 was $26.0 million of gas sales resulting in net income of $11.9 million. The major adjustments to net income were depletion, depreciation and amortization of $4.2 million, which was driven by our capitalized costs of $169.4 million, and an increase in current liabilities of $8.6 million, of which $3.1 million relates to an agreement with The Investment Company for consulting services associated with the acquisition of our properties in the Robinson’s Bend Field. The remaining $5.5 million increase in current liabilities was primarily the result of higher royalties payable due to higher gas prices and the remaining payable to Everlast related to the acquisition of our properties in the Robinson’s Bend Field.

Net cash provided by operating activities of Everlast for the period from January 1, 2005 to June 12, 2005 was $6.6 million. The major component of Everlast’s cash flow was $12.9 million of gas sales, resulting in a net

Index to Financial Statements

loss of $10.6 million. The loss was primarily due to $15.3 million in losses from mark-to-market activities, which is one of the major adjustments to net income. Another major non-cash adjustment for the period was depletion, depreciation and amortization of $1.7 million, which was driven by Everlast’s capitalized costs of $63.8 million.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas prices. Natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather, and other factors beyond our control. Our future cash flow from operations will depend on our ability to maintain and increase production through our projected production, development and exploitation program and acquisitions, as well as the prices of natural gas and the extent and effectiveness of our planned hedging program.

We enter into hedging arrangements to reduce the impact of natural gas price volatility on our operations. Currently, we use fixed-price swaps to hedge the prices of approximately 78% of our expected production from currently producing wells for October 2006 through December 2009.

By removing the price volatility from a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

The following table summarizes, for the periods indicated, our hedges currently in place through December 31, 2009. Currently, we use fixed-price swaps as our mechanism for hedging commodity prices.

Our derivative positions at June 30, 2006 were:


	For the quarter ended (in MMBtu)
	March 31,			June 30,			Sept 30,			Dec 31,			Total
	MMBtu	$/MMBtu		MMBtu	$/MMBtu		MMBtu	$/MMBtu		MMBtu	$/MMBtu		MMBtu	$/MMBtu
2006	—		—	—		—	—		—	930,000	$	8.83	930,000	$	8.83
2007	924,999	$	9.35	924,999	$	9.35	924,999	$	9.35	924,999	$	9.35	3,699,996	$	9.35
2008	875,001	$	8.91	875,001	$	8.91	875,001	$	8.91	875,001	$	8.91	3,500,004	$	8.91
2009	825,000	$	8.40	825,000	$	8.40	825,000	$	8.40	825,000	$	8.40	3,300,000	$	8.40

													11,430,000

Investing Activities—Acquisitions and Capital Expenditures

Our capital expenditures were $7.5 million for the six months ended June 30, 2006, which primarily relate to drilling, development and exploitation of natural gas properties during that quarter. We paid Everlast $2.4 million, which was the remaining balance of the purchase price for the Robinson’s Bend properties. We drilled 15 gross wells (15 net wells) and completed 17 gross wells (17 net wells) during the six months. In addition, we had $12.2 million of cash flows used in investing activities due to the cash pool with CCG. In February 2006, we entered into a cash pool arrangement with CCG. We administer and manage this cash pool arrangement. CCG may borrow from the pool at market interest rates. If we require cash, and CCG has an outstanding balance, CCG is required to immediately remit payment to us for the required cash amount. We expect that the cash pool arrangement will be terminated prior to the closing of this offering. At the termination of the arrangement, our net receivable balance under the cash pool will be canceled and CCG will retain the funds in respect of that receivable. The cash pool is recorded as an investment due from affiliate. This investment is due on demand.

Our capital expenditures were $147.2 million for the period from February 7, 2005 (inception) to December 31, 2005. This includes $8.3 million for drilling, development and exploitation of natural gas

Index to Financial Statements

properties since we acquired the Robinson’s Bend Field and $139.0 million for the acquisition of the Robinson’s Bend Field from Everlast. The total acquisition price for the Robinson’s Bend properties was $161.1 million. The difference between the $139.0 million and the total purchase price of $161.1 million primarily relates to $18.0 million of mark-to-market derivative liabilities assumed by CCG as part of the acquisition, plus other miscellaneous obligations. During this period, we drilled 9 gross (9 net) wells and completed 12 gross (12 net) wells.

Our capital expenditures were $139.4 million for the period from February 7, 2005 (inception) to June 30, 2005. This includes $0.4 million for drilling, development and exploitation of natural gas properties since we acquired our properties in the Robinson’s Bend Field and $139.0 million for the acquisition of our properties in the Robinson’s Bend Field from Everlast. The total acquisition price for the Robinson’s Bend Field properties was $161.1 million. The difference between the $139.0 million and the total purchase price of $161.1 million primarily relates to $18.0 million of mark-to-market derivative liabilities assumed by CCG as part of the acquisition, plus other miscellaneous obligations. During this period, we drilled no wells and completed 2 gross (2 net) wells.

Everlast’s capital expenditures for the period from January 1, 2005 to June 12, 2005 were $4.2 million. This includes $0.2 million of new lease acquisitions and $4.0 million of drilling, development and exploitation of natural gas properties. During this period, Everlast drilled 9 gross (9 net) wells and completed 6 gross (6 net) wells.

We currently anticipate our capital budget will be $9.2 million for the twelve months ending September 30, 2007, including interest expense of approximately $0.2 million. The capital budget, which predominantly consists of capital for drilling, also includes amounts for infrastructure projects and equipment. The amount and timing of our capital expenditures is largely discretionary and within our control. If natural gas prices decline to levels below acceptable levels, we could choose to defer a portion of these planned capital expenditures until later periods. We routinely monitor and adjust our capital expenditures in response to changes in natural gas prices, drilling and acquisition costs, industry conditions and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs and crews. Based upon current natural gas price expectations for the twelve months ending September 30, 2007, we anticipate that the proceeds of this offering, our cash flow from operations and available borrowing capacity under our reserve-based credit facility will exceed our planned capital expenditures and other cash requirements for the twelve months ending September 30, 2007. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Financing Activities

Our net cash used in financing activities was $11,000 for the six months ended June 30, 2006. This represents a payment of our debt for the quarter.

Net cash provided by financing activities was $138.8 million for the period from February 7, 2005 (inception) to December 31, 2005 and from February 7, 2005 (inception) to June 30, 2005. CCG contributed to us $138.8 million for its limited liability company interest in us.

As of December 31, 2005, we had $0.1 million of borrowings. We assumed this debt from Everlast, and it relates to a note payable issued in conjunction with the purchase of equipment.

Everlast repaid $2.5 million of debt for the period from January 1, 2005 to June 12, 2005. At June 12, 2005, they had $65.0 million of indebtedness outstanding. Everlast had no significant financing activities in 2004 and 2003.

Index to Financial Statements

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the period from February 7, 2005 (inception) through June 30, 2006, or Everlast’s results of operations for the period from January 1, 2005 through June 12, 2005 and the years ended December 31, 2003 and 2004.

Higher natural gas prices have led to industry-wide increases in drilling and oilfield service costs. These increases in drilling and service costs are also driven by shortages of drilling rigs, pipe, equipment and qualified support personnel. Continued increases in costs or shortages of equipment and personnel could negatively impact our drilling programs and increase our operating costs.

Contingencies and Contractual Obligations

As of December 31, 2005, 404 of our wells in the Robinson’s Bend Field were subject to a non-operating net profits interest, or NPI, held by the Trust. Through the NPI, the Trust is entitled to a royalty payment, calculated as a percentage of the net revenue, that is specified revenues reduced by specified associated expenditures, from certain wells in the Robinson’s Bend Field, or the Trust Wells. Under the terms of the NPI and related contractual arrangements, the royalty payment we are required to make to the Trust under the NPI is calculated using a sharing arrangement with a pricing formula that has been below market and has had the effect of keeping the payments to the Trust significantly lower than if such payments had been calculated based on then prevailing market prices. The sharing arrangement may be terminated under specified circumstances that are beyond our control. If we lose the benefit of the sharing arrangement in respect of calculating payments under the NPI, the payments to the Trust will increase and our revenues will decrease in each case compared to the amounts if the sharing arrangement remained in effect. For a further description of the NPI and the related contractual arrangement, as well as the circumstances under which the sharing arrangement may be terminated, please read “Business—Natural Gas Data—Torch Royalty NPI.”

Our contractual obligations as of December 31, 2005 are provided in the following table. These payments are for debt and interest related to a note for support equipment.


	Payments due by period (in thousands)
Contractual Obligations	Total		2006		2007-2008		2009-2010		Thereafter
Notes payable including interest	$	68	$	30	$	38	$	—	$	—

Total	$	68	$	30	$	38	$	—	$	—

Quantitative and Qualitative Disclosure About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas production. Realized pricing is primarily driven by the SONAT Inside FERC Price and the spot market prices applicable to our natural gas production. Pricing for natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control.

Index to Financial Statements

We have entered into hedging arrangements with respect to a portion of our projected natural gas production through various transactions that hedge the future prices received. These transactions were natural gas price swaps whereby we receive a fixed price for our production and pay a variable market price to the contract counterparty. These hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

At the date of our acquisition of our properties in the Robinson’s Bend Field from Everlast on June 13, 2005, we acquired certain fixed price swap liabilities that had approximately $18.0 million in unrealized losses with our counterparty. These derivatives were assigned to CCG. This resulted in a zero balance of the fair value of our derivative positions for 2005.

However, a $1.00 per MMBtu price increase (decrease) in the natural gas prices of our unhedged natural gas production of 2,525 MMcf from June 13, 2005 (the date of the acquisition) through December 31, 2005 would have increased or decreased our cash available for distribution by approximately $2.4 million.

Interest Rate Risk

At December 31, 2005, we had debt outstanding of $63,000, which incurred interest at a fixed rate of 6.12%. We had no variable interest rate debt at that date. At June 30, 2006, we had debt outstanding of $52,000, which incurred interest at a fixed rate of 6.12%. We had no variable interest rate debt at that date.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of our financial statements. Below, we have provided an expanded discussion of our more critical accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of the Consolidated Financial Statements. Please read Note 1 to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Natural Gas Properties

We follow the successful efforts method of accounting for our natural gas exploration, development and production activities. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing natural gas and oil properties is recorded based on units-of-production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed

Index to Financial Statements

reserves. As more fully described in Note 17 to the consolidated financial statements, proved reserves are estimated by our internal reserve engineers, and are subject to future revisions when additional information becomes available.

As described in Note 13 to the consolidated financial statements we follow SFAS No. 143, Accounting for Asset Retirement Obligations. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Geological, geophysical, and dry hole costs on natural gas and oil properties relating to unsuccessful exploratory wells are charged to expense as incurred.

Natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2005, the estimated undiscounted future cash flows for our proved natural gas and oil properties exceeded the net capitalized costs, and no impairment was required to be recognized.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Impairment is deemed to have occurred if a lease is going to expire prior to any planned drilling on the leased property.

Property acquisition costs are capitalized when incurred.

Everlast used the full-cost method of accounting. All costs related to the acquisition, exploration or development of oil and gas properties were capitalized into the “full-cost pool.” Such costs include those related to lease acquisitions, drilling and equipping of productive and nonproductive wells, delay rentals, geological and geophysical work and certain internal costs directly associated with the acquisition, exploration or development of oil and gas properties. Upon the sale or disposition of oil and gas properties, no gain or loss was recognized, unless such adjustments of the full-cost pool would significantly alter the relationship between capitalized costs and proved reserves.

Under the full-cost method of accounting, a “full-cost ceiling test” is required, wherein net capitalized costs of oil and gas properties cannot exceed the present value of estimated future net revenues from proved oil and gas reserves, discounted at 10%, less any related income tax effects.

Costs of acquiring undeveloped gas leases that are capitalized and not subject to amortization are assessed periodically to determine whether impairment has occurred. Appropriate valuation allowances are established when necessary. No such allowance was required during the period from January 1, 2005 to June 12, 2005, and for the years ended December 31, 2004 and 2003.

Depletion, depreciation and amortization of oil and gas properties is computed using the units-of-production method based on estimated proved oil and gas reserves.

Natural Gas Reserve Quantities

Our estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership in the Robinson’s Bend Field based on various factors, including consideration of reserve reports prepared by NSAI, an independent reserve engineer.

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Index to Financial Statements

Reserves and their relation to estimated future net cash flows impacts our depletion calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We prepared our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The accuracy of our reserve estimates was a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Our proved reserve estimates were a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

Net Profits Interest

A significant portion of our properties in the Robinson’s Bend Field is subject to the NPI. The NPI represents an interest in production created from the working interest and is based on a contractual revenue calculation (see Note 14 of the notes to the consolidated financial statements included elsewhere in this prospectus). We account for the NPI as an overriding royalty interest. This is consistent with our accounting for the NPI for reserve estimate purposes. Similar to royalty payments, our revenue excludes any payments made to the NPI holder. Everlast’s financials have been restated to reflect this method of accounting.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas contracts are customary in the industry.

Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no gas imbalance positions as of December 31, 2005, June 12, 2005, December 31, 2004 or December 31, 2003.

Hedging Activities

We implemented a hedging policy to hedge approximately 80% of our expected proved developed production for a period of up to five years, as appropriate. On June 20, 2006, we entered into hedges for the first time since our formation on February 7, 2005. We will account for these hedging activities as cash flow hedges pursuant to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.

We will record changes in the fair value of derivatives designated as hedges that are effective in offsetting the variability in cash flows of forecasted transactions in other comprehensive income until the forecasted transactions occur. At the time the forecasted transactions occur, we will reclassify the amounts recorded in other comprehensive income into earnings. We will record the ineffective portion of changes in the fair value of derivatives used as hedges immediately in earnings. We will summarize hedging activities under SFAS No. 133 and the income statement classification of amounts reclassified from “Accumulated other comprehensive income (loss)” generally as gas sales.

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Accounting Standards Adopted

In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and FASB Statement No. 3. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. This Statement does not change the guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate. The provisions of this Statement are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of this standard did not have a material impact on our financial results. We discuss 2004 and 2003 restatements in Note 2 to the historical financial statements included elsewhere in this prospectus.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) No. 19-1—Accounting for Suspended Well Costs. This staff position amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting. The FSP states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in the FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The adoption of this standard did not have a material impact on our financial results.

On March 30, 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, Accounting for Conditional Asset Retirement Obligations. This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for us at the end of the fiscal year ended December 31, 2005. The adoption of this standard did not have a material impact on our financial results.

Accounting Standards Issued But Not Effective

In April 2006, the FASB issued Staff Position FIN 46R-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R. FSP FIN 46R-6 addresses how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. The variability to be considered should be based on an analysis of the design of the entity and should consider the nature of the entity’s risks and the purpose for which the entity was created. FSP FIN 46R-6 must be applied prospectively to all entities beginning July 1, 2006. We have determined that there was no impact on our financial results as a result of FSP FIN 46R-6.

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BUSINESS

Overview

We are a limited liability company that was formed by Constellation to acquire coalbed methane reserves and production in June 2005. We are focused on the acquisition, development and exploitation of E&P properties, as well as related midstream assets. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions. Currently, our estimated proved reserves are 100% natural gas and are located in the Robinson’s Bend Field in Alabama’s Black Warrior Basin. Our estimated proved reserves at December 31, 2005 were approximately 112.0 Bcf, approximately 80% of which were classified as proved developed producing. Our estimated proved reserves at December 31, 2005 had an estimated Standardized Measure of approximately $295.4 million. Our average proved reserve-to-production ratio is approximately 25 years based on our estimated proved reserves at December 31, 2005 and annualized production for the six months ended December 31, 2005. We currently own a 100% working interest (an approximate 75% average net revenue interest, calculated before the Torch Royalty NPI described below) in our Robinson’s Bend Field producing properties, which had 436 producing natural gas wells as of December 31, 2005.

The Black Warrior Basin is one of the oldest and most prolific coalbed methane basins in the country, with over 2,750 producing coalbed methane wells as of 2002 (the most recent date for which information is available), based on a report by the Department of Energy, Energy Information Administration. These multi-seam vertical wells range from 500 to 3,700 feet deep, with coal seams averaging a total of 25 to 30 feet of net pay per well. Coalbed methane wells are generally more shallow and produce less than conventional natural gas wells, require pumping units to remove the water from the wells, which we refer to as dewatering, and require fracturing to enhance production. These wells also tend to start producing gas and water immediately upon completion, and production increases as the well is dewatered. However, production rates from newly drilled and completed wells in the Robinson’s Bend Field do not always increase as the formation dewaters. Once dewatered, coalbed methane wells often demonstrate fairly constant production rates for up to five years and then start on a decline to a final decline rate of as low as 5% to 6% per year. A typical well produces over a period of 20 to over 50 years and on average have less favorable economic characteristics than conventional gas wells. For a further description of the characteristics of coalbed methane production, please read “—Description of Our Properties and Projects—Characteristics of Coalbed Methane.”

Business Strategies

Make accretive acquisitions of E&P properties characterized by a high percentage of proved producing reserves with long-lived, stable production and step-out development opportunities, which may include associated midstream assets such as gathering systems, compression, dehydrating and treating facilities and other similar facilities. We seek to acquire from third parties and Constellation long–lived properties with a high percentage of proved producing reserves, moderate production decline rates and with reserve development and exploitation potential, such as is found in coalbed methane, shale and tight sands properties, and associated midstream assets, like gathering systems, compression, dehydrating and treating facilities and other similar facilities. Proved producing reserves tend to be the lowest risk category for oil and natural gas production, providing immediate cash flow and more predictable future production. The long–lived, stable production profile of our target properties is well suited to our primary business objective. While we are currently focused on the Black Warrior Basin, we will continue to assess opportunities in other areas in the United States that provide long–lived reserves and may expand into those areas if attractive opportunities become available. Our property base in the Robinson’s Bend Field provides us with opportunities to increase our ownership in the Robinson’s Bend Field.

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Index to Financial Statements

Identify and work with third-party operators who have experience in regions in which we seek to acquire an ownership interest and who will hold an ownership interest in our properties. We plan to target acquisitions of significant working interests in areas in which we can work with third-party operators on our E&P properties that have technical development expertise and experience in the particular oil or natural gas field in which we are acquiring an interest and who will hold a working interest in such properties. By working with experienced operators that also own a working interest in such properties, we expect to have significant influence over the development and operations of our future acquisitions.

Increase reserves and production through what we believe to be low-risk development and exploitation drilling. We plan to balance our acquisition efforts with growth of our proved reserves through development and exploitation activities. As of December 31, 2005, we had identified 364 total potential drilling locations on our acreage in the Robinson’s Bend Field, of which 120 locations were proved undeveloped drilling locations. As of December 31, 2005, we also had identified 133 gross (133 net) existing wells that were candidates for refracture stimulation activities, or refractures, designed to enhance production from those wells. Pursuant to the development and exploitation plan we intend to implement upon completion of this offering, we plan to drill, complete and place on production approximately 20 gross (20 net) development wells and refracture formations on an average of 27 gross (27 net) wells over each of the next six years. We expect to refracture the formation on 7 gross (7 net) wells during the twelve months ending September 30, 2007. Based upon current drilling and completion costs and expected increases in the same, we have budgeted approximately $7.9 million per year for our 20-well annualized drilling program for each of the next six years. In addition, the cost to refracture a formation is approximately $137,500, or an average of about $3.7 million per year over the six-year period.

Reduce the volatility in our revenues resulting from changes in oil and natural gas commodity prices through hedging. On June 20, 2006, we entered into hedging arrangements to reduce the impact of natural gas price volatility on our cash flow from operations. We have hedged the future prices of approximately 78% of our expected production from currently producing wells from October 2006 through December 2009. We currently intend to hedge approximately 80% of our total expected production from our proved developed properties for the next five years. By removing the price volatility from a significant portion of our proved developed natural gas production, we will mitigate, but not eliminate, the potential effects of changing natural gas prices on our cash flow from operations. Please read “Management’s Discussion and Analysis and Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities.”

Competitive Strengths

We believe we are positioned to successfully execute our business strategies because of the following competitive strengths:

•

Our relationship with Constellation. We believe our ability to grow through acquisitions is enhanced by our relationship with Constellation, an integrated energy company that has developed a portfolio of oil and natural gas investments in North America.

•

Operational and Technical Support from Constellation. We believe our relationship with Constellation will provide us with a wide range of operational, commercial, technical, risk management, asset management and other expertise including:

•

a technical evaluation team whose professionals have many years of experience in engineering, geology, recovery methods and production of oil and natural gas;

•

a portfolio management team whose professionals have many years of land, title, marketing and sales, operations and development experience; and

•

a team of professionals with substantial risk management expertise, including commodity price hedging.

•

Low-Risk Development Drilling Operations. During the twelve months ended December 31, 2005, we (and our predecessor, Everlast) drilled and completed 18 gross (18 net) development wells, 100% of

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Index to Financial Statements

which are producing natural gas in commercial quantities. For additional detail, please read “—Natural Gas Data—Development Costs.” Our average well currently takes four days to drill and complete, and we budget an average cost of $400,000 to drill, complete and place on production each well. Most of our wells are producing and are typically connected to a pipeline within approximately 40 days after drilling has commenced. In order to sustain or grow our production in the long term, we will have to acquire or develop other producing E&P properties, which may not have the same production characteristics and will likely increase our costs.

•

Predictable, Long-Lived Reserves. Our properties are located in the Black Warrior Basin in Alabama, a coal seam natural gas basin with a long history of relatively stable production characterized by low to moderate rates of production decline compared to rates generally experienced in conventional production. Our current reserves have an average reserve life of approximately 25 years.

•

Control of Operations. We own at least a 75% working interest in all of our currently undeveloped leasehold acreage, and a 100% working interest in all of our leasehold acreage that is held by production, in the Robinson’s Bend Field. In addition, we own and operate all of the compression, gas gathering, water handling and related facilities for the Robinson’s Bend Field. As a result, we are able to control decisions with respect to the development and operations of our properties in the Robinson’s Bend Field.

•

Large Undeveloped Acreage Base. As of December 31, 2005, we had identified 364 total potential drilling locations on our acreage in the Robinson’s Bend Field, of which 120 locations were proved undeveloped drilling locations. We also had identified 133 gross (133 net) well formation refracture candidates as of December 31, 2005. We drilled, completed and placed on production 25 gross (25 net) development wells and refractured the formation of 2 gross (2 net) well locations during the nine months ended September 30, 2006. During the twelve months ending September 30, 2007, we currently plan to drill, complete and place on production approximately 20 gross (20 net) development wells and to refracture the formations of approximately 7 gross (7 net) existing wells.

Our Relationship With Constellation

We believe that one of our principal strengths is our relationship with Constellation, an integrated energy company with 2005 revenues of approximately $17.1 billion and total assets of approximately $19.2 billion as of June 30, 2006. Constellation’s common stock trades on The New York Stock Exchange under the symbol “CEG.” Constellation is engaged in numerous aspects of the energy industry, including, through CCG, oil and natural gas E&P, natural gas transportation, natural gas storage and physical and financial natural gas trading.

A principal component of our business strategy is to grow our asset base and production through the acquisition of E&P properties characterized by long-lived, stable production. Constellation, through CCG, has a track record of successfully acquiring developed and undeveloped E&P properties. CCG is currently developing several other E&P projects in various locations with unconventional production, including coalbed methane, tight sands and shale. As CCG continues to develop the E&P properties that comprise these projects, and potentially other undeveloped E&P properties that it may acquire in the future, it is possible these projects will have characteristics suitable for us and our business strategies. These characteristics may include a combination of the following:

•

a high percentage of proved developed producing reserves;

•

long-lived, stable production;

•

a significant number of step-out development opportunities; that is, properties where, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves;

•

a significant working interest in the wells;

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•

properties where we can work with third-party operators with experience in the applicable regions and who hold an interest in such properties; and

•

low operating costs.

Constellation views us as an integral component of the growth strategy for its upstream oil and natural gas business and intends to use us as its primary vehicle to develop a portfolio of long-lived, proved producing E&P properties. However, Constellation has no obligation or commitment to do so, and may act in a manner that is beneficial to its interests and detrimental to ours.

We will enter into a management services agreement with CEPM, an indirect wholly owned subsidiary of Constellation. Pursuant to that agreement, CEPM will provide us with legal, accounting, finance and tax services. We also expect that CEPM will provide us with property management, engineering and other services and with assistance in hedging our production, as well as acquisition services in respect of opportunities for us to acquire long-lived, stable and proved oil and natural gas reserves. While we are consolidated with Constellation for accounting purposes, we will be required under the management services agreement to use CEPM or its designee for legal, accounting, finance, tax and risk management services. While neither Constellation nor CEPM has any obligation to provide us with acquisition services under the management services agreement we expect that their ownership of our Class A units, common units and management incentive interests will provide them with an incentive to grow our business, by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash.

While our relationship with Constellation and its subsidiaries is a significant strength, it is also a source of potential conflicts. For example, none of Constellation or any of its affiliates (other than us) is restricted from competing with us and each of our executive officers and our Class A managers also serves as a manager, director, officer or employee of Constellation or its other affiliates. Constellation or its affiliates (other than us) may acquire, invest in or dispose of E&P or other assets in the future without any obligation to offer us the opportunity to purchase or own interests in those assets. The ultimate resolution of the conflicts of interest that exist or arise as a result of either our relationship with Constellation and its other affiliates or the status of our executive officers and our Class A managers as a manager, director, officer or employee of Constellation or its other affiliates may result in the interests of Constellation or its affiliates being favored over your interests and may be to our detriment. Please read “Conflicts of Interest and Fiduciary Duties.”

Description of Our Properties and Projects

We produce gas out of our Robinson’s Bend Field properties in the Black Warrior Basin in Alabama. At December 31, 2005, we operated 436 gross productive wells, which constituted all producing wells in the Robinson’s Bend Field.

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Black Warrior Basin

Characteristics of Coalbed Methane

The rock containing natural gas, referred to as source rock, is usually different from reservoir rock, which is the rock through which the natural gas is produced, while, in coalbed methane, the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional natural gas, but in coalbed methane, most, and frequently all, of the gas is stored by adsorption. This adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of coalbed methane is that the gas flow can be increased by reducing the reservoir pressure. Frequently, the coalbed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. While a conventional natural gas well typically decreases in flow as the reservoir pressure is drawn down, a coalbed methane well will typically increase in production for up to five years depending on well spacing and then start on a decline to a final decline rate of as low as 5% to 6% per year. A typical well produces over a period of 20 to over 50 years. Production rates from newly drilled and completed wells in the Robinson’s Bend Field do not always increase as the formation dewaters.

Coalbed methane and conventional natural gas both have methane as their major component. While conventional natural gas often has more complex hydrocarbon gases, coalbed methane rarely has more than 2% of the more complex hydrocarbons. In the eastern coal fields of the United States, coalbed methane is generally 98% to 99% pure methane and requires only dehydration of the gas to remove moisture to achieve pipeline quality. In the western coal fields of the United States, it is also sometimes necessary to strip out either carbon dioxide or nitrogen. Once coalbed methane has been produced, it is gathered, transported, marketed and priced in the same manner as conventional natural gas.

The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the well bore in a coalbed methane well is determined by the fracture or cleat network in the coal. While, at shallow depths of less than 500 feet, these fractures are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand proppant is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.

Robinson’s Bend Field

The Robinson’s Bend Field was first drilled in the early 1990’s by Torch Energy Corporation and its affiliates to take advantage of certain tax credits. Therefore, most of our wells were drilled before 1992. Robinson’s Bend Field was owned and operated by Torch Energy until January 2003, when it was acquired by Everlast, a company formed by a former Torch Energy executive. We acquired our properties in the Robinson’s Bend Field from Everlast in June 2005.

The Robinson’s Bend Field is located in rural western Tuscaloosa County and Pickens County, Alabama and encompasses a gross surface area of approximately 109 square miles. As of December 31, 2005, the Robinson’s Bend Field operated with approximately 436 natural gas wells. The field has been primarily developed on 80-acre spacing. The State of Alabama has approved field-wide 40-acre spacing. We are currently developing our properties in the field on both 40- and 80-acre spacing.

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The field has nine compressor stations with 800-1,200 horse power compressors, approximately 170 miles of gas gathering lines (wells to header) and 25 miles of transportation lines (header to compressor). In addition, there are 180 miles of water gathering pipes and 28 miles of water transportation pipes.

One of our typical well sites consists of a single gas well and associated gas/water separators connected via subsurface piping. Gas and produced water are discharged from the wellhead to compressor facilities, where over 85% of the gas is routed to a natural gas pipeline operated by Southern Natural Gas Company, or SONAT. A small portion of the natural gas (approximately 15%) is routed to the Enterprise Alabama Intrastate Pipeline from the Maxwell Crossing module. Water produced from these wells is transferred via a facility pipeline to one of three wastewater treatment facilities, where particulates are removed by settling and the water is then discharged into the Black Warrior River in accordance with effluent standards established by the Alabama Department of Environmental Management, or ADEM, and our National Pollutant Discharge Elimination System, or NPDES, permits. In addition, there are three saltwater disposal wells that are not currently in use.

Our subsidiary, Robinson’s Bend Operating II, LLC, has a staff of 24 full-time employees that perform field level operations, maintenance and drilling. These employees are supervised by Ironhorse, our third-party operations supervisor. See “—Operations—General.” Engineering and project management services will continue to be provided by CEPM, pursuant to a management services agreement, with the assistance of third-party contractors and consultants. Drilling is conducted using third-party rigs under the supervision of our field staff. Well completion services and logging services are also conducted using third-party contractors. There is an ongoing drilling program in place with the objective of drilling and completing an average of 20 gross (20 net) development wells per year over the six-year period ending September 30, 2012. Three third-party rig contractors operate nine rigs and drill wells in the Black Warrior Basin. We have not experienced unanticipated delays in scheduling drilling rigs and completion and stimulation services with our contractors since purchasing the Robinson’s Bend Field in June 2005. In the Black Warrior Basin, it typically takes 3 to 4 days to drill the well to the targeted depth using a land-based rig and an additional 3 to 5 days to complete and stimulate the well.

The following development and exploitation techniques are used by us in an effort to increase reserves and production from our existing wells and drill sites: (1) assessing additional production formations in existing wellbores, (2) formation stimulation, (3) artificial lift equipment enhancement, (4) infill drilling on closer well spacing and (5) drilling for deeper formations. During 2005, a total of 18 gross (18 net) wells were drilled and completed. From June 13, 2005 through December 31, 2005, we drilled and completed 9 gross (9 net) of those 18 wells. Those 18 wells developed 6.0 Bcf of natural gas previously categorized as proved undeveloped reserves and added 1.6 Bcf of estimated proved undeveloped reserves and 0.15 Bcf of estimated proved developed reserves. A total of approximately $8.2 million was invested in these and other activities on the properties. From June 13, 2005 through December 31, 2005, the field’s reserve replacement rate, or the ratio of added proved reserves to production, was approximately 69%.

We plan to maximize our production through our development and exploitation activities in the Robinson’s Bend Field and to grow our proved reserve base and production through selective acquisitions of long-lived producing properties. As of December 31, 2005, we had identified 364 total potential gross drilling locations in the Robinson’s Bend Field, of which 120 gross (120 net) were proved undeveloped drilling locations. We had also identified 133 gross (133 net) formation refracture wells. During the nine months ended September 30, 2006 we drilled and completed 25 gross (25 net) development wells and spudded an additional 6 gross (6 net) wells that are in the process of completion. We currently intend to drill and complete an average of 20 gross (20 net) wells during each of the six years ending September 30, 2012 and to refracture the formation on an average of 27 gross (27 net) wells during each year of such six-year period. We expect to refracture the formation on 7 gross (7 net) wells during the twelve months ending September 30, 2007.

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Natural Gas Data

Proved Reserves

The following table reflects our internal estimates of net proved natural gas reserves based on SEC definitions that were used to prepare our financial statements for the periods presented. The estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering. The Standardized Measures shown in the table are not intended to represent the current market values of our estimated natural gas reserves.


	Predecessor						Successor
	Everlast Energy LLC						Constellation Energy Partners LLC
	As of December 31,
Reserve data:	2003			2004			2005
Estimated net proved reserves:
Natural gas (Bcf)		163.7			162.2			112.0
Proved developed reserves (Bcf)		100.7			101.4			89.3
Proved undeveloped reserves (Bcf)		63.0			60.8			22.7
Proved developed reserves as a percent of total reserves		62	%		62	%		80	%
Standardized Measure (in millions) (a)	$	194.2		$	206.8		$	295.4
Natural gas price—SONAT Gas Daily (price per Mmbtu) (b)	$	5.92		$	6.05		$	10.06

(a)

(b)

Natural gas prices as of each period end were based on the SONAT Gas Daily Price, on the last business day of the relevant period.

The data presented in the table above is based on our own internal estimates prepared for the predecessor and successor companies at the corresponding year ends and was used to prepare the financial statements presented elsewhere in this prospectus. Our 2005 estimates of proved reserves are lower than the 2004 and 2003 estimates for Everlast, the predecessor company, because of the decision of our current management to (i) reduce our future drilling program to 20 wells per year over the next six years, (ii) reflect our interpretation of well performance data from new wells drilled in the Robinson’s Bend Field in 2004 and 2005, and (iii) reflect the impact of a revised refracture program. There was no drilling in the Robinson’s Bend Field between 1994 and late 2003. While the performance data from new wells in the Robinson’s Bend Field at December 31, 2005 was limited, we believe it provides relevant current information for the purposes of estimating reserves. The revised 20-well drilling program reflects our current intention of how we plan to develop the properties in the future. Our estimate of reserves at December 31, 2005 is also approximately 5.8 Bcf lower than the December 31, 2004 estimates of proved reserves due to a reduction for estimated reserves attributed to the NPI. No corresponding adjustment was made to the December 31, 2004 estimate of reserves because no amounts were due or paid in respect of the NPI at that time.

Our 2005 proved reserve estimate is 112.0 Bcf. At December 31, 2005, NSAI, an independent petroleum engineering firm, prepared an estimate of our proved reserves. NSAI also prepared an updated report at our request to provide a sensitivity of the estimates of the NSAI December 31, 2005 reserves based on our reduced drilling program, our revised refracture program and the elimination of estimated reserves attributable to the NPI. NSAI’s estimates of our 2005 proved reserves is materially consistent with our internal estimate.

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Our 2004 and 2003 proved reserve estimates are 162.2 Bcf and 163.7 Bcf, respectively. These are our internal estimates of proved reserves that were used in the 2004 and 2003 Everlast financial statements included elsewhere in this prospectus. We prepared the estimates of 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 net proved reserve estimate, which was prepared based upon a continuation of the assumptions used by Everlast, including the prior accelerated drilling program and reserve assumptions, and rolling back the estimate to December 31, 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back approach was necessary because the reserve report prepared by NSAI for Everlast as of December 31, 2004 was not based on the SEC definition of proved reserves, while the reserve report prepared by NSAI for Everlast as of December 31, 2003, which was based on the SEC definition of proved reserves, included different assumptions than those used in NSAI in preparing, December 31, 2005 proved reserves estimate. To prepare reserve estimates for these periods in compliance with the SEC definitions, we adopted the roll back approach described above and in Note 2 and Note 17 to the historical financial statements. Everlast’s previous non-SEC compliant reserve estimates were 173.4 Bcf at December 31, 2004 and 166.2 Bcf at December 31, 2003.

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The data in the above table represents estimates only. Natural gas reserve engineering is an inherently subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering, geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of natural gas that are ultimately recovered. Please read “Risk Factors—Risks Related to Our Business—Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure values shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Market Price Sensitivity

We are exposed to market price changes of natural gas and oil commodities, specifically to NYMEX Henry Hub gas and SONAT Inside FERC Price gas for our existing properties. On June 20, 2006, we executed derivative transactions that hedge the future prices of approximately 78% of our expected production from currently producing wells from October 2006 through December 2009. Prior to this offering, we expect to adopt a hedging policy under which we expect to hedge approximately 80% of our expected production from proved developed reserves for the next five-year period. We believe that we will significantly reduce, but not eliminate, our risk relative to natural gas market price moves by implementing such hedges. For instance, if on a pro forma basis we had hedged 80% of our pro forma 2005 production, we estimate that a $1.00 per MMBtu increase (decrease) in natural gas prices would have increased (decreased) our natural gas sales by approximately $0.9 million.

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Index to Financial Statements

Production and Price History

The following table sets forth information regarding net production of natural gas and certain price and cost information for each of the periods indicated:


	Everlast Energy LLC							Constellation Energy Partners LLC
	For the year ended December 31,				For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005^(a)			For the six months ended June 30, 2006
	2003		2004		For the period from January 1, 2005 to June 12, 2005						For the six months ended June 30, 2006
Net Production:
Total production (MMcf)		4,566		4,527		1,970			2,525			2,200
Average daily production (Mcf/d)		12,500		12,400		12,100			12,500			12,156
Average Sales Prices:
Price per Mcf including economic hedges	$	4.09	$	4.06	$	(1.23	)^(c)	$	10.28	^(b)	$	8.00	^(b)
Price per Mcf excluding economic hedges	$	4.89	$	6.07	$	6.54		$	10.28		$	8.00
Average Unit Costs Per Mcf:
Field operating expenses^(d)	$	1.25	$	1.49	$	1.75		$	2.21		$	2.00
General and administrative expense	$	0.43	$	0.60	$	0.30		$	1.66		$	1.24
Depreciation, depletion and amortization	$	0.81	$	0.82	$	0.85		$	1.65		$	1.73

(a)

Until our acquisition of the Robinson’s Bend Field from Everlast on June 13, 2005, we did not conduct any operations and therefore had no production.

(b)

We had no derivatives as of December 31, 2005. On June 20, 2006, we entered into derivative transactions that hedge the future prices of approximately 78% of our expected production from currently producing wells from October 2006 to December 2009.

(c)

Price per Mcf including economic hedges includes mark-to-market losses of approximately $15 million on derivative transactions that did not qualify for hedge accounting treatment.

(d)

Field operating expenses include lease operating expenses and production taxes.

Torch Royalty NPI

The NPI

The majority of our properties in the Robinson’s Bend Field are subject to the NPI held by the Trust. The NPI is a non-operating net revenue interest upon specified natural gas sales revenues from the Trust Wells reduced by specified associated expenditures. The units of the Trust are listed for trading on The NYSE. An affiliate of Torch Energy Corporation conveyed the NPI to the Trust in November 1993, together with net profits interests on three other properties. The Trust terminates on a specified date, unless terminated earlier in accordance with its terms. In connection with the termination of the Trust, the trustee is required to sell the NPI and distribute the net proceeds from that sale to its unitholders. We acquired our initial properties in the Robinson’s Bend Field from Everlast subject to the NPI. The NPI conveyance gives the Trust an ownership interest in specified properties in the Robinson’s Bend Field.

Not all of our wells within the Robinson’s Bend Field are subject to the NPI. Under the NPI, the Trust is entitled to receive monthly payments. As of December 31, 2005, we owned a working interest in 436 producing wells in the Robinson’s Bend Field, of which 404 were subject to the NPI:

•

with respect to 393 wells, the lesser of (i) 95% of the net proceeds from such wells for the quarter; and (ii) the net proceeds from the sale of 912.5 MMcf of natural gas for the quarter; and

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Index to Financial Statements

•

with respect to the remaining 11 wells that are subject to the NPI as of December 31, 2005, and all wells drilled thereafter on leases subject to the NPI other than wells drilled to replace damaged or destroyed wells, 20% of the net proceeds from such wells for the quarter.

Net proceeds is defined under the NPI as gross revenue from the sale of production attributable to the NPI less specified development, operating and other costs and taxes, in each case as calculated under the Net Overriding Royalty Conveyance. After January 1, 2003, lease operating expenses and capital expenditures have also been deducted in calculating net proceeds under the NPI on the Robinson’s Bend Field production. If permitted deductions exceed the gross revenue from the sale of production attributable to the NPI, the Trust is not entitled to a payment in respect of the NPI, and such excess, plus interest on such excess, is deducted from gross revenue attributable to future production in respect of the NPI. Payment of the net proceeds, if any, attributable to the NPI are made quarterly. Since July 1, 2003, deductible expenses have exceeded gross proceeds attributable to the Trust Wells, and as of December 31, 2005, the cumulative deficit was approximately $69,000. The deficit was eliminated as a result of net proceeds attributable to the Trust Wells in January 2006, and we made a payment to the Trust in respect of the NPI of approximately $0.2 million in the aggregate for January through August 2006.

The Gas Purchase Contract

A gas purchase contract was executed in connection with the formation of the Trust in 1993, which established a minimum price for the purchase of the gas from the Trust Wells as well as a sharing arrangement when the applicable index price for gas increased over a specified sharing price. TEMI, as buyer, and another affiliate of TEMI, as seller, entered into the gas purchase contract pursuant to which the parties were obligated to purchase and sell, as the case may be, all net production attributable to the properties subject to the NPI, including the Trust Wells, for an amount equal to the greater of (a) the minimum price of $1.70 per MMBtu, adjusted for inflation, and (b) 97% of a specified index price for natural gas, less certain specified permitted deductions for gathering, treating and transportation that are calculated monthly. The index price for Robinson’s Bend Field production equals the SONAT Inside FERC Price. In addition, if 97% of the index price exceeds the sharing price specified in the gas purchase contract as adjusted for inflation, which we refer to as the sharing price, the purchase price for the gas is equal to the sharing price plus 50% of the difference between 97% of the index price and the sharing price. As a result, the purchaser is entitled to retain 50% of that difference between 97% of the index price and sharing price. The sharing price was $2.18 and $2.13 per MMBtu in 2005 and 2004, respectively, and is estimated to be approximately $2.22 per MMBtu in 2006. Despite increases in recent years in spot prices for natural gas, the sharing arrangement under the gas purchase contract has had the effect of keeping the payments to the Trust significantly lower than if the NPI were calculated using the prevailing market price for production from the Trust Wells.

In connection with our acquisition of the Robinson’s Bend Field from Everlast, our subsidiary, Robinson’s Bend Marketing II, LLC, assumed TEMI’s obligations under the gas purchase contract and our subsidiary, Robinson’s Bend Production II, LLC, assumed the TEMI affiliate’s obligations under the gas purchase contract, in each case in respect of the Robinson’s Bend Field for production from and after June 13, 2005. As a result, we are obligated to sell and to purchase all production from the Trust Wells on the terms and conditions set forth in the gas purchase contract.

Termination of the Gas Purchase Contract

The gas purchase contract, by its terms, automatically terminates on December 31, 2012 or upon the earlier termination of the Trust. The Trust will terminate upon the first to occur of:

•

an affirmative vote to liquidate the Trust by holders of not less than 66²/3% of the outstanding Trust units; and

•

such time as the ratio of the cash amounts received by the Trust from the NPI to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters.

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Index to Financial Statements

The Trust will also terminate on March 1 of any year if it is determined that the pre-tax future net cash flows, discounted at 10%, attributable to the estimated net proved reserves of the NPI (including the NPI on three other properties) on the preceding December 31 are equal to or less than $25.0 million. The Trust has previously advised its investors that, unless the Henry Hub spot price for natural gas on December 31, 2006 exceeded approximately $6.25 per MMBtu, the Trust would terminate on March 1, 2007. On December 30, 2005 and September 1, 2006, the Henry Hub spot prices for natural gas were $10.08 and $5.815 per MMBtu, respectively. However, on September 1, 2006 the December 2006 futures contract price for natural gas was approximately $9.901 per MMbtu.

If the Trust is terminated, the gas purchase contract will be terminated, and we will no longer be obligated to sell gas produced from the Robinson’s Bend Field pursuant to the gas purchase contract. Notwithstanding the termination of the gas purchase contract, the NPI will continue to burden the Trust Wells, and it should continue to be calculated as if the gas purchase contract were still in effect, regardless of what proceeds may actually be received by us as the seller of the gas. The documents creating the NPI are not clear as to this point, however, and if it is finally determined that the NPI is to be calculated based on the actual proceeds received for sale of the gas or otherwise without regard to the sharing arrangement, our obligations to the Trust for the NPI could be significantly higher, which would adversely affect our revenues, and results of operations and our ability to pay cash distributions.

In order to address, to an extent, the risks of the potential adverse impact on our operating results from the early termination, without the prior consent of our board of managers, of the sharing arrangement in respect of the calculation of amounts payable to the Trust for the NPI, CHI will contribute to us at the closing of this offering $8.0 million for all of our Class D interests. This contribution will be returned to CHI in 24 special quarterly distributions over a period of approximately six years if the sharing arrangement remains in effect during that period. If the amounts payable by us to the Trust are not calculated based on continued applicability of the sharing arrangement through December 31, 2012, unless such change is approved in advance by our board of managers and our conflicts committee, the following will occur: the Class D interests will cease receiving the special quarterly cash distributions; and the Class D interests will only be returned the remaining undistributed amount of the original $8.0 million contribution under certain circumstances upon our liquidation. The effect of our retention and use of the unreturned amount is to provide us with cash that will reduce, but likely not eliminate, the adverse impact of our reduced revenues from the termination of the sharing arrangement. For a further description of this special distribution right, please read “Cash Distribution Policy and Restrictions on Distributions” and “Certain Relationships and Related Party Transactions— Agreements Governing the Transactions—Class D Contribution by CHI.”

Productive Wells

The following table sets forth information at December 31, 2005 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.


	Natural Gas
	December 31, 2005
	Gross	Net
Operated	436	436
Non-operated	—	—

Total	436	436

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Index to Financial Statements

Drilling Activity

The following table sets forth information with respect to wells completed by us or, for the period prior to June 13, 2005, by Everlast during the years ended December 31, 2003, 2004 and 2005 and the nine months ended September 30, 2006, and wells commenced by us during the nine months ended September 30, 2006. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of natural gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled during the years ended December 31, 2003, 2004 or 2005 or the nine months ended September 30, 2006.


	Year Ended December 31,			Nine Months Ended September 30, 2006	Wells in Progress as of September 30, 2006
	2003	2004	2005	Nine Months Ended September 30, 2006	Wells in Progress as of September 30, 2006
Gross:
Development
Productive	1	9	18	25	6
Dry	—	—	—	—	—

Total	1	9	18	25	6
Net:
Development
Productive	1	9	18	25	6
Dry	—	—	—	—	—

Total	1	9	18	25	6

Development Costs

From June 13, 2005 through December 31, 2005, we drilled and completed 9 gross (9 net) of the 18 wells completed during the year ended December 31, 2005. Those 18 wells developed 6.0 Bcf of natural gas previously categorized as proved undeveloped reserves and added 1.6 Bcf of estimated proved undeveloped and 0.15 Bcf of estimated proved developed reserves. We invested a total of $7.9 million in these and other activities on our properties in the Robinson’s Bend Field. Our historical development costs may not be indicative of our future development costs, as developing properties involves a variety of risks, and we are unable to predict the amount or timing of future proved reserve additions or the costs that we may incur in connection with any such reserve additions.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2005 relating to our leasehold acreage. We own a 100% working interest, or an approximate 75% net revenue interest, in all our developed acreage.


	Developed Acreage^(a)		Undeveloped Acreage^(b)
	Gross^(c)	Net^(d)	Gross^(c)	Net^(d)
Total	38,000	38,000	18,500	17,100

(a)

Developed acres are acres spaced or assigned to productive wells/units.

(b)

Undeveloped acres are acres on which wells have not been drilled or acres that have not been pooled with a productive well.

(c)

A gross acre is an acre in which a working interest is either fully or partially leased. The number of gross acres may include minerals not under lease as a result of leasing some but not all joint mineral owners under any given tract.

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Index to Financial Statements

(d)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Leases

We have over 850 leases in the Robinson’s Bend Field. The typical lease agreement covering our properties provides for the payment of royalties to the mineral owner for all natural gas produced from any wells drilled on or pooled with the leased property. There are other burdens on the lease in the form of overriding royalty interests and net profits interests, including the NPI. In the Robinson’s Bend Field and adjoining areas, depending on the location of a particular well, the total lease burden is generally 25% corresponding to a 75% net revenue interest to us. In some instances, our lease net revenue interest may be as high as 83%.

Under our lease agreements, our leases of E&P properties on which there is a productive well extends beyond their stated lease term and will not expire unless and until associated production falls below commercially viable levels. Such leases are said to be “held by production” and do not require us to make rental payments beyond the royalty amount stipulated by each lease. The area held by production from a particular well is typically the applicable spacing unit for such well as specified under state law. Our leases cover approximately 55,000 total project acres with 38,000 (69%) considered to be held by production. The remaining 17,100 (31%) acres related to undeveloped leases that are still within their original lease term and still have the potential for development, if warranted by drilling success in nearby locations. Barring establishment of commercial production, most of these leases will expire between September 2006 and October 2010. Leases covering approximately 7,614 net acres are scheduled to expire before September 30, 2007. Recently, higher potential locations were identified on the project and we petitioned the state to approve an enlargement of the existing field area to include those lands. The State of Alabama approved the request and we have acquired new leases on approximately 700 net acres and expect to acquire an additional 300 acres in this area.

Operations

General

We have entered into a professional services agreement with Ironhorse Energy LP, or Ironhorse, an independent company, to provide us with project management services for the operations of the Robinson’s Bend Field. The owner of Ironhorse is the project manager for our activities in the Robinson’s Bend Field, and he has over 25 years of experience in various producing areas.

Project Management

Ironhorse has responsibility for the overall operations of the field, directing field employees and contractors and executing the drilling program and other production enhancement opportunities. Field operations are conducted by employees of our subsidiary, Robinson’s Bend Operating II, LLC, which employees operate the field under the direct supervision of Ironhorse. All other support services including geology, engineering, land administration and revenue accounting will continue to be provided by CEPM through our management services agreement.

Through the Ironhorse arrangement we operate 100% of our natural gas production in the Robinson’s Bend Field. We approve the design and the development, maintenance, re-completion and workover for all of the wells on the field. Our professional services agreement and management services agreement provide us access to drilling, production and reservoir engineers, geologists and other specialists who will work to improve production rates, increase reserves and lower the cost of operating our properties. The ongoing drilling program is designed by us and implemented by Ironhorse. We do not own drilling rigs or other oil field services equipment used for drilling wells on our properties. Our site construction in the field for new wells is currently conducted by Sartain Contracting Company, and the drilling rigs are provided by and the wells are

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Index to Financial Statements

currently drilled by Pense Brothers Drilling Company, an established Black Warrior Basin drilling contractor. Cementing and completion is currently conducted by Superior Well Services, Schlumberger currently provides well logging services, and Halliburton currently provides the design for and executes upon the well stimulation program.

The administration and operation of the Robinson’s Bend Field may be divided into the following four functions:

Field Operations

Our day-to-day operations are currently conducted by field employees of Robinson’s Bend Operations II, LLC under the supervision of Ironhorse. The field management team has extensive experience in the Black Warrior Basin and has been operating the Robinson’s Bend Field since the early 1990s. This group is responsible for the operation of the existing production wells, pipelines, compressors and water handling facilities, as well as interaction with Alabama regulatory authorities with regard to permitting and compliance matters. In addition, they assist with the execution of the drilling program and the management of the contractors responsible for the drilling and completion of these wells.

Land Administration

Our lease positions will continue to be managed by CEPM under the management services agreement, with assistance from contract landmen. The landmen provide assistance with management of our current lease positions, acquisitions of new leases, permitting for drilling and laying pipelines as well as negotiating agreements with landowners for the use of their property. The land administration function is currently led by a CCG employee who is a landman with over 20 years of experience in various Texas and Gulf Coast producing areas.

Geology and Engineering

In addition to our project management team, we are provided geologic and engineering assistance by CEPM, with access to CCG’s in-house technical team including its contract engineers, geologists and consultants who have experience in drilling and producing coalbed methane reserves. As a result, our project management team has the ability to draw from a base of experienced and capable talent on an as needed basis to select drilling locations and completion approaches to improve productivity and generate and test new ideas to improve production and reserves from existing wells through the use of re-completions, optimizing compression and gathering systems and the like.

Revenue Accounting

Our revenue accounting function has been outsourced to Petroleum Financial, Inc., a Dallas-based revenue accounting firm. It manages the cash flow associated with Robinson’s Bend Field, including the payment of invoices, calculation and payment of royalties, calculation and payment of the NPI, receiving the revenues from gas sales and providing entries that are used to generate financial statements for us.

Marketing and Major Customers

While our production and marketing subsidiaries are successors-in-interest to a gas purchase contract dated October 1, 1993, and originally entered into by and among TEMI, Torch Royalty Company and Velasco Gas Company Ltd as it relates to our production from the Trust Wells, no gas produced by us is sold to unaffiliated third parties under this gas purchase contract. The primary purpose of the portion of the gas purchase contract to which we have succeeded is to provide the calculation of gross proceeds for purposes of determining any royalty amounts we owe in respect of the NPI. Please read “—Natural Gas Data—Torch Royalty NPI.”

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Index to Financial Statements

TEMI is currently providing us with natural gas marketing services in connection with the gas produced from Robinson’s Bend Field, including the Trust Wells, in exchange for a fee of $30,000 per month plus an incentive payment of 50% of any revenue created in excess of the revenue that would have been created if the gas had been sold at the SONAT Inside FERC Price for the relevant period. Under this arrangement, we determine acceptable purchasers, the type of the sales and the credit terms of the purchasers. TEMI does not take title to the gas or receive the sales proceeds. The marketing arrangement terminates on June 30, 2007.

For the six months ended June 30, 2006, five customers accounted for 100% of our total sales volumes, specifically, Interconn Resources Inc., BP Energy Company, Enterprise Alabama, Conoco Phillips and Coral Energy Resources, L.P., accounted for approximately 31%, 27%, 18%, 13% and 11% of our sales. We are paid based on the SONAT Inside FERC Price, which is a liquid trading pricing point that has historically settled at an average premium of $0.02/MMBtu over the NYMEX Henry Hub monthly price for the six months ended June 30, 2006.

Hedging Activity

We expect to enter and have entered into hedging transactions with unaffiliated third parties with respect to natural gas prices to achieve more predictable cash flows and to reduce our exposure to short–term fluctuations in natural gas prices. For a more detailed discussion of our hedging transactions and our expected hedging policy, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk.”

Competition

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. None of Constellation or any of its affiliates is restricted from competing with us. Constellation or its affiliates may acquire, invest in or dispose of E&P or other assets in the future without any obligation to offer us the opportunity to purchase or own interests in those assets.

We are also affected by competition for drilling rigs, completion rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling and completion rigs, equipment, pipe and personnel, which has delayed development drilling and other development and exploitation activities and has caused significant increases in the prices for this equipment and personnel. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program. To date, however, we have not experienced the effects of any such shortages that have affected our operations in the Robinson’s Bend Field. In addition, over the past several years, our field employees have been working with the team of drilling and completion contractors that operate in the Black Warrior Basin and have developed relationships that should enable us to mitigate the risks associated with equipment availability.

Title to Properties

At the time we acquired the Robinson’s Bend Field, we obtained a title opinion or review on the most significant leases in the field. As a result, title opinions or reviews have been obtained on a significant portion of our properties.

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Index to Financial Statements

In some instances and as is customary in the oil and natural gas industry, we conducted only a cursory review of the title to certain properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, however, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry and in case of the Trust Wells, the NPI, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In addition, we believe that we have obtained sufficient rights–of–way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Environmental Matters and Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

•

require the acquisition of various permits before drilling commences;

•

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with natural gas drilling, production and transportation activities;

•

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

•

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws, rules and regulations may also restrict the rate of natural gas production below the rate that would otherwise be possible. The regulatory burden on the natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the natural gas industry could have a significant impact on our operating costs.

Environmental laws and regulations that could have a material impact on the natural gas industry include the following:

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous wastes and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most other wastes associated with the exploration, development, and production of natural gas are currently regulated under RCRA’s non-hazardous waste

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provisions. Certain of our operations are known to bring to the surface naturally occurring radioactive material, or NORM, which is accumulated at our facilities and is subject to permitting and controls for storage, as well as requirements for proper disposal. We believe our operations are in substantial compliance with the radioactive materials license issued by the State of Alabama Department of Public Health to cover activities associated with NORM. Although we do not believe the current costs of managing any of our wastes are material under presently applicable laws, any future reclassification of natural gas exploration and production wastes as hazardous wastes, or more stringent regulation of NORM wastes, could increase our costs to manage and dispose of wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for coalbed methane exploration and production for a number of years. Although we believe operating and waste disposal practices utilized in the past with respect to these properties were typical for the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We maintain permits issued pursuant to the Clean Water Act that authorize the discharge of produced waters and similar wastewaters generated as a result of our operations, in accordance with effluent standards established by the Alabama Department of Environmental Management, also known as ADEM. While we believe we are in substantial compliance with these permits and all other requirements of the Clean Water Act, we have several ponds used for the treatment and storage of wastewaters that were found to have leaked into the subsurface beneath the ponds at sometime in the past. ADEM is aware of these leaks. We are in the process of replacing the liners beneath these treatment ponds and, under the supervision of ADEM, monitoring for the presence of chlorides in the subsurface to better determine what cleanup measures, if any, may be required by the ADEM. Based on present information, we do not believe we will incur material costs or penalties in connection with this matter, but there can be no assurance that significant costs will not be incurred if future data reveals elevated levels of chlorides beneath the ponds.

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Air Emissions

The Clean Air Act, and comparable state laws, regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA and ADEM have developed, and continue to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. We believe our operations are in substantial compliance with federal and state air emission standards. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

OSHA and Other Laws and Regulation

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communications standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Our operations in the Robinson’s Bend Field are subject to the rules and regulations of the State Oil and Gas Board of Alabama Governing Coalbed Methane Gas Operations and these rules and regulations are found in the State Oil and Gas Board of Alabama Administrative Code. We believe we are in substantial compliance with these rules and regulations.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. As of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have a material impact on our financial position or results of operations. However, we cannot predict how future environmental laws and regulations may impact our operations, and therefore cannot provide assurance that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial condition, results of operations or ability to make distributions to our unitholders.

Employees

As of June 30, 2006, our subsidiary, Robinson’s Bend Operations II, LLC, has 24 full-time field employees. The field employees average over nine years of experience operating and working on the Robinson’s Bend Field with six of the employees averaging over 15 years of experience operating this specific field. None of these employees is subject to a collective bargaining agreement or an employment contract.

Under the management services agreement, CEPM will provide or contract for other necessary services including in land, engineering, regulatory, accounting, financial and other disciplines as needed. We will reimburse CEPM for expenses it incurs on our behalf, including employee compensation expenses. Please read

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“Management—Reimbursement of Expenses of CEPM.” We believe that we and our subsidiaries have favorable relationships with our employees.

Offices

We are headquartered in Baltimore, Maryland where we share office space with Constellation. We also share office space with Constellation in Houston, Texas. In addition, we have a field office located in Tuscaloosa, Alabama that houses the field supervisor and the rest of our field employees. Our subsidiary, Robinson’s Bend Production, LLC, owns both the land and office space in Tuscaloosa.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT

Management of Constellation Energy Partners LLC

Our Board of Managers

Upon completion of this offering, our board of managers will consist of five members, three of whom will satisfy the independence requirements of NYSE Arca and SEC rules. Our current board of managers consists of two members, Felix J. Dawson and John R. Collins, who are senior officers of Constellation and not independent. Our current board is expected to appoint an independent manager to serve as the initial member of the audit committee, the compensation committee, the conflicts committee and the nominating and governance committee immediately following the pricing of this offering. Our current board is expected to appoint the remaining two independent managers within 90 days of the pricing of this offering. The current members and the remaining members of the board expected to be appointed following the pricing of this offering will serve until the first annual meeting of the holders of our Class A and common units following this offering and will be subject to re-election annually as described below. The board intends to appoint four functioning committees immediately following the pricing of this offering: an audit committee, a compensation committee, a conflicts committee and a nominating and governance committee.

Audit Committee

We currently contemplate that the audit committee will initially consist of one manager with two additional managers to be appointed within 90 days of the pricing of this offering. All members of the audit committee will be independent under the independence standards established by NYSE Arca and SEC rules, and we expect that the committee will have an “audit committee financial expert,” as defined under the SEC rules. The audit committee will be directly responsible for the appointment, compensation, retention and oversight of the work of the independent public accountants to audit our financial statements, including assessing the independent auditor’s qualifications and independence, and will establish the scope of, and oversee, the annual audit. The committee will also approve any other services provided by public accounting firms. The audit committee will provide assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and our board of managers established. In doing so, it will be the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of our company.

Compensation Committee

We currently contemplate that the compensation committee will consist of up to three managers. All members of the compensation committee will be independent under the independence standards established by NYSE Arca and SEC rules. The compensation committee will establish and review general policies related to our compensation and benefits. The compensation committee will make recommendations to the board of managers with respect to the compensation and benefits of our chief executive officer and our other executive officers. We currently contemplate that we will pay no additional remuneration to employees of Constellation and its affiliates who also serve as our executive officers, provided that this compensation policy could change from time to time.

Conflicts Committee

We currently contemplate that the conflicts committee will consist of up to three managers. The conflicts committee will review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to our company. Our limited liability company agreement will provide that members of the conflicts committee may not be officers or

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employees of our company or directors, officers or employees of any of our affiliates and must meet the independence standards for service on an audit committee of a board of directors as established by NYSE Arca and SEC rules. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to our company and approved by all of our unitholders.

Nominating and Governance Committee

We currently contemplate that the nominating and governance committee will consist of up to three managers. All members of the nominating and governance committee will be independent under the independence standards established by NYSE Arca and SEC rules. This committee will nominate candidates to serve on our board of managers. The nominating and governance committee will also be responsible for monitoring a process to assess manager, board and committee effectiveness, developing and implementing our corporate governance guidelines, setting the remuneration for non-employee managers, committee members and committee chairpersons and otherwise taking a leadership role in shaping the corporate governance of our company.

Election of Our Board of Managers

At our first annual meeting of the holders of our Class A and common units following this offering:

•

CEPM, as the holder of all of our Class A units, will have the right to elect two members of our board of managers; and

•

our common unitholders will have the right to elect the remaining three members of our board of managers.

The board of managers will be subject to re-election on an annual basis in this manner at each annual meeting of the holders of our Class A and common units.

Removal of Members of Our Board of Managers

Any manager elected by the holder of our Class A units may be removed, with or without cause, by 66²/3% of the outstanding Class A units then entitled to vote at an election of managers. Any manager elected by the holders of our common units may be removed, with or without cause, by at least a majority of the outstanding common units then entitled to vote at an election of managers.

Governance Matters

Independence of Board Members

We are committed to having a board of managers that consists of at least a majority of independent managers. Pursuant to NYSE Arca listing standards, a manager will be considered independent if the board determines that he or she does not have a material relationship with us (either directly or as a member, unitholder or officer of an organization that has a material relationship with us).

Heightened Independence for Audit Committee Members

As required by the Sarbanes-Oxley Act of 2002, the SEC has adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Our board of managers expects that all members of its audit committee will satisfy this heightened independence requirement.

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Audit Committee Financial Expert

An audit committee plays an important role in promoting effective corporate governance, and it is imperative that members of an audit committee have requisite financial literacy and expertise. As required by the SEC rules, a public company must disclose whether its audit committee has a member that is an “audit committee financial expert.” An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses all of the following attributes:

•

An understanding of generally accepted accounting principles and financial statements;

•

An ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

•

Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by a company’s financial statements, or experience actively supervising one or more persons engaged in such activities;

•

An understanding of internal controls and procedures for financial reporting; and

•

An understanding of audit committee functions.

Our board of managers expects that our audit committee will have an “audit committee financial expert.”

Executive Sessions of Board

Our board of managers will hold regular executive sessions in which non-management board members meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management managers. During such executive sessions, one manager is designated as the “presiding manager” and is responsible for leading and facilitating such executive sessions.

Compensation Committee Interlocks and Insider Participation

During the year ended December 31, 2005, we had no compensation committee. None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of managers or compensation committee.

Meetings of Board of Managers

Our board will hold regular and special meetings at any time as may be necessary. Regular meetings may be held without notice on dates set by the board from time to time. Special meetings of the board may be called with reasonable notice to each member upon request of the chairman of the board or upon the written request of a majority of the board members. A quorum for a regular or special meeting will exist when a majority of the members are participating in the meeting either in person or by telephone conference. Any action required or permitted to be taken at a board meeting may be taken without a meeting, without prior notice and without a vote, if all of the members sign a written consent authorizing the action.

Our Board of Managers and Executive Officers

The following table shows information for members of our board of managers and our executive officers. Members of our board of managers are elected for one–year terms, and our executive officers will hold office at the discretion of, and may be removed by, our board of managers in its discretion.


Name	Age	Position with Constellation Energy Partners LLC
Felix J. Dawson	38	Chief Executive Officer, President and Manager
John R. Collins	49	Manager
Angela A. Minas	42	Chief Financial Officer, Chief Accounting Officer and Treasurer

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Felix J. Dawson is our Chief Executive Officer, President and a member of our board of managers. He also serves as Co-President and CEO of CCG, a position to which he was appointed in August 2005. Mr. Dawson joined Constellation in April 2001, initially as Managing Director – Co-Head Origination for CCG, and subsequently held positions as Managing Director – Portfolio Management for CCG and Co-Chief Commercial Officer for CCG before obtaining his current position at CCG. Prior to joining Constellation, Mr. Dawson was Vice President – Origination in Goldman Sachs’ Fixed Income Currency and Commodities division and was a key member of the Goldman Sachs team that worked in partnership with Constellation to develop its energy marketing and trading business. Mr. Dawson joined Goldman Sachs in 1997.

John R. Collins is a member of our board of managers. Mr. Collins also serves as Chief Risk Officer and Senior Vice President of Constellation, a position that he has held since December 2001. Mr. Collins serves as a member of Constellation’s Management Committee. Prior to joining Constellation, Mr. Collins was Managing Director – Finance and Treasurer of Constellation Power Source Holdings, Inc. from January 2000 to December 2001. From February 1997 to December 2001, Mr. Collins served as the senior financial officer of CCG. Mr. Collins currently serves as the Chairman of the Board of the Committee of Chief Risk Officers, an energy industry association of risk management professionals.

Angela A. Minas is our Chief Financial Officer, Chief Accounting Officer and Treasurer, a position to which she was appointed in September 2006. Ms. Minas also serves as Managing Director – Portfolio Management of CCG, a position to which she was appointed in August 2006. Prior to joining CCG, Ms. Minas held various positions with Science Applications International Corporation (“SAIC”), including the following: from January 2006 through July 2006, she served as Senior Vice President of Operations for the Commercial Business Services business unit; from January 2004 through December 2005, she served as Senior Vice President of Global Consulting; and from June 2002 through December 2003, she served as Vice President of US Consulting. From September 1997 until June 2002, Ms. Minas served as a partner of Arthur Andersen LLP, additionally serving as partner responsible for North American Oil & Gas Consulting from September 1999 until her departure from Arthur Andersen LLP.

Executive Compensation

We were formed in February 2005 and did not begin operations until our acquisition of the Robinson’s Bend Field from Everlast in June 2005. On May 9, 2006, we replaced our prior officers and board of directors with Mr. Dawson, who, at that time, was our only officer and manager. To date, all of our current officers and managers have been employees of Constellation or its affiliates, and they have received no additional compensation from us. CEPM will manage certain of our operations and activities through its officers and employees pursuant to the management services agreement under the direction of our board of managers and executive officers. We will reimburse CEPM for direct and indirect general and administrative expenses incurred on our behalf, including the compensation of executive officers as our board of managers may determine from time to time. We currently contemplate that we will not reimburse CEPM for the compensation of our executive officers to be paid by CCG for 2006, as set forth in the table below. Please read “—Reimbursement of Expenses of CEPM.”

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The following table sets forth the annual compensation that we expect CCG to pay to our chief executive officer and our chief financial officer and chief accounting officer in 2007 for services related to our business and affairs to be performed upon consummation of this offering. No compensation will be paid in 2006. We have no other officers.


Name and Principal Position	Annual Salary
Felix J. Dawson, Chief Executive Officer and President	$	150,000	⁽¹⁾⁽²⁾
Angela A. Minas, Chief Financial Officer, Chief Accounting Officer and Treasurer	$	150,000	⁽¹⁾⁽²⁾

(1)

Represents the amount that we have agreed to pay for these two officers under the management services agreement and excludes the amount of any bonus to such officers paid by CCG, which bonus amount(s) we will not be required to reimburse CCG.

(2)

Our executive officers may participate in the benefit plans of Constellation and its affiliates.

Employment Agreements

We have no employment agreements for specific terms with our officers or employees or those of our subsidiaries.

Compensation of Managers

Following the completion of this offering, officers or employees of Constellation and its affiliates who also serve as our managers will not receive additional compensation for serving as our managers. Each independent manager will receive an annual retainer of $40,000 and $2,500 per meeting for attending meetings of our board of managers, as well as committee meetings. In addition, each independent manager will be reimbursed for out-of-pocket expenses in connection with attending meetings of our board of managers or committees thereof. Each manager will be indemnified by us for actions associated with being a manager to the full extent permitted under Delaware law.

Reimbursement of Expenses of CEPM

We will reimburse CEPM on a quarterly basis for its costs in providing services to us including all supervisory and management direct and indirect costs and expenses incurred by CEPM, pursuant to the management services agreement. Our limited liability company agreement provides that our board of managers has the right and the duty to review the services provided, and the costs charged, by CEPM under that agreement. These costs and expenses will be deducted from cash available for distribution to our unitholders. These expenses include the cost of employee and officer compensation and benefits allocable to us and all other expenses necessary or appropriate to the performance of CEPM’s obligations under the management services agreement. The limited liability company agreement provides that our board of managers will approve the expenses that are allocable to us. There is no limit on the amount of expenses for which CEPM may be reimbursed. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management Services Agreement.”

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SECURITY OWNERSHIP OF CERTAIN

BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units immediately following the consummation of this offering and the formation transactions, assuming no exercise of the underwriters’ option to purchase additional common units, and held by:

•

each unitholder who then will be a beneficial owner of more than 5% of our outstanding units;

•

each of our managers and named executive officers; and

•

our managers and executive officers as a group.

The amounts and percentage of units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.


Name of Beneficial Owner	Common Units to be Beneficially Owned			Class A Units to be Beneficially Owned			Percentage of Total Units to be Beneficially Owned
Name of Beneficial Owner	Number	Percentage		Number	Percentage		Percentage
Constellation Energy Group, Inc.⁽¹⁾	8,214,010	57	%	295,690	100	%	58	%
Constellation Energy Partners Holdings, LLC⁽²⁾	8,214,010	57	%	295,690	100	%	58	%
Constellation Energy Partners Management, LLC⁽³⁾	—	—		295,690	100	%	2	%
Felix J. Dawson	—	—		—	—		—
John R. Collins	—	—		—	—		—
Angela A. Minas	—	—		—	—		—
All managers and executive officers as a group (3 persons)	—	—		—	—		—

(1)

Constellation Energy Group, Inc., through its direct and indirect ownership of Constellation Enterprises, Inc., Constellation Holdings, Inc. and Constellation Power Source Holdings, Inc., is the ultimate parent company of Constellation Energy Partners Holdings, LLC and Constellation Energy Partners Management, LLC and may, therefore, be deemed to beneficially own the common units held by Constellation Energy Partners Holdings, LLC and the Class A units held by Constellation Energy Partners Management, LLC. The address of Constellation Energy Group, Inc. is 750 East Pratt Street, Baltimore, MD 21202.

(2)

Constellation Energy Partners Holdings, LLC is the parent company of Constellation Energy Partners Management, LLC and may, therefore, be deemed to beneficially own the Class A units held by Constellation Energy Partners Management, LLC. The address of Constellation Energy Partners Holdings, LLC is 111 Market Place, Baltimore, MD 21202.

(3)

The address of Constellation Energy Partners Management, LLC is 111 Market Place, Baltimore, MD 21202.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, assuming no exercise of the underwriters’ option to purchase additional common units:

•

CEPM will own 295,690 Class A units, representing a 2% limited liability company interest in us, and all of the management incentive interests;

•

CEPH will own 8,214,010 common units, representing an approximate 56% limited liability company interest in us; and

•

CHI will own all of our Class D interests.

Distributions and Payments to CCG, CEPH, CEP Equity II LLC, CHI and CEPM

The following table summarizes the distributions and payments to be made by us to CCG, CEPH, CEP Equity II LLC, CHI and CEPM in connection with the formation, ongoing operation and any liquidation of Constellation Energy Partners LLC. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

Consideration received by CEPM and CEPH in our restructuring

• 295,690 Class A units;

• 8,214,010 common units; and

• the management incentive interests.

Consideration received by CEP Equity II LLC in exchange for $475,000

the Floyd Shale Rights.

Consideration received by CHI for the $8.0 million contribution to us

all of our Class D interests.

Consideration received by CCG for cash in excess of $7.8 million

Distribution of all cash in excess of $7.8 million, including the cash pool balance, which was $12.2 million as of June 30, 2006.

Operational Stage

Distributions of available cash to CEPM and CEPH

We will generally make cash distributions 98% to common unitholders, including CEPH, and 2% to CEPM in respect of its Class A units. In addition, if distributions exceed the Target Distribution and certain other requirements are met, CEPM will be entitled in respect of its management incentive interests to 15% of distributions above the Target Distribution. For a discussion of the management incentive interests, please read “How We Make Cash Distributions—Management Incentive Interests.”

Assuming we have sufficient available cash to pay the IQD on all of our outstanding units for four quarters, but no distributions in excess of the full IQD, CEPM would receive an annual distribution of approximately $0.5 million on its Class A units and CEPH would receive an annual distribution of approximately $14.0 million on its common units.

Distributions to CHI

For each full calendar quarter during the period commencing January 1, 2007 and ending on December 31, 2012 that the sharing arrangement in respect of the calculation of amounts payable to the

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Trust for the NPI remains in effect, we will distribute to CHI, in respect of its Class D interests, $333,333, as a partial return of the $8.0 million capital contribution made for the Class D interests, which payment will be made concurrently with the quarterly cash distribution to our common and Class A unitholders for that quarter. Unless the special distribution right has been terminated earlier, the Class D interests will be cancelled upon the payment of the final distribution of $333,341 to CHI for the quarter ending December 31, 2012. If the amounts payable by us to the Trust are not calculated based on the sharing arrangement through December 31, 2012, unless such change is approved in advance by our board of managers and our conflicts committee, the special distribution right for future quarters will terminate. In the case of such early termination, CHI will only have the right under specific circumstances upon our liquidation to receive the unpaid portion of the $8.0 million capital contribution that has not then been distributed to CHI in such special distributions. If the special distribution right is terminated during a quarter, the special distribution in respect of the Class D interests will be pro rated for that quarter based upon the ratio of the number of days in such quarter prior to the effective date of such termination to 90.

Payments to CEPM

Pursuant to our management services agreement with CEPM, if CEPM provides us acquisition services with respect to a particular opportunity, we will be obligated to reimburse CEPM for the costs it incurs in providing such acquisition services to us. In addition, subject to the arrangements relating to acquisition services described above, CEPM will be entitled to be reimbursed on a quarterly basis for all supervisory and management costs incurred by it in performing services for us.

Conversion of Class A units and management incentive interests

Generally, if the common unitholders vote to eliminate the special voting rights of the holder of our Class A units, the Class A units will be converted into common units on a one for one basis and CEPM will have the right to elect to convert its management incentive interests into common units at fair market value.

Please read “The Limited Liability Company Agreement—Election of Members of Our Board of Managers—Elimination of Special Voting Rights of Class A Units.” Should CEPM’s Class A units and its management incentive interests convert into common units, CEPM will receive cash distributions on its common units as described above in “—Distributions and Payments to CCG, CEPH, CEP Equity II LLC, CHI and CEPM.”

Liquidation Stage

Liquidation

Upon our liquidation, the unitholders, including CEPH, as a common unitholder, CEPM, as the holder of the Class A units and CHI, as the holder of our Class D interests that are then outstanding, will be entitled to receive liquidating distributions according to their respective capital account balances. Please read “How We Make Cash Distributions—Distributions of Cash Upon Liquidation.”

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Index to Financial Statements

Agreements Governing the Transactions

We and other Constellation affiliates have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the contribution of $8.0 million to us by CHI and the conveyance by us to CEP Equity II, LLC of the Floyd Shale Rights. These agreements, including the management services agreement described below, will not be the result of arm’s–length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

Class D Contribution by CHI

In order to address the risks of early termination, without the prior consent of our board of managers, of the sharing arrangement in respect of the calculation of amounts payable to the Trust for the NPI, and the potential reduction in our revenues resulting therefrom, at the closing of this offering CHI will contribute $8.0 million to us for all of our Class D interests. For each full calendar quarter during the period commencing January 1, 2007 and ending on December 31, 2012 that the sharing arrangement remains in effect, we will distribute to the holder of the Class D interests $333,333, as a partial return of the $8.0 million capital contribution made for the Class D interests, which payment will be made concurrently with the quarterly cash distribution to our unitholders for that quarter. The Class D interests will be cancelled upon the payment of the final distribution of $333,341 to CHI for the quarter ending December 31, 2012, unless the special distribution right has been terminated earlier. If the amounts payable by us to the Trust are not calculated based on the sharing arrangement through December 31, 2012, unless such change is approved in advance by our board of managers and our conflicts committee, the special distribution right for future quarters will terminate and the remaining portion of the $8.0 million original contribution not so returned in special cash distributions will be retained by us to partially offset the reduction in our revenues resulting from termination of the sharing arrangement in respect of the Trust. In the case of such termination of the special distribution right, CHI will have the right only under specific circumstances upon our liquidation to receive the unpaid portion of the $8.0 million capital contribution that has not then been distributed to CHI in such special distributions. If the distribution right is terminated during a quarter, the special distribution to the holder of the Class D interests will be pro rated for that quarter based upon the ratio of the number of days in such quarter prior to the effective date of such termination to 90.

Based upon our estimated production for the twelve months ending September 30, 2007 and the weighted average net realized sales price for our production used in calculating our Estimated Adjusted EBITDA for that twelve-month period under the caption “Cash Distribution Policy and Restrictions on Distributions,” we estimate that, if the sharing arrangement in respect of the Trust was terminated as of October 1, 2006, our revenue would be reduced by approximately $5.6 million during such twelve-month period and the $8.0 million contributed to us for the Class D interests would offset such a shortfall for approximately 1.4 years, if the production and prices set forth under “Cash Distribution Policy and Restrictions on Distributions—Our Estimated Cash Available to Pay Distributions” were to remain constant throughout such period.

Distribution of Floyd Shale Rights

In connection with this offering, we will distribute to an affiliate of Constellation, CEP Equity II, LLC, an undivided mineral interest in our properties in the Robinson’s Bend Field for depths below 100 feet below the base of the lowest producing coal seam. We refer to this mineral interest as the Floyd Shale Rights. The Floyd Shale Rights are not material to our business and no value has been assigned to them in our historical financial statements included elsewhere in this prospectus. The Floyd Shale Rights do not fit our investment strategy, given the uncertainty of encountering commercial quantities of oil and natural gas. We will receive $475,000 in return for this distribution of the Floyd Shale Rights.

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Omnibus Agreement

Upon the closing of this offering, we will enter into the omnibus agreement with CCG. Under the omnibus agreement, CCG will indemnify us after the closing of this offering against certain liabilities relating to:

•

for a period of six years and 30 days after the closing of this offering, any of our income tax liabilities, or any income tax liability attributable to our operation of our properties, in each case relating to periods prior to the closing of this offering;

•

legal actions pending against Constellation or us at the time of the closing of this offering;

•

events and conditions associated with the ownership by Constellation or its affiliates of the Floyd Shale Rights after the closing of this offering; and

•

for a period of one year after the closing, any miscalculation in the amount payable to the Trust in respect of the NPI for any period prior to the closing of this offering, provided (i) that such miscalculation relates to amount(s) payable no more than four years prior to the closing of this offering and (ii) the aggregate amount payable by CCG pursuant to this bullet point does not exceed $500,000.

Management Services Agreement

Upon the closing of this offering, we will enter into a management services agreement with CEPM that will govern our relationship with them regarding the following matters:

•

CEPM’s provision to us of certain supervisory and management services, including financial, acquisition and hedging and other risk management services;

•

reimbursement of supervisory and management costs incurred by CEPM in performing services for us.

Financial, Acquisition and Other Services

While we are consolidated with Constellation for accounting purposes, we will be required under the management services agreement to use CEPM or its designee for legal, accounting, audit, tax, financial and risk management services. No other aspect of the management services agreement will be exclusive. Upon our request, CEPM will also provide us with engineering, geological, geophysical, property management and project management services.

CEPM may provide us with acquisition services upon our request, but is not obligated to do so. As a result, CEPM will have no commitment to offer us any particular E&P property, whether from CEPM or its other affiliates or a third-party. In connection with the acquisition services, we may acquire E&P properties with long-lived proved reserves in any of the following types of transactions:

•

drop-downs, or acquisitions directly by us from CCG or its affiliates of properties previously acquired or developed by CCG or its affiliates;

•

joint transactions in which CCG or its affiliates contemporaneously acquires from unaffiliated third parties E&P properties that do not fit our risk profile; and

•

purchases made by us from unaffiliated third parties.

If CEPM provides us acquisition services with respect to a particular opportunity, we will be obligated to reimburse CEPM for the costs it incurs in providing those acquisition services to us.

Competition

None of CEPM, Constellation, CCG or any of their affiliates will be restricted under the management services agreement from competing with us. CEPM, Constellation, CCG and any of their affiliates may acquire

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or dispose of any assets, including, among other things, E&P properties, in the future without any obligation to offer us the opportunity to purchase those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Reimbursement of Costs

Subject to the arrangements relating to acquisition services described above, CEPM will be entitled to be reimbursed on a quarterly basis for all supervisory and management costs incurred by it in performing services for us. These costs and expenses will be deducted from cash available for distribution to our unitholders.

Review by Our Board of Managers

Except with respect to exclusive arrangements under the management services agreement during the period in which we are consolidated with Constellation for accounting purposes, our board of managers will have the right to evaluate CEPM’s performance thereunder and, if considered desirable by our board of managers, arrange for third parties to provide some or all of the services to be provided pursuant to the management services agreement.

Standard of Care

In exercising its powers and discharging its duties under the management services agreement, CEPM will be required to act honestly and in good faith, and is to exercise that degree of care, diligence and skill that a reasonably prudent advisor and manager would exercise in comparable circumstances.

Indemnification

The management services agreement provides that, except arising out of our gross negligence, willful misconduct or a breach of the agreement, CEPM must indemnify us for any damages, liabilities, costs and expenses (including reasonable attorneys’ fees) arising from the rendering of CEPM’s services under the management services agreement. We will indemnify CEPM for damages, liabilities, costs and expenses (including reasonable attorneys’ fees) arising from our gross negligence, willful misconduct or breach of this agreement.

Term and Termination

The management services agreement will be in effect for continuous one-year terms, with the initial term ending on December 31, 2007. The management services agreement may be terminated by us or CEPM at any time and for any reason upon six months advance notice to the other party; provided that we may not terminate the management services agreement while we are consolidated with Constellation for accounting purposes.

Amendments

The management services agreement may not be amended without the prior approval of the conflicts committee of our board of managers if the proposed amendment will, in the reasonable discretion of our board of managers, adversely affect holders of our common units.

Trademark License

Constellation will grant a limited license to us for the use of certain trademarks in connection with our business. The license will terminate upon the elimination of the right of the holder or holders of our Class A Units to elect the Class A Managers pursuant to our limited liability company agreement. Constellation will indemnify us from any third-party claims alleging trademark infringement that may arise out of our use of the Constellation trademarks under the license.

Gas Purchase Contract

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Index to Financial Statements

Company Ltd as it relates to our production from the Trust Wells, no gas produced by us is sold to unaffiliated third parties under this gas purchase contract. The primary purpose of the portion of the gas purchase contract to which we have succeeded is to provide the calculation of gross proceeds for purposes of determining any royalty amounts we owe in respect of the NPI. Please read “Business—Natural Gas Data—Torch Royalty NPI.”

Cash Pool Arrangement

In February 2006, we entered into a cash pool arrangement with CCG. This cash pool arrangement is administered and managed by us. CCG may borrow from the pool at market interest rates. If we require cash, and CCG has an outstanding balance, CCG is required to immediately remit payment to us for the required cash amount. We expect that our participation in the cash pool arrangement will be terminated prior to the closing of this offering. Upon the termination of the arrangement, our net receivable balance under the cash pool arrangement will be canceled and CCG will retain the funds in respect of that receivable.

Transactions with Executive Officers, Managers and Principal Unitholders

Please read “Summary—Constellation Energy Partners LLC—The Transactions and Limited Liability Company Structure” for a description of transactions between us and our principal unitholders.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interests

Affiliates of Constellation own all of our Class A units, 8,214,010 common units, our management incentive interests and our Class D interests. In addition, upon the consummation of this offering, we will enter into a management services agreement with CEPM, a subsidiary of Constellation, and following this offering we will be dependent on CEPM for the management of our operations. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management Services Agreement.” Conflicts of interest exist and may arise in the future as a result of the relationships between us and our unaffiliated unitholders and our board of managers and executive officers and Constellation and its affiliates, including CEPM and CEPH. These potential conflicts may relate to the divergent interests of these parties.

Whenever a conflict arises between Constellation and its affiliates, on the one hand, and us or any other unitholder, on the other hand, our board of managers will resolve that conflict. Our limited liability company agreement limits the remedies available to unitholders in the event a unitholder has a claim relating to conflicts of interest.

No breach of obligation will occur under our limited liability company agreement in respect of any conflict of interest if the resolution of the conflict is:

•

approved by the conflicts committee of our board of managers, although our board of managers is not obligated to seek such approval;

•

approved by the vote of a majority of the outstanding units, excluding any common or Class A units owned by CEPM, CEPH or any of their affiliates although our board of managers is not obligated to seek such approval;

•

on terms no less favorable to us than those generally provided to or available from unaffiliated third parties; or

•

fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

We anticipate that our board of managers will submit for review and approval by our conflicts committee any acquisitions of properties or other assets that we propose to acquire from Constellation or any of its affiliates.

If our board of managers does not seek approval from the conflicts committee of our board of managers and our board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of managers, including board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any member or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our limited liability company agreement, our board of managers or its conflicts committee may consider any factors in good faith when resolving a conflict. When our limited liability company agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in our best interests, unless the context otherwise requires.

Conflicts of interest could arise in the situations described below, among others.

Constellation and its affiliates may compete with us.

None of Constellation or any of its affiliates is restricted from competing with us. Constellation and its affiliates may acquire, invest in or dispose of E&P or other assets, including those that might be in direct competition with us.

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Neither Constellation nor its affiliates have any obligation to offer us the opportunity to purchase or own interests in any assets.

We intend to rely on CEPM to provide us with opportunities for the acquisition of oil and natural gas reserves, however, neither Constellation nor its affiliates has any obligation to offer us the opportunity to purchase or own interests in any assets.

Affiliates of Constellation not only have the exclusive right to elect two members of our board of managers but also can assert great influence in the election of the other three members of our board of managers.

CEPM, as the holder of our Class A units will have the exclusive right to elect two members of our board of managers, and CEPH, as the holder of a majority of our common units, will be able to assert great influence in any vote of common unitholders, including the election of the three members of our board of managers that are elected by the common unitholders. In turn, our board of managers shall have the power to appoint our officers. Situations in which the interests of our management and Constellation and its affiliates may differ from interests of our unaffiliated unitholders include the following situations:

•

our limited liability company agreement gives our board of managers broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;

•

our management team determines the timing and extend of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional membership interests and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders;

•

our board of managers may cause us to borrow funds in order to permit us to pay cash distributions to our unitholders, even if the purpose or effect of the borrowing is to make management incentive distributions; and

•

our board of managers is allowed to take into account the interest of parties other than us, such as Constellation and its affiliates, in resolving conflicts of interest, which has the effect of limiting the fiduciary duty to our unaffiliated unitholders.

Our executive officers and our Class A managers also serve as managers, directors, officers or employees of Constellation or its other affiliates as a result of which conflicts of interest exist and will arise in the future.

Our executive officers and our Class A managers are also managers, directors, officers or employees of Constellation or its affiliates (other than us). While acting in such person’s capacity as a manager, director, officer or employee of Constellation or such affiliates, as opposed to such person’s capacity as our executive officer or Class A manager, such person will not owe any fiduciary duty to us or our security holders. In addition, in making decisions in such person’s capacity as a manager, director, officer or employee of Constellation or such affiliate, such person may make a decision that favors the interests of Constellation or such affiliate over your interests and may be to our detriment, notwithstanding that in making decisions in such person’s capacity as our officer or manager such person is required to act in good faith and in accordance with the standards set forth in our limited liability company agreement. If in resolving a conflict of interest any of our executive officers and our Class A managers satisfies the applicable standards set forth in our limited liability company agreement for resolving a conflict of interest, you will not be able to assert that such resolution constituted a breach of fiduciary duty owed to us or to you by such executive officer or Class A manager.

We may compete for the time and effort of our managers and officers who are also managers, directors and officers of Constellation and its affiliates.

Constellation and its affiliates conduct business and activities of their own in which we have no economic interest. Certain of our managers and officers are employees of Constellation and serve as managers, directors

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Index to Financial Statements

and officers of Constellation and its affiliates. Our managers and officers are not required to work full time on our business and affairs and may devote significant time to the affairs of Constellation and its affiliates. There could be material competition for the time and effort of our managers and officers who provide services to Constellation and its affiliates.

Unitholders will have no right to enforce obligations of Constellation and its affiliates under agreements with us.

Any agreements, including the management services agreement, between us, on the one hand, and Constellation and its affiliates, on the other hand, will not grant to our unitholders any right to enforce the obligations of Constellation and its affiliates in our favor.

Contracts between us, on the one hand, and Constellation and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Neither our limited liability company agreement nor any of the other contracts or arrangements, including our management services agreement, between us and Constellation and its affiliates are or will be the result of arm’s-length negotiations.

Fiduciary Duties

Our limited liability company agreement provides that our business and affairs shall be managed under the direction of our board of managers, which shall have the power to appoint our officers. Our limited liability company agreement further provides that the authority and function of our board of managers and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the Delaware General Corporation Law, or DGCL. Finally, our limited liability company agreement provides that the fiduciary duties and obligations owed to us and to our members by our board of managers and officers is generally to act in good faith in the performance of their duties on our behalf. Our limited liability company agreement permits affiliates of our managers to invest or engage in other businesses or activities that compete with us. In addition, if our conflicts committee approves a transaction involving potential conflicts, or if a transaction is on terms generally available from unaffiliated third parties or an action is taken that is fair and reasonable to the company, unitholders will not be able to assert that such approval constituted a breach of fiduciary duties owed to them by our managers and officers.

We are unlike publicly traded partnerships whose business and affairs are managed by a general partner with fiduciary duties to the partnership. While CEPM will provide legal, accounting, finance, tax, property management, engineering and other services to us, pursuant to the management services agreement, subject to the oversight of our board of managers, we have no general partner with fiduciary duties to us. CEPM’s duties to us are contractual in nature and arise solely under the management services agreement. As a consequence, none of Constellation, CEPM, CEPH, CCG or their affiliates will owe to us a fiduciary duty similar to that owed by a general partner to its limited partners.

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Index to Financial Statements

DESCRIPTION OF THE COMMON UNITS

The Common Units

The common units represent limited liability company interests in us. The holders of common units are entitled to participate in distributions and exercise the rights or privileges provided under our limited liability company agreement. For a description of the relative rights and preferences of holders of common units in and to distributions, please read this section and “How We Make Cash Distributions.” For a description of the rights and privileges of holders of common units under our limited liability company agreement, including voting rights, please read “The Limited Liability Company Agreement.”

Transfer Agent and Registrar

Computershare will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following fees that will be paid by holders of common units:

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

•

special charges for services requested by a holder of a common unit; and

•

other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, managers, officers and employees against all claims and losses that may arise out of acts performed or omitted in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, we are authorized to act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our limited liability company agreement, each transferee of common units shall be admitted as a unitholder of our company with respect to the common units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of common units:

•

becomes the record holder of the common units;

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our limited liability company agreement;

•

represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;

•

grants powers of attorney to our officers and any liquidator of our company as specified in the limited liability company agreement; and

•

makes the consents and waivers contained in our limited liability company agreement.

A transferee will become a unitholder of our company for the transferred common units upon the recording of the name of the transferee on our books and records.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE LIMITED LIABILITY COMPANY AGREEMENT

The following is a summary of the material provisions of our limited liability company agreement. The form of the limited liability company agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of the form of this agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

•

with regard to distributions of available cash on our Class A units, common units, management incentive interests and Class D interests, please read “How We Make Cash Distributions.”

•

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units;”

•

with regard to the election of members of our board of managers, please read “Management—Management of Constellation Energy Partners LLC—Our Board of Managers;” and

•

with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization

Our company was formed in February 2005 and will remain in existence until dissolved in accordance with our limited liability company agreement.

Purpose

Under our limited liability company agreement, we are permitted to engage, directly or indirectly, in any activity that our board of managers approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that our board of managers shall not cause us to engage, directly or indirectly, in any business activities that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our board of managers has the ability to cause us and our operating subsidiaries to engage in activities other than the acquisition, development and exploitation, of oil and natural gas properties and related midstream assets, our board of managers has no current plans to do so. Our board of managers is authorized in general to perform all acts it deems to be necessary or appropriate to carry out our purposes and to conduct our business.

Fiduciary Duties

For a description of fiduciary duties, please read “Conflicts of Interest and Fiduciary Duties.”

Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

By purchasing a common unit in us, you will be admitted as a member of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Pursuant to this agreement, each holder of common units and each person who acquires a common unit from a holder of common units grants to our board of managers (and, if appointed, a liquidator) a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our board of managers the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement.

Capital Contributions

Unitholders (including holders of common units) are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

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Index to Financial Statements

Limited Liability

Unlawful Distributions

The Delaware Limited Liability Company Act (the “Delaware Act”) provides that any unitholder who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the company for the amount of the distribution for three years. Under the Delaware Act, a limited liability company may not make a distribution to any unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the Delaware Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business

Our subsidiaries will initially conduct business only in the State of Alabama. We may decide to conduct business in other states, and maintenance of limited liability for us, as a member of our operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that our board of managers considers reasonable and necessary or appropriate to preserve the limited liability of our unitholders.

Voting Rights

Holders of our common units and our Class A units, have voting rights on most matters. Upon the consummation of this offering, CEPM will own all of our Class A units and CEPH will own 8,214,010 of our common units. The following matters require the unitholder vote specified below:

Election of members of the board of managers

Following our initial public offering, our board of managers will consist of five members, as required by our limited liability company agreement. Except as set forth below, at the first annual meeting of our unitholders following this offering, Class A unitholders, voting as a single class, will elect two managers and their successors, and the holders of our common units, voting together as a single class, will elect the remaining three managers and their successors. Please read “—Election of Members of Our Board of Managers,” “—Removal of Members of Our Board of Managers” and “—Elimination of Special Voting Rights of Class A Units.”

Issuance of additional securities including common units

No approval right.

Amendment of the limited liability company agreement

Certain amendments may be made by our board of managers without unitholder approval. Other amendments generally require the

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Index to Financial Statements

approval of both a common unit majority and Class A unit majority. Please read “—Amendment of Our Limited Liability Company Agreement.”

Merger of our company or the sale of all or substantially all of our assets

Common unit majority and Class A unit majority. Please read “—Merger, Sale or Other Disposition of Assets.”

Dissolution of our company

Common unit majority and Class A unit majority. Please read “—Termination and Dissolution.”

Matters requiring the approval of a “common unit majority” require the approval of at least a majority of the outstanding common units voting together as a single class. In addition, matters requiring the approval of a “Class A unit majority” require the approval of at least a majority of the outstanding Class A units voting together as a single class.

Issuance of Additional Securities

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and authorizes us to buy securities for the consideration and on the terms and conditions determined by our board of managers without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units, Class A units and management incentive interests in our distributions of available cash. Also, the issuance of additional common units or other equity securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of managers, may have special voting or other rights to which the units are not entitled.

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

Election of Members of Our Board of Managers

At our first annual meeting of the holders of our Class A units and our common unitholders following this offering:

•

two members of our board of managers will be elected by CEPM, as the holder of all of our Class A units; and

•

three members of our board of managers will be elected by our common unitholders.

The board of managers will be subject to re-election on an annual basis in this manner at our annual meeting of the holders of our Class A units and our common unitholders.

Removal of Members of Our Board of Managers

Any manager elected by the holder of our Class A units may be removed, with or without cause, by the holders of 66²/3% of the outstanding Class A units then entitled to vote at an election of managers. Any manager

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elected by the holders of our common units may be removed, with or without cause, by the holders of at least a majority of the outstanding common units then entitled to vote at an election of managers.

Increase in the Size of Our Board of Managers

The size of our board of managers may increase only with the approval of the holders of 66²/3% outstanding Class A units. If the size of our board of managers is so increased, the vacancy created thereby shall be filled by a person appointed by our board of managers or a nominee approved by a majority vote of our common unitholders, unless such vacancy is specified by an amendment to our limited liability company agreement as a vacancy to be filled by our Class A unitholders, in which case such vacancy shall be filled by a person approved by our Class A unitholders.

Elimination of Special Voting Rights of Class A Units

The holders of our Class A units have the right, voting as a separate class, to elect two of the five members of our board of managers and any replacement of either of such members, subject to the matters described under “—Election of Members of Our Board of Managers—Increase in the Size of Our Board of Managers” above. This right can be eliminated only upon a proposal submitted by or with the consent of our board of managers and the vote of the holders of not less than 66²/3% of our outstanding common units. If such elimination is so approved and Constellation and its affiliates do not vote their common units in favor of such elimination, the Class A units will be converted into common units on a one-for-one basis and CEPM will have the right to convert its management incentive interests into common units based on the then-fair market value of such interests.

Amendment of Our Limited Liability Company Agreement

General

Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of managers. To adopt a proposed amendment, other than the amendments discussed below, our board of managers is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our unitholders to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a common unit majority and a Class A unit majority.

Prohibited Amendments

No amendment may be made that would:

•

enlarge the obligations of any unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected;

•

provide that we are not dissolved upon an election to dissolve our company by our board of managers that is approved by a common unit majority and a Class A unit majority;

•

change the term of existence of our company;

•

give any person the right to dissolve our company other than our board of managers’ right to dissolve our company with the approval of a common unit majority and a Class A unit majority; or

•

enlarge the size of our board of managers without the approval of the holder of our Class A units.

The provision of our limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding common units, voting together as a single class, and 75% of the outstanding Class A units, voting together as a single class.

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No Unitholder Approval

Our board of managers may generally make amendments to our limited liability company agreement without unitholder approval to reflect:

•

a change in our name, the location of our principal place of our business, our registered agent or our registered office;

•

the admission, substitution, withdrawal or removal of members in accordance with our limited liability company agreement;

•

a change that our board of managers determines to be necessary or appropriate for us to qualify or continue our qualification as a company in which our members have limited liability under the laws of any state or to ensure that neither we, our operating subsidiaries nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•

the merger of our company or any of its subsidiaries into, or the conveyance of all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity;

•

an amendment that is necessary, in the opinion of our counsel, to prevent us, members of our board, or our officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

•

an amendment that our board of managers determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;

•

any amendment expressly permitted in our limited liability company agreement to be made by our board of managers acting alone;

•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our limited liability company agreement;

•

any amendment that our board of managers determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our limited liability company agreement;

•

a change in our fiscal year or taxable year and related changes;

•

a merger, conversion or conveyance effected in accordance with the limited liability company agreement; and

•

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our board of managers may make amendments to our limited liability company agreement without unitholder approval if our board of managers determines that those amendments:

•

do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) in any material respect;

•

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

•

are necessary or appropriate to facilitate the trading of common units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the common units are or will

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be listed for trading, compliance with any of which our board of managers deems to be in the best interests of us and our common unitholders;

•

are necessary or appropriate for any action taken by our board of managers relating to splits or combinations of units under the provisions of our limited liability company agreement; or

•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

Opinion of Counsel and Unitholder Approval

Our board of managers will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the common units and Class A units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder of our company.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

Our board of managers is generally prohibited, without the prior approval of a common unit majority and a Class A unit majority from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries, provided that our board of managers may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our board of managers may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in the limited liability company agreement are satisfied, our board of managers may merge our company or any of its subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. Additionally, the Company may convert into any “other entity” as defined in the Delaware Limited Liability Company Act, whether such entity is formed under the laws of the State of Delaware or any other state in the United States of America. Our unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a company until terminated under our limited liability company agreement. We will dissolve upon: (1) the election of our board of managers to dissolve us, if approved by a common unit majority and a Class A unit majority; (2) the sale, exchange or other disposition of all or substantially all of the assets and properties of our company and our subsidiaries; or (3) the entry of a decree of judicial dissolution of our company.

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Liquidation and Distribution of Proceeds

Upon our dissolution, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of managers that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “How We Make Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to unitholders in kind if it determines that a sale would be impractical or would cause undue loss to our unitholders.

Anti-Takeover Provisions

Our limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of our company without the approval of our board of managers. Specifically, our limited liability company agreement provides that we will elect to have Section 203 of the DGCL apply to transactions in which an interested common unitholder (as described below) seeks to enter into a merger or business combination with us. Under this provision, such a holder will not be permitted to enter into a merger or business combination with us unless:

•

prior to such time, our board of managers approved either the business combination or the transaction that resulted in the common unitholder’s becoming an interested common unitholder;

•

upon consummation of the transaction that resulted in the common unitholder becoming an interested common unitholder, the interested common unitholder owned at least 85% of our outstanding common units at the time the transaction commenced, excluding for purposes of determining the number of common units outstanding those common units owned:

•

by persons who are managers and also officers; and

•

by employee common unit plans in which employee participants do not have the right to determine confidentially whether common units held subject to the plan will be tendered in a tender or exchange offer; or

•

at or subsequent to such time the business combination is approved by our board of managers and authorized at an annual or special meeting of our common unitholders, and not by written consent, by the affirmative vote of the holders of at least 66²/3% of our outstanding voting common units that are not owned by the interested common unitholder.

Section 203 defines “business combination” to include:

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any merger or consolidation involving the company and the interested common unitholder;

•

any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested common unitholder;

•

subject to certain exceptions, any transaction that results in the issuance or transfer by the company of any common units of the company to the interested common unitholder;

•

any transaction involving the company that has the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested common unitholder; or

•

the receipt by the interested common unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, by reference to Section 203, an “interested common unitholder” is any person or entity, other than Constellation, CEPM, their affiliates or transferees, that beneficially owns (or within three years did own) 15% or more of the outstanding common units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

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The existence of this provision would be expected to have an anti-takeover effect with respect to transactions not approved in advance by our board of managers, including discouraging attempts that might result in a premium over the market price for common units held by common unitholders.

Our limited liability agreement also restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Constellation, CEPM, their affiliates or transferees and persons who acquire such units with the prior approval of the board of managers, cannot vote on any matter.

Limited Call Right

If at any time any person owns more than 80% of the then-issued and outstanding common units, it will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons as of a record date to be selected by our board of managers, on at least 10 days but not more than 60 days notice. The common unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

•

the highest cash price paid by such person for any common units purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase the remaining common units; and

•

the closing market price of the common units as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of common units may have his limited liability company interests purchased at an undesirable time or price. Please read “Risk Factors—Risks Related to Our Structure.” The tax consequences to a common unitholder of the exercise of this call right are the same as a sale by that common unitholder of his common units in the market. Please read “Material Tax Consequences—Disposition of Units.”

Meetings; Voting

All notices of meetings of unitholders shall be sent or otherwise given in accordance with Sections 11.4 and 14.1 of our limited liability company agreement not less than 10 days nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of managers, at the time of giving the notice, intends to present for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which managers are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the board of managers intends to present for election. Any previously scheduled meeting of the unitholders may be postponed, and any special meeting of the unitholders may be cancelled, by resolution of the board of managers upon public notice given prior to the date previously scheduled for such meeting of unitholders.

Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a member, shall be voted at the written direction of the record holder by a proxy designated by our board of managers. Absent direction of this kind, the units will not be voted, except that units held by us on behalf of non-citizen assignees shall be voted in the same ratios as the votes of unitholders on other units are cast.

Any action required or permitted to be taken by our unitholders must be effected at a duly called annual or special meeting of unitholders and may not be effected by any consent in writing by such unitholders.

Meetings of the unitholders may only be called by a majority of our board of managers. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units for which a

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Index to Financial Statements

meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional units having special voting rights could be issued. Please read “—Issuance of Additional Securities.” Units held in nominee or street name accounts will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our limited liability company agreement will be delivered to the record holder by us or by the transfer agent.

Non-Citizen Assignees; Redemption

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of managers, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, we may redeem, upon 30 days’ advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, our board of managers may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our board of managers determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our limited liability company agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by law from and against all losses, claims, damages or similar events any person who is or was our manager or officer, or while serving as our manager or officer, is or was serving as a tax matters member or, at our request, as a manager, officer, tax matters member, employee, partner, fiduciary or trustee of us or any of our subsidiaries. Additionally, we shall indemnify to the fullest extent permitted by law and authorized by our board of managers, from and against all losses, claims, damages or similar events any person is or was an employee or agent (other than an officer) of our company.

Any indemnification under our limited liability company agreement will only be out of our assets. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our limited liability company agreement.

Books and Reports

We are required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

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We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of unitholders can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right To Inspect Our Books and Records

Our limited liability company agreement provides that a unitholder can, for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

•

a current list of the name and last known address of each unitholder;

•

a copy of our tax returns;

•

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each unitholder and the date on which each became a unitholder;

•

copies of our limited liability company agreement, the certificate of formation of the company, related amendments and powers of attorney under which they have been executed;

•

information regarding the status of our business and financial condition; and

•

any other information regarding our affairs as is just and reasonable.

Our board of managers may, and intends to, keep confidential from our unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of managers believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third-party to keep confidential.

Registration Rights

We have agreed to register for sale under the Securities Act and applicable state securities laws any common units or other of our securities held by CEPM, CEPH or any of their affiliates if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any termination of the special voting rights of the holders of our Class A units. We have also agreed to include any of our securities held by CEPM, CEPH or their affiliates in any registration statement that we file to offer our securities for cash, except an offering relating solely to an employee benefit plan, for the same period. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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Index to Financial Statements

UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, and assuming that the underwriters’ option to purchase additional common units is not exercised, CEPH will hold an aggregate of 8,214,010 common units and CEPM will hold all of our 295,690 Class A units and management incentive interests that upon certain circumstances may convert into common units. Please read “The Limited Liability Company Agreement—Election of Members of Our Board of Managers—Elimination of Special Voting Rights of Class A Units.” The sale of these common units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three–month period, the greater of:

•

1% of the total number of the securities outstanding; and

•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our limited liability company agreement does not restrict our ability to issue equity securities without unitholder approval at any time. Any issuance of additional units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, units then outstanding. Please read “The Limited Liability Company Agreement—Issuance of Additional Securities.”

Under our limited liability company agreement, CEPM, CEPH and their affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our limited liability company agreement, these registration rights allows CEPM, CEPH or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. CEPM will continue to have these registration rights for two years following any termination of the special voting rights of the Class A units. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, managers and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, CEPM or CEPH may sell their units in private transactions at any time, subject to compliance with applicable laws.

We, our officers and managers, and CEPH and CEPM and their affiliates, have agreed not to sell any units for a period of 180 days after the date of this prospectus, subject to certain exceptions. Please read “Underwriting” for a description of these lock–up provisions.

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Index to Financial Statements

MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax consequences that may be relevant to prospective common unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Constellation Energy Partners LLC and our limited liability company operating subsidiaries.

This section does not address all federal income tax matters that affect us or common unitholders. Furthermore, this section focuses on common unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other common unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective holder of common units to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of our units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective common unitholders. Instead, we will rely on opinions and advice of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our units and the prices at which our units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our common unitholders and thus will be borne directly by our common unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Andrews Kurth LLP.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues:

•

the treatment of a common unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”);

•

whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”);

•

whether percentage depletion will be available to a common unitholder or the extent of the percentage depletion deduction available to any common unitholder (please read “—Tax Treatment of Operations—Depletion Deductions”);

•

whether the deduction related to United States production activities will be available to a common unitholder or the extent of such deduction to any holder of common units (please read “—Tax Treatment of Operations—Deduction for United States Production Activities”); and

•

whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

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Partnership Status

Except as discussed in the following paragraph, a limited liability company that has more than one member and that has not elected to be treated as a corporation is treated as a partnership for federal income tax purposes and, therefore, is not a taxable entity and incurs no federal income tax liability. Instead, each partner is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current gross income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP. Andrews Kurth LLP is of the opinion, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us, for federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us. The representations made by us upon which Andrews Kurth LLP has relied include:

•

Neither we, nor any of our limited liability company subsidiaries, have elected nor will we elect to be treated as a corporation; and

•

For each taxable year, more than 90% of our gross income will be income that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to common unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to common unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to common unitholders, and our net income would be taxed to us

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Index to Financial Statements

at corporate rates. In addition, any distribution made to a common unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the common unitholder’s tax basis in his units, or taxable capital gain, after the common unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a common unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Common Unitholder Status

Common unitholders who become members of Constellation Energy Partners LLC will be treated as partners of Constellation Energy Partners LLC for federal income tax purposes. Also, common unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as partners of Constellation Energy Partners LLC for federal income tax purposes.

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Items of our income, gain, loss, or deduction are not reportable by a common unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a common unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These common unitholders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.

The references to “common unitholders” in the discussion that follows are to persons who are treated as partners in Constellation Energy Partners LLC for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each common unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a common unitholder even if he has not received a cash distribution. Each common unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a common unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a common unitholder in an amount in excess of his tax basis in his units generally will be considered to be

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gain from the sale or exchange of those units, taxable in accordance with the rules described under “—Disposition of Units” below. To the extent that cash distributions made by us cause a common unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

Any reduction in a common unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that common unitholder. A decrease in a common unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a common unitholder, regardless of his tax basis in his units, if the distribution reduces the common unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the common unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the common unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of our common units in this offering who holds those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2009, will be allocated on a cumulative basis an amount of federal taxable income for that period that will be approximately 20% of the cash distributed to the common unitholder with respect to that period. We anticipate that thereafter, the ratio of taxable income allocable to cash distributions to the common unitholders will increase. These estimates are based upon assumptions with respect to gross income, capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the units.

Basis of Units

A common unitholder’s initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A common unitholder’s share of our nonrecourse liabilities will generally be based on his share of our profits. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a common unitholder of his share of our losses will be limited to his tax basis in his units and, in the case of an individual common unitholder or a corporate common unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt

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organizations, to the amount for which the common unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A common unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a common unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a common unitholder will be at risk to the extent of his tax basis in his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the common unitholder or can look only to the units for repayment. A common unitholder’s at-risk amount will increase or decrease as the tax basis of the common unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a common unitholder’s at risk amount will decrease by the amount of the common unitholder’s depletion deductions and will increase to the extent of the amount by which the common unitholder’s percentage depletion deductions with respect to our property exceed the common unitholder’s share of the basis of that property.

The at risk limitation applies on an activity-by-activity basis, and in the case of oil and natural gas properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer’s oil and natural gas properties. It is uncertain how this rule is implemented in the case of multiple oil and natural gas properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a common unitholder’s at risk limitation with respect to us. If a common unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his units as a whole.

The passive loss limitation generally provides that individuals, estates, trusts and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitation is applied separately with respect to each publicly traded partnership. Consequently, any losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments, a common unitholder’s investments in other publicly traded partnerships, or a common unitholder’s salary or active business income. If we dispose of all or only a part of our interest in an oil and gas property, common unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Notwithstanding whether a natural gas and oil property is a separate activity, passive losses that are not deductible because they exceed a common unitholder’s share of income we generate may only be deducted by the common unitholder in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after certain other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.

A common unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

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Limitation on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

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interest on indebtedness properly allocable to property held for investment;

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our interest expense attributable to portfolio income; and

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a common unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its common unitholders. In addition, the common unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any common unitholder or any former common unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the common unitholder on whose behalf the payment was made. If the payment is made on behalf of a common unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current common unitholders. We are authorized to amend our limited liability company agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our limited liability company agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a common unitholder in which event the common unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the common unitholders in accordance with their percentage interests in us. If we have a net loss for an entire year, the loss will be allocated to our common unitholders according to their percentage interests in us to the extent of their positive capital account balances.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as “Contributed Property.” These allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations to a common unitholder who purchases units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional units or engage in certain other transactions in the future, Section 704(c) allocations will be made to all holders of partnership interests, including purchasers of units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to

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the common unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other common unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a common unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a common unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

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his relative contributions to us;

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the interests of all the common unitholders in profits and losses;

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the interest of all the common unitholders in cash flow; and

•

the rights of all the common unitholders to distributions of capital upon liquidation.

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election,” “—Uniformity of Units” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our limited liability company agreement will be given effect for federal income tax purposes in determining a common unitholder’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A common unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for tax purposes with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

•

none of our income, gain, loss or deduction with respect to those units would be reportable by the common unitholder;

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any cash distributions received by the common unitholder with respect to those units would be fully taxable; and

•

all of these distributions would appear to be ordinary income.

Andrews Kurth LLP has not rendered an opinion regarding the treatment of a common unitholder whose units are loaned to a short seller. Therefore, common unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Units—Recognition of Gain or Loss.”

Alternative Minimum Tax

Each common unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective common unitholders are urged to consult their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

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Tax Rates

In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other common unitholders. Please also read, however, “—Allocation of Income, Gain, Loss and Deduction” above. For purposes of this discussion, a common unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our limited liability company agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read “—Uniformity of Units.”

Although Andrews Kurth LLP is unable to opine on the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent a Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some common unitholders. Please read “—Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or

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if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each common unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a common unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Depletion Deductions

Subject to the limitations on deductibility of losses discussed above, common unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and natural gas interests. Although the Internal Revenue Code requires each common unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our common unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to common unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance. A common unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the common unitholder’s daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder’s total taxable income from all sources for the year, computed without the

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depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the common unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Common unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the common unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our oil and natural gas interests or the disposition by the common unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury regulations relating to the availability and calculation of depletion deductions by the common unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the common unitholders for any taxable year. We encourage each prospective common unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs

We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each common unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a common unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to oil and natural gas wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a common unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of oil and natural gas products exceeding $5 million per year in the aggregate.

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IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a common unitholder of interests in us. Recapture is generally determined at the common unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See “—Disposition of Units—Recognition of Gain or Loss.”

Deduction for United States Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, common unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such common unitholder. The percentages are 3% for qualified production activities income generated in the year 2006; 6% for the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each common unitholder will aggregate his share of the qualified production activities income allocated to him from us with the common unitholder’s qualified production activities income from other sources. Each common unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the common unitholder’s share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a common unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages paid by the common unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each common unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the common unitholder’s allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our common unitholders.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 Wages, or how such items are allocated by us to common unitholders. Further, because the Section 199 deduction is required to be computed separately by each common unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the common unitholders. Each prospective common unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs

The cost of acquiring oil and natural gas leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and

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abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “Tax Treatment of Operations—Depletion Deductions.”

Geophysical Costs

Geophysical costs paid or incurred in connection with the exploration for, or development of, oil or gas within the U.S. are allowed as a deduction ratably over the 24-month period beginning on the date that such expense was paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses which are reasonable in amount.

Tax Basis, Depreciation and Amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our existing common unitholders, and (ii) any other offering will be borne by our common unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a common unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by common unitholders might change, and common unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the common unitholder’s amount realized and the common unitholder’s tax basis for the units sold. A common unitholder’s amount

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realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a common unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the common unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a common unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. A portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a common unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury regulations under Section 1223 of the Internal Revenue Code allow a selling common unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A common unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A common unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;

•

an offsetting notional principal contract; or

•

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the common unitholders in proportion to the number of units owned by

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Index to Financial Statements

each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the common unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a common unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury regulations. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between common unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the common unitholder’s interest, our taxable income or losses might be reallocated among the common unitholders. We are authorized to revise our method of allocation between common unitholders, as well as among common unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury regulations.

A common unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A common unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties.

Constructive Termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all common unitholders. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and common unitholders receiving two Schedule K-1s) for one calendar year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

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Index to Financial Statements

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code. This method is consistent with the Treasury regulations applicable to property depreciable under the accelerated cost recovery system or the modified accelerated cost recovery system, which we expect will apply to substantially all, if not all, of our depreciable property. We also intend to use this method with respect to property that we own, if any, depreciable under Section 167 of the Internal Revenue Code, even though that position may be inconsistent with Treasury regulation Section 1.167(c)-1(a)(6). We do not expect Section 167 to apply to a material portion, if any, of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized book-tax disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If we adopt this position, it may result in lower annual deductions than would otherwise be allowable to some common unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. We will not adopt this position if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the common unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the common unitholders. Our counsel, Andrews Kurth LLP, is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a common unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or “mutual fund,” is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a “qualified publicly traded partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign common unitholders. Each foreign common unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

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In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate common unitholder is a “qualified resident.” In addition, this type of common unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling issued by the IRS, a foreign common unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a United States trade or business of the foreign common unitholder. Apart from the ruling, a foreign common unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each common unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each common unitholder’s share of income, gain, loss and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective common unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each common unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a common unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The limited liability company agreement appoints CEPM as our Tax Matters Partner, subject to redetermination by our board of managers from time to time.

The Tax Matters Partner will make some elections on our behalf and on behalf of common unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against common unitholders for items in our returns. The Tax Matters Partner may bind a common unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that common unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the common unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any common unitholder having at least a 1% interest in profits or by any group of common unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each common unitholder with an interest in the outcome may participate.

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A common unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a holder of common units to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;

•

a statement regarding whether the beneficial owner is:

•

a person that is not a United States person,

•

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

•

a tax-exempt entity;

•

the amount and description of units held, acquired or transferred for the beneficial owner; and

•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, “substantial authority,” or

•

as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

We believe we will not be classified as a tax shelter. If any item of income, gain, loss or deduction included in the distributive shares of common unitholders could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for common unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a “tax shelter.”

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the

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valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “—Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-related Penalties,”

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business and own property in Maryland and Alabama. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective common unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder’s income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each common unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Andrews Kurth LLP has not rendered an opinion on the state local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective common unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each common unitholder to file all tax returns, that may be required of him.

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INVESTMENT IN OUR COMPANY BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit–sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, the person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should consider:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

•

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after–tax investment return.

A plan fiduciary should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibits employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that CEPM also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

•

the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

•

the entity is an “operating company,”––i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or

•

there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by CEPM, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first bullet above.

Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Citigroup Global Markets Inc. and Lehman Brothers Inc. are acting as joint bookrunning managers of this offering, and are acting as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each of the underwriters named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.


Underwriters		Number of Common Units
Citigroup Global Markets Inc.
Lehman Brothers Inc.
UBS Securities LLC
Wachovia Capital Markets, LLC
Scotia Capital (USA) Inc.

Total		6,275,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the option to purchase additional common units described below) if they purchase any of the common units.

The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of the prospectus and some of the common units to dealers at the public offering price less a concession not to exceed $ per common unit. If all of the common units are not sold at the initial offering price, the representative may change the public offering price and the other selling terms. The representative has advised us that the underwriters do not intend sales to discretionary accounts to exceed 5% of the total number of our common units offered by them.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 941,250 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.

We, our officers and managers and CEPH and CEPM have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc. and Lehman Brothers Inc., dispose of or hedge or make any demand for or exercise any right to file or cause to be filed a registration statement with respect to the registration of any of our common units or any securities convertible into or exchangeable for our common units.

Citigroup Global Markets Inc. and Lehman Brothers Inc., in their discretion, may release any of the securities subject to these lock-up agreements at any time without notice. Factors in deciding whether to release these units may include the length of time before the particular lock-up expires, the number of common units involved, historical trading volumes of our common units and whether the person seeking the release is our officer, manager or affiliate.

The 180-day restricted period described in the preceding paragraph will be extended if:

•

during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or

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Index to Financial Statements

•

prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or event.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units will be determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price will be our record of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the prices at which our common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.


	No Exercise	Full Exercise
Per common unit
Total

In connection with the offering, the underwriters may purchase and sell common units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of common units to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of common units made in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units. In determining the source of common units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the option to purchase additional common units. Transactions to close out the covered syndicate short involve either purchases of the common units in the open market after the distribution has been completed or the exercise of the option to purchase additional common units. The underwriters may also make “naked” short sales of common units in excess of their option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of common units in the open market while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when an underwriter repurchases common units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

Any of these activities may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE Arca or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

We have applied to list our common units on NYSE Arca under the symbol “CEP.”

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In addition, we will pay Citigroup Global Markets Inc. and Lehman Brothers Inc. a structuring fee equal to % of the gross proceeds of this offering for evaluation, analysis and structuring of our company.

The expenses of the offering that are payable by us are estimated to be approximately $3.2 million (exclusive of underwriting discounts and the structuring fee). The underwriters have agreed to reimburse us for a portion of these expenses in an amount of up to 0.25% of the gross proceeds of this offering (including any exercise of the underwriters’ option to purchase additional common units).

In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed 10% of the gross proceeds (plus 0.5% for bona fide, accountable due diligence expenses).

The underwriters may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. Affiliates of each of Citigroup Global Markets, Inc., Lehman Brothers Inc., UBS Securities LLC, Wachovia Capital Markets, LLC and Scotia Capital (USA) Inc. are lenders under Constellation’s credit facility. Additionally, affiliates of each of UBS Securities LLC, Wachovia Capital Markets, LLC and Scotia Capital (USA) Inc. are expected to be lenders under our new reserve-based credit facility.

A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. The representative will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as an underwriter and should not be relied upon by investors.

We and CCG have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, including liabilities incurred in connection with the directed unit program referred to above, and to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because the National Association of Securities Dealers, Inc. views the common units offered by this prospectus as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

If you purchase any units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

VALIDITY OF THE UNITS

The validity of the common units will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the common units offered by us will be passed upon for the underwriters by Vinson & Elkins L.L.P., New York, New York.

EXPERTS

The financial statements of Constellation Energy Partners LLC as of December 31, 2005 and for the period February 7, 2005 (inception) through December 31, 2005 and of Everlast Energy LLC as of December 31, 2004 and for the period January 1, 2005 through June 12, 2005 and for each of the two years in the periods ended December 31, 2004 appearing in this Prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of such firm as experts in auditing and accounting.

170

Index to Financial Statements

Certain information included in this prospectus regarding our estimated quantities of natural gas reserves was prepared by Netherland, Sewell & Associates, Inc.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S–l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1–800–SEC–0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

171

Index to Financial Statements

INDEX TO FINANCIAL STATEMENTS


		PAGE
Constellation Energy Partners LLC and Subsidiaries and Everlast Energy LLC and Subsidiaries:
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Statements of Operations and Comprehensive Income (Loss)		F-3
Consolidated Balance Sheets		F-4
Consolidated Statements of Cash Flows		F-5
Consolidated Statements of Changes in Members’ Equity		F-6
Notes to Consolidated Financial Statements		F-7

Constellation Energy Partners LLC:
Unaudited Consolidated Pro Forma Financial Statements		F-33
Notes to Unaudited Consolidated Pro Forma Financial Statements		F-37

F-1

Index to Financial Statements

REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of Constellation Energy Partners LLC:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations and comprehensive income (loss), cash flows, and changes in member’s equity present fairly, in all material respects, the financial position of Constellation Energy Partners LLC (formerly Constellation Energy Resources LLC and CBM Equity IV Holdings, LLC) and its subsidiaries (CEP) (Successor Company) at December 31, 2005 and the results of their operations and their cash flows for the period from February 7, 2005 (inception) to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of CEP’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Baltimore, Maryland

June 12, 2006

To the Member of Constellation Energy Partners LLC:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations and comprehensive income (loss), cash flows, and changes in members’ equity present fairly, in all material respects, the financial position of Everlast Energy LLC and its subsidiaries (Everlast) (Predecessor Company) at December 31, 2004 and the results of their operations and their cash flows for the period from January 1, 2005 to June 12, 2005, and for each of the two years ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Everlast’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2, Everlast has restated its financial statements for the years ended December 31, 2004 and 2003.

As discussed in Note 6, Everlast changed its method of accounting for outstanding preferred units that were subject to mandatory redemption in 2003.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Baltimore, Maryland

June 12, 2006

F-2

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES and

EVERLAST ENERGY LLC and SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)


	Successor								Predecessor
	CEP								Everlast
	For the period from February 7, 2005 (inception) to December 31, 2005		For the period February 7, 2005 (inception) to June 30, 2005			Six months ended June 30, 2006			For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005
						Six months ended June 30, 2006			As Restated (see Note 2)			As Restated (see Note 2)			For the period from January 1, 2005 to June 12, 2005
			Unaudited			Unaudited
	(In '000's except unit data)								(In '000's except unit data)
Revenues
Gas sales	$	25,957	$	1,377		$	17,605		$	22,320		$	27,494		$	12,882
Loss from mark-to-market activities (see Note 5)		—		—			—			(3,664	)		(9,107	)		(15,313	)

Total revenues		25,957		1,377			17,605			18,656			18,387			(2,431	)

Expenses:
Operating expenses:
Lease operating expenses		4,175		357			3,495			4,428			5,270			2,769
Production taxes		1,400		72			909			1,279			1,479			676
General and administrative		4,184		3,275			2,731			1,945			2,706			594
Depreciation, depletion, and amortization		4,176		350			3,811			3,684			3,719			1,683
Accretion expense		78		7			71			73			86			46

Total operating expenses		14,013		4,061			11,017			11,409			13,260			5,768

Other expense/(income)
Interest expense/(income), net		3		—			(197	)		1,961			3,028			2,437
Organization costs		—		—			—			299			—			—

Total other expenses/(income)		3		—			(197	)		2,260			3,028			2,437

Total expenses		14,016		4,061			10,820			13,669			16,288			8,205

Net income (loss)	$	11,941	$	(2,684	)	$	6,785		$	4,987		$	2,099		$	(10,636	)
Other comprehensive income		—		—			914			—			—			—

Comprehensive income (loss)	$	11,941	$	(2,684	)	$	7,699		$	4,987		$	2,099		$	(10,636	)

Pro forma earnings per unit (unaudited)
(See Note 1)
Earnings per unit	$	0.81				$	0.45
Pro forma units outstanding		14,711,498					14,969,298

See accompanying notes to consolidated financial statements.

F-3

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES and

EVERLAST ENERGY LLC and SUBSIDIARIES

Consolidated Balance Sheets


	Successor									Predecessor
	CEP									Everlast
							Pro Forma June 30, 2006 (see Note 3)			December 31, 2004
	December 31, 2005			June 30, 2006			Pro Forma June 30, 2006 (see Note 3)			As Restated (see Note 2)
				Unaudited			Unaudited
	(In '000's)									(In '000's)
Assets
Current assets
Cash and cash equivalents	$	14,831		$	3,880		$	3,880		$	2,012
Accounts receivable		5,824			3,955			3,955			3,824
Investment in affiliate cash pool		—			12,199			12,199			—
Prepaid expenses		62			137			137			19
Risk management assets		—			603			603			719
Other		211			1,018			1,018			—

Total current assets		20,928			21,792			21,792			6,574
Natural gas properties (See Note 8)
Natural gas properties and related equipment (successful efforts accounting method)
Natural gas properties and equipment		143,605			150,341			150,341			—
Support equipment and facilities		25,070			25,637			25,637			—
Material and supplies		712			1,291			1,291			—
Natural gas properties and related equipment (full cost accounting method)
Properties being amortized		—			—			—			59,651
Properties not being amortized		—			—			—			283
Less accumulated depreciation, depletion and amortization		(4,176	)		(7,987	)		(7,987	)		(7,403	)

Net natural gas properties		165,211			169,282			169,282			52,531
Other assets
Loan costs (net of accumulated amortization of $685 at December 31, 2004)		—			—			—			1,579
Risk management assets		—			311			311			—

Total assets	$	186,139		$	191,385		$	191,385		$	60,684

Liabilities and members' equity (deficit)
Liabilities
Current liabilities
Accounts payable	$	5,179		$	2,992		$	2,992		$	1,901
Accrued liabilities		5,483			5,812			5,812			552
Royalty payable		3,233			1,993			1,993			2,029
Dividends payable		—			—			135,977			—

Total current liabilities		13,895			10,797			146,774			4,482
Other liabilities
Asset retirement obligation		2,524			2,609			2,609			1,052
Mark-to-market derivatives liabilities		—			—			—			2,262
Environmental liabilities		490			490			490			—
Debt		63			52			52			67,500

Total other liabilities		3,077			3,151			3,151			70,814

Total liabilities		16,972			13,948			149,925			75,296
Members’ equity (deficit)
Common members equity (deficit)		169,167			176,523			40,546			(14,612	)
Accumulated other comprehensive income		—			914			914			—

Total members' equity (deficit)		169,167			177,437			41,460			(14,612	)

Total liabilities and members' equity (deficit)	$	186,139		$	191,385		$	191,385		$	60,684

See accompanying notes to consolidated financial statements.

F-4

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES and

EVERLAST ENERGY LLC and SUBSIDIARIES

Consolidated Statements of Cash Flows


	Successor									Predecessor
	CEP									Everlast
	For the period from February 7, 2005 (inception) to December 31, 2005			For the period February 7, 2005 (inception) to June 30, 2005			Six months ended June 30, 2006			For the year ended December 31, 2003			For the year ended December 31, 2004			For the period from January 1, 2005 to June 12, 2005
							Six months ended June 30, 2006			As Restated (see Note 2)			As Restated (see Note 2)			For the period from January 1, 2005 to June 12, 2005
				Unaudited			Unaudited
	(In '000's)									(In '000's)
Cash flows from operating activities:
Net income (loss)	$	11,941		$	(2,684	)	$	6,785		$	4,987		$	2,099		$	(10,636	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Expenses paid by CCG on behalf of CEP		64			—			571			—			—			—
Depletion, depreciation and amortization		4,176			350			3,811			3,684			3,719			1,683
Amortization of debt issuance costs		—			—			—			288			685			237
Accretion of return on preferred member units		—			—			—			656			432			—
Accretion of plugging and abandonment liability		78			7			71			73			86			46
Changes in Assets and Liabilities:
Increase (decrease) in net mark-to-market activities		—			—			—			(512	)		(2,156	)		15,265
(Increase) decrease in accounts receivable		(1,289	)		1,535			1,869			(1,547	)		(2,278	)		(707	)
(Increase) decrease in prepaid expenses		(62	)		(21	)		(75	)		(265	)		246			(131	)
(Increase) in other current assets		(211	)		—			(807	)		—			—			(7,035	)
Increase in deposit on sale of properties		—			—			—			—			—			7,025
Increase (decrease) in accounts payable		1,703			(863	)		(2,187	)		908			993			807
Increase (decrease) in accrued liabilities		5,054			4,243			7			180			372			(25	)
Increase (decrease) in royalty payable		1,859			364			(1,240	)		1,321			708			110

Net cash provided by operating activities		23,313			2,931			8,805			9,773			4,906			6,639

Cash flows from investing activities:
Acquisition of natural gas properties		(138,951	)		(138,951	)		(261	)		(45,851	)		(1,304	)		(201	)
Development of natural gas properties		(8,286	)		(406	)		(7,285	)		(2,040	)		(5,680	)		(4,000	)
Investment in affiliate cash pool		—			—			(12,199	)		—			—			—
Other, net		—			—			—			59			(13	)		(2	)

Net cash used in investing activities		(147,237	)		(139,357	)		(19,745	)		(47,832	)		(6,997	)		(4,203	)

Cash flows from financing activities:
Members’ contribution (distributions)		138,770			138,770			—			1			(21,102	)		—
Preferred members’ contributions (redemptions)		—			—			—			15,500			(17,184	)		—
Proceeds from issuance of debt		—			—			—			30,500			48,000			—
Repayment of debt		(15	)		—			(11	)		(4,500	)		(6,500	)		(2,500	)
Loan costs		—			—			—			(879	)		(1,674	)		—

Net cash provided by (used in) financing activities		138,755			138,770			(11	)		40,622			1,540			(2,500	)

Net increase (decrease) in cash		14,831			2,344			(10,951	)		2,563			(551	)		(64	)
Cash and cash equivalents, beginning of period		—			—			14,831			—			2,563			2,012

Cash and cash equivalents, end of period	$	14,831		$	2,344		$	3,880		$	2,563		$	2,012		$	1,948

Supplemental disclosures of cash flow information:
Non-cash items
Assumption of receivables from Everlast by CEP	$	4,536		$	—		$	—		$	—		$	—		$	—
Assumption of liabilities from Everlast by CEP		3,640			—			—			—			—			—
Acquisition costs related to accrual for asset retirement obligation		2,446			—			—			893			—			—
Acquisition costs related to payable to Everlast		2,361			—			—			—			—			—
Derivative liabilities assumed by CEP as part of the acquisition and then subsequently assumed by CCG		18,003			—			—			—			—			—
Derivative liabilities assumed by Everlast as part of the acquisition from Torch		—			—			—			4,210			—			—
Direct costs related to the acquisition of the properties paid by CCG on behalf of CEP		389			—			—			—			—			—
Expenses paid by CCG on behalf of CEP		64			—			571			—			—			—
Accretion of distributions to preferred members		—			—			—			597			—			—
Cash paid during the period for interest	$	3		$	—		$	2		$	808		$	1,484		$	2,196

See accompanying notes to consolidated financial statements.

F-5

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES and

EVERLAST ENERGY LLC and SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity


	Common Members
	(In '000's)
CEP (Successor)
Contributions	$	157,226
Net income		11,941

Balance, December 31, 2005		169,167
Contributions (unaudited)		571
Other comprehensive income (unaudited)		914
Net income (unaudited)		6,785

Balance, June 30, 2006 (unaudited)	$	177,437


Everlast (Predecessor) (as restated, see Note 2)
Initial contributions—common members	$	1
Initial contributions—preferred members		15,500
Reclass to shares subject to mandatory redemption as required by SFAS No. 150 (see Note 6)		(16,097	)
Net income		4,987

Balance, December 31, 2003		4,391
Distributions		(21,102	)
Net income		2,099

Balance, December 31, 2004	$	(14,612	)

See accompanying notes to consolidated financial statements.

F-6

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

INTERIM INFORMATION AS OF JUNE 30, 2006 AND FOR THE

PERIODS ENDED JUNE 30, 2006 AND 2005 IS UNAUDITED

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Organization and Basis of Presentation

CBM Equity IV Holdings, LLC was organized as a limited liability company on February 7, 2005 under the laws of the State of Delaware and had no principal operations prior to our acquisition of our properties in the Robinson’s Bend Field (the “Properties”) from Everlast Energy LLC (“Everlast”) on June 13, 2005. On May 10, 2006, CBM Equity IV Holdings, LLC changed its name to Constellation Energy Resources LLC. On July 18, 2006, Constellation Energy Resources LLC changed its name to Constellation Energy Partners LLC (“CEP”). CEP is a wholly owned subsidiary of Constellation Energy Commodities Group, Inc. (“CCG”) and is currently focused on the development, exploitation and acquisition of natural gas properties in the Robinson’s Bend Field located in the Black Warrior Basin in Alabama (the “Field”). CEP acquired the natural gas properties, including equipment and a natural gas gathering facility and water treatment plant at the Properties from Everlast effective June 13, 2005.

The accompanying financial statements for CEP include the accounts of CEP and its wholly owned subsidiaries, Robinson’s Bend II Production LLC (“Production”), Robinson’s Bend II Operating LLC (“Operating”) and Robinson’s Bend II Marketing LLC (“Marketing”) (collectively, the “Entities”). All significant intercompany accounts and transactions have been eliminated in consolidation. CEP’s natural gas production is related to the Properties acquired as of June 13, 2005.

Everlast was organized as a limited liability company on November 20, 2002 under the laws of the State of Delaware. Everlast was primarily engaged in the acquisition, development and production of gas reserves and operation of gas wells in the Field from January 7, 2003 to June 12, 2005.

CEP’s and Everlast’s only operations were derived from the Properties. During the last three years, the Properties were wholly owned by either CEP or Everlast. CEP’s purchase of the Properties from Everlast resulted in a new basis of accounting. In addition, new management, new assumptions, and new accounting policies were put into place. Though the financial statements represent the operation of the same Properties, due to these differences the financial statements for the periods prior to and after CEP’s purchase of the Properties are not comparable. For that purpose, a black line has been placed between the CEP and Everlast financial statements.

Accounting policies used by CEP and Everlast conform to accounting principles generally accepted in the United States of America. Unless otherwise indicated, CEP and Everlast follow the same significant accounting policies.

CEP and Everlast both operated the Properties as one business segment, the exploration, development and production of natural gas. Management of both CEP and Everlast evaluated performance based on one business segment as there are not different economic environments within the operation of the Properties.

(b) Unaudited Interim Financial Information

The accompanying unaudited consolidated balance sheet as of June 30, 2006, unaudited consolidated statements of operations and comprehensive income (loss) and cash flows for the six months ended June 30, 2006 and for the period from February 7, 2005 (inception) through June 30, 2005, and the unaudited consolidated statement of changes in members’ equity for the six months ended June 30, 2006 have been prepared in accordance with generally accepted accounting principles for interim financial information. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete

F-7

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

financial statements. In the opinion of management, all adjustments, consisting of normal, recurring adjustments, considered necessary for a fair presentation have been included. The information disclosed in the notes to the consolidated financial statements for these periods is unaudited. Operating results for the six months ended June 30, 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2006 or any future period.

(c) Cash and Cash Equivalents

All highly liquid investments with original maturities of three months or less are considered cash equivalents by both CEP and Everlast.

(d) Concentration of Credit Risk and Accounts Receivable

Financial instruments that potentially subject CEP and Everlast to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. Both CEP and Everlast place their cash with high credit quality financial institutions and Everlast placed its derivative financial instruments with financial institutions and other firms that its management believed had a high credit rating. Substantially all of CEP’s and Everlast’s accounts receivable are due from purchasers of natural gas. Natural gas sales are generally unsecured. As CEP generally has fewer than 10 customers for its natural gas sales, CEP routinely assesses the financial strength of its customers. Bad debt expense is recognized on an account-by-account review after all means of collection have been exhausted and recovery is not probable. There has been no bad debt expense for any of the periods presented herein. Neither CEP nor Everlast have any off-balance-sheet credit exposure related to customers.

For the six months ended June 30, 2006, five customers accounted for approximately 31%, 27%, 18%, 13% and 11%, respectively, of the gas sales revenues related to the Properties. For the period from February 7, 2005 (inception) to December 31, 2005, five customers accounted for approximately 31%, 20%, 20%, 17%, and 12%, respectively, of the gas sales revenues related to the Properties. For the year ended December 31, 2004, five customers accounted for approximately 31%, 20%, 16%, 15% and 11%, respectively, of the gas sales revenues related to the Properties. For the year ended December 31, 2003, five customers accounted for approximately 19%, 18%, 18%, 17%, and 10%, respectively, of the gas sales revenues related to the Properties.

(e) Natural Gas Properties

(1) CEP

(a) Natural Gas Properties

CEP follows the successful efforts method of accounting for its natural gas exploration, development and production activities. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Depreciation and depletion of producing natural gas and oil properties is recorded based on units-of-production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Statement of Financial Accounting Standards (“SFAS”) No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, developed and undeveloped, and that capitalized development costs (including wells and related equipment and facilities) be amortized on the basis of proved developed reserves. As more fully described in Note 17, proved reserves are estimated by CCG’s internal reserve engineers, and are subject to future revisions when additional information becomes available.

F-8

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As described in Note 13, CEP follows SFAS No. 143, Accounting for Asset Retirement Obligations. Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by CEP’s engineers using existing regulatory requirements and anticipated future inflation rates.

Geological, geophysical, and dry hole costs on natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.

Natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. CEP assesses impairment of capitalized costs of proved natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. As of December 31, 2005, the estimated undiscounted future cash flows for CEP’s proved natural gas and oil properties exceeded the net capitalized costs, and no impairment was required to be recognized.

Property acquisition costs are capitalized when incurred.

(b) Support Equipment and Facilities

Support equipment and facilities consist of CEP’s water treatment facility, gas lines, roads, and other various support equipment. Items are capitalized when acquired and depleted using units-of-production method over the total proved developed reserves.

(c) Materials and Supplies

Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of the Properties.

(2) Everlast

Everlast used the full-cost method of accounting for its natural gas properties. All of Everlast’s properties and assets were located in the Black Warrior Basin in Alabama; therefore its costs were capitalized in one cost center. Under the full-cost method, all costs related to the acquisitions, exploration, or development of natural gas properties are capitalized into the “full-cost pool”. Such costs include those related to lease acquisitions, drilling and equipping of productive and nonproductive wells, delay rentals, geological and geophysical work and certain internal costs directly associated with the acquisition, exploration, or development of natural gas properties. Upon the sale or disposition of natural gas properties, no gain or loss is recognized, unless such adjustments of the full-cost pool would significantly alter the relationship between the capitalized costs and proved reserves.

Under the full-cost method of accounting, a “full-cost ceiling test” is required wherein net capitalized costs of natural gas properties cannot exceed the present value of estimated future net revenues from proved gas reserves, discounted at 10%, less any related income tax effects.

Costs of acquiring undeveloped gas leases that are capitalized and not subject to amortization (see Note 9) are assessed periodically to determine whether impairment has occurred. Appropriate valuation allowances

F-9

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

are established when necessary. No such allowance was required during the period from January 1, 2005 to June 12, 2005, and for the years ended December 31, 2004 and 2003.

Depletion, depreciation, and amortization of natural gas properties were computed using the units-of-production method based on estimated proved gas reserves.

(f) Natural Gas Reserve Quantities

(1) CEP

CEP’s estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty to be recoverable from established reservoirs in the future under current operating and economic parameters. Management calculated reserves based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and economic evaluation of all of CEP’s properties on a well-by-well basis. The process used to complete the internal estimates of proved reserves at December 31, 2005 is described in detail in Note 17.

Reserves and their relation to estimated future net cash flows impact CEP’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of CEP’s reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

CEP’s proved reserve estimates were a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas eventually recovered.

(2) Everlast

Everlast’s estimates of proved reserves were based on the quantities of natural gas and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. The proved reserve estimates of 162.2 Bcf for 2004 and 163.7 Bcf for 2003 were used to prepare the 2004 and 2003 financial statements. CEP prepared the estimates internally by starting with a December 31, 2005 proved reserve estimate that was prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) based on the prior accelerated drilling program and reserve assumptions and rolling that back to year end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back was necessary because the reserve report prepared by NSAI for Everlast for year end 2004 was not considered to be based on the Securities and Exchange Commission (SEC) definition of proved reserves, which we use for financial statement preparation purposes. The reserve report prepared by NSAI for Everlast for year end 2003 while based on the SEC definition of proved reserves included different assumptions than those used by NSAI in preparing the 2005 estimate.

Due to this inconsistency in the preparation of reserve reports for the periods presented, CEP has adopted the roll back approach of reserves at December 31, 2005 to year end 2004 and 2003 in preparing the financial statements for year end 2004 and 2003.

Changes to reserve estimates affect estimated future net cash flows, depletion and impairment calculations. The accuracy of Everlast’s reserve estimates was a function of: the quality and quantity of available data,

F-10

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Everlast’s proved reserve estimates were a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas eventually recovered.

(g) Deposit on Sale of Properties

As of June 12, 2005, Everlast had a restricted cash balance of $7.0 million. This account was cash held in escrow and was restricted until the purchase of the Properties by CEP was completed. It was released on June 13, 2005 to Everlast.

(h) Derivatives and Hedging Activities

(1) CEP

As of December 31, 2005, CEP did not have any outstanding derivative positions.

On June 20, 2006, CEP entered into certain over-the-counter contracts to hedge approximately 85% of the cash flow from the sale of expected gas production from currently producing wells from October 2006 through December 2009. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that all derivative instruments be recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes in fair value recognized in earnings unless specific hedge accounting criteria are met. CEP elected to designate these contracts as cash-flow hedges for accounting purposes. The fair value of its derivative contracts are recorded on its balance sheet as “Risk management assets” and “Accumulated other comprehensive income.” Changes in the fair value of the cash flow hedges are reflected on the consolidated statements of operations and comprehensive income (loss) as other comprehensive income.

(2) Everlast

During 2003, 2004, and 2005, Everlast entered into certain over-the-counter contracts to economically hedge the cash flow of the forecasted sale of gas production. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, requires that all derivative instruments be recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes recognized in earnings unless specific hedge accounting criteria are met. Everlast did not elect to document and designate these contracts as hedges for accounting purposes. Thus, the changes in the fair value and ultimate settlement of these over-the-counter contracts are reflected in Everlast’s earnings as “loss from mark-to-market activities” for the period from January 1, 2005 to June 12, 2005 and for the years ended December 31, 2004 and December 31, 2003.

In addition to the over-the-counter contracts, Everlast entered into one long-term, fixed price natural gas sales contract that expired December 31, 2003. This contract met the criteria of a derivative under SFAS No. 133.

(i) Net Profits Interest

Certain of the Properties are subject to a net profits interest (“NPI”). The NPI represents an interest in production created from the working interest and is based on a contracted revenue calculation (see Note 14). CEP

F-11

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

accounts for the NPI as an overriding royalty interest. This is consistent with how CEP accounts for the NPI for reserves purposes, similar to royalty payments. Any payments made to the NPI holder are reflected as a reduction in revenue. Everlast financials have been changed to reflect this method of accounting. For a discussion of restatements, see Note 2.

(j) Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold on a monthly basis. Most of CEP’s and Everlast’s sales contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. CEP believes that the pricing provisions of its natural gas contracts are customary in the industry.

Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. CEP and Everlast use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no gas imbalance positions as of June 30, 2006, June 30, 2005, December 31, 2005, June 12, 2005, December 31, 2004 or December 31, 2003.

(k) Income Taxes

CEP is a single-member liability company that is a disregarded entity for federal income tax purposes under Regulation 301.7701-3(b). That means, for Federal income tax purposes, CEP is accounted for as a division of CCG and does not file separate tax returns. Under Constellation Energy tax sharing practices, no provision for income taxes was made in CEP’s financial statements because the taxable income or loss of CEP was included in the income tax return of CCG, the single corporate member. If CEP were a separate taxpayer, income taxes for the period from February 7, 2005 (inception) to December 31, 2005, for the period from February 7, 2005 (inception) to June 30, 2005, and for the six months ended June 30, 2006 would have been $4.7 million, $1.1 million, and $2.7 million, respectively. As of December 31, 2005, the income tax basis of CEP’s assets was $170.1 million.

No provision for incomes taxes was made in Everlast’s consolidated financial statements because the taxable income or loss of Everlast was included in the income tax returns of the individual members. As of June 12, 2005, December 31, 2004 and 2003, the income tax basis of Everlast’s assets was $53.8 million, $55.9 million, and $54.7 million, respectively.

(l) Use of Estimates

Estimates and assumptions are made when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:

•

reported amounts of revenue and expenses in the Consolidated Statement of Operations and Other Comprehensive Income (Loss) during the reported periods of CEP and Everlast,

F-12

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

•

reported amounts of assets and liabilities in the Consolidated Balance Sheets at the dates of the financial statements of CEP and Everlast,

•

disclosure of quantities of reserves and use of those reserve quantities for depletion, depreciation and amortization, and

•

disclosure of contingent assets and liabilities at the date of the financial statements of CEP and Everlast.

These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control. As a result, actual amounts could materially differ from these estimates.

(m) Earnings per Unit

CEP had one common member who held one common unit as of December 31, 2005 and June 30, 2006. Therefore, historical earnings per unit information is not meaningful. CEP intends to unitize the legal entity subsequent to the publishing of these audited financial statements but prior to the public offering. See discussion of the determination of pro forma earnings per unit below.

Historical Pro Forma Earnings per Unit (Unaudited)

In contemplation of a public offering, CEP has included an unaudited computation of pro forma earnings per unit. CEP expects to declare a distribution of approximately $136.0 million to CCG immediately prior to the proposed initial public offering. Because these distributions exceed net income for 2005 and the six months ended June 30, 2006, 6,201,798 and 6,459,598 units were added to the outstanding units to compute the unaudited pro forma basic and diluted earnings per unit for the period February 7, 2005 (inception) to December 31, 2005 and for the six months ended June 30, 2006, respectively. These units represent the incremental number of units at the expected offering price that would be required to fund the distribution to CCG in excess of each period’s net income. The pro forma earnings per unit also includes the impact of the conversion of CEP’s outstanding units into approximately 8,214,010 Class B units and 295,690 Class A units to be effective immediately prior to the public offering.

The following table sets forth the calculation of historical pro forma earnings per unit:


(In ‘000’s except earnings per unit)	For the period February 7, 2005 (inception) to December 31, 2005		For the six months ended June 30, 2006
Net income	$	11,941	$	6,785

Unit conversion		8,510		8,510
Additional units issued		6,202		6,460

Total units		14,712		14,970
Pro forma earnings per unit	$	.81	$	.45

(n) Accounting Standards Adopted

F-13

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

change. This Statement does not change the guidance for reporting the correction of an error in previously issued financial statements or a change in accounting estimate. The provisions of this Statement shall be effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. CEP is not able to assess at this time the future impact of this Statement on its financial results. CEP discusses 2004 and 2003 restatements in Note 2.

On April 4, 2005, the FASB issued FASB Staff Position (“FSP”) No. 19-1, Accounting for Suspended Well Costs. This Staff Position amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in the FSP is required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The adoption of this standard did not have a material impact on CEP’s financial results.

On March 30, 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, Accounting for Conditional Asset Retirement Obligations. This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. FIN No. 47 was effective for CEP at the end of the fiscal year ended December 31, 2005. The adoption of this standard did not have a material impact on its financial results.

(o) Accounting Standards Issued but not Effective

In April 2006, the FASB issued FSP FIN 46R-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46R. FSP FIN 46R-6 addresses how a reporting enterprise should determine the variability to be considered in applying FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. The variability to be considered should be based on an analysis of the design of the entity and should consider the nature of the entity’s risks and the purpose for which the entity was created. FSP FIN 46R-6 must be applied prospectively to all entities beginning July 1, 2006. CEP has determined that there was no impact on its financial results as a result of FSP FIN 46R-6.

F-14

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(2) RESTATEMENT OF EVERLAST FINANCIAL STATEMENTS

The financial statements as of December 31, 2004 and for the two years ended December 31, 2004 which were prepared and issued by the predecessor entity, Everlast, have been restated for the following:

•

to correct depletion expense that was recorded based on incorrect reserve quantities and future development costs;

•

to include the impact of cost escalation for plugging and abandoning wells in the calculation of asset retirement obligations;

•

to correct for costs recorded in the wrong periods;

•

to correct the misclassification of revenues related to a long-term, fixed price natural gas sales contract accounted for as a derivative contract;

•

to expense operating costs originally capitalized;

•

to capitalize and amortize deferred financing costs originally expensed;

•

to capitalize certain property costs originally expensed; and

•

to account for a net profits interest as an overriding royalty interest.

In 2003 and 2004, Everlast recorded depletion expense based on a depletion base that understated future development costs that are required to be included in the depletion base under the full cost method. In addition, recorded depletion expense was based on reserve estimates that incorrectly included certain proved undeveloped reserves. For purposes of reserve determination, it is inappropriate to include proved undeveloped reserves that are not immediately adjoining currently producing wells. The original year-end proved reserves for 2003 and 2004 were adjusted to remove these proved undeveloped reserves. In 2003, Everlast’s original accounting was based on a proved reserve estimate of 166.2 Bcf, while the revised accounting was based on a proved reserve estimate of 163.7 Bcf. Similarly, in 2004, Everlast’s original accounting was based on a proved reserve estimate of 173.4 Bcf, while the revised accounting was based on a proved reserve estimate of 162.2 Bcf. These adjustments resulted in additional depletion expense and a reduction of net income of $0.7 million and $76,000 for the years ended December 31, 2003 and 2004, respectively, and an increase in accumulated depletion of $0.8 million at December 31, 2004.

In 2003 and 2004, the cost estimates associated with plugging and abandoning wells should have been computed based on estimates of future costs, including inflation through the period in which the actual cash outflows would be incurred. The impact of correcting the expense to include all such future costs in the asset retirement obligation results in an increase in the asset retirement obligation along with an associated asset retirement asset of $0.8 million at December 31, 2004, and additional accretion expense and reduction of net income of $57,000 and $70,000 for the years ended December 31, 2003 and 2004, respectively.

As part of CEP’s cut-off procedures, CEP identified certain costs incurred in 2003 and 2004 which should have been included in expenses and liabilities in different periods. Recording these costs in the correct periods resulted in additional liabilities of $108,000 and an increase in oil and gas properties of $51,000 at December 31, 2004 and an increase in operating expenses and reduction of net income of $25,000 and $37,000 for the years ended December 31, 2003 and 2004, respectively.

In 2003, Everlast assumed one long term, fixed price natural gas sales contract in connection with the acquisition of the Properties from Torch. This contract met the definition of a derivative under SFAS No. 133

F-15

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

and Everlast accounted for it by recording changes in the fair value of the contract to the income statement. Everlast’s original accounting was to record in “Gas sales” the volumes sold at the current spot price and to record the difference between volumes sold at the spot price and volumes sold at the contractual price in “Loss from mark-to-market activities.” In addition, the change in the fair value of this contract in 2003 was originally recorded as a gain in “Loss from mark-to-market activities.” Since these contracts physically delivered and Everlast was paid the contractual amount, it was incorrect to recognize gas revenues at spot prices with an offset in loss from mark-to-market activities. Accordingly, the financial statements for the year-ended December 31, 2003 have been restated to record all activity related to this contract in “Gas sales”. This resulted in a reduction of gas sales by approximately $1.9 million, the net of these errors, and a corresponding reduction in loss from mark-to-market activities. There was no impact on total revenues or net income in 2003.

Indirect costs associated with acquiring business operations were capitalized by Everlast when it acquired the Properties in January 2003. These costs should have been included as operating costs in the accompanying financial statements and approximately $0.1 million has been expensed (with a corresponding reduction of net income) resulting in a decrease in “Natural gas properties and related equipment (full cost accounting method)-properties being amortized.”

In 2004, Everlast completed a modification of its line of credit and wrote-off all deferred financing costs associated with the previous facility. In accordance with the guidance in EITF 98-14, Debtors Accounting for Changes in Line-of-Credit or Revolving-Debt Agreements, certain of these debt issuance costs should have continued to be capitalized and amortized over the life of the modified revolving credit agreement because one of the financial institutions was a participant in both the original credit facility as well as the modified one. This adjustment resulted in an increase of $0.2 million in capitalized loan costs at December 31, 2004 and a reduction in interest expense and an increase in net income of $0.2 million for the year ended December 31, 2004.

Everlast expensed certain capital costs in 2003 that should have been capitalized. Accordingly, in the restated financial statements, $0.5 million has been recorded to increase properties being amortized at December 31, 2004 and a reduction in operating expenses of $0.5 million has been recorded for the year ended December 31, 2003. This increased depletion expense by $13,000 in both periods presented. The impact of these corrections increased net income by $0.5 million in 2003, and decreased net income by $13,000 in 2004.

Certain of the Properties are subject to an NPI (see Notes 1 and 14). In 2003 and 2004, Everlast determined its reserves as if the NPI were an overriding royalty interest. This was inconsistent with how the NPI was reflected in the statement of operations for those years. Generally accepted accounting principles require that the determination of reserves be consistent with the financial statement reporting. CEP believes that treatment of the NPI as an overriding royalty interest for both financial statement and reserve reporting is appropriate in the circumstances. As a result, the statement of operations has been restated to account for the NPI as an overriding royalty interest which resulted in an increase in revenues and a corresponding increase in expenses of $2.2 million and $2.1 million for the years ended December 31, 2003 and 2004, respectively. This restatement had no impact on net income for either 2003 or 2004. In addition, because reserves in those periods were determined as if the NPI were an overriding royalty interest this adjustment had no impact on reserves.

F-16

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following is a summary of the effects of these adjustments on Everlast’s balance sheet as of December 31, 2004, and on the statements of operations, cash flows and members’ equity for the two years ended December 31, 2004.


Statements of Operations
For the year ended December 31, 2004	As Previously Reported			Adjustments			As Restated
	(In ‘000’s)
Revenues:
Gas sales	$	25,363		$	2,131		$	27,494
Loss from mark-to-market activities		(9,107	)		—			(9,107	)

Total revenues		16,256			2,131			18,387
Expenses:
Operating expenses:
Lease operating expenses		3,682			1,588			5,270
Production taxes		921			558			1,479
General and administrative		2,689			17			2,706
Depreciation, depletion, and amortization		3,643			76			3,719
Accretion expense		16			70			86

Total operating expenses		10,951			2,309			13,260
Other expenses:
Interest expense, net		2,803			(206	)		2,597

Total other expenses		2,803			(206	)		2,597

Total expenses		13,754			2,103			15,857

Net income	$	2,502		$	28		$	2,530


For the year ended December 31, 2003	As Previously Reported			Adjustments			As Restated
	(In ‘000’s)
Revenues:
Gas sales	$	22,094		$	226		$	22,320
Loss from mark-to-market activities		(5,631	)		1,967			(3,664	)

Total revenues		16,463			2,193			18,656
Expenses:
Operating Expenses:
Lease operating expenses		3,205			1,223			4,428
Production taxes		781			498			1,279
General and administrative		1,806			139			1,945
Depreciation, depletion, and amortization		3,000			684			3,684
Accretion expense		16			57			73

Total operating expenses		8,808			2,601			11,409
Other expenses:
Interest expense, net		1,306			—			1,306
Organization costs		299			—			299

Total other expenses		1,605			—			1,605

Total expenses		10,413			2,601			13,014

Net income	$	6,050		$	(408	)	$	5,642

F-17

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


Balance Sheet
December 31, 2004	As Previously Reported			Adjustments			As Restated
	(In ‘000’s)
Natural gas properties and related equipment (full cost)	$	58,813		$	1,121		$	59,934
Accumulated depreciation, depletion and amortization		(6,644	)		(759	)		(7,403	)
Net natural gas properties		52,169			362			52,531
Loan costs (net of accumulated amortization)		1,378			201			1,579
Total assets		60,121			563			60,684
Accounts payable		1,793			108			1,901
Royalty payable		2,037			(8	)		2,029
Total current liabilities		4,382			100			4,482
Asset retirement obligation		210			842			1,052
Total liabilities		74,354			942			75,296
Total members’ capital (deficit)		(14,233	)		(379	)		(14,612	)

Statements of Cash Flows
For the year ended December 31, 2004	As Previously Reported			Adjustments			As Restated
	(In ‘000’s)
Net cash provided by operating activities	$	4,654		$	252		$	4,906
Net cash used in investing activities		(6,947	)		(50	)		(6,997	)
Net cash provided by (used in) financing activities		1,742			(202	)		1,540
Cash and cash equivalents, beginning of period		2,563			—			2,563

Cash and cash equivalents, end of period	$	2,012		$	—		$	2,012


For the year ended December 31, 2003	As Previously Reported			Adjustments			As Restated
	(In ‘000’s)
Net cash provided by operating activities	$	9,416		$	357		$	9,773
Net cash used in investing activities		(47,475	)		(357	)		(47,832	)
Net cash provided by financing activities		40,622			—			40,622
Cash and cash equivalents, beginning of period		—			—			—

Cash and cash equivalents, end of period	$	2,563		$	—		$	2,563


Statement of Members’ Equity
	As Previously Reported			Adjustments			As Restated
	(In ‘000’s)
Balance, December 31, 2003	$	21,553		$	(408	)	$	21,145
Distributions		(38,287	)		—			(38,287	)
Net income		2,502			28			2,530

Balance, December 31, 2004	$	(14,232	)	$	(380	)	$	(14,612	)

The information in the tables above reflects the correction of errors in the 2003 and 2004 Everlast financial statements. The information in the tables above does not, however, reflect the impact of Everlast’s adoption of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity in 2003. See discussion of the adoption of SFAS No. 150 in Note 6.

F-18

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(3) PRO FORMA BALANCE SHEET INFORMATION (UNAUDITED)

CEP intends to declare a dividend (currently estimated to be approximately $136.0 million) to its parent, CEPH, prior to closing of an initial public offering of CEP’s common units. The net proceeds (after deducting underwriting discounts and commissions and expenses of the offering) of the initial public offering are expected to approximate $113.8 million. The net proceeds (less $7.8 million to be retained for working capital purposes) and borrowings under a reserve-based credit facility will be used to pay that dividend. The pro forma adjustments to the historical CEP balance sheet at June 30, 2006 reflects the accrual of the dividends payable (estimated to be $136.0 million) and resulting reduction in members’ equity to reflect the impact of the planned dividend, but not the proceeds of the initial public offering.

(4) ACQUISITIONS

On June 13, 2005, CEP acquired the Properties consisting of 424 producing wells, land, tangible wellhead equipment, production facilities, and other support equipment in Alabama from Everlast for $141.3 million in cash plus the assumption of $19.8 million of net liabilities. Of the cash amount, $2.4 million was payable to Everlast as of December 31, 2005. The outstanding balance was remitted to Everlast on January 31, 2006.

The following table represents the fair value of the assets acquired and liabilities assumed at the date of the acquisition:


	(In ‘000’s)
Accounts receivable	$	4,536
Natural gas properties and equipment		135,741
Support equipment and facilities		24,935
Material and supplies		372
Accounts payable		(1,114	)
Accrued liabilities		(802	)
Royalty payable		(1,374	)
Asset retirement obligation		(2,387	)
Mark-to-market derivative liabilities		(18,003	)
Environmental liabilities		(490	)
Debt		(78	)

Net cash consideration	$	141,336

As part of the acquisition, the hedges were novated to CCG, on behalf of CEP, at a cost of $0.019 per hedged MMBtu or $0.2 million. The fair market value of the derivative liabilities at the time of the novation was $18.0 million and was capitalized as part of CEP’s purchase price. The derivatives were then assigned to CCG in exchange for equity in CEP.

The following unaudited pro forma information presents the financial information of CEP as if the acquisition of the Properties had occurred on February 7, 2005 (inception).


	As Reported		Pro Forma
	(In ‘000’s)
Gas sales	$	25,957	$	36,497

Net income	$	11,941	$	7,325

F-19

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On January 7, 2003, Everlast acquired the Properties from various affiliates of Torch Energy Corporation (the “Torch Acquisition”) for a gross purchase price of $43.0 million, before closing adjustments. Everlast utilized its credit facility to acquire the Properties (see Note 7). All costs were allocated to one amortization pool as Everlast used the full cost method of accounting.

On June 6, 2003, Everlast acquired additional properties in the Black Warrior Basin from Energen Resources Corporation. The gross purchase price was $0.7 million, before closing adjustments.

(5) DERIVATIVE AND FINANCIAL INSTRUMENTS

(a) Hedging Activities

CEP has hedged approximately 78% of its expected natural gas sales from currently producing wells from October 2006 to December 2009. The value of its cash flow hedges included in Accumulated other comprehensive income was a net unrealized gain of $0.9 million at June 30, 2006. CEP expects that $0.6 million will be reclassified from Accumulated other comprehensive income to the income statement in the next twelve months. There was no material ineffectiveness for the six months ended June 30, 2006.

(b) Mark-to-Market Activities

Everlast entered into various derivative instruments to economically hedge the market price fluctuations of natural gas.

In 2004, in connection with the Restated Credit Agreement (see Note 7), Everlast terminated derivative instruments that were below specified gas prices for a total cost of $8.0 million. Everlast was required to hedge at least 80% of its estimated gas production through 2007 and 50% of its estimated gas production in years 2008 and 2009 at or above specific gas prices. The terminated hedges were replaced by floating to fixed gas swaps.

At December 31, 2004, the carrying amount of Everlast’s derivative instruments equaled their fair value.

(c) Fair Value of Financial Instruments

The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. The amounts on the Consolidated Balance Sheets for CEP and Everlast approximate fair value for the following financial instruments because of their short term nature: cash and cash equivalents, accounts receivable, other current assets, current liabilities and deferred credits and other liabilities. CEP believes the carrying value of long-term debt approximates its fair value because the fixed interest rates on the debt approximated market interest rates for debt with similar terms.

(6) EVERLAST PREFERRED UNIT ISSUANCE

On January 6, 2003, Everlast closed a transaction pursuant to which it issued and sold to Greenhill Capital Resources, L.P., Greenhill Capital Resources (Cayman), L.P., Greenhill Resources (Executives), L.P., and Greenhill Capital, L.P. (collectively, “Greenhill”); Eos Resources, L.P., Eos Resources SBIC II L.P., Eos Resources SBIC III, L.P. (collectively, “Eos”); and Tgoff Energy LLC (“Tgoff”) (Tgoff together with Greenhill and Eos, the “Investors”) 1.5 million of Everlast’s Series A Preferred Units and 50,000 of Everlast’s Series B

F-20

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Preferred Units (“Preferred Units”) for cash of $15.5 million. As additional consideration, Everlast issued an aggregate of 1,125,000 shares of its common units to the Investors, which represented 100% of the outstanding common units at such time.

A preferred return on the Preferred Units was equal to 8% per annum compounded quarterly. In April 2004, Everlast redeemed the outstanding Preferred Series A and Preferred Series B units for $17.2 million. Everlast treated the redemption as retirement of the units and recognized no gain or loss upon redemption.

At December 31, 2004 and 2003, Everlast had $0 and $16.7 million, respectively, of preferred units outstanding that were subject to mandatory redemption. Effective July 1, 2003, Everlast adopted SFAS No. 150, Accounting for Certain Financial Investments with Characteristics of Both Liabilities and Equity. As a result, the preferred units were classified as “units subject to mandatory redemption” in the liability section of Everlast’s balance sheets. In addition, Everlast began accounting for the preferred units’ return as interest expense which totaled $0.4 million and $0.7 million for the years ended December 31, 2004 and 2003, respectively.

(7) DEBT

On December 31, 2005, CEP had $63,000 in outstanding debt. This debt is an installment note securitized by a piece of equipment and was assumed as part of the acquisition of the Properties. It has an annual interest rate of 6.12% and matures on March 31, 2008.

On January 6, 2003, Everlast entered into a syndicated credit agreement (“Credit Agreement”) with Wells Fargo Bank of Texas, NA (“Wells Fargo”) and two other banks (together with Wells Fargo, the “Banks”), with Wells Fargo serving as administrative agent. Proceeds from the Credit Agreement were used to make the Torch Acquisition. Borrowings under the Credit Agreement were secured by mortgages covering substantially all of Everlast’s producing natural gas properties. In accordance with the Credit Agreement, the Banks were paid various underwriting, administrative and advisory fees totaling $0.9 million.

In April 2003, Everlast entered into a five year note for the purchase of equipment (“Equipment Note”). Everlast made monthly payments with an effective interest rate of 6.12%. Upon acquisition of the Properties by CEP, the Equipment Note was assumed by CEP, who continues to make monthly payments according to the same terms. Future minimum payments remaining under the agreement are as follows:


	(In ‘000’s)
2006	$	30
2007		30
2008		8

Total payments	$	68
Less interest		5

Principal remaining	$	63

On April 26, 2004, Everlast entered into the First Amendment to the Credit Agreement (the “Amendment”). This Amendment provided for an increase in Everlast’s borrowing base to $46.5 million and provided for a limited consent and waiver from the lenders allowing Everlast to repurchase, on a one-time basis, all of its outstanding Preferred Series A and Preferred Series B units. Everlast immediately borrowed $17.0 million under

F-21

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the amended credit facility of which $16.7 million was used to redeem the outstanding Preferred Series A and Preferred Series B units.

Effective October 15, 2004, Everlast entered into an amended and restated credit agreement (“Everlast’s Restated Credit Agreement”) with Wells Fargo and other lenders, with Wells Fargo serving as administrative agent. Proceeds from Everlast’s Restated Credit Agreement were used to fully refinance Everlast’s previous bank indebtedness. As required by Everlast’s Restated Credit Agreement, Everlast economically hedged approximately 80% of estimated gas production generated from the Torch Acquisition through 2007 and 50% of the estimated gas production in 2008 and 2009. In accordance with Everlast’s Restated Credit Agreement the Banks were paid various underwriting, administrative and advisory fees totaling $1.0 million.

The total commitment amount under Everlast’s Restated Credit Agreement was $100.0 million with a borrowing base at December 31, 2004 of $50.0 million (“Borrowing Base”) and a maturity date of October 15, 2007. Borrowings under Everlast’s Restated Credit Agreement as of December 31, 2004 were $47.5 million. Everlast’s Restated Credit Agreement bore interest at the Base Rate (which was the higher of the lender’s “Prime Rate” or the Federal Funds Rate plus 0.50%) plus an applicable margin or at LIBOR (reserve adjusted) plus an applicable margin, at Everlast’s choice.

The applicable margin for borrowings under Everlast’s Restated Credit Agreement was computed based on Borrowing Base utilization and ranged from 0.75% to 1.75% for Base Rate loans and 1.75% to 2.75% for LIBOR loans.

Everlast was subject to various commitment and other fees associated with Everlast’s Restated Credit Agreement above. At June 12, 2005 and December 31, 2004, there was $0.5 million and $0.6 million of accrued interest and fees payable, respectively.

In connection with Everlast’s Restated Credit Agreement, on October 15, 2004 Everlast entered into a $20.0 million subordinated term credit agreement (“Everlast’s Term Credit Agreement”) from Wells Fargo Energy Capital (“WFEC”). Everlast’s Term Credit Agreement matures on October 15, 2008. Everlast’s Term Credit Agreement bore interest at the Base Rate plus 6.25%. Proceeds under Everlast’s Term Credit Agreement were distributed to the members. In accordance with Everlast’s Term Credit Agreement, the Banks were paid various underwriting, administrative and advisory fees totaling $0.4 million.

On July 13, 2005, as part of the acquisition of the Properties, Everlast instructed CEP to wire $45.1 million of the purchase price for the Properties to Wells Fargo to pay off the Restated Credit Agreement, and to wire $20.5 million of the purchase price for the Properties to WFEC to pay off the Term Credit Agreement. Everlast had no outstanding debt after these events.

F-22

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(8) NATURAL GAS PROPERTIES

Natural gas properties consist of the following:


	Successor			Predecessor
	CEP			Everlast
	December 31, 2005			December 31, 2004
	(In ‘000’s)			(In ‘000’s)
Natural gas properties and related equipment (successful efforts method)
Property (acreage) costs
Proved property	$	168,327		$	—
Unproved property		188			—
Natural gas properties and related equipment (full cost method)
Costs subject to amortization		—			59,651
Cost not subject to amortization		—			123

Total property costs		168,515			59,774
Materials and supplies		712			—
Land		160			160

Total		169,387			59,934
Less: Accumulated depreciation, depletion and amortization		(4,176	)		(7,403	)

Natural gas properties and equipment, net	$	165,211		$	52,531

(9) NATURAL GAS PROPERTIES NOT SUBJECT TO AMORTIZATION

Everlast used the full cost method of accounting for its natural gas properties. Under full cost, if a determination can not be made about the extent of additional gas reserves and can not be attributed to certain capital costs, the costs are excluded from the depreciation base until gas reserve estimate can be made.

At December 31, 2004, acquisition costs of $0.1 million were excluded from the depreciation basis. These costs were related to potential acquisitions, and a determination could not be made about the extent of additional gas reserves that should have been classified as a result of the project. Consequently, the associated acquisition costs were excluded in computing amortization of the full cost pool. Everlast began to amortize these costs when the project was evaluated in 2005.

Everlast acquired 210 acres of land in fee simple at the gas field in Alabama. This land was the site of the compressors and the field office. The cost of this land was $0.2 million, and was excluded from the depreciation basis as land is not depreciated.

(10) BENEFIT PLANS

Eligible employees of CEP participate in pension, postretirement, other post employment, and savings plans sponsored and administered by Constellation Energy. Contributions by Constellation Energy were approximately $1,000 and $16,000 for the period from February 7, 2005 (inception) to December 31, 2005 and for the six

F-23

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

months ended June 30, 2006, respectively. There were no costs allocated to CEP for the period February 7, 2005 (inception) to June 30, 2005.

Everlast employees who had been employed at least twelve months were eligible to participate in the Everlast Energy LLC qualified defined contribution plan. Contributions under the plan were determined annually by the Board of Directors of Everlast and were $37,000 for the period January 1, 2005 through June 12, 2005 and $27,000 and $18,000 for the years ended December 31, 2004 and 2003, respectively.

(11) RELATED PARTY TRANSACTIONS

CEP is owned and managed by CCG. CCG has performed various management tasks on behalf of CEP, including the operation and accounting functions. The costs to perform these management tasks were calculated by taking the percentage of time CCG employees were engaged with CEP business multiplied by their annual salary. CCG also processed the payroll and 401(k) transactions on behalf of CEP. These costs charged to CEP were calculated by taking the field employees’ total salary multiplied by a corporate overhead allocation percentage. Finally, CCG hired outside consultants to augment its current workforce specifically for the management of CEP. The full cost of these consultants was allocated to CEP. These costs totaled approximately $0.4 million and $1.4 million for the period February 7, 2005 (inception) to December 31, 2005 and for the six months ended June 30, 2006, respectively. There were no costs allocated to CEP for the period February 7, 2005 (inception) to June 30, 2005. CEP had an intercompany payable to CCG of $0.4 million and $1.9 million as of December 31, 2005 and June 30, 2006, respectively. This intercompany payable balance is included in accrued liabilities in the accompanying balance sheets.

During six months ended June 30, 2006, CCG paid $0.6 million of additional expenses on CEP’s behalf in exchange for additional equity in CEP. These expenses included legal fees, fees for consultants hired by CEP and various other expenses.

In February 2006, CEP entered into a cash pool arrangement with CCG. This cash pool arrangement is administered and managed by CEP. CCG may borrow from the pool at market interest rates. If CEP requires cash, and CCG has an outstanding balance, CCG is required to immediately remit payment to CEP for the required cash amount. If the initial public offering by CEP is successfully completed, CEP will cease its participation in the cash pool arrangement contemporaneously with the closing of that offering. As of June 30, 2006, the amount borrowed by CCG from the cash pool was $12.2 million.

Due to the affiliate relationship described above, the financial position, results of operations, and cash flows of CEP may differ from those that would have been achieved had CEP operated autonomously or as an entity independent of the ultimate parent and its subsidiaries.

Everlast had a loan to one of its officers outstanding at June 12, 2005 for a total of $17,000 that was subsequently paid off after the CEP acquisition of the Properties.

(12) COMMITMENTS AND CONTINGENCIES

In the course of its normal business affairs, CEP is subject to possible loss contingencies arising from federal, state and local environmental, health, and safety laws and regulations and third-party litigation. As of December 31, 2005, other than the matter discussed below, there are no matters which, in the opinion of management, will have a material adverse effect on the financial position, results of operations, or cash flows of CEP.

The Robinson’s Bend Field is subject to a NPI held by Torch Energy Royalty Trust (the “Trust”) (See Note 14). The royalty payment to the Trust is calculated using a sharing arrangement with a pricing formula that has

F-24

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

been below market and has had the effect of keeping our payments to the Trust lower than if such payments had been calculated based on prevailing market prices. If the sharing agreement were to terminate, CEP’s payments to the Trust will increase and CEP’s revenue will decrease. CEP is uncertain of the financial impact of the NPI over the life of the Robinson’s Bend field as it has volumetric and price risk variables. However, in order to address a portion of the risk of the potential adverse impact on CEP’s operating results from a termination of the sharing arrangement, Constellation Holdings, Inc. (“CHI”) will contribute $8.0 million to CEP in exchange for all of CEP’s Class D interests at the closing of its initial public offering to be used to protect the distributions to the common unit holders in the event the sharing arrangement is terminated. This contribution will be returned to CHI in 24 special quarterly distributions as long as the sharing agreement remains in effect for the distribution period.

(13) ASSET RETIREMENT OBLIGATION

CEP and Everlast follow SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the ARC is allocated to expense using a systematic and rational method over the assets’ useful life. The ARO’s recorded by CEP and Everlast relate to the plugging and abandonment of natural gas wells, and decommissioning of the gas gathering and processing facilities.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO, a corresponding adjustment is made to the gas property balance.

The following table is a reconciliation of the ARO:


	Successor				Predecessor
	CEP				Everlast
	December 31, 2005		June 30, 2006		December 31, 2004
			(unaudited)
(In thousands)	(In ‘000’s)				(In ‘000’s)
Asset retirement obligation, beginning balance	$	—	$	2,524	$	966
Liabilities incurred from acquisition of the properties		2,387		—		—
Liabilities incurred		59		14		—
Accretion expense		78		71		86

Asset retirement obligation, ending balance	$	2,524	$	2,609	$	1,052

At December 31, 2005 and June 30, 2006, there were no assets legally restricted for purposes of settling existing ARO’s. Additional retirement obligations increase the liability associated with new natural gas wells and other facilities as these obligations are incurred.

(14) NET PROFITS INTEREST

Certain of the Properties are subject to a non-operating NPI. The holder of the NPI, the Trust, does not have the right to receive production from the Properties. Instead, the Trust only has the right to receive a specified

F-25

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

portion of the future contractual cash flows from specified wells as defined by the “Net Overriding Royalty Conveyance Agreement.” CEP records the NPI as an overriding royalty interest net in revenue in the Consolidated Statement of Operations. As discussed in Note 2, the Everlast financial statements have been corrected to reflect this method of accounting.

Amounts due to the Trust with respect to NPI are comprised of the sum of the Net Proceeds and the Infill Net Proceeds, which are described below.

The Net Proceeds equal the lesser of (i) 95% of the net proceeds from 393 producing wells at the Properties and (ii) the net proceeds from the sale of 912.5 MMcf of natural gas for the quarter. Net proceeds equal gross proceeds, currently calculated by reference to the gas purchase contract (for a description of the gas purchase contract, please read “Business—Natural Gas Data—Torch Royalty NPI—The Gas Purchase Contract), less specified costs attributable to the Properties. The specified costs deducted for purposes of calculating net proceeds for purposes of clause (i) of the first sentence of this paragraph (the “NPI Net Proceeds Calculation”) include: (a) delay rentals, shut-in royalties and similar payments, (b) property, production, severance and similar taxes and related audit charges, (c) specified refunds, interest or penalties paid to purchasers of hydrocarbons or governmental agencies, (d) certain liabilities for environmental damage, personal injury and property damage, (e) certain litigation costs, (f) costs of environmental compliance, (g) specified operating costs incurred to produce hydrocarbons, (h) specified development costs (including costs to increase recoverable reserves or the timing of recovery of such reserves), (i) costs of specified lease renewals and extensions and unitization costs, and (j) the unrecovered portion, if any, of the foregoing costs for preceding time periods plus interest on such unrecovered portion at a rate equal to the base rate (compounded quarterly) as announced from time to time by Citibank, N.A. The specified costs deducted for purposes of calculating net proceeds for purposes of clause (ii) of the first sentence of this paragraph include: (a) property, production, severance and similar taxes, (b) specified refunds, interest or penalties paid to purchasers of hydrocarbons or governmental agencies, and (c) the unrecovered portion, if any, of the foregoing costs for preceding time periods plus interest on such unrecovered portion at a rate equal to the base rate (compounded quarterly) as announced from time to time by Citibank, N.A. Net proceeds are calculated quarterly and any negative balance (expenses in excess of revenues) within the “net proceeds” calculation accumulates and is charged interest as described above.

F-26

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following represent the Net NPI Proceeds Calculation for the periods from January 1, 2003 to December 31, 2005:


	Successor		Predecessor
	CEP		Everlast
	For the period February 7, 2005 (inception) to December 31, 2005		For the period January 1, 2005 to June 12, 2005			For the year ended December 31, 2004			For the year ended December 31, 2003
	(In ‘000’s)		(In ‘000’s)
Gross Proceeds	$	6,098	$	3,034		$	7,241		$	6,922
NPI Costs
Water Handling		1,300		1,020			2,450			2,467
Gathering fees		828		455			1,102			1,085
COPAS		952		666			1,567			1,555
Severance Tax		532		231			547			498
LOE Charge		977		605			1,634			1,322
Capital Expenditures		60		168			709			495
Interest on Previous Negative Balances		59		20			32			10

Total NPI Costs		4,708		3,165			8,041			7,432

Net NPI Proceeds (Deficit)	$	1,390	$	(131	)	$	(800	)	$	(510	)

The cumulative “Net NPI Proceeds” balance must be greater than $0 before any payments are made to the Trust. Payments to the Trust are expected to occur in 2006. The cumulative Net Proceeds Deficits were $0.1 million, $1.4 million, $1.3 million and $0.5 million for the periods ended December 31, 2005 and June 12, 2005 and the years ended December 31, 2004 and 2003. As a result, no payments were made to the Trust with respect to the NPI for any periods presented. With respect to production for the six months ended June 30, 2006, CEP paid the Trust a total of $0.2 million.

The calculation of the Infill Net Proceeds uses the same methodology as the NPI Net Proceeds Calculation described above except that the proceeds and costs are attributable, not to the NPI Net Proceeds Wells, but to the remaining wells that are subject to the NPI and that have been drilled since the Trust was formed and wells that will be drilled (other than wells drilled to replace damaged or destroyed wells), in each case on leases subject to the NPI. The NPI in the Infill Wells entitles the Trust to receive 20% of the Infill Net Proceeds. There has never been a payout on the Infill Net Proceeds. The accumulated deficit as of December 31, 2005 was $0.4 million.

(15) ENVIRONMENTAL LIABILITY

CEP is subject to costs resulting from an increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. As of June 30, 2006 and December 31, 2005 accrued environmental obligations were $0.7 million, of which $0.2 million is current and $0.5 million is noncurrent.

(16) OTHER CONTINGENCIES

On June 7, 2006, CCG and a subsidiary of CEP entered into an agreement with The Investment Company LLC (“TIC”) pursuant to which CCG has agreed to pay TIC $3.1 million for consulting services associated with

F-27

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the acquisition of the Properties if CEP completes an initial public offering on or before October 31, 2006. If the public offering of CEP does not occur prior to November 1, 2006, no payment will be made by CCG, and instead TIC will have the option to purchase a 3% working interest in certain of the Properties at the book value as of that date. This option expires November 30, 2006. If TIC purchases the 3% working interest, a subsidiary of CEP will loan TIC the purchase price, and the loan will be repaid by the net proceeds from production related to the 3% working interest and bear interest at the Citibank, N.A. prime rate. The fair value of this option also approximates $3.1 million. Accordingly, $3.1 million, has been recorded in accrued liabilities as of December 31, 2005 and June 30, 2006 as resolution of this matter related to a claim for prior service that was finalized prior to the issuance of the consolidated financial statements for those periods. The corresponding charge is reflected as “General and administrative” expense in the CEP Statement of Operations for the period ending December 31, 2005.

(17) SUPPLEMENTAL INFORMATION ON GAS PRODUCING ACTIVITIES (UNAUDITED)

(a) Costs

The following table sets forth capitalized costs at December 31, 2005 and December 31, 2004:


	Successor			Predecessor
	CEP			Everlast
	December 31, 2005			December 31, 2004
	(In ‘000’s)			(In ‘000’s)
Capitalized costs at the end of the period: (a)

Natural gas properties and related equipment
(successful efforts method)
Property (acreage) costs
Proved property	$	168,327		$	—
Unproved property		188			—
Natural gas properties and related equipment
(full cost method)
Costs subject to amortization		—			59,651
Costs not subject to amortization		—			123

Total property costs		168,515			59,774

Materials and supplies		712			—

Land		160			160

Total		169,387			59,934
Less: Accumulated depreciation, depletion and amortization		(4,176	)		(7,403	)

Net capitalized cost	$	165,211		$	52,531

(a)

Capitalized costs include the cost of equipment and facilities for our natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for natural gas leaseholds where proved reserves do not exist.

F-28

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table sets forth costs incurred for gas producing activities for the period from February 7, 2005 (inception) to December 31, 2005, for the period from January 1, 2005 to June 12, 2005, and for the years ended December 31, 2004 and 2003:


	Successor		Predecessor
	CEP		Everlast
	For the period February 7, 2005 (inception) to December 31, 2005		For the period January 1, 2005 to June 12, 2005		For the year ended December 31, 2004		For the year ended December 31, 2003
	(In ‘000’s)				(In ‘000’s)
Costs incurred for the period:
Acquisition of properties
Proved	$	158,707	$	201	$	1,310	$	50,877
Unproved		188		—		—		—
Exploration costs		—		—		—		—
Development costs		7,851		3,998		5,674		2,040

Total costs incurred	$	166,746	$	4,199	$	6,984	$	52,917

(b) Results of Operations

The revenues and expenses associated directly with gas producing activities are reflected in the Consolidated Statement of Operations. Substantially all of CEP’s and Everlast’s operations are gas producing activities, and those gas activities are located in a single geographic location.

(c) Net Proved Gas Reserves

The following table sets forth information with respect to changes in CEP’s and Everlast’s proved (i.e., proved developed and undeveloped) reserves. This information excludes reserves related to royalty and net profit interests.


	Successor		Predecessor
Gas (mmcf)	CEP		Everlast
	For the period February 7, 2005 (inception) to December 31, 2005		January 1 to June 12, 2005		2004		2003
	(In ‘000’s)				(In ‘000’s)
Beginning Balance	—		162,215		163,745		—
Extensions and discoveries	—		—		824		—
Purchases of reserves in place	160,245		—		—		168,311
Sales of reserves in place	—		—		—		—
Revisions of previous estimates	(45,695	)	—		2,173		—
Production	(2,525	)	(1,970	)	(4,527	)	(4,566	)

Ending Balance	112,025		160,245		162,215		163,745

Total developed reserves	89,272				101,352		100,681

Reserves and Related Estimates

CEP’s estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.

F-29

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CEP’s 2005 proved reserve estimate is 112.0 Bcf. At year-end, NSAI, an independent petroleum engineering firm, prepared an estimate of CEP’s proved reserves. NSAI also prepared an updated report at our request to provide a sensitivity of the estimates of the NSAI year-end reserves based on our reduced drilling program, our revised refracture program and the elimination of estimated reserves attributable to the NPI. NSAI’s estimates of our 2005 proved reserves is materially consistent with our internal estimate report.

CEP’s 2005 estimates of proved reserves are lower than our predecessor’s estimates of proved reserves primarily because of the following factors:

•

A Reduction of 24.5 Bcf Based on Interpretation of Well Performance: The information on which CEP based this adjustment includes its interpretation of well performance data that was available at December 31, 2005 for new wells drilled and completed in the Robinson’s Bend Field in 2004 and 2005. There was no drilling in the field between 1994 and late 2003. While the performance data at year-end 2005 is from a limited number of new wells drilled in the field in 2004 and 2005, CEP believes it provides relevant information for the purposes of estimating reserves and CEP has interpreted the data and reflected the results of that analysis in its reserve estimates and assumptions. The majority of the 24.5 Bcf reduction in the reserve estimate at December 31, 2005 associated with CEP’s interpretation of the recent well performance data is in the proved developed non-producing (PDNP) category and the proved undeveloped (PUD) categories of reserves.

•

A Reduction of 15.4 Bcf Based on CEP’s Planned Drilling Program: The 112.0 Bcf estimate also reflects CEP’s planned drilling program of 20 gross wells per year for the next six years. CEP uses a six year time horizon for drilling program and reserves estimation purposes because it is consistent with what CEP uses for internal capital expenditure planning purposes and because CEP believes that using a longer time horizon would create additional uncertainty with regard to capital budgeting, therefore potentially reducing its ability to prepare a reliable estimate of reserves. Everlast’s drilling program, which was designed to provide maximum returns in a relatively short time period, was to drill and complete 197 gross wells within a five-year period. CEP’s planned drilling program is designed to provide a steady and constant return by drilling an average of 20 wells per year over a six year period. Due to this difference in drilling programs, certain proved undeveloped reserves that were based on the predecessor’s accelerated drilling program and using NSAI’s reserve assumptions cannot be included in CEP’s proved reserve estimates because under CEP’s current drilling program those reserves are scheduled to be drilled more than six years after the date of the reserve report and as such are outside the time horizon CEP uses to prepare its internal estimates of proved reserves.

•

A Reduction of 5.8 Bcf for Reserves Attributed to the NPI: CEP’s December 31, 2005 reserve estimates removed 5.8 Bcf of reserves that are attributed to the NPI using an overriding royalty interest approach. The estimated reserves attributed to the NPI at December 31, 2004 was zero due to the lower gas prices compared to December 31, 2005 prices.

The 2004 and 2003 proved reserve estimates for the predecessor company are 162.2 Bcf and 163.7 Bcf, respectively. These are the estimates of proved reserves used in the 2004 and 2003 predecessor company financial statements. CEP prepared the estimates of 2004 and 2003 proved reserves for financial statement purposes by starting with NSAI’s December 31, 2005 net proved reserve estimate, which was prepared based upon the predecessor’s accelerated drilling program and reserve assumptions, and rolling back the estimate to year-end 2004 and 2003 by making appropriate adjustments for actual production, prices and development activity. The roll back approach was necessary because the reserve report prepared by NSAI for Everlast as of year-end 2004 was not based on the SEC definition of proved reserves, while the reserve report prepared by

F-30

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NSAI for Everlast as of year-end 2003, which was based on the SEC definition of proved reserves, included different assumptions than those used by NSAI in preparing 2005 proved reserves estimate.

Due to this inconsistency in the preparation of reserve reports for the periods presented, CEP adopted the roll back approach of reserves at December 31, 2005 to year-end 2004 and 2003 in preparing the financial statements for year end 2004 and 2003. In preparing the roll back to year-end 2004 and 2003, CEP did not adjust the estimated proved reserve volumes to reflect its reserve assumptions based upon its interpretation of recent well performance in the Robinson’s Bend Field because these assumptions were based on recent information that was not available to Everlast when it was preparing the 2004 and 2003 financials statements. In addition, CEP did not adjust the volumes to reflect its current drilling program of 20 gross wells per year for the next six years because this drilling program was not the drilling program adopted by Everlast in 2004 and 2003. The previous reserve estimates were 173.4 Bcf in 2004 and 166.2 Bcf in 2003.

(d) Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein

The following table sets forth the standardized measure of the discounted future net cash flows attributable to CEP’s and Everlast’s proved gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.

Future cash inflows are calculated by applying year-end prices of gas, relating to the proved reserves, to the year-end quantities of those reserves. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because CEP and Everlast are both non-taxable entities.

The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present value. In addition, variations from expected production rates could result directly or indirectly from factors outside of CEP’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

The following table summarizes the standardized measure of estimated discounted future cash flows from the natural gas properties:


	Successor			Predecessor
	CEP			Everlast
	December 31, 2005			December 31, 2004			December 31, 2003
	(In ‘000’s)			(In ‘000’s)
Future cash inflows	$	1,125,857		$	984,758		$	973,991
Future production costs		(234,512	)		(235,003	)		(235,370	)
Future estimated development costs		(60,283	)		(93,041	)		(95,678	)

Future net cash flows		831,062			656,714			642,943
10% annual discount for estimated timing of cash flows		(535,627	)		(449,946	)		(448,754	)

Standardized measure of discounted estimated future net cash flows related to proved gas reserves	$	295,435		$	206,768		$	194,189

F-31

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

AND EVERLAST ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows:


	Successor			Predecessor
	CEP			Everlast
	For the period February 7, 2005 (inception) to December 31, 2005			For the year ended December 31, 2004			For the year ended December 31, 2003
	(In ‘000’s)			(In ‘000’s)
Beginning of the period	$	—		$	194,189		$	—
Sales and transfers of natural gas, net of production costs		—			(21,582	)		—
Net changes in prices and production costs related to future production		—			7,790			—
Development costs incurred during the period		—			3,970			—
Changes in extensions and discoveries		—			500			—
Revisions of previous quantity estimates		(54,899	)		3,742			—
Purchase of reserves in place		350,047			—			193,949
Accretion discount		—			19,469			—
Other		287			(1,310	)		240

Standardized measure of discounted future net cash flows related to proved gas reserves	$	295,435		$	206,768		$	194,189

F-32

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC

UNAUDITED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS

Introduction

The unaudited pro forma consolidated financial statements are based upon the historical consolidated statements of financial position and operations of Constellation Energy Partners LLC and its subsidiaries (collectively “CEP”), with respect to the six months ended June 30, 2006, the period from February 7, 2005 through December 31, 2005, and as of June 30, 2006 and Everlast Energy LLC and its subsidiaries (collectively, “Everlast”) with respect to the period from January 1, 2005 through June 12, 2005. CEP commenced its operations on February 7, 2005. It acquired its first natural gas field on June 13, 2005 from Everlast. The properties and assets acquired by CEP from Everlast are referred to herein as the “Properties.” CEP is currently a wholly owned, indirect subsidiary of Constellation Energy Group, Inc. (“CEG”). Two subsidiaries of CEG, Constellation Energy Partners Management, LLC (“CEPM”) and Constellation Energy Partners Holding LLC (“CEPH”), are the direct owners of the outstanding equity interests of CEP. The unaudited pro forma consolidated financial statements for CEP have been derived from the consolidated financial statements of CEP and Everlast set forth elsewhere in this prospectus and are qualified in their entirety by reference to such consolidated financial statements and related notes contained therein. The unaudited pro forma consolidated financial statements have been prepared on the basis that CEP will be treated as a partnership for federal income tax purposes. The unaudited pro forma consolidated financial statements should be read in conjunction with the notes accompanying such financial statements, the historical consolidated financial statements and related notes, and our management’s discussion and analysis set forth elsewhere in this prospectus.

The following unaudited pro forma statement of operations for the six months ended June 30, 2006 and for the year ended December 31, 2005 give effect to the purchase of the Properties and to the transactions described below as if they had occurred on January 1, 2005. The following unaudited pro forma balance sheet as of June 30, 2006 gives effect to the transactions described below as if they had occurred on June 30, 2006. The term “transactions” are defined as the following events.

•

A net borrowing by CEP of $22.0 million under CEP’s new reserve-based credit facility of $100.0 million at an assumed interest rate of 7%. CEP expects to enter into the new reserve-based credit facility prior to the initial public offering.

•

Issuance by CEP of its Class D interests to Constellation Holdings, Inc. (“CHI”) in consideration for a contribution of $8.0 million.

•

The issuance by CEP of 6,275,000 common units at an assumed initial public offering price of $20.00 per common unit (the mid-point of the price range on the cover page of the prospectus) for a total of $117.0 million, which is net of estimated underwriting discounts and commissions of $8.5 million but before deducting estimated expenses of the offering of $3.2 million.

•

The payment by CEP to CEPH of an aggregate cash distribution (currently estimated to be $136.0 million), consisting of (i) $30.0 million borrowed under CEP’s reserve-based credit facility, and (ii) $106.0 million from the estimated proceeds (assuming the mid point of the price range on the cover page of the prospectus) after deducting underwriting discounts and commissions and expenses related to the offering and after giving effect to the retention of $7.8 million for working capital purposes.

•

An equity contribution of $0.5 million will be made prior to the closing of the offering resulting from the distribution of an undivided mineral interest in our properties in the Robinson’s Bend Field for depths below 100 feet below the lowest producing coal seam at April 30, 2006, to an affiliate of Constellation, CEP Equity II, LLC. CEP refers to the mineral interest, which does not fit its investment strategy, as the Floyd Shale Rights.

•

The distribution of excess cash above $7.8 million to CCG including the cash pool receivable balance, which was $12.2 million as of June 30, 2006, will be made prior to the closing of this offering.

The following unaudited financial statements are presented for illustrative purposes only, and do not purport to be indicative of the financial position or results of operations that would actually have occurred if the transactions described occurred as presented in such statements or that may be obtained in the future. In addition, future results may vary significantly from the results in such statements due to factors described in “Risk Factors” included elsewhere in this prospectus.

F-33

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC

UNAUDITED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS

Unaudited Consolidated Pro Forma Statement of Operations


	Everlast Energy LLC			Constellation Energy Partners LLC
	For the period from January 1, 2005 to June 12, 2005			For the period from February 7, 2005 (inception) to December 31, 2005		Pro Forma Adjustments			Pro Forma Year Ended December 31, 2005
	(In ‘000’s, except for unit data)			(In ‘000’s, except for unit data)
Revenues:
Gas sales	$	12,882		$	25,957	$	—		$	38,839
(Loss) from mark-to-market activities		(15,313	)		—		—	(a)		(15,313	)

Total revenues		(2,431	)		25,957		—			23,526

Operating Expenses:
Lease operating expenses		2,769			4,175		—			6,944
Production taxes		676			1,400		—			2,076
General and administrative		594			4,184		—	(b)		4,778
Depreciation, depletion and amortization		1,683			4,176		1,422	(c)		7,281
Accretion expense		46			78		17	(d)		141

Total operating expenses		5,768			14,013		1,439			21,220

Other expenses:
Interest expense, net		2,437			3		(2,434	)(e)		1,546
							1,540	(f)

Total other expenses		2,437			3		(894	)		1,546

Total expenses		8,205			14,016		545			22,766

Net income (loss)	$	(10,636	)	$	11,941	$	(545	)	$	760

Pro Forma Earnings per unit
Earnings per unit									$	.05
Units outstanding										14,170,548

F-34

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC

UNAUDITED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS

Unaudited Consolidated Pro Forma Statement of Operations


	Six Months Ended June 30, 2006			Pro Forma Adjustments			Pro Forma Six Months Ended June 30, 2006
	(In ‘000’s except for unit data)
Revenues:
Gas sales	$	17,605		$	—		$	17,605

Operating Expenses (Income):
Lease operating expenses		3,495			—			3,495
Production taxes		909			—			909
General and administrative		2,731			—	(b)		2,731
Depreciation, depletion and amortization		3,811			—			3,811
Accretion expense		71						71

Total operating expenses		11,017			—			11,017

Other (Income) Expense:
Interest (income) expense, net		(197	)		770	(f)		573

Total other expenses		(197	)		770			573

Total expenses		10,820			770			11,590

Net income (loss)	$	6,785		$	(770	)	$	6,015


Pro Forma Earnings per unit
Earnings per unit							$	0.43
Units outstanding								13,907,798

F-35

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC

UNAUDITED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS

Unaudited Consolidated Pro Forma Balance Sheet


	Historical June 30, 2006			Pro Forma Adjustments			Pro Forma June 30, 2006
	(In ‘000’s)
Assets:
Current assets
Cash and cash equivalents	$	3,880		$	8,000	(g)	$	7,827
					30,000	(h)
					(8,000	)(h)
					(135,977	)(i)
					(3,225	)(i)
					117,029	(j)
					475	(k)
					(4,355	)(l)
Accounts receivable		3,955			—			3,955
Investment in affiliate cash pool		12,199			4,355	(l)		—
					(16,554	)(m)
Prepaid expenses		137			—			137
Risk management assets		603			—			603
Other		1,018			—			1,018

Total current assets		21,792			(8,252	)		13,540

Oil and gas properties:
Natural gas properties and related equipment (successful efforts):
Natural gas properties and related equipment		150,341			—			150,341
Support equipment and facilities		25,637			—			25,637
Materials and supplies		1,291			—			1,291
Less accumulated depreciation, depletion, and amortization		(7,987	)		—			(7,987	)

Net natural properties		169,282			—			169,282
Risk management assets		311			—			311

Total assets	$	191,385		$	(8,252	)	$	183,133

Liabilities and members’ equity:
Liabilities:
Current liabilities:
Accounts payable	$	2,992		$	—		$	2,992
Accrued liabilities		5,812			—			5,812
Royalty payable		1,993			—			1,993

Total current liabilities		10,797			—			10,797
Other liabilities:
Asset retirement obligation		2,609			—			2,609
Environmental liabilities		490			—			490
Debt		52			30,000	(h)		22,052
					(8,000	)(h)
Class D interests		—			8,000	(g)		8,000

Total other liabilities		3,151			30,000			33,151

Total liabilities		13,948			30,000			43,948
Members’ equity					(135,977	)(i)
					(3,225	)(i)
Common members’ equity		176,523			117,029	(j)		138,271
					475	(k)
					(16,554	)(m)
Accumulated other comprehensive income		914			—			914

Total members’ equity		177,437			(38,252	)		139,185

Total liabilities and members’ equity	$	191,385		$	(8,252	)	$	183,133

F-36

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC

NOTES TO UNAUDITED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS

(1) Pro Forma Adjustments and Assumptions:

The adjustments reflected above are as follows:

(a)

Everlast entered into derivative instruments to economically hedge the market price fluctuations of natural gas and accounted for these instruments as mark-to-market activities. As of June 13, 2005, these derivative instruments were in a net liability position. Contemporaneously with the acquisition of the Properties, on June 13, 2005, CEP assigned these derivatives to CCG in exchange for equity in CEP. For the periods subsequent to the June 13, 2005 acquisition by CEP from Everlast through December 31, 2005, CEP held no derivative instruments. On June 20, 2006, CEP entered into hedges as a part of its hedging program;

(b)

no adjustments were made to general and administrative expense to record approximately $1.8 million of CEP’s annual estimated costs associated with annual and quarterly reports to unit holders, annual meeting of unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, fees of independent managers, external accounting fees and legal fees. Other overhead charges, including financial, portfolio management and hedging services performed on CEP’s behalf by CEPM under the management services agreement, other third party consulting fees and reimbursement of affiliate employee and officer compensation expense will comprise approximately an additional $1.1 million of CEP’s estimated annual total general and administrative expenses, which amounts are also not reflected in the pro forma adjustments;

(c)

to record incremental depreciation, depletion and amortization expense resulting from the conversion by CEP to the successful efforts method of accounting from the full cost method of accounting that was used by Everlast, using CEP’s January 1, 2005 reserve estimates and reflecting the new basis in Properties that resulted from CEP’s acquisition of the Properties from Everlast;

(d)

to record additional accretion expense related to CEP’s asset retirement obligations. CEP and Everlast utilized different discount rates, as well as different assumptions, that had a direct impact on the calculation of the beginning balance of the asset retirement obligation;

(e)

to record the elimination of interest expense paid by Everlast related to debt that was not assumed by CEP;

(f)

to record the estimated interest expense on $22.0 million of net borrowing under CEP’s reserve-based credit facility at an assumed interest rate of 7%. CEP expects to incur such borrowing immediately prior to the closing of the initial public offering;

(g)

to record the issuance by CEP of the Class D interests in exchange for the capital contribution to CEP of $8.0 million by CHI. The Class D interests represent CHI’s contribution of capital to address a portion of the risk that, prior to January 1, 2013, the sharing arrangement ceases to be applicable to the calculation of proceeds payable to the Torch Royalty Trust in respect of the net profits interest, which could potentially increase the future amounts payable by CEP to the Trust in respect of the net profits interest. The Class D interests have been classified in the liability section of the accompanying unaudited pro forma balance sheet in accordance with Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Shareholders of Both Liabilities and Equity;

(h)

to record $30.0 million of borrowings under CEP’s new reserve-based credit facility. Immediately following the offering, the $8.0 million contributed to CEP by CHI for the Class D interests will be used to reduce borrowings under the reserved-based credit facility from $30.0 million to $22.0 million;

F-37

Index to Financial Statements

CONSTELLATION ENERGY PARTNERS LLC

NOTES TO UNAUDITED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS

(i)

to record the cash distribution by CEP to CEPH currently estimated to total $136.0 million, consisting of:

(i)

$30.0 million borrowed under CEP’s reserve-based credit facility, and

(ii)

$106.0 million from estimated proceeds of $117.0 million (based on the mid-point of the price range on the cover page of the prospectus), after deducting estimated underwriting discounts and commissions, $3.2 million of estimated expenses related to the offering and $7.8 million retained for working capital purposes;

(j)

to record the assumed proceeds of approximately $117.0 million from the public issuance of 6,275,000 common units at an initial public offering price of $20.00 per common unit (the mid-point of the price range reflected on the cover page of the prospectus), after deducting estimated underwriters’ discounts and commissions of $8.5 million but before subtracting estimated offering expenses of $3.2 million.

(k)

to record the distribution of the Floyd Shale Rights to an affiliate of Constellation, CEP Equity II, LLC, in exchange for $.5 million.

(l)

to record the distribution of excess cash above $7.8 million into the cash pool.

(m)

to record the distribution of the cash pool receivable to CCG.

(2) Pro Forma Earnings Per Unit

CEP expects to declare a distribution (currently estimated to total approximately $136.0 million) to CCG immediately prior to the proposed initial public offering. Because these distributions exceed net income, 5,398,098 and 5,660,848 units were added to the outstanding units to compute the unaudited pro forma basic and diluted earnings per unit for the six months ended June 30, 2006 and for the year ended December 31, 2005, respectively. These units represent the incremental number of units at the expected offering price that would be required to fund the distribution to CCG in excess of net income. The pro forma earnings per unit also includes the impact of the conversion of the sole outstanding member interest of CEP into approximately 8,214,010 common units and 295,690 Class A units to be effective immediately prior to the public offering as well as the impact of our $22.0 million borrowing:

The following table sets forth the calculation of pro forma earnings per unit for the periods presented:


(In ‘000’s except unit data)	Six months ended June 30, 2006		Year ended December 31, 2005
Pro forma net income	$	6,015	$	760
Unit conversion		8,510		8,510
Additional units issued		5,398		5,661

Total units		13,908		14,171

Pro forma earnings per unit	$	0.43	$	0.05

F-38

Index to Financial Statements

APPENDIX A

FORM OF

SECOND AMENDED AND RESTATED

OPERATING AGREEMENT

CONSTELLATION ENERGY PARTNERS LLC

Index to Financial Statements

TABLE OF CONTENTS


ARTICLE 1 DEFINITIONS		1

Section 1.1	Definitions.	1
Section 1.2	Construction.	19

ARTICLE 2 ORGANIZATION		19

Section 2.1	Formation.	19
Section 2.2	Name.	19
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices.	19
Section 2.4	Purposes and Business.	19
Section 2.5	Powers.	20
Section 2.6	Power of Attorney.	20
Section 2.7	Term.	21
Section 2.8	Title to Company Assets.	21

ARTICLE 3 RIGHTS OF MEMBERS		22

Section 3.1	Limitation of Liability.	22
Section 3.2	Members.	22
Section 3.3	Management of Business.	22
Section 3.4	Outside Activities of the Members.	22
Section 3.5	Member Interests.	22
Section 3.6	Respective Voting Rights of Classes of Units and Interests.	23
Section 3.7	Retirement of Class D Interests.	23
Section 3.8	Conversion of Class A and Management Incentive Interests.	23
Section 3.9	Rights of Members.	24

ARTICLE 4 CERTIFICATES; RECORD HOLDERS; TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS		24

Section 4.1	Certificates.	24
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates.	25
Section 4.3	Record Holders.	25
Section 4.4	Transfer Generally.	25
Section 4.5	Registration and Transfer of Member Interests.	26
Section 4.6	Restrictions on Transfers.	26
Section 4.7	Citizenship Certificates; Non-citizen Assignees.	27
Section 4.8	Redemption of Member Interests of Non-citizen Assignees.	28

ARTICLE 5 CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS		28

Section 5.1	Redemption or Exchange of the Pre-IPO Member Interests.	28
Section 5.2	Contributions by CHI and Underwriters.	29
Section 5.3	Interest and Withdrawal.	29
Section 5.4	Capital Accounts.	29
Section 5.5	Issuances of Additional Company Securities.	31
Section 5.6	Limitations on Issuance of Additional Company Securities.	32
Section 5.7	No Preemptive Rights.	32
Section 5.8	Splits and Combinations.	32
Section 5.9	Fully Paid and Non-Assessable Nature of Member Interests.	33
Section 5.10	Registration Rights of CEPM, CEPH and their Affiliates.	33

A-i

Index to Financial Statements


ARTICLE 6 ALLOCATIONS AND DISTRIBUTIONS		35

Section 6.1	Allocations for Capital Account Purposes.	35
Section 6.2	Allocations for Tax Purposes.	39
Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders.	41
Section 6.4	Distributions of Available Cash from Operating Surplus.	42
Section 6.5	Payment of the EP MID.	43
Section 6.6	Distributions of Available Cash from Capital Surplus.	43
Section 6.7	Adjustment of Initial Quarterly Distribution, Target Distribution and Unrecovered Issue Price.	43
Section 6.8	Entity-Level Taxation.	43

ARTICLE 7 MANAGEMENT AND OPERATION OF BUSINESS		44

Section 7.1	Board of Managers.	44
Section 7.2	Certificate of Formation.	47
Section 7.3	Restrictions on the Board of Managers’ Authority.	48
Section 7.4	Officers.	48
Section 7.5	Outside Activities.	50
Section 7.6	Loans or Contributions from the Company or Group Members.	50
Section 7.7	Indemnification.	50
Section 7.8	Exculpation of Liability of Indemnitees.	53
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.	53
Section 7.10	Duties of Officers and Managers.	55
Section 7.11	Purchase or Sale of Company Securities.	55
Section 7.12	Reliance by Third Parties.	55

ARTICLE 8 BOOKS, RECORDS, ACCOUNTING AND REPORTS		56

Section 8.1	Records and Accounting.	56
Section 8.2	Fiscal Year.	56
Section 8.3	Reports.	56

ARTICLE 9 TAX MATTERS		57

Section 9.1	Returns and Information.	57
Section 9.2	Tax Elections.	57
Section 9.3	Tax Controversies.	57
Section 9.4	Withholding.	57

ARTICLE 10 DISSOLUTION AND LIQUIDATION		58

Section 10.1	Dissolution.	58
Section 10.2	Liquidator.	58
Section 10.3	Liquidation.	58
Section 10.4	Cancellation of Certificate of Formation.	59
Section 10.5	Return of Contributions.	59
Section 10.6	Waiver of Partition.	59
Section 10.7	Capital Account Restoration.	59

ARTICLE 11 AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE		59

Section 11.1	Amendment of Operating Agreement.	59
Section 11.2	Amendment Requirements.	61
Section 11.3	Unitholder Meetings.	61
Section 11.4	Notice of Meetings of Members.	62
Section 11.5	Record Date.	62

A-ii

Index to Financial Statements


Section 11.6	Adjournment.	63
Section 11.7	Waiver of Notice; Approval of Meeting.	63
Section 11.8	Quorum; Required Vote for Member Action; Voting for Managers.	63
Section 11.9	Conduct of a Meeting; Member Lists.	64
Section 11.10	Action Without a Meeting.	64
Section 11.11	Voting and Other Rights.	65
Section 11.12	Proxies and Voting.	65
Section 11.13	Notice of Member Business and Nominations.	65

ARTICLE 12 MERGER, CONSOLIDATION OR CONVERSION		68

Section 12.1	Authority.	68
Section 12.2	Procedure for Merger, Consolidation or Conversion.	68
Section 12.3	Approval by Members of Merger, Consolidation or Conversion.	69
Section 12.4	Certificate of Merger; Certificate of Conversion.	70
Section 12.5	Effect of Merger or Conversion.	70
Section 12.6	Business Combination Limitations.	71

ARTICLE 13 RIGHT TO ACQUIRE MEMBER INTERESTS		72

Section 13.1	Right to Acquire Member Interests.	72

ARTICLE 14 GENERAL PROVISIONS		73

Section 14.1	Addresses and Notices.	73
Section 14.2	Further Action.	73
Section 14.3	Binding Effect.	73
Section 14.4	Integration.	73
Section 14.5	Creditors.	73
Section 14.6	Waiver.	73
Section 14.7	Counterparts.	73
Section 14.8	Applicable Law.	74
Section 14.9	Invalidity of Provisions.	74
Section 14.10	Consent of Members.	74

Exhibit A: Form of Common Unit Certificate

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Index to Financial Statements

SECOND AMENDED AND RESTATED OPERATING

AGREEMENT OF CONSTELLATION ENERGY PARTNERS LLC

This SECOND AMENDED AND RESTATED OPERATING AGREEMENT OF CONSTELLATION ENERGY PARTNERS LLC, dated as of , 2006 is entered into by and among Constellation Energy Partners Holdings, LLC (“CEPH”) and Constellation Holdings, Inc. (“CHI”), together with any other Persons who hereafter become Members in Constellation Energy Partners LLC or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

Article 1

DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“12-Quarter Test” requires that, during the First MII Earnings Period:

(a) the Company distributes Available Cash from Operating Surplus to holders of the Outstanding Class A Units and Common Units that on average exceeds the Target Distribution on all of the Outstanding Class A Units and Common Units over the First MII Earnings Period;

(b) Adjusted Operating Surplus, on average, equals to or exceeds 100% of all distributions of Available Cash to holders of the Outstanding Class A Units and Common Units up to the Target Distribution on all of the Outstanding Class A Units and Common Units, plus 117.65% of all such distributions in excess of the Target Distribution on all of the Outstanding Class A Units and Common Units in the First MII Earnings Period; and

(c) the Company does not reduce the amount of Available Cash distributed per Outstanding Class A Unit or Common Unit in respect of any Quarter in the First MII Earnings Period.

“4-Quarter Test” requires that, during each of the last four full, consecutive, non-overlapping Quarters in the First MII Earnings Period:

(a) the Company distributes Available Cash from Operating Surplus to holders of the Outstanding Class A Units and Common Units that exceeds the Target Distribution on all of the Outstanding Class A Units and Common Units;

(b) Adjusted Operating Surplus equals or exceeds 100% of all distributions of Available Cash to holders of the Outstanding Class A Units and Common Units up to the Target Distribution on all of the Outstanding Class A Units and Common Units, plus 117.65% of all such distributions in excess of the Target Distribution on all of the Outstanding Class A Units and Common Units; and

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the asset base of the Company Group from the asset base of the Company Group existing immediately prior to such transaction; provided however, that any acquisition of properties or assets of another Person that is made solely for investment purposes shall not constitute an Acquisition under this Agreement.

Index to Financial Statements

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceed the remaining Additional Book Basis attributable to all of the Company’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (ii) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Company’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Additional Member” means a Member admitted as a member of the Company pursuant to Section 5.5 and who is shown as such on the books and records of the Company.

“Adjusted Capital Account” means the Capital Account maintained for each Member as of the end of each fiscal year of the Company, (a) increased by any amounts that such Member is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year are expected to be made to such Member’s Capital Account in respect of the oil and gas properties of the Company, (ii) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Member in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Member in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Member’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Member in respect of a Common Unit, a Class A Unit, a Management Incentive Interest, a Class D Interest or any other Member Interest shall be the amount that such Adjusted Capital Account would be if such Common Unit, a Class A Unit, a Management Incentive Interest, a Class D Interest or other Member Interest were the only interest in the Company held by such Member from and after the date on which such Common Unit, Class A Unit, Management Incentive Interest, Class D Interest or other Member Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to that period; less (b) any net increase in Working Capital Borrowings with respect to that period (excluding any such borrowings to the extent the proceeds are distributed to the Record Holder of the Class D Interests pursuant to Section 6.3(a)); less (c) any net reduction in cash reserves for Operating Expenditures with

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Index to Financial Statements

respect to that period not relating to an Operating Expenditure made with respect to that period; plus (d) any net decrease in Working Capital Borrowings with respect to that period; plus (e) any net increase in cash reserves for Operating Expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) and clause (b) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.4(d)(i) or Section 5.4(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all Members.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the Board of Managers. The Board of Managers shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Company in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC, as it may be amended, supplemented or restated from time to time.

“Anniversary” has the meaning assigned to such term in Section 11.13(b).

“Assignee” means a Non-citizen Assignee or a Person to whom one or more Member Interests have been transferred in a manner permitted under this Agreement but who has not been admitted as a Substituted Member.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a manager, director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Audit Committee” means a committee of the Board of Managers composed entirely of Independent Managers.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of:

(i) all cash and cash equivalents of the Company Group (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of that Quarter; and

(ii) all additional cash and cash equivalents of the Company Group (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned)

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Index to Financial Statements

on hand on the date of determination of Available Cash for that Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter,

(b) less the amount of any cash reserves established by the Board of Managers (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) to

(i) provide for the proper conduct of the business of the Company Group (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs of the Company Group);

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions pursuant to Section 6.3(a), Section 6.4, Section 6.5 and Section 6.6 with respect to any one or more of the next four quarters;

provided, however, that the Board of Managers may not establish cash reserves pursuant to clause (iii) above if the effect of such reserves would be that the Company is unable to distribute the Initial Quarterly Distribution on all Common Units and Class A Units with respect to such Quarter; and provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of that Quarter but on or before the date of determination of Available Cash for that Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that Quarter if the Board of Managers so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Managers” has the meaning assigned to such term in Section 7.1(a).

“Book Basis Derivative Items” means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, or gain, loss, Simulated Gain or Simulated Loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Members pursuant to Section 5.4(d).

“Book-Tax Disparity” means, with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Member’s share of the Company’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Member’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Member’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Members pursuant to Section 5.4(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America, the State of Maryland or the State of Texas shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Member pursuant to Section 5.4. The Capital Account of a Member in respect of a Unit or any other Member Interest shall be the amount that such Capital

A-4

Index to Financial Statements

Account would be if such Unit or other Member Interest were the only interest in the Company held by such Member from and after the date on which such Unit or other Member Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Member contributes to the Company.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new or the improvement of existing, capital assets (including, without limitation, undeveloped leasehold acreage, properties containing estimated proved reserves (whether or not producing), gas gathering systems, natural gas treatment or processing facilities, natural gas liquids fractionation facilities, storage facilities, pipeline systems or other midstream assets or facilities, and other similar assets) or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has an equity interest that is made by such, Group Member to fund the Group Member’s pro rata share of the cost of the acquisition of existing, or the construction of new or the improvement of existing, capital assets (including undeveloped leasehold acreage, properties containing estimated proved reserves (whether or not producing), gas gathering systems, natural gas treatment or processing facilities, natural gas liquids fractionation facilities, storage facilities, pipeline systems or other midstream assets or facilities, and other similar assets), in each case if such addition, improvement, acquisition or construction is made to increase the asset base of the Company Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from asset base of the Company Group or such Person, as the case may be, immediately prior to such addition, improvement, acquisition or construction; provided, however, that any such addition, improvement, acquisition or construction that is made solely for investment purposes shall not constitute a Capital Improvement under this Agreement.

“Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

“Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Members’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Company property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(d)(i) and Section 5.4(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Company properties, as deemed appropriate by the Board of Managers.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding such Manager liable for actual fraud or willful misconduct in its capacity as a manager of the Company.

“CEPH” has the meaning assigned to such term in the preamble to this Agreement.

“CEPM” means Constellation Energy Partners Management, LLC, a Delaware limited liability company.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the Board of Managers, issued by the Company evidencing ownership of one or more Units or (b) a certificate, in such form as may be adopted by the Board of Managers, issued by the Company evidencing ownership of one or more other Company Securities.

“Certificate of Formation” means the Certificate of Formation of the Company filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Formation may be amended, supplemented or restated from time to time.

“Chairman of the Board” has the meaning assigned to such term in Section 7.1(j).

“CHI” has the meaning assigned to such term in the preamble to this Agreement.

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Index to Financial Statements

“Citizenship Certification” means a properly completed certificate in such form as may be specified by the Board of Managers by which an Assignee or a Member certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

“Class A Manager” has the meaning assigned to such term in Section 11.8(d).

“Class A Member Interests” means the Member Interests represented by the Class A Units.

“Class A Unit” means a Unit representing a fractional part of the Member Interests of all Members and, to the extent they are treated as Members hereunder, Assignees, and having the rights and obligations specified with respect to Class A Units in this Agreement. As specified in Section 3.5(a), the Class A Member Interests constitute the Class A Units.

“Class A Unit Majority” means at least a majority of the Outstanding Class A Units, voting together as a single class separate from the Common Units and any other Member Interest or Company Securities.

“Class B Manager” has the meaning assigned to such term in Section 11.8(d).

“Class B Member Interests” means the Member Interests represented by the Common Units.

“Class C Member Interests” means the Member Interests represented by the Management Incentive Interests.

“Class D Interests” means a non-voting Member Interest representing a fractional part of the Member Interests of all Members and, to the extent they are treated as Members hereunder, Assignees, and having the rights and obligations specified with respect to Class D Member Interests in this Agreement. As specified in Section 3.5(d), the Class D Member Interests constitute the Class D Interests.

“Class D Member Interests” means the Member Interests represented by the Class D Units.

“Closing Date” means the first date on which Common Units are sold by the Company to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” for any day means the average of the high bid and low asked prices on such day, regular way, or in the case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system for securities listed or admitted for trading on the principal National Securities Exchange on which the Member Interests of that class are listed or admitted to trading, or if the Member Interests of that class are not listed or admitted for trading on any National Securities Exchange, the last quoted price on that day, or if no quoted price exists, the average of the high bid low asked price on that day in the over-the-counter market, as reported by the Nasdaq National Market or such other system then in use, or, if on any such day such Member Interests of such class are not quoted by any such organization of that type, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Member Interests of such class selected by the Board of Managers, or if on any such day no market maker is making a market in such Member Interests of such class, the fair value of such Member Interests on such day as determined by the Board of Managers.

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Commences Commercial Service” and “Commenced of Commercial Service” shall mean the date a Capital Improvement is first put into commercial service following completion of construction and testing.

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Index to Financial Statements

“Commission” means the United States Securities and Exchange Commission.

“Commodity Hedge Contract” means any commodity exchange, swap, forward, cap, floor, collar or other similar agreement or arrangement, each of which is for the purpose of hedging the exposure of the Company Group to fluctuations in the price of hydrocarbons in their operations and not for speculative purposes.

“Common Unit” means a Unit representing a fractional part of the Member Interests of all Members and, to the extent they are treated as Members hereunder, Assignees, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Class A Unit prior to its conversion into a Common Unit pursuant to this Agreement. As specified in Section 3.5(b), the Class B Member Interests constitute the Common Units.

“Common Unit Majority” means at least a majority of the Outstanding Common Units, voting together as a single class separate from the Class A Units and any other Member Interests or Company Securities.

“Company” means Constellation Energy Partners LLC, a Delaware limited liability company, and any successors thereto.

“Company Group” means the Company and each Subsidiary of the Company, treated as a single consolidated entity.

“Company Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

“Company Security” means any class or series of equity interest in the Company (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Company), including the Units, the Class D Interests and the Management Incentive Interests.

“Conflicts Committee” means a committee of the Board of Managers composed entirely of two or more Managers who are not (a) Officers or employees of the Company or any Subsidiary of the Company, (b) managers, directors, officers or employees of any Affiliate of the Company or (c) holders of any ownership interest in the Company Group other than Common Units, and who also meet the independence standards established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed for trading, which standards are applicable to members of audit committees of boards of directors.

“Constellation” means Constellation Energy Group, Inc., a Maryland corporation, and its successors.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Company. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(x).

“Current Market Price” as of any date of any class of Member Interests listed or admitted to trading on any National Securities Exchange means the average of the daily Closing Prices per Member Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Limited Liability Company Act, 6 Del. C. Section 18-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Delayed 4-Quarter Test” requires that:

(a) the 12-Quarter Test, but not the 4-Quarter Test, has been met in respect of the First MII Earnings Period or any Later MII Earnings Period;

A-7

Index to Financial Statements

(b) the 4-Quarter Test has been met in any MII 4-Quarter Earnings Period; and

(c) the Company distributes Available Cash from Operating Surplus to holders of Outstanding Class A Units and Common Units in an amount that equals or exceeds the Initial Quarterly Distribution on all Outstanding Class A Units and Common Units in each Quarter occurring between the end of the First MII Earnings Period or Later MII Earnings Period, as the case may be, and the beginning of the MII 4-Quarter Earnings Period.

“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“DGCL” means the General Corporation Law of the State of Delaware, 8 Del. C. Section 101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

“Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Member or Assignee does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

“EP MID” means a Management Incentive Distribution equal to 17.65% of the sum of the amounts, if any, by which per Unit distributions of Available Cash from Operating Surplus to the holders of Outstanding Class A Units and Common Units pursuant to Section 6.4(a), during the First MII Earnings Period or Later MII Earnings Period, as the case may be, exceeded the Target Distribution.

“Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.8.

“Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Managers of the Company (with the concurrence of the Conflicts Committee) of the average quarterly Maintenance Capital Expenditures that the Company will need to incur over the long term to maintain the asset base of the Company Group existing at the time the estimate is made. The Board of Managers of the Company (with the concurrence of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future Estimated Maintenance Capital Expenditures. The Company shall disclose to its Members any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements. Expansion Capital Expenditures shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Expansion Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction of a Capital Improvement and paid during the period beginning on the date that the Company enters into a binding obligation to commence construction of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service or the date that such Capital Improvement is abandoned or disposed of. Debt incurred or equity issued to fund such construction period interest payments or such construction period distributions on equity paid during such period, shall also be deemed to be debt incurred or equity issued, as the case may be, to finance the construction of a Capital Improvement. Where capital expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the Board of Managers, with the concurrence of the Conflicts Committee, shall determine the allocation between the amounts paid for each.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor for such statute.

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Index to Financial Statements

“Final Adjudication” has the meaning assigned to such term in Section 7.7(e).

“First MII Earnings Period” means the 12 full, consecutive, non-overlapping Quarters that begin with the first Quarter in respect of which the Company distributes per Unit Available Cash from Operating Surplus to holders of the Outstanding Class A Units and Common Units in an amount equal to or greater than the Target Distribution.

“Gas Purchase Contract” means the Oil and Gas Purchase Contract, dated October 1, 1993, by and between Torch Energy Marketing, Inc., Torch Royalty Company and Velasco Gas Company, L.P., including the Sharing Arrangement provided in Article IV thereunder.

“Group” means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to ten or more Persons), exercising investment power or disposing of any Member Interest with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Member Interests.

“Group Member” means a member of the Company Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Company, that is a limited or general partnership, the limited liability company or operating agreement of any Group Member, other than the Company, that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Holder” has the meaning assigned to such term in Section 5.10(a).

“Indemnified Persons” has the meaning assigned to such term in Section 5.10(c).

“Indemnitee” means (a) any Person who is or was a Manager, Officer or other employee of the Company or a Tax Matters Partner of the Company, (b) any Person who is or was a member, partner, manager, director, officer, fiduciary or trustee of any Group Member (other than the Company) or any Affiliate of a Group Member (other than the Company), (c) any Person who is or was serving at the request of the Company as a director, manager, officer, tax matters partner, fiduciary or trustee of another Person; provided that a Person shall not be an “Indemnitee” by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services and (d) any Person that the Company designates as an “Indemnitee” for purposes of this Agreement.

“Independent Manager” means a Manager who meets the independence and other standards required of the members of the audit committee of a board of directors, which standards are established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed for trading.

“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Members” means CEPH (with respect to the Common Units, the Class A Units and Management Incentive Interests received by it pursuant to Section 5.1), CHI with respect to the Class D Interests received by it pursuant to Section 5.2(a) and the Underwriters with respect to the Common Units issued to the Underwriters as described in Section 5.2(b) and Section 5.2(c) in connection with the Initial Offering, in each case upon being admitted to the Company in accordance with this Agreement.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

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Index to Financial Statements

“Initial Operating Agreement” means the Operating Agreement of Constellation Energy Resources LLC (formerly CBM Equity IV Holdings, LLC), dated as of February 7, 2005, as amended through the date of this Agreement, including by the Amended and Restated Operating Agreement of Constellation Energy Resources LLC, dated as of May 9, 2006.

“Initial Quarterly Distribution” means $0.425 per Common Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2006, it means the product of $0.425 multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Section 6.7 and Section 6.8.

“Initial Unit Price” means (a) with respect to the Common Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Company Securities, the price per Unit at which such class or series of Company Securities is initially sold by the Company, as determined by the Board of Managers, in each case adjusted as the Board of Managers determines to be appropriate to give effect to any distribution, subdivision or combination of Company Securities.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the exercise of the Over-Allotment Option); and (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) the termination of Commodity Hedge Contracts and interest rate swap agreements prior to their respective specified termination dates; (e) capital contributions received; and (f) corporate organizations and restructurings.

“Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

“Issue Price” means the price at which a Unit is purchased from the Company, after taking into account any sales commission or underwriting discount charged to the Company by the Underwriters.

“Later MII Earnings Period” means, if the 12-Quarter Test is not met with respect to the First MII Earnings Period, the 12 full, consecutive, non-overlapping Quarters in respect of which the Company distributes per Unit Available Cash from Operating Surplus to holders of Outstanding Class A Units and Common Units in an amount equal to or greater than the Target Distribution commencing with the Quarter during the First MII Earnings Period either (a) after the Quarter in which the 12-Quarter Test is not met or (b) in which the reduction that caused the Company to fail to satisfy clause (c) of the definition of the 12-Quarter Test occurs.

“Liquidation Date” means the date on which an event giving rise to the dissolution of the Company occurs.

“Liquidator” means one or more Persons selected by the Board of Managers to perform the functions described in Section 10.2 as liquidating trustee of the Company within the meaning of the Delaware Act.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures for the addition or improvement to the asset base owned by any Group Member (including plugging and abandonment costs) or for the acquisition of existing, or the construction or development of new, capital assets, including, without limitation, undeveloped leasehold acreage, properties containing estimated proved reserves, gas gathering systems, natural gas treatment or processing facilities, natural gas liquids fractionation facilities, storage

A-10

Index to Financial Statements

facilities, pipeline facilities or other midstream assets or facilities and other similar assets) if such expenditure is made to maintain, including over the long term, the asset base of the Company Group. Maintenance Capital Expenditures shall not include (a) Expansion Capital Expenditures or (b) Investment Capital Expenditures. Maintenance Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction or development of a replacement asset and paid during the period beginning on the date that the Company enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued to fund construction or development period interest payments, or such construction or development period distributions on equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset.

“Management Incentive Distribution” means any distribution made to the holder of the Management Incentive Interests pursuant to Section 6.4(b)(iii)(C) or Section 6.5.

“Management Incentive Interests” means the non-voting Member Interest having the rights and obligations specified with respect to Management Incentive Interests in this Agreement. As specified in Section 3.5(c), the Class C Member Interests constitute the Management Incentive Interests. The holder(s) of the Management Incentive Interests have the right to receive any Management Incentive Distributions.

“Management Services Agreement” means the Management Services Agreement to be entered into on or prior to the Closing Date between CEPM, Constellation Energy Group, Inc. and the Company, as the same may be amended or supplemented during the term of this Agreement.

“Manager” means a member of the Board of Managers.

“Member” means, unless the context otherwise requires, (a) each Initial Member, Substituted Member and Additional Member or (b) solely for purposes of Articles 5, 6, 7, 9, 11 and 12, each Assignee; provided, however, that when the term “Member” is used herein in the context of any vote or approval, including in Articles 11 and 12, such term shall not, solely for such purpose, include any holder of the Management Incentive Interests or Class D Interests (in each case solely with respect to such Management Incentive Interests or Class D Interests and not with respect to any other Member Interest held by such Person) except as required by law.

“Member Interest” means the ownership interest of a Member or Assignee in the Company, which may be evidenced by Units, Management Incentive Interests, Class D Interests or other Company Securities or a combination thereof or interest therein, and includes any and all benefits to which such Member or Assignee is entitled as provided in this Agreement, together with all obligations of such Member or Assignee to comply with the terms and provisions of this Agreement; provided however, that when the term “Member Interest” is used herein in the context of any vote or approval, including Article 11 and Article 12, such term shall not, solely for such purpose, include any Management Incentive Interests or Class D Interests except as may be required by applicable law.

“Member Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Member Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Member Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Member Nonrecourse Debt.

“Merger Agreement” has the meaning assigned to such term in Section 12.1.

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Index to Financial Statements

“MII 4-Quarter Earnings Period” means any four full, consecutive and non-overlapping Quarters occurring after the end of the First MII Earnings Period or Later MII Earnings Period, as the case may be, up to three of which Quarters can fall within the First MII Earnings Period or Later MII Earnings Period, as the case may be.

“MII Tests” means both the 12-Quarter Test and 4-Quarter Test.

“MII Vesting Period” means the period commencing with the Closing Date and ending on the expiration of the earliest to occur of:

(a) the First MII Earnings Period, if both the 12-Quarter Test and 4-Quarter Test are met with respect to the First MII Earnings Period;

(b) the Later MII Earnings Period, if both the 12-Quarter Test and 4-Quarter Test are met with respect to the Later MII Earnings Period; and

For the avoidance of doubt, the MII Vesting Period shall end as of the close of business on the last day of the Quarter in respect of which clause (a), (b) or (c) of this definition is satisfied.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Exchange Act of 1934 and any successor to such statute.

“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Company upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Member or Assignee by the Company, the Company’s Carrying Value of such property (as adjusted pursuant to Section 5.4(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Member or Assignee upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

“Net Income” means, for any taxable year, the excess, if any, of the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xi) were not in this Agreement.

“Net Loss” means, for any taxable year, the excess, if any, of the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xi) were not in this Agreement.

“Net Positive Adjustments” means, with respect to any Member, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Member pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of

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Index to Financial Statements

Net Termination Gain shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Non-citizen Assignee” means a Person whom the Board of Managers has determined does not constitute an Eligible Citizen, pursuant to Section 4.7.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Members pursuant to Section 6.2(c)(iii), Section 6.2(d)(i)(A), Section 6.2(d)(ii)(A) and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 13.1(b).

“NPI” means the “Net Royalty Interest” as that term is defined in the Net Profits Overriding Royalty Conveyance, dated November 22, 1993, but effective as of October 1, 1993 from, pursuant to Part I thereof, Velasco Gas Company, L.P. to Torch Energy Advisors Incorporated and, pursuant to Part II thereof, from Torch Energy Advisors Incorporated to the Trust.

“Officers” has the meaning assigned to such term in Section 7.4(a).

“Omnibus Agreement” means the Omnibus Agreement among Constellation Energy Commodities Group, Inc., the Company, Robinson’s Bend II Operating, LLC, Robinson’s Bend II Marketing, LLC and Robinson’s Bend II Production, LLC dated , 2006.

“Operating Companies” means (i) Robinson’s Bend II Marketing, LLC, a Delaware limited liability company, (ii) Robinson’s Bend II Production, LLC, a Delaware limited liability company, (iii) Robinson’s Bend II Operating, LLC, a Delaware limited liability company, and (iv) any other operating Subsidiaries of the Company and any successors thereto.

“Operating Expenditures” means all Company Group expenditures (or the Company’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes, amounts paid under the Management Services Agreement, payments made in the ordinary course of business under Commodity Hedge Contracts (excluding payments made in connection with the termination of any Commodity Hedge Contract prior to the expiration of its terms), provided that with respect to amounts paid in connection with the initial purchase or placing of a Commodity Hedge Contract, such amounts shall be amortized over the life of the applicable Commodity Hedge Contract and upon its termination, if earlier, Manager and Officer compensation, compensation paid to members of the Board of Managers, repayment of Working Capital Borrowings, debt service payments, and Estimated Maintenance Capital Expenditures, subject to the following:

(a) Repayment of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (c)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid.

(b) Payments (including prepayments) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures.

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Index to Financial Statements

(c) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) actual Maintenance Capital Expenditures, (iii) Investment Capital Expenditures, (iv) payment of transaction expenses (which, with respect to the termination of a Commodity Hedge Contract prior to its stipulated settlement or termination date, such transaction expenses shall constitute any payments due from any Group Member upon such settlement or termination) relating to Interim Capital Transactions, (v) distributions to Members (including distributions in respect of the Class D Interests and any Management Incentive Distributions) or (vi) non-Pro Rata repurchases of Units of any class made with proceeds of a substantially concurrent equity issuance.

(d) Where capital expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the Board of Managers, with the concurrence of the Conflicts Committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for Maintenance Capital Expenditures, the period over which such Maintenance Capital Expenditures will be included in Estimated Maintenance Capital Expenditures and deducted as an Operating Expenditure in calculating Operating Surplus.

“Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of (i) $20.0 million, (ii) all cash receipts of the Company Group (or the Company’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, excluding cash receipts from Interim Capital Transactions (except to the extent specified in ), (iii) all cash receipts of the Company Group (or the Company’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings and (iv) cash distributions paid on equity issued to finance all or a portion of the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset (such as equipment or reserves) during the period beginning on the date that the Group Member enters into a binding obligation to commence the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset and ending on the earlier to occur of the date the Capital Improvement or capital asset Commences Commercial Service or the date that it is abandoned or disposed of (equity issued to fund construction period interest payments on debt incurred, or construction period distributions on equity issued, to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)); plus

(b) if the right to receive distributions (other than distributions in liquidation) on the Class D Interests terminates before December 31, 2012, the excess of the amount of the original $8.0 million contribution by CHI for the Class D Interests over the cumulative cash distributions paid on the Class D Interests before such termination shall be included in Operating Surplus, such inclusion to occur over a series of quarters with the amount included in each Quarter to be equal to the amount of the payment a Group Member makes to the Trust in respect of the NPI for such Quarter that would not have been paid but for termination of the Sharing Arrangement under the Gas Purchase Contract; less

(i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period;

(ii) the amount of cash reserves established by the Board of Managers (or the Company’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to provide funds for future Operating Expenditures; and

(iii) all Working Capital Borrowings not repaid within twelve months after having been incurred;

provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been

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Index to Financial Statements

made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the Board of Managers so determines.

Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Company or any of its Affiliates) acceptable to the Board of Managers.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Company to the Underwriters upon exercise of the Over-Allotment Option.

“Outstanding” means, with respect to Company Securities, all Company Securities that are issued by the Company and reflected as outstanding on the Company’s books and records as of the date of determination; provided, however, that (i) no Company Securities held by the Company or any other Group Member shall be considered Outstanding and (ii) if at any time any Person or Group (other than CEPM or CEPH or their Affiliates) beneficially owns 20% or more of any Outstanding Company Securities of any class then Outstanding, all Company Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Members to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, provided that the foregoing limitation shall not apply to any Person or Group who acquired 20% or more of any Outstanding Company Securities of any class then Outstanding directly from CEPM or CEPH or their Affiliates with the prior approval of the Board of Managers.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Company pursuant to the Underwriting Agreement.

“Percentage Interest” means, as of any date of determination (a) as to any Unitholder holding Class A Units, the product obtained by multiplying (i) 2% by (ii) the quotient obtained by dividing (A) the number of Class A Units held by such Unitholder by (B) the total number of Outstanding Class A Units; (b) as to any Unitholder holding Common Units, the product obtained by multiplying (i) 98% by (ii) the quotient obtained by dividing (A) the number of Common Units held by such Unitholder by (B) the total number of all Outstanding Common Units, and (c) as to the holders of other Company Securities issued by the Company in accordance with Section 5.5, the percentage established as a part of such issuance.

“Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization or other enterprise (including an employee benefit plan), association, government agency or political subdivision thereof or other entity.

“Plan of Conversion” has the meaning assigned to the term in Section 12.1.

“Pre-IPO Member Interest” shall have the meaning assigned to such term in Section 3.5(a).

“Prime Rate” means the prime rate of interest as quoted from time to time by the Wall Street Journal or another source reasonably selected by the Company.

“Pro Rata” means (a) when modifying Units or any class thereof, apportioned equally among all such Units, in accordance with their relative Percentage Interests, (b) when modifying other Member Interests with respect to which a Percentage Interest is assigned, apportioned equally among such class of Member Interests in accordance with their Percentage Interests, (c) when modifying other Member Interests with respect to which a Percentage Interest is not assigned, apportioned among the holders of such Member Interests based upon the ratio that each

A-15

Index to Financial Statements

Member’s share of such Member Interests bears to the total of such Member Interest, and (d) when modifying Members, apportioned among all designated Members in accordance with their relative Percentage Interest.

“Purchase Date” means the date determined by the Board of Managers as the date for purchase of all Outstanding Units of a certain class pursuant to Article 13.

“Quarter” means, unless the context requires otherwise, a fiscal quarter, or, with respect to the first fiscal quarter after the Closing Date, the portion of such fiscal quarter after the Closing Date, of the Company.

“Recapture Income” means any gain recognized by the Company (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Company, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the Company for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Members or entitled to exercise rights in respect of any lawful action of Members or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Company Securities, the Person in whose name any such other Company Security is registered on the books that the Company has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Member Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.8.

“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-134995) as it has been or as it may be amended or supplemented from time to time, filed by the Company with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, with respect to the Unitholders, the excess of (i) the Net Positive Adjustments of the Unitholders as of the end of such period over (ii) the sum of those Members’ Share of Additional Book Basis Derivative Items for each prior taxable period.

“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) and Section 6.1(c) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii) or Section 6.1(d)(ix).

“Residual Gain” or “Residual Loss” means any item of gain or loss or Simulated Gain or Simulated Loss, as the case may be, of the Company recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or Section 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, with respect to the Unitholders, the amount that bears the

A-16

Index to Financial Statements

same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

“Sharing Arrangement” means the method of calculating the price at which natural gas is sold pursuant to Article IV of the Gas Purchase Contract.

“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property were its adjusted tax basis) and in the manner specified in Treasury Regulation §1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Solicitation Notice” has the meaning assigned to such term in Section 11.13(c).

“Special Approval” means approval by a majority of the members of the Conflicts Committee.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Substituted Member” means a Person who is admitted as a Member pursuant to Section 4.5 in place of and with all rights of a Member and who is shown as a Member on the books and records of the Company.

“Surviving Business Entity” has the meaning assigned to such term in Section 12.2(b)(ii).

“Suspension Period” has the meaning assigned to such term in Section 6.3(b).

“Target Distribution” has the meaning assigned to such term in Section 6.4(b)(ii).

“Tax Matters Partner” means the Tax Matters Partner as defined in the Code.

“Trademark License” means the Trademark License Agreement dated as of the Closing Date by and between Constellation and the Company, as the same may be amended or supplemented during the term of this Agreement.

“Trading Day” means a day on which the principal National Securities Exchange on which Member Interests of any class are listed or admitted to trading is open for the transaction of business or, if Member

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Index to Financial Statements

Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” has the meaning assigned to such term in Section 4.4.

“Transfer Agent” means such bank, trust company or other Person (including the Company or one of its Affiliates) as shall be appointed from time to time by the Company to act as registrar and transfer agent for the Common Units; provided that if no Transfer Agent is specifically designated for any other Company Securities, the Company shall act in such capacity.

“Trust” means Torch Energy Royalty Trust.

“Trust Wells” means the natural gas wells in the Robinson’s Bend Field in the Black Warrior Basin in Alabama in which the Company Group owns an interest and that are burdened by the NPI.

“Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement, dated October , 2006, among the Underwriters, the Company and certain other parties, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Company security that is designated as a “Unit” and shall include Class A Units and Common Units but shall not include Class D Interests or the Management Incentive Interests.

“Unit Majority” means at least a majority of the Outstanding Common Units and Class A Units, voting together as a single class.

“Unitholders” means the holders of Units.

“Unrealized Gain” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date).

“Unrealized Loss” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(d))

“Unrecovered Capital” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of such Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Company theretofore made in respect of such Unit, adjusted as the Board of Managers determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“Unrecovered Issue Price” means at any time, with respect to an Initial Common Unit, the Initial Issue Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the

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Index to Financial Statements

dissolution and liquidation of the Company theretofore made in respect of an Initial Common Unit, adjusted as the Board of Managers determines to be appropriate to give effect to any distribution, subdivision or combination of such Common Units.

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Members made pursuant to a credit facility, commercial paper facility or other similar financing arrangement, provided that when it is incurred it is the intent of the borrower to repay such borrowings within 12 months from other than Working Capital Borrowings.

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “include” or “includes” means includes, without limitation, and “including” means including, without limitation.

Article 2

ORGANIZATION

Section 2.1 Formation.

The Company has previously been formed as a limited liability company pursuant to the provisions of the Delaware Act. CEPH and CHI hereby amend and restate the Initial Operating Agreement in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Members and the administration, dissolution and termination of the Company shall be governed by the Delaware Act. All Member Interests shall constitute personal property of the owner thereof for all purposes and a Member has no interest in specific Company property.

Section 2.2 Name.

The name of the Company shall be Constellation Energy Partners LLC. The Company’s business may be conducted under any other name or names, as determined by the Board of Managers. The words “Limited Liability Company,” “LLC,” or similar words or letters shall be included in the Company’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The Board of Managers may change the name of the Company at any time and from time to time and shall notify the Members of such change in the next regular communication to the Members.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the Board of Managers, the registered office of the Company in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Company in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Company shall be located at 111 Market Place, Baltimore, Maryland 21202 or such other place as the Board of Managers may from time to time designate by notice to the Members. The Company may maintain offices at such other place or places within or outside the State of Delaware as the Board of Managers determines to be necessary or appropriate.

Section 2.4 Purposes and Business.

The purpose and nature of the business to be conducted by the Company shall be to (a) serve as a member, partner or stockholder, as the case may be, of, and hold limited liability company interests, partnership (whether

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general or limited) interests or stock, as the case may be, in the Operating Companies and, in connection therewith, to exercise all the rights and powers conferred upon the Company as a member or stockholder, as the case may be, of such entities, (b) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that the Operating Companies are permitted to engage in or that their Subsidiaries are permitted to engage in by their organizational documents or agreements and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity, (c) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the Board of Managers and that lawfully may be conducted by a limited liability company organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity; and (d) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the Company shall not engage, directly or indirectly, in any business activity that the Board of Managers determines would cause the Company to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. The Board of Managers has no obligation or duty to the Company or the Members to propose or approve, and may decline to propose or approve, the conduct by the Company of any business.

Section 2.5 Powers.

The Company shall be empowered to do any and all acts and things necessary and appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Company.

Section 2.6 Power of Attorney.

Each Member and Assignee hereby constitutes and appoints each of the Chief Executive Officer, the President and the Secretary and, if a Liquidator shall have been selected pursuant to Section 10.2, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(a) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices:

(i) all certificates, documents and other instruments (including this Agreement and the Certificate of Formation and all amendments or restatements hereof or thereof) that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Company as a limited liability company in the State of Delaware and in all other jurisdictions in which the Company may conduct business or own property;

(ii) all certificates, documents and other instruments that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement;

(iii) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the Board of Managers, such Officer or the Liquidator determines to be necessary or appropriate to reflect the dissolution, liquidation and termination of the Company pursuant to the terms of this Agreement;

(iv) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Member pursuant to, or other events described in, Article 4 or Article 10;

(v) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Company Securities issued pursuant to Section 5.5;

(vi) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Company pursuant to Article 12; and

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(b) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the Board of Managers or the Liquidator determines to be necessary or appropriate to (i) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Members hereunder or is consistent with the terms of this Agreement or (ii) effectuate the terms or intent of this Agreement; provided, that when required by Section 11.2 or any other provision of this Agreement that establishes a percentage of the Members or of the Members of any class or series required to take any action, the Chief Executive Officer, President or Secretary, or the Liquidator, may exercise the power of attorney made in this Section 2.6(b) only after the necessary vote, consent or approval of the Members or of the Members of such class or series, as applicable.

Nothing contained in this Section 2.6 shall be construed as authorizing the Chief Executive Officer, President or Secretary, or the Liquidator, to amend this Agreement except in accordance with Article 11 or as may be otherwise expressly provided for in this Agreement.

(c) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Member or Assignee and the transfer of all or any portion of such Member’s or Assignee’s Member Interest and shall extend to such Member’s or Assignee’s heirs, successors, assigns and personal representatives. Each such Member or Assignee hereby agrees to be bound by any representation made by the Chief Executive Officer, President or Secretary, or the Liquidator, acting in good faith pursuant to such power of attorney; and each such Member or Assignee, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the Chief Executive Officer, President or Secretary, or the Liquidator, taken in good faith under such power of attorney. Each Member or Assignee shall execute and deliver to the Chief Executive Officer, President or Secretary, or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as any of such Officers or the Liquidator, determines to be necessary or appropriate to effectuate this Agreement and the purposes of the Company.

Section 2.7 Term.

The Company’s term shall be perpetual, unless and until it is dissolved in accordance with the provisions of Article 10. The existence of the Company as a separate legal entity shall continue until the cancellation of the Certificate of Formation as provided in the Delaware Act.

Section 2.8 Title to Company Assets.

Title to Company assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Company as an entity, and no Member, Manager or Officer, individually or collectively, shall have any ownership interest in such Company assets or any portion thereof. Title to any or all of the Company assets may be held in the name of the Company, one or more of its Affiliates or one or more nominees, as the Board of Managers may determine. The Company hereby declares and warrants that any Company assets for which record title is held in the name of one or more of its Affiliates or one or more nominees shall be held by such Affiliates or nominees for the use and benefit of the Company in accordance with the provisions of this Agreement; provided, however, that the Board of Managers shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the Board of Managers determines that the expense and difficulty of conveyancing makes transfer of record title to the Company impracticable) to be vested in the Company as soon as reasonably practicable. All Company assets shall be recorded as the property of the Company in its books and records, irrespective of the name in which record title to such Company assets is held.

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Article 3

RIGHTS OF MEMBERS

Section 3.1 Limitation of Liability.

As provided in Section 18-303 of the Delaware Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and liabilities of the Company. The Members shall have no liability under this Agreement, or for any such debt, obligation or liability of the Company, in their capacity as a Member, except as expressly required in this Agreement or the Delaware Act.

Section 3.2 Members.

(a) Other than with regard to the Initial Members, a Person shall be admitted as a Member and shall become bound by the terms of this Agreement if such Person purchases or otherwise lawfully acquires any Member Interest and becomes the Record Holder of such Member Interest in accordance with the provisions of Article 4 hereof. A Person may become a Record Holder without the consent or approval of any of the Members. A Person may not become a Member without acquiring a Member Interest. Notwithstanding the foregoing, the rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.7 hereof.

(b) The name and mailing address of each Member shall be listed on the books and records of the Company maintained for such purpose by the Company or the Transfer Agent. The Secretary of the Company shall update the books and records of the Company from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Member’s Interest may be represented by a Certificate, as provided in Section 4.1 hereof.

(c) Members may not be expelled from or removed as Members of the Company other than in accordance with Section 4.7 or Section 4.8. Members shall not have any right to resign from the Company; provided, that when a transferee of a Member’s Interest becomes a Record Holder of such Member Interest, such transferring Member shall cease to be a member of the Company with respect to the Member Interest so transferred.

Section 3.3 Management of Business.

No Member, in its capacity as such, shall participate in the operation or management of the Company’s business, transact any business in the Company’s name or have the power to sign documents for or otherwise bind the Company by reason of being a Member.

Section 3.4 Outside Activities of the Members.

Any Member shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Company, including business interests and activities in direct competition with the Company Group. Neither the Company nor any of the other Members shall have any rights by virtue of this Agreement in any business ventures of any Member.

Section 3.5 Member Interests.

(a) Pursuant to the terms of the Initial Operating Agreement, a single Member Interest is issued and outstanding as of the date of this Agreement, which Member Interest constitutes 100% of the Member Interests (the “Pre-IPO Member Interest”). The Pre-IPO Member Interest is owned of record by CEPH. Immediately prior to the closing of the Initial Offering, the Pre-IPO Member Interest will be converted into and exchanged for [295,690] Class A Units, [8,214,010] Common Units and the Management Incentive Interests, such conversion and exchange to be effected in accordance with Section 5.1. Concurrently with the closing of the Initial Offering, on the Closing Date the Company will issue to CHI the Class D Interests, such issuance to be effected in accordance with Section 5.2(a). At the closing of the Initial Offering, the Company will issue to the Underwriters (i) the number of Common Units determined in accordance with Section 5.2(b), such issuance to be effected in accordance with Section 5.2(b), and (ii) if the Over-Allotment Option is exercised and the closing of such

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exercise occurs concurrently with closing of the Initial Offering, such additional number of Common Units as is determined in accordance with Section 5.2(c). The rights and obligations of the Class A Units, Common Units, Management Incentive Interests and Class D Interests shall be as specified in this Agreement.

(b) Immediately after the closing of the Initial Offering and as a result of the transactions referred to in Section 3.5(a), the Member Interests of the Company shall be comprised of four classes of Company Securities. The Class A Member Interests and Class B Member Interests shall be issued in equal, whole unit increments. Pursuant to the transactions to be effected on the Closing Date, the Company will issue the following:

(i) up to [295,690] Class A Units representing Class A Member Interests;

(ii) up to [15,430,260] Common Units representing Class B Member Interests;

(d) Class D Member Interests which constitute, and are referred to herein as, the Class D Interests.

Section 3.6 Respective Voting Rights of Classes of Units and Interests.

(a) The Record Holder(s) of a Class A Unit(s) who have been admitted as Members of the Company in respect of such Class A Unit(s) shall have one vote per Class A Unit and be entitled to vote on all matters with respect to which a holder of Class A Units is entitled to vote under this Agreement.

(b) The Record Holder(s) of a Common Unit(s) who have been admitted as Members of the Company in respect of such Common Unit(s) shall have one vote per Common Unit and be entitled to vote on all matters with respect to which a holder of Common Units is entitled to vote under this Agreement.

(c) The Management Incentive Interests and Class D Interests shall constitute non-voting Member Interests in the Company except to the extent required by applicable law.

(d) A holder of any Unit who has not been admitted as a Member in accordance with this Agreement shall not be entitled to vote on any matters, and any Member who becomes a Non-citizen Assignee shall be subject to the voting restrictions set forth in Section 4.7.

(e) Except as set forth in this Agreement or as required by law, holders of Units and other Member Interests or Company Securities shall have no voting rights and their consent shall not be required for taking any action, including the merger, consolidation or conversion of the Company.

Section 3.7 Retirement of Class D Interests.

The Outstanding Class D Interests shall be automatically canceled and retired, and any rights of any holder of any Class D Interests shall be canceled, upon the payment by the Company of the final quarterly Management Incentive Distribution of $333,341 for the Quarter ending December 31, 2012 pursuant to Section 6.3(b), provided that such cancellation and retirement shall not occur if quarterly cash distributions in respect of the Class D Interests cease to be made in accordance with the second or third paragraph of Section 6.3(b).

Section 3.8 Conversion of Class A and Management Incentive Interests.

Concurrently with any termination of the right of the holder(s) of the Class A Unit(s) to elect Class A Managers pursuant to Section 11.8(e) that is not supported by the affirmative vote of any Common Units held by the holders of a majority of the Outstanding Class A Units or a majority of the Outstanding Management Incentive Interests or their Affiliates, then:

(a) each Outstanding Class A Unit shall automatically convert into, and shall thereafter constitute, one Common Unit; and

(b) the holder(s) of the Management Incentive Interests shall have the right, exercisable upon notice to the Company delivered at any time within 180 days thereafter, to require the conversion by the Company of the

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Management Incentive Interests into a number of Common Units, the fair market value of which is equal to the fair market value of such Management Incentive Interests, as conclusively established by an investment banking firm selected by the Board of Managers.

Section 3.9 Rights of Members.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.9(b), each Member shall have the right, for a lawful purpose reasonably related to such Member’s Member Interest as a Member in the Company, upon reasonable written demand containing a concise statement of such purposes and at such Member’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Company;

(ii) promptly after becoming available, to obtain a copy of the Company’s federal, state and local income tax returns for each year;

(iii) to have furnished to him a current list of the name and last known business, residence or mailing address of each Member;

(iv) to have furnished to him a copy of this Agreement and the Certificate of Formation and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Formation and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Member and that each Member has agreed to contribute in the future, and the date on which each became a Member; and

(vi) to obtain such other information regarding the affairs of the Company as is just and reasonable and consistent with the stated purposes of the written demand.

(b) The Board of Managers may keep confidential from the Members, for such period of time as the Board of Managers determines, (i) any information that the Board of Managers determines to be in the nature of trade secrets or (ii) other information (including the Social Security Number or Tax Identification Number of any Member) the disclosure of which the Board of Managers determines (A) is not in the best interests of the Company Group, (B) could damage the Company Group or (C) that any Group Member is required by law, by the rules of any National Securities Exchange on which any Company Security is listed for trading, or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Company the primary purpose of which is to circumvent the obligations set forth in this Section 3.9).

Article 4

CERTIFICATES; RECORD HOLDERS;

TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS

Section 4.1 Certificates.

Upon the Company’s issuance of Common Units to any Person, the Company may issue one or more Certificates in the name of such Person evidencing the number of such Common Units being so issued. In addition, upon the request of any Person owning any other Company Securities other than Common Units, the Company shall issue to such Person one or more Certificates evidencing such other Company Securities. Certificates shall be executed on behalf of the Company by the Chairman of the Board, President or any Vice President and the Secretary or any Assistant Secretary. No Certificate representing Common Units shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the Board of Managers elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in

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accordance with the directions of the Company. Any or all of the signatures required on the Certificate may be by facsimile. If any Officer or Transfer Agent who shall have signed or whose facsimile signature shall have been placed upon any such Certificate shall have ceased to be such Officer or Transfer Agent before such Certificate is issued by the Company, such Certificate may nevertheless be issued by the Company with the same effect as if such Person were such Officer or Transfer Agent at the date of issue. Certificates shall be consecutively numbered and shall be entered on the books and records of the Transfer Agent as they are issued and shall exhibit the holder’s name and number and type of Company Securities represented thereby.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate Officers on behalf of the Company shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Company Securities as the Certificate so surrendered.

(a) The appropriate Officers on behalf of the Company shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the Company, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the Company has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the Company, delivers to the Company a bond, in form and substance satisfactory to the Company, with surety or sureties and with fixed or open penalty as the Company may direct to indemnify the Company and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the Company.

If a Member fails to notify the Company within a reasonable time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Member Interests represented by the Certificate is registered before the Company or the Transfer Agent receives such notification, the Member shall be precluded from making any claim against the Company or the Transfer Agent for such transfer or for a new Certificate.

(b) As a condition to the issuance of any new Certificate under this Section 4.2, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders.

The Company shall be entitled to recognize the Record Holder as the owner of a Member Interest and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such Member Interest on the part of any other Person, regardless of whether the Company shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Member Interests are listed for trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Member Interests, as between the Company on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Member Interest.

Section 4.4 Transfer Generally.

The term “transfer,” when used in this Agreement with respect to a Member Interest, shall be deemed to refer to any transaction pursuant to which the Company issues any Member Interest or by which the holder of a

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Member Interest assigns such Member Interest to another Person who is or becomes a Member, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage. Other than with respect to an assignment by CEPH of its Class A Units and Management Incentive Interests to CEPM immediately following the execution of this Agreement on the Closing Date no Member Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article 4. Any transfer or purported transfer of a Member Interest not made in accordance with this Article 4 shall be, to the fullest extent permitted by law, null and void.

Section 4.5 Registration and Transfer of Member Interests.

(a) The Company shall keep or cause to be kept on behalf of the Company a register that, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), will provide for the registration and transfer of Member Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Company shall not recognize transfers of Certificates evidencing Member Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Member Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate Officers of the Company shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the Record Holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Member Interests as were evidenced by the Certificate so surrendered.

(b) Except as provided in Section 4.7, the Company shall not recognize any transfer of Member Interests until the Certificates evidencing such Member Interests are surrendered for registration of transfer. No charge shall be imposed by the Company for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5(b), the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(c) By acceptance of the transfer of any Member Interest in accordance with this Section 4.5 and except as provided in Section 4.7, each transferee of a Member Interest (including any nominee holder or an agent or representative acquiring such Member Interests for the account of another Person) (i) shall be admitted to the Company as a Substituted Member with respect to the Member Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Company, with or without execution of this Agreement, (ii) shall be deemed to agree to be bound by the terms of, this Agreement, (iii) shall become the Record Holder of the Member Interests so transferred, (iv) represents that the transferee has the capacity, power and authority to enter into this Agreement, (v) grants powers of attorney to the Officers of the Company and any Liquidator of the Company in accordance with Section 2.6, and (vi) makes the consents and waivers contained in this Agreement. The transfer of any Member Interests and the admission of any new Member shall not constitute an amendment to this Agreement.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.6, (iv) with respect to any class or series of Member Interests other than the Class A Units, Common Units, Management Incentive Interests and Class D Interests, the provisions of any amendment to this Agreement containing the statement of designations establishing such class or series, (v) any contractual provision binding on any Member and (vi) provisions of applicable law including the Securities Act, Member Interests shall be freely transferable to any Person.

Section 4.6 Restrictions on Transfers.

(a) In addition to the restrictions set forth in Section 4.5(b) and except as provided in Section 4.6(b) below, but notwithstanding the other provisions of this Article 4, no transfer of any Member Interests shall be made if

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such transfer would violate the then applicable federal or state securities laws or rules and regulations of the securities and exchange commission, any state securities commission or any other governmental authority with jurisdiction over such transfer.

(b) In addition to the restrictions set forth in Section 4.5(b), the Company may impose restrictions on the transfer of Member Interests if it receives an Opinion of Counsel providing that such restrictions are necessary to avoid a significant risk of any Group Member becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The Board of Managers may impose such restrictions by amending this Agreement in accordance with Article 11; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Member Interests on the principal National Securities Exchange on which such class of Member Interests is then traded must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Member Interests of such class. Notwithstanding Section 11.10, such approval may be obtained through a written consent of such holders.

(c) Nothing contained in this Article 4, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Member Interests entered into through the facilities of any National Securities Exchange on which such Member Interests are listed for trading.

Section 4.7 Citizenship Certificates; Non-citizen Assignees.

(a) If any Group Member is or becomes subject to any federal, state or local law or regulation that the Board of Managers determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Member or Assignee, the Board of Managers may request any Member or Assignee to furnish to the Board of Managers, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Member or Assignee is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the Board of Managers may request. If a Member or Assignee fails to furnish to the Board of Managers within such 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the Board of Managers determines that a Member or Assignee is not an Eligible Citizen, the Member Interests owned by such Member or Assignee shall be subject to redemption in accordance with the provisions of Section 4.8. In addition, the Board of Managers may require that the status of any such Member or Assignee be changed to that of a Non-citizen Assignee and, thereupon, such Member shall cease to be a member of the Company and shall have no voting rights, whether arising hereunder, under the Delaware Act, at law, in equity or otherwise, in respect of its Member Interests. The voting rights in respect of Member Interests of Non-citizen Assignees shall be deemed to have been exercised with the votes being distributed in the same ratios or for the same candidates for election as Managers as the votes of Members in respect of Member Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter or election.

(b) Upon dissolution of the Company, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 10.3, but shall be entitled to the cash equivalent thereof, and the Company shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Company purposes as a purchase by the Company from the Non-citizen Assignee of his economic interest in the Company (representing his right to receive his share of such distribution in kind).

(c) At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the Board of Managers, request admission as a Substituted Member with respect to any Member Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.8, such Non-citizen Assignee be admitted as a Member, and upon approval of the Board of Managers, such Non-citizen Assignee shall be admitted as a Member and shall no longer constitute a Non-citizen Assignee and shall reacquire all voting rights of his Member Interests.

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Section 4.8 Redemption of Member Interests of Non-citizen Assignees.

(a) If at any time a Member or Assignee fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.7(a), or if upon receipt of such Citizenship Certification or other information the Board of Managers determines, with the advice of counsel, that a Member or Assignee is not an Eligible Citizen, the Company may, unless the Member or Assignee establishes to the satisfaction of the Board of Managers that such Member or Assignee is an Eligible Citizen or has transferred his Member Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the Board of Managers prior to the date fixed for redemption as provided below, redeem the Member Interest of such Member or Assignee as follows:

(i) The Board of Managers shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Member or Assignee, at his last address designated on the records of the Company or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Member would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Member Interests of the class to be so redeemed multiplied by the number of Member Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the Board of Managers, in cash or by delivery of a promissory note of the Company in the principal amount of the redemption price, bearing interest at the Prime Rate annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Member or Assignee, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, the Member or Assignee or his duly authorized representative shall be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Member Interests.

(b) The provisions of this Section 4.8 shall also be applicable to Member Interests held by a Member or Assignee as nominee of a Person determined to be other than an Eligible Citizen.

(c) Nothing in this Section 4.8 shall prevent the recipient of a notice of redemption from transferring his Member Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the Board of Managers shall withdraw the notice of redemption, provided the transferee of such Member Interest certifies to the satisfaction of the Board of Managers in a Citizenship Certification that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

Article 5

CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS

Section 5.1 Redemption or Exchange of the Pre-IPO Member Interests.

On the Closing Date and immediately prior to the closing of the Initial Offering, CEPH’s Pre-IPO Member Interests in the Company shall be converted into and exchanged for [295,690] Class A Units, [8,214,010] Common Units, and the Management Incentive Interests, and concurrently with such conversion and exchange CEPH shall be classified as a Member in respect of such Class A Units, Common Units and Management

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Index to Financial Statements

Incentive Interests. Up to [941,250] of the Common Units issued to CEPH shall be subject to purchase by the Company pursuant to Section 5.2(c).

Section 5.2 Contributions by CHI and Underwriters.

(a) On the Closing Date and concurrently with the closing of the Initial Offering, CHI shall contribute $8,000,000 to the Company in exchange for the issuance to CHI of the Class D Interests, and CHI shall be admitted to the Company as a Member in respect of such Class D Interests.

(b) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In consideration for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made a number of Common Units equal to the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Closing Date, and upon such issuance such Underwriter shall be admitted to the Company as a Member in respect of the Common Units so issued to such Underwriter.

(c) Upon the exercise of the Over-Allotment Option and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made, a number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Option Closing Date, and upon such issuance such Underwriter shall be admitted to the Company as a Member in respect of the Common Units so issued to such Underwriter pursuant to this Section 5.2(c). Upon receipt by the Company of the Capital Contributions from the Underwriters as provided in this Section 5.2(c), the Company shall use such cash to purchase from CEPH, and CEPH agrees to sell to the Company, at the Issue Price per Initial Common Unit a number of Common Units equal to the number of Common Units issued to the Underwriters in accordance with this Section 5.2(c).

(d) The Member Interests that will be issued or issuable as of or at the Closing Date shall be (i) the [295,690] Class A Units, the [8,214,010] Common Units, and the Management Incentive Interests issuable to CEPH pursuant to Section 5.1, (ii) the [6,275,000] Common Units issuable pursuant to Section 5.2(b) to the Underwriters, (iii) the “Option Common Units,” as such term is used in the Underwriting Agreement, in an aggregate number up to [941,250] Common Units issuable upon exercise of the Over-Allotment Option pursuant to Section 5.2(c), and (iv) the Class D Interests issuable to CHI pursuant to Section 5.2(a).

Section 5.3 Interest and Withdrawal.

No interest shall be paid by the Company on Capital Contributions. No Member shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution of the Company may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Member shall have priority over any other Member either as to the return of Capital Contributions or as to profits, losses or distributions.

Section 5.4 Capital Accounts.

(a) The Company shall maintain for each Member (or a beneficial owner of Member Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method acceptable to the Company) owning a Member Interest a separate Capital Account with respect to such Member Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Company with respect to such Member Interest pursuant to this Agreement and (ii) all items of Company income and gain (including Simulated Gain and income and gain exempt from tax) computed

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Index to Financial Statements

in accordance with Section 5.4(b) and allocated with respect to such Member Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Member Interest pursuant to this Agreement and (y) all items of Company deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.4(b) and allocated with respect to such Member Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article 6 and is to be reflected in the Members’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.4, the Company shall be treated as owning directly its proportionate share (as determined by the Board of Managers based upon the provisions of the applicable Group Member Agreement) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes.

(ii) All fees and other expenses incurred by the Company to promote the sale of (or to sell) a Member Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Members pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Company and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Company property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Company’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Company were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Company property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery, amortization or Simulated Depletion derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery, amortization or Simulated Depletion deductions shall be determined using any method that the Board of Managers may adopt.

(vi) If the Company’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Members pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Members to whom such deemed deduction was allocated.

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Index to Financial Statements

(c) A transferee of a Member Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Member Interest so transferred.

(d)

(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Member Interests for cash or Contributed Property and the issuance of Member Interests as consideration for the provision of services, the Capital Account of all Members and the Carrying Value of each Company property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Members at such time pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Company assets (including cash or cash equivalents) immediately prior to the issuance of additional Member Interests shall be determined by the Board of Managers using such method of valuation as it may adopt; provided, however, that the Board of Managers, in arriving at such valuation, must take fully into account the fair market value of the Member Interests of all Members at such time. The Board of Managers shall allocate such aggregate value among the assets of the Company (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Member of any Company property (other than a distribution of cash that is not in redemption or retirement of a Member Interest), the Capital Accounts of all Members and the Carrying Value of all Company property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Members, at such time, pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Company assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 10.3 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.4(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 10.3, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.5 Issuances of Additional Company Securities.

(a) Subject to Section 5.6, at any time or from time to time after the closing of the Initial Offering the Company may issue additional Company Securities, and options, rights, warrants and appreciation rights relating to the Company Securities for any Company purpose to such Persons, and admit such Persons as members of the Company, for such consideration and on such terms and conditions as the Board of Managers shall determine in its sole discretion, all without the approval of the Members of any class of Company Securities then Outstanding.

(b) Each additional Company Security authorized to be issued by the Company pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such relative designations, preferences, rights, powers and duties (which may be senior or prior, pari passu or junior to the preferences, rights, powers and duties of any then Outstanding class and series of Company Securities), as shall be fixed by the Board of Managers, including (i) the right to share Company profits and losses or items thereof; (ii) the right to share in Company distributions; (iii) the rights upon dissolution and liquidation of the Company; (iv) whether, and the terms and conditions upon which, the Company may redeem the Company Security, including sinking fund provisions, if any; (v) whether such Company Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Company Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Company Security; and (viii) the right, if any, of the

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Index to Financial Statements

holders of each such Company Security to vote on Company matters, including matters relating to the relative rights, preferences and privileges of such Company Security.

(c) The Board of Managers shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Company Securities and options, rights, warrants and appreciation rights relating to Company Securities pursuant to this Section 5.5, (ii) the conversion of Class A Units and Management Incentive Interests into Common Units pursuant to the terms of this Agreement, (iii) the admission of any Person(s) as an Additional Member(s) and (iii) all additional issuances of Company Securities. The Board of Managers shall determine the relative designations, preferences, rights, powers and duties of the holders of the Units or other Company Securities being so issued. The Board of Managers shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Company Securities pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Common Units or other Company Securities are listed for trading.

Section 5.6 Limitations on Issuance of Additional Company Securities.

The issuance of Company Securities pursuant to Section 5.5 shall be subject to the limitation that no fractional Units shall be issued by the Company.

Notwithstanding anything in this Agreement to the contrary, additional Company Securities, issuable without the approval of the Members of any class of Company Securities then Outstanding, may include (i) Company Securities with preferences, rights, powers and duties (including rights to distributions, allocations, voting or in liquidation) that are senior or prior, pari passu or junior to any other class or series of Company Securities then Outstanding, or (ii) additional Company Securities of any class or series then Outstanding.

Section 5.7 No Preemptive Rights.

No Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Company Security, whether unissued, held by the Company or hereafter created.

Section 5.8 Splits and Combinations.

(a) Subject to Section 5.6, Section 5.8(d) and Section 6.7, the Company may make a Pro Rata distribution of Company Securities of any class or series to all Record Holders of Company Securities of such class or series or may effect a subdivision or combination of Company Securities so long as, after any such event, each Member shall have the same Percentage Interest in the Company as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted retroactive to the date of formation of the Company.

(b) Whenever such a distribution, subdivision or combination of Company Securities is declared, the Board of Managers shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The Board of Managers also may cause a firm of independent public accountants selected by it to calculate the number of Company Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The Board of Managers shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Company may issue Certificates to the Record Holders of Company Securities as of the applicable Record Date representing the new number of Company Securities held by such Record Holders, or the Board of Managers may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Company Securities Outstanding, the Company shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

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Index to Financial Statements

(d) The Company shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.6 and this Section 5.8(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.9 Fully Paid and Non-Assessable Nature of Member Interests.

All Member Interests issued pursuant to, and in accordance with the requirements of, this Article 5 shall be validly issued, fully paid and non-assessable Member Interests in the Company, except as such non-assessability may be affected by Sections 18-607 or 18-804 of the Delaware Act and except to the extent otherwise provided in this Agreement.

Section 5.10 Registration Rights of CEPM, CEPH and their Affiliates.

(a) If (i) CEPM, CEPH or any of their Affiliates (including for purposes of this Section 5.10, any Person that is an Affiliate of CEPM or CEPH at the date hereof notwithstanding that it may later cease to be an Affiliate of CEPM or CEPH) holds Company Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Company Securities (the “Holder”) to dispose of the number of Company Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Company shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period following its effective date until all Company Securities covered by such registration statement have been sold or until Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) becomes available for such Company Securities, a registration statement under the Securities Act registering the offering and sale of the number of Company Securities specified by the Holder (which registration statement may constitute a “shelf” registration statement covering the Company Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission); provided, however, that the Company shall not be required to effect more than three registrations pursuant to Section 5.10(a); and provided further, however, that if the Conflicts Committee determines in good faith that the requested registration, or use of any prospectus forming a part thereof, would be materially detrimental to the Company and its Members because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Company, (y) require premature disclosure of material information that the Company has a bona fide business purpose for preserving as confidential or (z) render the Company unable to comply with requirements under applicable securities laws, then the Company shall have the right to postpone such requested registration or use of any such prospectus for a period of not more than three months after receipt of the Holder’s request, such right to postpone a requested registration or use of any such prospectus pursuant to this Section 5.10(a) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Company shall be deemed not to have used all commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Company Securities covered thereby not being able to offer and sell such Company Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to this Section 5.10(a), the Company shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Company would become subject to general service of process or to taxation or qualification to do business as a foreign corporation, limited liability company or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Company Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Company Securities in such states. Except as set forth in Section 5.10(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Company, without reimbursement by the Holder.

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Index to Financial Statements

(b) If the Company shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Company for cash (other than an offering relating solely to an employee benefit plan or a business combination), the Company shall use all commercially reasonable efforts to include such number or amount of securities held by any Holder in such registration statement as the Holder shall request; provided, that the Company is not required to make any effort or take any action to so include the securities of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 5.10(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Company and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Company Securities, in addition to the equity securities of the Company that the Company proposes to sell, would adversely and materially affect the success of the offering, the Company shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 5.10(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Company, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 5.10, the Company shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Company’s obligation under Section 7.7, the Company shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 5.10(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Company Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Company is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Company shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Company by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 5.10(a) and Section 5.10(b) shall continue to be applicable with respect to the CEPM and CEPH (and any of their respective Affiliates) after any termination pursuant to Section 11.8(e) of the right of the holders of the Class A Units to appoint the Class A Managers pursuant to Section 11.8(d) during a period of two years subsequent to the effective date of such termination and for so long thereafter as is required for the Holder to sell all of the Company Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Company shall not be required to file successive registration statements covering the same Company Securities for which registration was demanded during such two-year period. The provisions of Section 5.10(c) shall continue in effect thereafter.

(e) The rights to cause the Company to register Company Securities pursuant to this Section 5.10 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Company Securities, provided (i) the Company is, within a reasonable time after such transfer, furnished with written

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Index to Financial Statements

notice of the name and address of such transferee or assignee and the Company Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 5.10.

(f) Any request to register Company Securities pursuant to this Section 5.10 shall (i) specify the Company Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Company Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Company Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Company to comply with all applicable requirements in connection with the registration of such Company Securities.

Article 6

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Members among themselves, the Company’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.4(b)) shall be allocated among the Members in each taxable year (or portion thereof) as provided herein below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated to the Unitholders in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated to the Unitholders in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account).

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 10.3.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Gain shall be allocated among the Members in the following manner (and the Capital Accounts of the Members shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Member having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Members, until each such Member has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

(B) Second, 98% to the holders of Common Units, Pro Rata, and 2% to the holders of Class A Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to

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Index to Financial Statements

(1) its Unrecovered Capital plus (2) the Initial Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid IQD”);

(C) Third, 100% to the holders of the Class D Interests, until the Capital Account in respect of the Class D Interests is equal to the excess, if any, of (1) $8,000,000 over (2) the cumulative amount of all distributions made pursuant to Section 6.3(b);

(D) Fourth, 98% to the holders of Common Units, Pro Rata, and 2% to the holders of Class A Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital, (2) the Unpaid IQD and (3) the excess of (a) the Target Distribution less the Initial Quarterly Distribution for each Quarter of the Company’s existence over (b) the amount of any distributions of Available Cash made pursuant to Sections 6.4(a) in excess of the Initial Quarterly Distribution for each Quarter during the MII Vesting Period and any distributions previously made pursuant to 6.4(b)(ii); and

(E) Fifth, 2% to the holders of Class A Units, Pro Rata, 83% to the holders of Common Units, Pro Rata, and 15% to the holders of the Management Incentive Interests, Pro Rata.

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.4(d)), such Net Termination Loss shall be allocated among the Members in the following manner:

(A) First, to the Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero;

(B) Second, to the holders of the Class D Interests, Pro Rata, until the Capital Account in respect of each Class D Interest has been reduced to zero; and

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Company Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Company Minimum Gain during any Company taxable period, each Member shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Company Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Member Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Member Nonrecourse Debt Minimum Gain during any Company taxable period, any Member with a share of Member Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to

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Index to Financial Statements

Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) Items of Company gross income or gain for the taxable period, if any, shall be allocated to the holders of the Management Incentive Interests, Pro Rata, until the aggregate amount of such items allocated to the holders of the Management Incentive Interests pursuant to this Section 6.1(d)(iii)(A) for the current taxable year and all previous taxable years is equal to the cumulative amount of all EP MIDs distributed pursuant to Section 6.5.

(B) After application of Section 6.1(d)(iii)(A), all or a portion of the remaining items of Company gross income or gain for the taxable period, if any, shall be allocated (1) to the holders of the Management Incentive Interests, Pro Rata, until the aggregate amount of such items allocated to the holders of the Management Incentive Interests pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Management Incentive Distributions made pursuant to Section 6.4(b)(iii)(C) from the Closing Date to a date 45 days after the end of the current taxable year and (2) to the General Partner in an amount equal to 2/98ths of the sum of the amounts allocated in clause (1) above.

(iv) Qualified Income Offset. In the event any Member unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Company income, gain and Simulated Gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or (ii).

(v) Gross Income Allocations. In the event any Member has a deficit balance in its Capital Account at the end of any Company taxable period in excess of the sum of (A) the amount such Member is required to restore pursuant to the provisions of this Agreement and (B) the amount such Member is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Member shall be specially allocated items of Company gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Member would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Members in accordance with their respective Percentage Interests. If the Board of Managers determines that the Company’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the Board of Managers is authorized, upon notice to the other Members, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Member Nonrecourse Deductions. Member Nonrecourse Deductions for any taxable period shall be allocated 100% to the Member that bears the Economic Risk of Loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Member bears the Economic Risk of Loss with respect to a Member Nonrecourse Debt, such Member Nonrecourse Deductions attributable thereto shall be allocated between or among such Members in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Members agree that Nonrecourse Liabilities of the Company in excess of the sum of (A) the amount of

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Index to Financial Statements

Company Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Members in accordance with their respective Percentage Interests.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss allocated to each Member pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Member under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Company Minimum Gain and (2) Member Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Member Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(x)(A) shall only be made with respect to Required Allocations to the extent the Board of Managers reasonably determines that such allocations will otherwise be inconsistent with the economic agreement among the Members. Further, allocations pursuant to this Section 6.1(d)(x)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the Board of Managers determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The Board of Managers shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(x)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(x)(A) among the Members in a manner that is likely to minimize such economic distortions.

(xi) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.4(d) hereof) to only certain Members (the “Allocated Members”), the Board of Managers shall allocate additional items of gross income, gain and Simulated Gain away from the Allocated Members to the extent that the Additional Book Basis Derivative Items allocated to the Allocated Members exceed their Share of Additional Book Basis Derivative Items and to the remaining Members (or shall allocate additional items of deduction, loss, Simulated Depletion and Simulated Loss away from the other Members and to the Allocated Members). For this purpose, a Member shall be treated as having been allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that otherwise have been allocated to the Member under this Agreement. Any allocation made pursuant to this Section 6.1(d)(xi)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xi) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

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Index to Financial Statements

(B) In the case of any negative adjustments to the Capital Accounts of the Members resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the Board of Managers, that to the extent possible the aggregate Capital Accounts of the Members will equal the amount that would have been the Capital Account balance of the Members if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(C) In making the allocations required under this Section 6.1(d)(xi), the Board of Managers may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xi).

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Members in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Members rather than by the Company in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii)), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Company under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Members in accordance with their respective Percentage Interests.

Each Member shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Company.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Member on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Company’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Members as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Members in the same proportion as the depletable basis of such property was allocated to the Members pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii));

(ii) second, the remainder of such amount realized, if any, to the Members so that, to the maximum extent possible, the amount realized allocated to each Member under this Section 6.2(c)(ii) will equal such Member’s share of the Simulated Gain recognized by the Company from such sale or disposition.

(iii) The Members recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Members to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d) except as otherwise determined by the Board of Managers with respect to goodwill.

(iv) Any elections or other decisions relating to such allocations shall be made by the Board of Managers in any manner that reasonably reflects the purpose and intention of the Agreement.

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Index to Financial Statements

(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than an oil and gas property pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Members as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Members in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Members in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.4(d)(i) or (Section 5.4(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Members in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The Board of Managers shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities except as otherwise determined by the Board of Managers with respect to goodwill.

(e) For the proper administration of the Company and for the preservation of uniformity of the Common Units (or any class or classes thereof), the Board of Managers shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Common Units (or any class or classes thereof). The Board of Managers may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Members, the holders of any class or classes of Common Units issued and Outstanding or the Company, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The Board of Managers may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Company’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the Board of Managers determines that such reporting position cannot be taken, the Board of Managers may adopt depreciation and amortization conventions under which all purchasers acquiring Common Units in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Company’s property. If the Board of Managers chooses not to utilize such aggregate method, the Board of Managers may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Member Interests, so long as such conventions would not have a material adverse effect on the Members or the Record Holders of any class or classes of Common Units.

(g) Any gain allocated to the Members upon the sale or other taxable disposition of any Company asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such

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Index to Financial Statements

Members (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Company for federal income tax purposes and allocated to the Members in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Company; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the Board of Managers) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Company income, gain, loss and deduction shall, for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Company or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the Board of Managers, shall be allocated to the Members as of the opening of the New York Stock Exchange on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The Board of Managers may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Member under the provisions of this Article 6 shall instead be made to the beneficial owner of Common Units held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method determined by the Board of Managers.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 18-607 of the Delaware Act, be distributed in accordance with this Article 6 by the Company to the Members as of the Record Date selected by our Board of Managers for such distribution (or by an Officer designated by our Board of Managers to select the Record Date for such distribution). All amounts of Available Cash distributed by the Company on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Company to the Members pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the date of determination. Any remaining amounts of Available Cash distributed by the Company on such date shall, except as otherwise provided in Section 6.4, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Section 18-607 or Section 18-804 of the Delaware Act.

(b) Within 45 days following the end of each Quarter ending on or prior to December 31, 2012 during any part of which the Sharing Arrangement is in effect and concurrently with distributions, if any, made for such Quarter pursuant to Section 6.3(a), commencing with the Quarter ending on March 31, 2007, the Company shall, subject to Section 18-607 of the Delaware Act and to the second sentence of this Section 6.3(b) distribute Pro Rata to the Record Holder of Class D Interests as of the Record Date selected by our Board of Managers for such distribution (or by an Officer designated by our Board of Managers to select the Record Date for such distribution) the following:

(i) in respect of each Quarter ending on or prior to September 30, 2012, an amount in cash equal to $333,333.00; and

(ii) in respect of the Quarter ending on December 31, 2012, an amount in cash equal to $333,341.00.

Notwithstanding the immediately preceding sentence, if (i) the amount payable by the Company Group to the Trust in respect of the NPI ceases prior to December 31, 2012 to be calculated based on the Sharing

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Index to Financial Statements

Arrangement, and (ii) such cessation did not occur as a result of the prior approval by the Board of Managers and the Conflicts Committee of the elimination of the minimum purchase price provision in Article IV of the Gas Purchase Contract, then the cash distributions pursuant to this Section 6.3(b) to the Record Holder of the Class D Interests for all future Quarters shall cease and the distribution for the Quarter in which such cessation occurs shall be equal to the product of (x) the amount of the distribution (that would have been made for such Quarter if such cessation had not occurred times (y) a fraction, of which the numerator is the number of days in such Quarter up to, but not including, the date of such cessation, and of which the denominator is 90.

Notwithstanding the preceding sentence, if the Company and any of the Trust, the trustee of the Trust or any subsequent holder of the NPI become involved in a dispute or proceeding in which such other Person asserts that prior to December 31, 2012 the Sharing Arrangement ceased to be applicable in calculating amounts payable in respect of production from the Trust Wells, special cash distributions in respect of the Class D Interests will be suspended for the period (the “Suspension Period”) commencing with the Quarter in which the Company receives written notice of such dispute or proceeding and extending until such dispute or proceeding, is finally resolved, and such suspended amounts will only be paid to the Record Holder of the Class D Interests to the extent it is finally determined that the Sharing Arrangement remained applicable during some or all of the Suspension Period. If the final resolution of the dispute or proceeding referred to in the immediately preceding sentence is that the Sharing Arrangement remained in effect for all or some portion of the Suspension Period, the Company will promptly distribute to the Record Holder of the Class D Interests as of the date of such final resolution an amount in cash equal to the amount of the suspended distribution for the portion of the Suspension Period that the Sharing Arrangement is determined to have remained in effect.

(c) Notwithstanding Section 6.3(a) or Section 6.3(b), in the event of the dissolution and liquidation of the Company, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 10.3.

(d) The Company may treat taxes paid by the Company on behalf of, or amounts withheld with respect to, all or less than all of the Members, as a distribution of Available Cash to such Members.

(e) Each distribution in respect of a Member Interest shall be paid by the Company, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Member Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Company’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) During the MII Vesting Period. Available Cash with respect to any Quarter ending prior to or on the date of the end of the MII Vesting Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.6 shall, subject to Section 18-607 of the Delaware Act, be distributed, except as otherwise required by Section 5.5(b) in respect of other Company Securities issued pursuant thereto, as follows: (A) 2% to the holder(s) of the Class A Units, Pro Rata and (B) 98% to the holders of the Common Units, Pro Rata.

(b) After the MII Vesting Period. Available Cash with respect to each Quarter after the MII Vesting Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.6 shall, subject to Section 18-607 of the Delaware Act, be distributed, except as otherwise required by Section 5.5(b) in respect of additional Company Securities issued pursuant thereto, as follows:

(i) First, (A) 2% to the holders of the Class A Units, Pro Rata, and (B) 98% to the holders of Common Units, Pro Rata, until there has been distributed in respect of each Class A Unit and each Common Unit then Outstanding an amount equal to the Initial Quarterly Distribution for such Quarter;

(ii) Second, (A) 2% to the holders of Class A Units, Pro Rata, and (B) 98% to the holders of Common Units, Pro Rata, until there has been distributed (including amounts distributed pursuant to Section 6.4(b)(i))

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Index to Financial Statements

in respect of each Class A Unit and each Common Unit then Outstanding an amount equal to the Initial Quarterly Distribution for such Quarter plus $0.06375 (the “Target Distribution”); and

(iii) Third, (A) 2% to the holders of the Class A Units, Pro Rata, (B) 83% to the holders of the Common Units, Pro Rata, and (C) 15% to the holders of the Management Incentive Interests, Pro Rata.

Section 6.5 Payment of the EP MID.

(a) First MII Earnings Period. If both the 12-Quarter Test and the 4-Quarter Test have been met with respect to the First MII Earnings Period, an EP MID shall be made contemporaneously with the distribution paid in respect of the Class A Units and Common Units pursuant to Section 6.4 for the twelfth calendar quarter in the First MII Earnings Period to the holder of the Management Incentive Interests. If the 12-Quarter Test is not met with respect to the First MII Earnings Period, Management Incentive Distributions will not be payable in respect of the First MII Earnings Period.

(b) Later MII Earnings Period. If an EP MID has not become previously payable pursuant to Section 6.5(a) and the 12-Quarter Test and the 4-Quarter Test are met in respect of any Later MII Earnings Period, then an EP MID shall be made contemporaneously with the distribution paid in respect of the Class A Units and Common Units pursuant to Section 6.4 for the twelfth calendar quarter in the Later MII Earnings Period to the holder of the Management Incentive Interests.

(c) MII 4-Quarter Earnings Period. If an EP MID has not become previously payable pursuant to Section 6.5(a) or 6.5(b), and the MII Vesting Period ends, then an EP MID shall be paid to the holder of the Management Incentive Interests with respect to the First MII Earnings Period or Later MII Earnings Period, as the case may be, such EP MID to be paid contemporaneously with the distribution paid in respect of the Class A Units and Common Units pursuant to Section 6.4 for the fourth Quarter in the MII 4-Quarter Earnings Period.

Section 6.6 Distributions of Available Cash from Capital Surplus.

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 18-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the holders of Common Units, Pro Rata, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Issue Price. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.3.

Section 6.7 Adjustment of Initial Quarterly Distribution, Target Distribution and Unrecovered Issue Price.

(a) The Initial Quarterly Distribution, Target Distribution and Unrecovered Issue Price shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Company Securities in accordance with Section 5.8. In the event of a distribution of Available Cash that is deemed to be from capital Surplus, the then applicable Initial Quarterly Distribution and Target Distribution, shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Initial Quarterly Distribution and Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Issue Price of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Capital of the Common Units immediately prior to giving effect to such distribution.

(b) The Initial Quarterly Distribution and Target Distribution shall also be subject to adjustment pursuant to Section 6.8.

Section 6.8 Entity-Level Taxation.

If legislation is enacted or the interpretation of existing language is modified by a governmental taxing authority so that a Company Group member is treated as an association taxable as a corporation or is otherwise

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Index to Financial Statements

subject to an entity-level tax for federal, state or local income tax purposes, then the Board of Managers shall estimate for each Quarter the Company Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all such income taxes that are payable by reason of any such new legislation or interpretation; provided that any difference between such estimate and the actual tax liability for such Quarter that is owed by reason of any such new legislation or interpretation shall be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Initial Quarterly Distribution shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.8 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the Board of Managers. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

Article 7

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Board of Managers.

(a) Except as otherwise expressly provided in this Agreement, the business and affairs of the Company shall be managed by or under the direction of a Board of Managers (the “Board of Managers”). As provided in Section 7.4, the Board of Managers shall have the power and authority to appoint Officers of the Company. The Managers shall constitute “managers” within the meaning of the Delaware Act. No Member, by virtue of its status as such, shall have any management power over the business and affairs of the Company or actual or apparent, authority to enter into, execute or deliver contracts on behalf of, or to otherwise bind, the Company. Except as otherwise specifically provided in this Agreement, the authority and functions of the Board of Managers, on the one hand, and of the Officers, on the other, shall be identical to the authority and functions of the board of directors and officers, respectively, of a corporation organized under the DGCL. In addition to the powers that now or hereafter can be granted to managers under the Delaware Act and to all other powers granted under any other provision of this Agreement, subject to Section 7.3, the Board of Managers shall have full power and authority to do, and to direct the Officers to do, all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Company, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Company Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Company;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Company or the merger or other combination of the Company with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article 12);

(iv) the use of the assets of the Company (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Company Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of the Company Group; and the making of capital contributions to any member of the Company Group;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Company under contractual arrangements to all or particular assets of the Company);

(vi) the distribution of Company cash;

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Index to Financial Statements

(vii) the selection and dismissal of Officers, employees, agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring, the creation and operation of employee benefit plans, employee programs and employee practices;

(viii) the maintenance of insurance for the benefit of the Company Group, the Members and any Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Company, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation, and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Member Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.6);

(xiii) the purchase, sale or other acquisition or disposition of Company Securities, or the issuance of options, rights, warrants and appreciation rights relating to Company Securities;

(xiv) the undertaking of any action in connection with the Company’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member.

(b) The Board of Managers shall consist of five natural Persons, except as otherwise set forth in this Section 7.1(b). Each Manager shall be elected as provided in Section 7.1(c) and shall serve in such capacity until his successor has been duly elected and qualified or until such Manager dies, resigns or is removed. A Manager may resign at any time upon written notice to the Company. The Board of Managers may from time to time determine the number of Managers then constituting the whole Board of Managers, but the Board of Managers shall not decrease the number of Persons that constitute the whole Board of Managers if such decrease would shorten the term of any Manager; provided, however, that the number of Persons serving as Managers shall not be increased at any time prior to termination of the right of the Class A Unitholders to elect the Class A Managers pursuant to Section 11.8(e) without the prior approval of all of the holders of sixty-six and two-thirds percent of the Outstanding Class A Units.

(c) The persons comprising the initial Board of Managers shall be as follows: Felix J. Dawson, John R. Collins and . Messrs. Dawson and Collins shall be the initial Class A Managers. The Class A Managers shall appoint the remaining two members of the initial Board of Managers. Such persons, including the persons appointed by the Class A Managers, shall serve as members of the Board of Managers until the annual meeting of Members to be held in 2007 and until their successors are duly elected and qualified, or until their earlier death, resignation, removal, termination or inability to continue as a Manager. Except as provided in this Section 7.1(c) with respect to the two members of the Board of Managers appointed by the Class A Managers, after the closing of the Initial Offering, the Managers shall be elected at each annual meeting of Members to serve for a term expiring at the next annual meeting of Members. Except as provided in this Section 7.1(c) with respect to the two members of the Board of Managers appointed by the Class A Managers, the nomination of Persons to serve as Managers and the election of the Board of Managers shall be in accordance with Article 11 hereof.

(d) Any Class A Manager may be removed at any time, with or without cause, only by the affirmative vote or consent of the holders of sixty-six and two-thirds percent of the Outstanding Class A Units. Any Class B Manager may be removed at any time, with or without cause, only by the affirmative vote or consent of a Common Unit Majority.

(e) Subject to applicable law and the rights of the holders of any series of Member Interests, vacancies existing on the Board of Managers created by virtue of an increase in the size of the Board of Managers may be

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Index to Financial Statements

filled only by the affirmative vote of a majority of the Managers then serving, even if less than a quorum, or by a nominee approved by a Common Unit Majority, unless such vacancy is specified by an amendment to this Agreement to be a vacancy to be filled by the holders of Class A Units. Any vacancy resulting from the death, resignation, removal, termination or inability to continue as a Manager shall be filled in the manner specified in Section 11.8(d). Any Manager chosen to fill a vacancy shall hold office until the next annual meeting of Members and until his successor has been duly elected and qualified or until such Manager’s earlier death, resignation, removal, termination or inability to continue as a Manager. The notice requirements set forth in Section 11.13 shall not apply in connection with the filling of any vacancies on the Board of Managers pursuant to this Section 7.1(e).

(f) Managers need not be Members. The Board of Managers may, from time to time and by the adoption of resolutions, establish qualifications for Managers.

(g) Unless otherwise required by the Delaware Act, other law or the provisions hereof,

(i) each member of the Board of Managers shall have one vote;

(ii) the presence at a meeting of the Board of Managers of a majority of the members of the Board of Managers shall constitute a quorum at any such meeting for the transaction of business; and

(iii) the act of a majority of the members of the Board of Managers present at a meeting of the Board of Managers at which a quorum is present shall be deemed to constitute the act of the Board of Managers.

(h)

(i) Regular meetings of the Board of Managers and any committee thereof shall be held at such times and places as shall be designated from time to time by resolution of the Board of Managers or such committee. Notice of such regular meetings shall not be required.

(ii) Special meetings of the Board of Managers or any committee thereof may be called by the Chairman of the Board or on the written request of a majority of the Managers or committee members, as applicable, to the Secretary, in each case on at least twenty-four hours personal, written, facsimile, electronic, telegraphic, cable or wireless notice to each Manager or committee member, which notice may be waived by any Manager or committee member. Any such notice, or waiver thereof, need not state the purpose of such meeting except as may otherwise be required by law. Attendance of a Manager or committee member at a meeting (including pursuant to the last sentence of this Section 7.1(h)) shall constitute a waiver of notice of such meeting, except where such Manager or committee member attends the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened.

(iii) Any action required or permitted to be taken at a meeting of the Board of Managers, or any committee thereof, may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, are signed by all members of the Board of Managers or committee. Members of the Board of Managers or any committee thereof may participate in and hold a meeting by means of conference telephone, video conference or similar communications equipment by means of which all Persons participating in the meeting can hear each other, and participation in such meetings shall constitute presence in person at the meeting.

(i) The Board of Managers shall, by resolution of a majority of the full Board of Managers, establish an Audit Committee and may, by resolution of a majority of the full Board of Managers, designate one or more committees (which may include one or more of a conflicts committee, compensation committee or a governance and nominating committee), each committee to consist of one or more of the Managers, and the Board of Managers may from time to time adopt a charter for any of such committees. The Board of Managers may designate one or more Managers as alternate members of any committee, who may replace any absent or disqualified Manager at any meeting of such committee. Any such committee, to the extent provided in the resolution of the Board of Managers or in this Agreement, shall have and may exercise all powers and authority of the Board of Managers in the management of the business and affairs of the Company; but no such committee shall have the power or authority in reference to the following matters: approving or adopting, or recommending

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Index to Financial Statements

to the Members, any action or matter expressly required by this Agreement or the Delaware Act to be submitted to the Members for approval, or adopting, amending or repealing any provision of this Agreement. Unless specified by resolution of the Board of Managers, any committee designated pursuant to this Section 7.1(i) shall choose its own chairman, shall keep regular minutes of its proceedings and report the same to the Board of Managers when requested, and, subject to Section 7.1(h), shall fix its own rules or procedures and shall meet at such times and at such place or places as may be provided by such rules. At every meeting of any such committee, the presence of a majority of all the members thereof shall constitute a quorum and the affirmative vote of a majority of the members present at a meeting of which a quorum is present shall be necessary for the adoption by the committee of any resolution.

(j) The Board of Managers may elect one of its members as Chairman of the Board (the “Chairman of the Board”). The Chairman of the Board, if any, and if present and acting, shall preside at all meetings of the Board of Managers and of Members, unless otherwise directed by the Board of Managers. If the Board of Managers does not elect a Chairman of the Board or if the Chairman of the Board is absent from the meeting, the Chief Executive Officer or President, if present and a Manager, or any other Manager chosen by the Board of Managers, shall preside. In the absence of a Secretary, the chairman of the meeting may appoint any Person to serve as Secretary of the meeting.

(k) Unless otherwise restricted by law, the Board of Managers shall have the authority to fix the compensation of the Managers. The Managers may be paid their expenses, if any, of attendance at each meeting of the Board of Managers and may be paid a fixed sum for attendance at each meeting of the Board of Managers or paid a stated salary or paid other compensation as Manager. No such payment shall preclude any Manager from serving the Company in any other capacity and receiving compensation therefor. Members of special or standing committees may also be paid their expenses, if any, of, and allowed compensation for, attending committee meetings.

(l) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Members and each other Person who may acquire an interest in Company Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Management Services Agreement, the Trademark License, the Omnibus Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the Board of Managers (on its own or through any Officer) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Company without any further act, approval or vote of the Members or the other Persons who may acquire an interest in Company Securities; and (iii) agrees that the execution, delivery or performance by the Company, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement shall not constitute a breach by the Board of Managers or any member thereof or any Officer of any duty that the Board of Managers or any member thereof or any Officer may owe the Company or the Members or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

Section 7.2 Certificate of Formation.

The Certificate of Formation has been filed with the Secretary of State of the State of Delaware as required by the Delaware Act, such filing being hereby confirmed, ratified and approved in all respects. The Board of Managers shall use all reasonable efforts to cause to be filed such other certificates or documents that it determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited liability company in the State of Delaware or any other state in which the Company may elect to do business or own property. To the extent that the Board of Managers determines such action to be necessary or appropriate, the Board of Managers shall direct the appropriate Officers to file amendments to and restatements of the Certificate of Formation and do all things to maintain the Company as a limited liability company under the laws of the State of Delaware or of any other state in which the Company may elect to do business or own property

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Index to Financial Statements

and any such Officer so directed shall be an “authorized person” of the Company within the meaning of the Delaware Act for purposes of filing any such certificate with the Secretary of State of the State of Delaware. The Company shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Formation, any qualification document or any amendment thereto to any Member.

Section 7.3 Restrictions on the Board of Managers’ Authority.

(a) Except as otherwise provided in this Agreement, the Board of Managers may not, without written approval of the specific act by holders of all of the Outstanding Member Interests or by other written instrument executed and delivered by holders of all of the Outstanding Member Interests subsequent to the date of this Agreement, take any action that is in breach or violation of this Agreement.

(b) Except as provided in Article 10 and Article 12, the Board of Managers may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Company Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Company’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the Board of Managers’ ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Company Group and shall not apply to any forced sale of any or all of the assets of the Company Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.4 Officers.

(a) The Board of Managers shall have the power and authority to appoint such officers with such titles, authority and duties as determined by the Board of Managers. Such Persons so designated by the Board of Managers shall be referred to as “Officers.” Unless provided otherwise by resolution of the Board of Managers, the Officers shall have the titles, power, authority and duties described below in this Section 7.4.

(b) The Officers shall include a Chief Executive Officer, a President, and a Secretary, and may also include a Chairman of the Board, Vice Chairman, Chief Operating Officer, Chief Financial Officer, Treasurer, one or more Vice Presidents (who may be further classified by such descriptions as “executive,” “senior,” “assistant” or otherwise, as the Board of Managers shall determine), one or more Assistant Secretaries and one or more Assistant Treasurers. Officers shall be elected by the Board of Managers, which shall consider that subject at its first meeting after every annual meeting of Members and as necessary to fill vacancies. Each Officer shall hold office until his or her successor is elected and qualified or until his or her earlier death, resignation or removal. Any number of offices may be held by the same Person. The compensation of Officers elected by the Board of Managers shall be fixed from time to time by the Board of Managers or by such Officers as may be designated by resolution of the Board of Managers.

(c) Any Officer may resign at any time upon written notice to the Company. Any Officer may be removed by the Board of Managers with or without cause at any time. The Board of Managers may delegate the power of removal as to Officers who have not been appointed by the Board of Managers. Such removal shall be without prejudice to a Person’s contract rights, if any, but the appointment of any Person as an Officer shall not of itself create contract rights.

(d) The President shall be the Chief Executive Officer of the Company unless the Board of Managers designates the Chairman of the Board as Chief Executive Officer. Subject to the control of the Board of Managers and the executive committee (if any), the Chief Executive Officer shall have general executive charge, management and control of the properties, business and operations of the Company with all such powers as may be reasonably incident to such responsibilities; he may employ and discharge employees and agents of the Company except such as shall be appointed by the Board of Managers, and he may delegate these powers; he may agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Company, and shall have such other powers and duties as designated in accordance with this Agreement and as from time to time may be assigned to him by the Board of Managers.

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Index to Financial Statements

(e) If elected, the Chairman of the Board shall preside at all meetings of the Members and of the Board of Managers unless otherwise directed by the Board of Managers; and shall have such other powers and duties as designated in this Agreement and as from time to time may be assigned to him by the Board of Managers.

(f) Unless the Board of Managers otherwise determines, the President and Chief Executive Officer (if other than the President) shall have the authority to agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Company; and, unless the Board of Managers otherwise determines, shall, in the absence of the Chairman of the Board or if there be no Chairman of the Board, preside at all meetings of the Members and (should he be a Manager) of the Board of Managers; and he shall have such other powers and duties as designated in accordance with this Agreement and as from time to time may be assigned to him by the Board of Managers.

(g) In the absence of the President, or in the event of his inability or refusal to act, a Vice President designated by the Board of Managers shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions upon the President. In the absence of a designation by the Board of Managers of a Vice President to perform the duties of the President, or in the event of his absence or inability or refusal to act, the Vice President who is present and who is senior in terms of uninterrupted time as a Vice President of the Company shall so act. The Vice President shall perform such other duties and have such other powers as designated in accordance with this Agreement and as the Board of Managers may from time to time assign. Unless otherwise provided by the Board of Managers, each Vice President will have authority to act within his or her respective areas and to agree upon and execute all contracts relating thereto.

(h) The Treasurer shall have responsibility for the custody and control of all the funds and securities of the Company and shall have such other powers and duties as designated in this Agreement and as from time to time may be assigned by the Board of Managers. The Treasurer shall perform all acts incident to the position of Treasurer, subject to the control of the Chief Executive Officer and the Board of Managers. Each Assistant Treasurer shall have the usual powers and duties pertaining to his office, together with such other powers and duties as designated in this Agreement and as from time to time may be assigned to him by the Chief Executive Officer or the Board of Managers. The Assistant Treasurers shall perform all the duties and exercise the powers of the Treasurer during that Officer’s absence or inability or refusal to act. The performance of any such duty shall, in respect of any other Person dealing with the Company, be conclusive evidence of his power to act. An Assistant Treasurer shall also perform such other duties as the Treasurer or the Board of Managers may assign to him.

(i) The Secretary shall issue all authorized notices for, and shall keep minutes of, all meetings of the Members and the Board of Managers. The Secretary shall have charge of the corporate books and shall perform such other duties and have such other powers as designated in accordance with this Agreement and as the Board of Managers may from time to time assign. In the absence or inability or refusal to act of the Secretary, any Assistant Secretary may perform all the duties and exercise all the powers of the Secretary. The performance of any such duty shall, in respect of any other Person dealing with the Company, be conclusive evidence of his power to act. An Assistant Secretary shall also perform such other duties as the Secretary or the Board of Managers may assign to him.

(j) The Board of Managers may from time to time delegate the powers or duties of any Officer to any other Officers, employees or agents, notwithstanding any provision hereof.

(k) Unless otherwise directed by the Board of Managers, the Chief Executive Officer, the President or any Officer authorized by the Chief Executive Officer shall have power to vote and otherwise act on behalf of the Company, in person or by proxy, at any meeting of Members of or with respect to any action of equity holders of any other entity in which the Company may hold securities and otherwise to exercise any and all rights and powers which the Company may possess by reason of its ownership of securities in such other entities.

(l) Unless otherwise directed by the Board of Managers or specified in an employment or other agreement to which an Officer is a party, a Person appointed as an Officer of the Company is required to devote to the business affairs of the Company only a portion of such Person’s full productive time as is required to perform the duties delegated to such Person by the Board of Managers. In addition, it shall not constitute a breach or violation of any duty owed to the Company or to any holder of Company Securities (or any class or series thereof) by a

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Index to Financial Statements

Person appointed as an Officer of the Company for such Person to be a director, manager, officer or employee of any Affiliate of the Company Group (other than the Company Group) provided that the Board of Managers is advised of such Person’s positions with such Affiliate(s) and does not object to same in a timely manner.

Section 7.5 Outside Activities.

(a) It shall be deemed not to be a breach of any duty (including any fiduciary duty) existing hereunder, at law, in equity or otherwise, or any other obligation of any type whatsoever of (i) any Manager or Officer for Affiliates of such Manager or Officer to engage in outside business interests and activities in preference to or to the exclusion of the Company or in direct competition with the Company; provided such Affiliate does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Company to such Manager or (ii) any Manager, Officer or other employee of the Company to be a director, manager, officer, employee or consultant of any Affiliate or Member or any Affiliate of any Member of the Company, provided that the Board of Managers is advised of such other relationship and does not object thereto; and further, provided, that such Officer or employee does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Company to such Person;

(b) None of the Managers or Officers shall have any obligation hereunder or as a result of any duty expressed or implied by law, in equity or otherwise to present business opportunities to the Company that may become available to Affiliates of such Manager or Officer or of which the person serving as a Manager or Officer acquires knowledge other than while serving in the capacity as such Manager or Officer. None of any Group Member, any Member or any other Person shall have any rights by virtue of a Manager’s or Officer’s duties as a Manager or Officer, as the case may be, under this Agreement, any Group Member Agreement, applicable law or otherwise in any business ventures of any Manager or Officer, as the case may be; and

(c) Notwithstanding anything to the contrary in this Agreement, to the extent that any provisions of this Section 7.5 purport or are interpreted to have the effect of restricting, eliminating or otherwise modifying the duties (including fiduciary duties) that might otherwise, as a result of Delaware or other applicable law, be owed by the Managers, the Officers or any of their Affiliates to the Company and its Members, or to constitute a waiver or consent by the Members to any such fiduciary duty, such provisions in this Section 7.5 shall be deemed to have been approved by the Members, and the Members hereby agree that such provisions shall replace or eliminate such duties.

Section 7.6 Loans or Contributions from the Company or Group Members.

(a) The Company may lend or contribute to any Group Member, and any Group Member may borrow from the Company, funds on terms and conditions determined by the Board of Managers.

(b) No borrowing by any Group Member or the approval thereof by the Board of Managers shall be deemed to constitute a breach of any duty (including any fiduciary duty), hereunder or existing at law, in equity or otherwise, of the Board of Managers to the Company or the Members by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the Members.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law as it currently exists and to such greater extent as applicable law hereafter may permit, but subject to the limitations expressly provided in this Agreement, the Company shall indemnify any Person who was or is a party or is threatened to be made a party to, or otherwise requires representation of counsel in connection with, any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Company) by reason of the fact that such Person is an Indemnitee or by reason of any action alleged to have been taken or omitted in such capacity, against losses, expenses (including attorneys’ fees of counsel for such Indemnitee), judgments, fines, damages, penalties, interest, liabilities and amounts paid in settlement actually and reasonably incurred by the Person in connection with such action, suit or proceeding; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking

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Index to Financial Statements

indemnification pursuant to this Section 7.7(a), the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the Person acted in bad faith or engaged in fraud, willful misconduct or, with respect to any criminal action or proceeding, acted with the knowledge that the Person’s conduct was unlawful.

(b) To the fullest extent permitted by law, but subject to the limitations expressly provided in this Agreement, the Company shall indemnify any Person who was or is a party or is threatened to be made a party to, or otherwise requires representation of counsel in connection with, any threatened, pending or completed action, suit or proceeding, by or in the right of the Company to procure a judgment in its favor by reason of the fact that such Person was serving as an Indemnitee, or by reason of any action alleged to have been taken or omitted in such capacity, against losses, expenses (including attorneys’ fees of counsel for such Indemnitee), judgments, fines, damages, penalties, interest, liabilities and amounts paid in settlement actually and reasonably incurred by the Person in connection with such action, suit or proceeding; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7(b), the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; and provided further, that no indemnification shall be made in respect of any claim, issue or matter as to which such Person shall have been adjudged to be liable to the Company unless and only to the extent that the Delaware Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such Person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper.

(c) To the extent an Indemnitee has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in Section 7.7(a) or Section 7.7(b), or in the defense of any claim, issue or matter therein, such Person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by such Person in connection therewith.

(d) Expenses (including reasonable attorneys’ fees of counsel for such Indemnitee) incurred by an Indemnitee in defending any action, suit or proceeding referred to in Section 7.7(a) or Section 7.7(b) shall be paid by the Company, when and as incurred, in advance of the final disposition of such action, suit or proceeding and in advance of any determination that such Indemnitee is not entitled to be indemnified, upon receipt of an undertaking by or on behalf of such Indemnitee to repay such amount if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (a “Final Adjudication”) that such Person is not entitled to be indemnified by the Company as authorized in this Section 7.7.

(e) The indemnification, advancement of expenses and other provisions of this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Member Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(f) The Company may purchase and maintain insurance, on behalf of its Managers and Officers, and such other Persons as the Board of Managers shall determine, against any liability that may be asserted against or expense that may be incurred by such Person in connection with the Company’s activities or such Person’s activities on behalf of the Company, regardless of whether the Company would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(g) For purposes of the definition of Indemnitee in Section 1.1, the Company shall be deemed to have requested a Person to serve as fiduciary of an employee benefit plan whenever the performance by such Person of his duties to the Company also imposes duties on, or otherwise involves services by, such Person to the plan or

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Index to Financial Statements

participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by such Person with respect to any employee benefit plan in the performance of such Person’s duties for a purpose reasonably believed by him to be in the interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in, or not opposed to, the best interests of the Company.

(h) Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Company, it being agreed that the Members shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Company to enable it to effectuate such indemnification.

(i) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(j) If a claim under Section 7.7 is not paid in full by the Company within 60 days after a written claim has been received by the Company, except in the case of a claim for an advancement of expenses, in which case the applicable period shall be 20 days, the Indemnitee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim. If successful in whole or in part in any such suit, or in a suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Indemnitee shall be entitled to be paid also the reasonable expenses of prosecuting or defending such suit. In (i) any suit brought by the Indemnitee to enforce a right to indemnification hereunder (but not in a suit brought by the Indemnitee to enforce a right to an advancement of expenses) it shall be a defense that, and (ii) in any suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Company shall be entitled to recover such expenses upon a Final Adjudication that, the Indemnitee has not met any applicable standard for indemnification set forth in this Agreement. Neither the failure of the Company (including its Managers who are not parties to such action, a committee of such Managers, independent legal counsel, or its Members) to have made a determination prior to the commencement of such suit that indemnification of the Indemnitee is proper in the circumstances because the Indemnitee has met the applicable standard of conduct set forth in this Agreement, nor an actual determination by the Company (including its Managers who are not parties to such action, a committee of such Managers, independent legal counsel, or its Members) that the Indemnitee has not met the applicable standard of conduct shall create a presumption that the Indemnitee has not met the applicable standard of conduct, or, in the case of such a suit brought by the Indemnitee, be a defense to such suit. In any suit brought by the Indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the Indemnitee is not entitled to be indemnified or to such advancement of expenses, under this Section 7.7 or otherwise shall be on the Company.

(k) The Company may indemnify any Person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (whether or not an action by or in the right of the Company) by reason of the fact that the Person is or was an employee (other than an Officer) or agent of the Company, or, while serving as an employee (other than an Officer) or agent of the Company is or was serving at the request of the Company as a director, officer, employee, partner, fiduciary, trustee or agent of another Group Member or another Person to the extent

(i) permitted by the laws of the State of Delaware as from time to time in effect, and

(ii) authorized by the Board of Managers.

The Company may, to the extent permitted by Delaware law and authorized by the Board of Managers, pay expenses (including attorneys’ fees) reasonably incurred by any such employee or agent in defending any civil, criminal, administrative or investigative action, suit or proceeding in advance of the final disposition of such action, suit or proceeding, upon such terms and conditions as the Board of Managers determine. The provisions of this Section 7.7(k) shall not constitute a contract right for any such employee or agent.

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Index to Financial Statements

(l) The indemnification, advancement of expenses and other provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(m) Except to the extent otherwise provided in Section 7.7(k), the right to be indemnified and to receive advancement of expenses in this Section 7.7 shall be a contract right. No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Company, nor the obligations of the Company to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

(n) Subject to Section 7.7(m), if Section 145 of the DGCL or any other provision of the DGCL is amended, modified or otherwise changed to authorize indemnification by a corporation of its directors or officers under a standard(s) that are broader than the standards specified in this Section 7.7, then the Board of Managers, acting alone and without the approval of any Member, may amend this Agreement to, entirely or in part, give effect to such broader standard(s) with respect to the Company’s obligations under this Section 7.7 in respect of Indemnitees.

Section 7.8 Exculpation of Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable to the Company, the Members or any other Persons who have acquired interests in Company Securities for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal. If the DGCL is amended, modified or otherwise changed to authorize Delaware corporations to eliminate or limit the personal liability of directors of a Delaware corporation beyond the standard for elimination of personal liability specified in the immediately preceding sentence, then the personal liability of an Indemnitee to the Company or its Members, in addition to the liability limitation provided in this Agreement, shall be further limited to the extent so permitted under the DGCL as so amended, modified or changed.

(b) Subject to its obligations and duties as Board of Managers set forth in this Article 7, the Board of Managers may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the Board of Managers shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the Board of Managers in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Company, to the Members or any other Persons who have acquired interests in Company Securities, none of the Managers and any other Indemnitee acting in connection with the Company’s business or affairs shall be liable to the Company, to any Member or any other Persons who have acquired interests in Company Securities for its good faith reliance on the provisions of this Agreement. The provisions of this Agreement, to the extent that they restrict or eliminate or otherwise modify the duties (including fiduciary duties) and liabilities of an Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of such Indemnitee.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of any Indemnitee under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

(e) An Indemnitee shall be fully protected in relying in good faith upon the records of the Company and upon information, opinions, reports or statements presented by a manager, member or liquidating trustee, an

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Index to Financial Statements

officer or employee of the Company, or committees of the Company, members or managers, or by any other person as to matters that the member, manager or liquidating trustees reasonably believes are within such other person’s professional or expert competence, including information, opinions, reports or statements as to the value and amount of the assets, liabilities, profits or losses of the Company, or the value and amount of assets or reserves or contracts, agreements or other undertakings that would be sufficient to pay claims and obligations of the Company or to make reasonable provision to pay such claims and obligations, or any other facts pertinent to the existence and amount of assets from which distributions to members or creditors might properly be paid.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between any Affiliate of the Company, on the one hand, and the Company or any Group Member, on the other, any resolution or course of action by the Board of Managers in respect of such conflict of interest shall be permitted and deemed approved by all Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty existing at law, in equity or otherwise, including any fiduciary duty, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of holders of a majority of the Outstanding Common Units (excluding Common Units held by interested parties), (iii) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company). The Board of Managers shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the Board of Managers may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is not sought and the Board of Managers determines that the resolution or course of action taken with respect to a conflict of interest complies with the standards set forth in clause (iii) or (iv) of the second preceding sentence, then (A) such resolution or course of action shall be permitted and deemed approved by all the Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty existing at law, in equity or otherwise, including any fiduciary duty and (B) it shall be presumed that, in making its decision, the Board of Managers acted in good faith, and in any proceeding brought by any Member or Assignee or by or on behalf of such Member or any other Member or the Company challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Members and shall not constitute a breach of this Agreement or any duty existing at law, in equity or otherwise.

(b) Each Person who is a Manager or Officer of the Company and also serves as a director, manager, officer or employee of Constellation or any of its Affiliates (other than a Group Member) shall, while acting or serving in such Person’s capacity as such director, manager, officer or employee, as the case may be, of Constellation or any such Affiliate (other than a Group Member) shall be deemed not to owe any duty (including any fiduciary or similar duty) or obligation to the Company Group or the holder(s) of Company Securities (or any class or series thereof) other than the obligation not to disclose to Constellation or such Affiliate confidential or proprietary information of the Company Group (unless Constellation or such Affiliate agrees in writing not to disclose such information to third parties or use such information for its purposes without the prior consent of the Company). For purposes of this Section 7.9 and Section 7.5(a) information acquired by a Person who is a Manager or Officer, which information is so acquired by such Person (i) other than from a Group Member and (ii) at a time while such Person is not then acting as such Manager or Officer and is instead engaged as a manager, director, officer or employee of a Person other than a Group Member, shall not constitute confidential or proprietary information of the Company Group.

(c) Whenever the Board of Managers or any Manager or Officer makes a determination or takes or declines to take any other action, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the

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Index to Financial Statements

Board of Managers or such Manager or Officer shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take other action must believe that the determination or other action is in the best interests of the Company. No action taken by the Board of Managers, any Manager or any Officer on behalf of the Company in good faith reliance on the provisions of this Agreement, including this Article 7, shall constitute a breach of any duty (including any fiduciary duty or other similar duty) on the part of such Board of Managers or any Manager or Officer, as the case may be. To the extent that the foregoing provisions have, or are construed to have, the effect of restricting, eliminating or otherwise modifying the duties and liabilities, including fiduciary duties, of the Managers or Officers, such provisions and any such restriction, elimination or modification are, and shall be deemed to have been, approved and agreed to by the Members.

(d) Notwithstanding anything to the contrary in this Agreement prior to the dissolution of the Company, the Board of Managers shall have no duty or obligation, express or implied, to sell or otherwise dispose of any asset of the Company Group other than in the ordinary course of business.

(e) Except as expressly set forth in this Agreement or required by law, none of the Managers, nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Company or any Member and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the Managers or any other Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of the Managers or such other Indemnitee.

(f) The Members hereby authorize the Board of Managers, on behalf of the Company as a partner or member of a Group Member, to approve of actions by the Board of Managers or managing member of such Group Member similar to those actions permitted to be taken by the Board of Managers pursuant to this Section 7.9.

Section 7.10 Duties of Officers and Managers.

(a) The duties and obligations owed to the Company and to the Members by the Officers and Managers shall be as set forth in this Agreement.

(b) A Manager shall, in the performance of his duties, be fully protected in relying in good faith upon the records of the Company and on such information, opinions, reports or statements presented to the Company by any of the Company’s Officers or employees, or committees of the Board of Managers, or by any other Person as to matters the Manager reasonably believes are within such other Person’s professional or expert competence and who has been selected with reasonable care by or on behalf of the Company.

(c) The Board of Managers shall have the right, in respect of any of its powers or obligations hereunder, to act through a duly appointed attorney or attorneys-in-fact or the duly authorized Officers of the Company.

Section 7.11 Purchase or Sale of Company Securities.

The Board of Managers may cause the Company to purchase or otherwise acquire Company Securities.

Section 7.12 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Company shall be entitled to assume that the Board of Managers and any Officer authorized by the Board of Managers to act on behalf of and in the name of the Company has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Company and to enter into any authorized contracts on behalf of the Company, and such Person shall be entitled to deal with the Board of Managers or any Officer as if it were the Company’s sole party in interest, both legally and beneficially. Each Member hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or

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Index to Financial Statements

disaffirm any action of the Board of Managers or any Officer in connection with any such dealing. In no event shall any Person dealing with the Board of Managers or any Officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the Board of Managers or any Officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Company by the Board of Managers or any Officer or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Company and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Company.

Article 8

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting.

The Board of Managers shall keep or cause to be kept at the principal office of the Company appropriate books and records with respect to the Company’s business, including all books and records necessary to provide to the Members any information required to be provided pursuant to this Agreement. Any books and records maintained by or on behalf of the Company in the regular course of its business, including the record of the Record Holders or Assignees of Common Units or other Company Securities, books of account and records of Company proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Company shall be maintained, for financial reporting purposes, on an accrual accounting basis in accordance with U.S. GAAP.

Section 8.2 Fiscal Year.

The fiscal year of the Company shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 90 days after the close of each fiscal year of the Company, the Board of Managers shall cause to be mailed or made available by any reasonable means (including posting on the Company’s website) to each Record Holder of a Common Unit as of a date selected by the Board of Managers, an annual report containing financial statements of the Company for such fiscal year of the Company, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, equity and cash flows, such statements to be audited by a registered public accounting firm selected by the Board of Managers.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the Board of Managers shall cause to be mailed or made available to each Record Holder of a Common Unit, as of a date selected by the Board of Managers, a report containing unaudited financial statements of the Company and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Common Units are listed for trading, or as the Board of Managers determines to be necessary or appropriate.

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Index to Financial Statements

Article 9

TAX MATTERS

Section 9.1 Returns and Information.

The Company shall timely file all returns of the Company that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days after the close of the calendar year in which the Company’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Company shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the Board of Managers’ determination that such revocation is in the best interests of the Members. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the Board of Managers shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Member Interest will be deemed to be the lowest quoted closing price of the Member Interests on any National Securities Exchange on which such Member Interests are traded during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(c)(i) without regard to the actual price paid by such transferee.

(b) The Company shall elect to amortize or deduct expenses incurred in organizing the Company as provided in Section 709 of the Code.

(c) Except as otherwise provided herein, the Board of Managers shall determine whether the Company should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

Subject to the provisions hereof, the Board of Managers shall designate one Officer who is a Member as the Tax Matters Partner (as defined in the Code). The Tax Matters Partner is authorized and required to represent the Company (at the Company’s expense) in connection with all examinations of the Company’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Company funds for professional services and costs associated therewith. Each Member agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings.

Section 9.4 Withholding.

Notwithstanding any other provision of this Agreement, the Board of Managers is authorized to take any action that may be required to cause the Company and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Company is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Member (including by reason of Section 1446 of the Code), the Board of Managers may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Member.

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Index to Financial Statements

Article 10

DISSOLUTION AND LIQUIDATION

Section 10.1 Dissolution.

The Company shall not be dissolved by the admission of Substituted Members or Additional Members. The Company shall dissolve, and its affairs shall be wound up, upon:

(a) an election to dissolve the Company by the Board of Managers that is approved by the holders of a Class A Unit Majority and a Common Unit Majority;

(b) the sale, exchange or other disposition of all or substantially all of the assets and properties of the Company Group;

(d) at such time as there are no Members, unless the Company is continued without dissolution in accordance with the Delaware Act.

Section 10.2 Liquidator.

Upon dissolution of the Company, the Board of Managers shall select one or more Persons to act as Liquidator. The Liquidator (if other than the Board of Managers) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the Board of Managers) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, death, incapacity, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a Unit Majority. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article 10, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the Board of Managers under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3(b)) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Company as provided for herein.

Section 10.3 Liquidation.

The Liquidator shall proceed to dispose of the assets of the Company, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 18-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Members on such terms as the Liquidator and such Member or Members may agree. If any property is distributed in kind, the Member receiving the property shall be deemed for purposes of Section 10.3(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Members. Notwithstanding anything to the contrary contained in this Agreement, the Members understand and acknowledge that a Member may be compelled to accept a distribution of any asset in kind from the Company despite the fact that the percentage of the asset distributed to such Member exceeds the percentage of that asset which is equal to the percentage in which such Member shares in distributions from the Company. The Liquidator may defer liquidation or distribution of the Company’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Company’s assets would be impractical or

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Index to Financial Statements

would cause undue loss to the Members. The Liquidator may distribute the Company’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Members.

(b) Liabilities of the Company include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 10.2) and amounts to Members otherwise than in respect of their distribution rights under Article 6. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be applied to other liabilities or distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 10.3(b) shall be distributed to the Members in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 10.3(c)) for the taxable year of the Company during which the liquidation of the Company occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 10.4 Cancellation of Certificate of Formation.

Upon the completion of the distribution of Company cash and property as provided in Section 10.3 in connection with the liquidation of the Company, the Certificate of Formation and all qualifications of the Company as a foreign limited liability company in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Company shall be taken.

Section 10.5 Return of Contributions.

None of any member of the Board of Managers or any Officer will be personally liable for, or have any obligation to contribute or loan any monies or property to the Company to enable it to effectuate, the return of the Capital Contributions of the Members or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Company assets. A Member may not resign or withdraw from the Company prior to the dissolution and winding up of the Company, provided that neither the transfer of any Member Interest nor the cancellation of the Class D Interests as provided in this Agreement shall constitute a breach or violation of this provision.

Section 10.6 Waiver of Partition.

To the maximum extent permitted by law, each Member hereby waives any right to partition of the Company property.

Section 10.7 Capital Account Restoration.

No Member shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Company.

Article 11

AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE

Section 11.1 Amendment of Operating Agreement.

(a) General Amendments. Except as provided in Section 11.1(b) and Section 11.1(c), the Board of Managers may amend any of the terms of this Agreement but only in compliance with the terms, conditions and procedures

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set forth in this Section 11.1(a). If the Board of Managers desires to amend any provision of this Agreement other than pursuant to Section 11.1(c), then it shall first adopt a resolution setting forth the amendment proposed, declaring its advisability and either calling a special meeting of the Members entitled to vote in respect thereof for the consideration of such amendment or directing that the amendment proposed be considered at the next annual meeting of the Members. Amendments to this Agreement may be proposed only by or with the consent of the Board of Managers. Such special or annual meeting shall be called and held upon notice in accordance with Section 11.3 and Section 11.4 of this Agreement. The notice of such meeting shall set forth such amendment in full or a brief summary of the changes to be effected thereby, as the Board of Managers shall deem advisable. At the meeting, a vote of Members entitled to vote thereon shall be taken for and against the proposed amendment. A proposed amendment shall be effective upon its approval by both a Class A Unit Majority and a Common Unit Majority, unless a greater percentage is required by this Agreement.

(b) Super-Majority Amendments. Notwithstanding Section 11.1(a) but subject to Section 11.1(c), the affirmative vote of the holders of at least 75% of all Outstanding Common Units and 75% of all Outstanding Class A Units shall be required to alter, amend or adopt any provision inconsistent with or repeal Section 7.1(b), this Section 11.1(b), Section 11.2, Section 11.3(d), Section 11.8(b), Section 11.8(c), Section 11.10 or Section 11.13.

(c) Amendments to be Adopted Solely by the Board of Managers. Notwithstanding Section 11.1(a) and Section 11.1(b), the Board of Managers, without the approval of any Member or holder of any Company Securities, may amend any provision of this Agreement, and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(i) a change in the name of the Company, the location of the principal place of business of the Company, the registered agent of the Company or the registered office of the Company;

(ii) admission, substitution, withdrawal or removal of Members in accordance with this Agreement;

(iii) a change that the Board of Managers determines to be necessary or appropriate to qualify or continue the qualification of the Company as a limited liability company under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(iv) a change that the Board of Managers determines (A) does not adversely affect the Members (including any particular class of Member Interests as compared to other classes of Member Interests) in any material respect, (B) to be necessary or appropriate to (1) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (2) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which Units are or will be listed for trading, compliance with any of which the Board of Managers deems to be in the best interests of the Company and the Members, (C) to be necessary or appropriate in connection with action taken by the Board of Managers pursuant to Section 5.8 or (D) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(v) a change in the fiscal year or taxable year of the Company and any other changes that the Board of Managers determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Company, including, if the Board of Managers shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Company;

(vi) an amendment that is necessary, in the Opinion of Counsel, to prevent the Company or its Managers, Officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

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(vii) subject to Section 5.6, an amendment that the Board of Managers determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Company Securities pursuant to Section 5.5;

(viii) any amendment expressly permitted in this Agreement to be made by the Board of Managers acting alone;

(ix) an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 12.3;

(x) an amendment that the Board of Managers determines to be necessary or appropriate to reflect and account for the formation by the Company of, or investment by the Company in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Company of activities permitted by the terms of Section 2.4;

(xi) a merger, consolidation, conversion or conveyance pursuant to Section 12.3(d);

(xii) an amendment that requires, in connection with a transfer of Member Interests, the Assignees of Member Interests to provide a statement, certification or other proof to the Company regarding such Assignee’s status as an Eligible Citizen; or

(xiii) any other amendments substantially similar to the foregoing.

Section 11.2 Amendment Requirements.

(a) Notwithstanding the provisions of Section 11.1, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Section 11.1, no amendment to this Agreement may (i) enlarge the obligations of any Member without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 11.2(c), (ii) change Section 10.1(a), (iii) change the term of the Company, or (iv) except as set forth in Section 10.1(a), give any Person the right to dissolve the Company.

(c) Except as provided in Section 12.3, and without limitation of the Board of Managers’ authority to adopt amendments to this Agreement without the approval of any Members as contemplated in Section 11.1 (including Section 11.1(c)(vii)), any amendment that would have a material adverse effect on the rights or preferences of any then Outstanding class of Member Interests in relation to other classes of Member Interests must be approved by the holders of not less than a majority of the Outstanding Member Interests of the class affected, provided that amending this Agreement to create a new class or series of Company Securities pursuant to Section 5.5 with relative rights, powers, preferences and duties that are senior or prior to, or pari passu with, the relative rights, powers, preferences or duties of any then Outstanding Member Interests shall not be deemed to cause such a material adverse effect.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 11.1(c) and except as otherwise provided by Section 12.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Common Units and Class A Units, voting as a single class, unless the Company obtains an Opinion of Counsel to the effect that such amendment will not adversely affect the limited liability of any Member under applicable law.

Section 11.3 Unitholder Meetings.

(a) All acts of Members to be taken hereunder shall be taken in the manner provided in this Article 11. An annual meeting of the Members for the election of Managers and for the transaction of such other business as may properly come before the meeting shall be held at such time and place as the Board of Managers shall

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specify, which date shall be within 13 months of the last annual meeting of Members. If authorized by the Board of Managers, and subject to such guidelines and procedures as the Board of Managers may adopt, Members and proxyholders not physically present at a meeting of Members, may by means of remote communication participate in such meeting, and be deemed present in person and vote at such meeting provided that the Company shall implement reasonable measures to verify that each Person deemed present and permitted to vote at the meeting by means of remote communication is a Member or proxyholder, to provide such Members or proxyholders a reasonable opportunity to participate in the meeting and to record the votes or other action made by such Members or proxyholders.

(b) A failure to hold the annual meeting of the Members at the designated time or to elect a sufficient number of Managers to conduct the business of the Company shall not affect otherwise valid acts of the Company or work a forfeiture or dissolution of the Company. If the annual meeting for election of Managers is not held on the date designated therefor, the Managers shall cause the meeting to be held as soon as is convenient. If there is a failure to hold the annual meeting for a period of 30 days after the date designated for the annual meeting, or if no date has been designated, for a period of 13 months after the latest to occur of the date of this Agreement or its last annual meeting, it is the intent of the parties that the Delaware Court of Chancery may summarily order a meeting to be held upon the application of any Member or Manager. The Outstanding Units present at such meeting, either in person or by proxy, and entitled to vote thereat, shall constitute a quorum for the purpose of such meeting, notwithstanding any provision of this Agreement to the contrary. The Delaware Court of Chancery may issue such orders as may be appropriate, including orders designating the time and place of such meeting, the record date for determination of Unitholders entitled to vote, and the form of notice of such meeting.

(c) All elections of Managers will be by written ballots; if authorized by the Board of Managers, such requirement of a written ballot shall be satisfied by a ballot submitted by electronic transmission, provided that any such electronic transmission must either set forth or be submitted with information from which it can be reasonably determined that the electronic transmission was authorized by the Member or proxyholder.

(d) Special meetings of the Members may be called only by a majority of the Board of Managers. No Members or group of Members, acting in its or their capacity as Members, shall have the right to call a special meeting of the Members.

Section 11.4 Notice of Meetings of Members.

(a) Notice, stating the place, day and hour of any annual or special meeting of the Members, as determined by the Board of Managers, and (i) in the case of a special meeting of the Members, the purpose or purposes for which the meeting is called, as determined by the Board of Managers or (ii) in the case of an annual meeting, those matters that the Board of Managers, at the time of giving the notice, intends to present for action by the Members, shall be delivered by the Company not less than 10 calendar days nor more than 60 calendar days before the date of the meeting, in a manner and otherwise in accordance with Section 14.1 to each Record Holder who is entitled to vote at such meeting. Such further notice shall be given as may be required by applicable law. The notice of any meeting of the Members at which Managers are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the Board of Managers intends to present for election. Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company’s notice of meeting. Any previously scheduled meeting of the Members may be postponed, and any special meeting of the Members may be canceled, by resolution of the Board of Managers upon public notice given prior to the date previously scheduled for such meeting of the Members.

(b) The Board of Managers shall designate the place of meeting for any annual meeting or for any special meeting of the Members. If no designation is made, the place of meeting shall be the principal office of the Company.

Section 11.5 Record Date.

For purposes of determining the Members entitled to notice of or to vote at a meeting of the Members or to give approvals without a meeting as provided in Section 11.10, the Board of Managers may set a Record Date,

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which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Common Units are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Members are requested by the Board of Managers to give such approvals. If no Record Date is fixed by the Board of Managers, then (a) the Record Date for determining Members entitled to notice of or to vote at a meeting of Members shall be at the close of business on the day next preceding the day on which notice is given and (b) the Record Date for determining the Members entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Company in care of the Board of Managers. A determination of Members of record entitled to notice of or to vote at a meeting of Members shall apply to any adjournment or postponement of the meeting; provided, however, that the Board of Managers may fix a new Record Date for the adjourned or postponed meeting.

Section 11.6 Adjournment.

The Chairman of the Board, or, if the Chief Executive Officer is acting as the chairman of such meeting, the Chief Executive Officer, may adjourn any meeting of the Members, whether for lack of a quorum or any other reason. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 30 days. At the adjourned meeting, the Company may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 30 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article 11.

Section 11.7 Waiver of Notice; Approval of Meeting.

Whenever notice to the Members is required to be given under this Agreement, a written waiver, signed by the Person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a Person at any such meeting of the Members shall constitute a waiver of notice of such meeting, except when the Person attends a meeting for the express purpose of objecting at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Members need be specified in any written waiver of notice unless so required by resolution of the Board of Managers. All waivers and approvals shall be filed with the Company records or made part of the minutes of the meeting.

Section 11.8 Quorum; Required Vote for Member Action; Voting for Managers.

(a) At any meeting of the Members, the holders of a majority of the Outstanding Units or Member Interests of each class then outstanding and entitled to vote, represented in person or by proxy, shall constitute a quorum of such class or classes unless any such action by the Members requires approval by holders of a greater percentage of Outstanding Units or Member Interests, in which case the quorum shall be such greater percentage. The submission of matters to Members for approval and the election of Managers shall occur only at a meeting of the Members duly called and held in accordance with this Agreement at which a quorum is present; provided, however, that the Members present at a duly called and held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Members to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Member Interests specified in this Agreement. In the absence of a quorum any meeting of Members may be adjourned from time to time by the chairman of the meeting to another place or time.

(b) The Members holding Outstanding Common Units and Class A Units shall be entitled to one vote per Unit on all matters submitted to Members for approval and in the election of Managers.

(c) Except as otherwise provided in this Agreement, all matters submitted to Members for approval shall be determined by a majority of the votes cast affirmatively or negatively by Members holding Outstanding Units

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unless a greater percentage is required with respect to such matter under the Delaware Act, under the rules of any National Securities Exchange on which the Common Units are listed for trading, or under the provisions of this Agreement, in which case the approval of Members holding Outstanding Common Units and Class A Units that in the aggregate represent at least such greater percentage shall be required.

(d) Subject only to Section 7.1(b), Section 7.1(e) and Section 11.8(e) and notwithstanding any other provision of this Agreement to the contrary, the Class A Unitholders, voting together as a single class, shall elect two Managers (each, a “Class A Manager”) and the Common Unitholders, voting together as a single class, shall elect three Managers (each, a “Class B Manager”). The Board of Manager agrees to call a meeting of the Common Unitholders as provided in this Article 11 when a vote of the Common Unitholders is to be held to elect a Class B Manager or fill a vacancy as provided in Section 7.1(e). Managers will be elected by a plurality of the votes cast for a particular position.

(e) The right of the holders of the Class A Units to appoint the Class A Managers pursuant to Section 11.8(d) may, subject to Section 11.13, be terminated at any duly called meeting of the Members upon the affirmative vote of holders of not less than 66 2/3% of Outstanding Common Units. Thereafter, if (i) the Class A Units are not converted into Common Units pursuant to Section 3.8, all five (or such other number as the Board of Managers may determine pursuant to Section 7.1(b)) Managers shall be elected by a plurality of the votes cast by the holders of Outstanding Common Units and Class A Units, voting as a single class, for a particular position; and (ii) if the Class A Units are converted into Common Units pursuant to Section 3.8, all five (or such other number as the Board of Managers may determine pursuant to Section 7.1(b)) Managers shall be elected by a plurality of the votes cast by the holders of Outstanding Common Units, voting as a single class, for a particular position.

Section 11.9 Conduct of a Meeting; Member Lists.

(a) The Board of Managers shall have full power and authority concerning the manner of conducting any meeting of the Members, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of this Article 11, the conduct of voting, the validity and effect of any proxies and (subject to Section 11.12(d)) the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The Board of Managers shall have the power to designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Company maintained by the Board of Managers. The Board of Managers may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Members, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes, the submission and examination of proxies and other evidence of the right to vote.

(b) A complete list of Members entitled to vote at any meeting of Members, arranged in alphabetical order for each class of Member Interests and showing the address of each such Member and the number of Outstanding Units or Member Interests registered in the name of such Member, shall be open to the examination of any Member, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days before the meeting, at the principal place of business of the Company. The Member list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any Member who is present.

Section 11.10 Action Without a Meeting.

The holders of Class A Units (and if the holders of the Management Incentive Interests or the Class D Interests are entitled to vote on any matter, the holder(s) of such Member Interests) may take any action or give any approval, whether together or as separate classes, without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken or approval so given shall be signed by the Members holding a sufficient percentage of Member Interests to otherwise take such action or give such approval and delivered to the Company. No other action permitted or required to be taken at a meeting of Members may

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be taken by written consent or by any other means or manner than a meeting of Members called and conducted in accordance with this Agreement.

Section 11.11 Voting and Other Rights.

(a) Only those Record Holders of Outstanding Units and Member Interests on the Record Date established pursuant to Section 11.5 shall be entitled to notice of, and to vote at, a meeting of Members or to act with respect to matters as to which the holders of the Outstanding Units and Member Interests have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units and Member Interests shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units and Member Interests.

(b) With respect to Outstanding Units or Member Interests that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Outstanding Units or Member Interests are registered, such other Person shall, in exercising the voting rights in respect of such Outstanding Units or Member Interests on any matter, and unless the arrangement between such Persons provides otherwise, vote such Outstanding Units or Member Interests in favor of, and at the direction of, the Person who is the beneficial owner, and the Company shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 11.11(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

Section 11.12 Proxies and Voting.

(a) At any meeting of the Members, every holder of an Outstanding Unit or Member Interests entitled to vote may vote in person or by proxy authorized by an instrument in writing or by a transmission permitted by law filed in accordance with the procedure established for the meeting. Any copy, facsimile telecommunication or other reliable reproduction of the writing or transmission created pursuant to this paragraph may be substituted or used in lieu of the original writing or transmission for any and all purposes for which the original writing or transmission could be used, provided that such copy, facsimile telecommunication or other reproduction shall be a complete reproduction of the entire original writing or transmission.

(b) The Company may, and to the extent required by law, shall, in advance of any meeting of Members, appoint one or more inspectors to act at the meeting and make a written report thereof. The Company may designate one or more alternate inspectors to replace any inspector who fails to act. If no inspector or alternate is able to act at a meeting of Members, the Person presiding at the meeting may, and to the extent required by law, shall, appoint one or more inspectors to act at the meeting. Each inspector, before entering upon the discharge of his or her duties, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of his or her ability. Every vote taken by ballots shall be counted by a duly appointed inspector or inspectors.

(c) With respect to the use of proxies at any meeting of Members, the Company shall be governed by paragraphs (b), (c), (d) and (e) of Section 212 of the DGCL and other applicable provisions of the DGCL, as though the Company were a Delaware corporation and as though the Members were stockholders of a Delaware corporation.

(d) With respect to any contested matter relating to any election, appointment, removal or resignation of any Manager, to the fullest extent permitted by law, the Company shall be governed by Section 225 of the DGCL and any other applicable provision of the DGCL, as though the Company were a Delaware corporation.

Section 11.13 Notice of Member Business and Nominations.

(a) Subject to Section 7.1(e), nominations of Persons for election to the Board of Managers and the proposal of business to be considered by the Members may be made at an annual meeting of Members (i) pursuant to the Company’s notice of meeting delivered pursuant to Section 11.4 of this Agreement, (ii) by or at the direction of the Board of Managers, (iii) for nominations to the Board of Managers only, by any holder of Outstanding Units

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who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraph (b) or (d) of this Section 11.13 and who was a Record Holder of a sufficient number of Outstanding Units as of the Record Date for such meeting to elect one or more members to the Board of Managers assuming that such holder cast all of the votes it is entitled to cast in such election in favor of a single candidate and such candidate received no other votes from any other holder of Outstanding Units, or (iv) by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraphs (c) or (d) of this Section 11.13 and who is a Record Holder of Outstanding Units at the time such notice is delivered to the Secretary of the Company.

(b) For nominations to be properly brought before an annual meeting by a Unitholder pursuant to Section 11.13(a)(iii), the Unitholder must have given timely notice thereof in writing to the Secretary of the Company. To be timely, a Unitholder’s notice shall be delivered to the Secretary at the principal executive offices of the Company not less than 90 or more than 120 days prior to the anniversary (the “Anniversary”) of the date on which the Company first mailed its proxy materials for the preceding year’s annual meeting of Members; provided, however, that if the date of the annual meeting is advanced more than 30 days prior to or delayed by more than 30 days after the anniversary of the preceding year’s annual meeting, notice by the Unitholder to be timely must be so delivered not later than the close of business on the later of (x) the ninetieth day prior to such annual meeting or (y) the tenth day following the day on which public announcement of the date of such meeting is first made. Such Unitholder’s notice shall set forth: (A) as to each Person whom the Unitholder proposes to nominate for election or reelection as a Manager all information relating to such Person that is required to be disclosed in solicitations of proxies for election of Managers, or is otherwise required, in each case pursuant to Regulation 14A under the Exchange Act, including such Person’s written consent to being named in the proxy statement as a nominee and to serving as a Manager if elected and (B) as to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination is made the name and address of such Unitholder, as they appear on the Company’s books, and of such beneficial owner, the class and number of Units which are owned beneficially and of record by such Unitholder and such beneficial owner. Such holder shall be entitled to nominate as many candidates for election to the Board of Managers as would be elected assuming such holder cast the precise number of votes necessary to elect each candidate and no more votes were cast by such holder or any other holder for such candidates.

(c) For nominations or other business to be properly brought before an annual meeting by a Unitholder pursuant to Section 11.13(a), (i) the Unitholder must have given timely notice thereof in writing to the Secretary of the Company, (ii) such business must be a proper matter for Member action under this Agreement and the Delaware Act, (iii) if the Unitholder, or the beneficial owner on whose behalf any such proposal or nomination is made, has provided the Company with a Solicitation Notice, such Unitholder or beneficial owner must, in the case of a proposal, have delivered a proxy statement and form of proxy to holders of at least the percentage of the Outstanding Units required under this Agreement or the Delaware Act to carry any such proposal, or, in the case of a nomination or nominations, have delivered a proxy statement and form of proxy to holders of a percentage of the Outstanding Units reasonably believed by such Unitholder or beneficial owner to be sufficient to elect the nominee or nominees proposed to be nominated by such Unitholder, and must, in either case, have included in such materials the Solicitation Notice and (iv) if no Solicitation Notice relating thereto has been timely provided pursuant to this Section 11.13, the Unitholder or beneficial owner proposing such business or nomination must not have solicited a number of proxies sufficient to have required the delivery of such a Solicitation Notice. To be timely, a Unitholder’s notice shall be delivered to the Secretary at the principal executive offices of the Company not less than 90 or more than 120 days prior to the first Anniversary; provided, however, that in the event that the date of the annual meeting is advanced more than 30 days prior to or delayed by more than 30 days after the anniversary of the preceding year’s annual meeting, notice by the Unitholder to be timely must be so delivered not later than the close of business on the later of (x) the ninetieth day prior to such annual meeting or (y) the tenth day following the day on which public announcement of the date of such meeting is first made. Such Unitholder’s notice shall set forth: (A) as to each Person whom the Unitholder proposes to nominate for election or reelection as a Manager all information relating to such Person that is required to be disclosed in solicitations of proxies for election of Managers, or is otherwise required, in each case pursuant to Regulation 14A under the Exchange Act, including such Person’s written consent to being named in the proxy statement as a nominee and

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to serving as a Manager if elected; (B) as to any other business that the Unitholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest in such business of such Unitholder and the beneficial owner, if any, on whose behalf the proposal is made; and (C) as to the Unitholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made the name and address of such Unitholder, as they appear on the Company’s books, and of such beneficial owner, the class and number of Units which are owned beneficially and of record by such Unitholder and such beneficial owner, and whether either such Unitholder or beneficial owner intends to deliver a proxy statement and form of proxy to holders of, in the case of a proposal, at least the percentage of the Outstanding Units required under this Agreement or Delaware law to carry the proposal or, in the case of a nomination or nominations, holders of a percentage of the Outstanding Units reasonably believed by such Unitholder or beneficial owner to be sufficient to elect the nominee or nominees proposed to be nominated by such Unitholder (an affirmative statement of such intent, a “Solicitation Notice”).

(d) Notwithstanding anything in the second sentence of Section 11.13(b) or the second sentence of Section 11.13(c) to the contrary, if the number of Managers to be elected to the Board of Managers is increased, there is no public announcement naming all of the nominees for Manager or specifying the size of the increased Board of Managers made by the Company at least 90 days prior to the Anniversary and the vacancy created by such increase can be filled by a nominee approved by a Common Unit Majority, then a Unitholder’s notice required by this Section 11.13 shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business on the tenth day following the day on which such public announcement is first made by the Company.

(e) Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company’s notice of meeting pursuant to Section 11.4 of this Agreement. Subject to Section 7.1(d) of this Agreement, nominations of Persons for election to the Board of Managers may be made at a special meeting of Members at which Managers are to be elected (i) pursuant to the Company’s notice of meeting, (ii) by or at the direction of the Board of Managers, (iii) by any holder of Outstanding Units who is entitled to vote at the meeting, who complied with the notice procedures set forth in paragraph (b) or (d) of this Section 11.13 and who was a Record Holder of a sufficient number of Outstanding Units as of the Record Date for such meeting to elect one or more members to the Board of Managers assuming that such holder cast all of the votes it is entitled to cast in such election in favor of a single candidate and such candidate received no other votes from any other holder of Outstanding Units, or (iv) by any holder of Outstanding Units who is entitled to vote at the meeting, who complies with the notice procedures set forth in paragraphs (c) or (d) of this Section 11.13 and who is a Record Holder of Outstanding Units at the time such notice is delivered to the Secretary of the Company. Nominations by Unitholders of Persons for election to the Board of Managers may be made at such a special meeting of Members if the Unitholder’s notice as required by Section 11.13(b) or Section 11.13(c) shall be delivered to the Secretary of the Company not earlier than the ninetieth day prior to such special meeting and not later than the close of business on the later of the seventieth day prior to such special meeting or the tenth day following the day on which public announcement is first made of the date of the special meeting and of the nominees proposed by the Board of Managers to be elected at such meeting. Holders of Outstanding Units making nominations pursuant to Section 11.13(e)(iii) shall be entitled to nominate the number of candidates for election at such special meeting as provided in Section 11.13(b) for an annual meeting.

(f) Except to the extent otherwise provided in Section 7.1(d) and Section 7.1(e), with respect to vacancies, only Persons who are nominated in accordance with the procedures set forth in this Section 11.13 shall be eligible to serve as Managers and only such business shall be conducted at a meeting of Members as shall have been brought before the meeting in accordance with the procedures set forth in this Section 11.13. Except as otherwise provided herein or required by law, the Chairman of the Board or other Person designated by the Board of Managers as the chairman of the meeting shall have the power and duty to determine whether a nomination or any business proposed to be brought before the meeting was made in accordance with the procedures set forth in this Section 11.13 and, if any proposed nomination or business is not in compliance with this Section 11.13, to declare that such defective proposal or nomination shall be disregarded.

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(g) Notwithstanding the foregoing provisions of this Section 11.13, a Member shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 11.13. Nothing in this Section 11.13 shall be deemed to affect any rights of Members to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

(h) All provisions of this Section 11.13 are subject to Section 11.8(d).

Article 12

MERGER, CONSOLIDATION OR CONVERSION

Section 12.1 Authority.

The Company may merge or consolidate with one or more limited liability companies or “other business entity” as defined in Section 18-209 of the Delaware Act, or convert into any “other entity” as defined in Section 18-214 of the Delaware Act, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article 12.

Section 12.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Company pursuant to this Article 12 requires the prior approval of the Board of Managers, provided, however, that, to the fullest extent permitted by law, the Board of Managers shall have no duty or obligation to consent to any merger, consolidation or conversion of the Company and may decline to do so free of any fiduciary duty or obligation whatsoever to the Company or any Member and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the Board of Managers shall determine to consent to a merger or consolidation, the Board of Managers shall approve the Merger Agreement, which shall set forth:

(i) the names and jurisdiction of domicile of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the rights or securities of, or interests in, each constituent business entity for, or into, cash, property, rights, or obligations of, securities of or interests in, the Surviving Business Entity; and (A) if any rights or securities of, or interests in, any constituent business entity are not to be exchanged or converted solely for, or into, cash, property, rights, or obligations of, securities of or interests in, the Surviving Business Entity, the cash, property, rights, or obligations of, securities of or interests in, any limited liability company or other business entity which the holders of such rights, securities or interests are to receive in exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property, rights or obligations of securities of or interests in the Surviving Business Entity or any other business entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the certificate of formation or limited liability company agreement, articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other

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similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger or consolidation, which may be the date of the filing of the certificate of merger pursuant to Section 12.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger or consolidation is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed at a date no later than the time of the filing of the certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the Board of Managers determines to be necessary or appropriate.

(c) If the Board of Managers shall determine to consent to a conversion, the Board of Managers shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Company is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(iv) the manner and basis of exchanging or converting the equity securities of the converting entity for or into securities of or interests in the converted entity or other property;

(v) in an attachment or exhibit, the certificate of formation of the Company; and

(vi) in an attachment or exhibit, the certificate of formation or limited liability company agreement, articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the certificate of conversion pursuant to Section 12.4 or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such certificate of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the Board of Managers determines to be necessary or appropriate.

Section 12.3 Approval by Members of Merger, Consolidation or Conversion.

(a) Except as provided in Section 12.3(d), the Board of Managers, upon its approval of the Merger Agreement or Plan of Conversion, as the case may be, shall direct that the Merger Agreement or Plan of Conversion, as applicable, be submitted to a vote of Members, whether at an annual meeting or a special meeting, in either case in accordance with the requirements of Article 11. A copy or a summary of the Merger Agreement or Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of meeting or the written consent.

(b) Except as provided in Section 12.3(d), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Class A Unit Majority and a Common Unit Majority unless the Merger Agreement or Plan of Conversion, as applicable, contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Members, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or Plan of Conversion, as applicable.

(c) Except as provided in Section 12.3(d), after such approval by vote or consent of the Members, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 12.4, the

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merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as applicable.

(d) Notwithstanding anything else contained in this Article 12 or in this Agreement, the Board of Managers is permitted without Member approval, to convert the Company or any Group Member into a new limited liability entity, to merge the Company or any Group Member into, or convey all of the Company’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Company or other Group Member if (i) the Board of Managers has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Member or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Company into another limited liability entity and (iii) the governing instruments of the new entity provide the Members and the Board of Managers with the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article 12 or in this Agreement, the Board of Managers is permitted without Member approval to merge or consolidate the Company with or into another entity if (A) the Board of Managers has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Member under Delaware law or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement other than any amendments that could be adopted pursuant to Section 11.1(c), (C) the Company is the Surviving Business Entity in such merger or consolidation, (D) each Member Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Member Interest of the Company after the effective date of the merger or consolidation, and (E) the number of Company Securities to be issued by the Company in such merger or consolidation do not exceed 20% of the Company Securities Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 18-209(f) of the Delaware Act, a Merger Agreement approved in accordance with this Article 12 may (i) effect any amendment to this Agreement or (ii) effect the adoption of a new limited liability company agreement for the Company if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 12.3 shall be effective at the effective time or date of the merger or consolidation.

(g) Members are not entitled to dissenters’ rights of appraisal in the event of a merger, consolidation or conversion pursuant to Section 12.1, a sale of all or substantially all of the assets of the Company or the Company’s Subsidiaries, or any other transaction or event.

Section 12.4 Certificate of Merger; Certificate of Conversion.

Upon the required approval by the Board of Managers and the Unitholders of a Merger Agreement, a certificate of merger, or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 12.5 Effect of Merger or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

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(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the certificate of conversion:

(i) the other entity or business form shall be deemed to be the same entity as the Company and the conversion shall constitute a continuation of the existence of the Company in the form of such other entity or business form;

(ii) such conversion shall not be deemed to affect any obligations or liabilities of the Company incurred prior to such conversion or the personal liability of any person incurred prior to such conversion, nor shall it be deemed to affect the choice of law applicable to the Company with respect to matters arising prior to such conversion;

(iii) the other entity or business form shall, for all purposes of the laws of the State of Delaware, be deemed to be the same entity as the Company;

(iv) all of the rights, privileges and powers of the Company that has converted, and all property, real, personal and mixed, and all debts due to the Company, as well as all other things and causes of action belonging to the Company, shall remain vested in the other entity or business form to which the Company has converted and shall be the property of such other entity or business form, and the title to any real property vested by deed or otherwise in the Company shall not revert or be in any way impaired;

(v) all rights of creditors and all liens upon any property of the Company shall be preserved unimpaired, and all debts, liabilities and duties of the Company shall remain attached to the other entity or business form to which the Company has converted, and may be enforced against it to the same extent as if said debts, liabilities and duties had originally been incurred or contracted by it in its capacity as such other entity or business form;

(vi) the rights, privileges, powers and interests in property of the Company, as well as the debts, liabilities and duties of the Company, shall not be deemed, as a consequence of the conversion, to have been transferred to the other entity or business form to the Company has converted for any purpose of the laws of the State of Delaware; and

(vii) the Company Securities that are to be exchanged for or converted into cash, property, rights or securities of or interests in the entity or business form into which the Company is being converted shall be so exchanged or converted in accordance with the Plan of Conversion, or, in addition to or in lieu thereof, if the Plan of Conversion so provides, the Company Securities may be exchanged for or converted into cash, property, rights or securities of or interests in another entity or business form or may be cancelled.

(c) It is the intent of the parties hereto that a merger, consolidation or conversion effected pursuant to this Article 12 shall not be deemed to result in a transfer or assignment of assets, liabilities, debts or duties from one entity to another.

Section 12.6 Business Combination Limitations.

Notwithstanding any other provision of this Agreement, with respect to any “Business Combination” (as such term is defined in Section 203 of the DGCL), the provisions of Section 203 of the DGCL shall be applied with respect to the Company as though the Company were a Delaware corporation.

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Article 13

RIGHT TO ACQUIRE MEMBER INTERESTS

Section 13.1 Right to Acquire Member Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time any Person holds more than 80% of the total Member Interests of any class then Outstanding, such Person shall then have the right, which right it may assign and transfer in whole or in part to the Company or any of its Affiliates, exercisable at its option, to purchase all, but not less than all, of such Member Interests of such class then Outstanding held by other holders, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 13.1(b) is mailed and (y) the highest price paid by such Person or any of its Affiliates for any such Member Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 13.1(b) is mailed.

(b) If any Person elects to exercise the right to purchase Member Interests granted pursuant to Section 13.1(a), the Board of Managers shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Member Interests of such class (as of a Record Date selected by the Board of Managers) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 13.1(a)) at which Member Interests will be purchased and state that such Person elects to purchase such Member Interests, upon surrender of Certificates representing such Member Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Member Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Member Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the Person exercising the right to purchase hereunder shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Member Interests to be purchased in accordance with this Section 13.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Member Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Member Interests (including any rights pursuant to Article 4, Article 5, Article 6, and Article 10) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 13.1(a)) for Member Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Member Interests, and such Member Interests shall thereupon be deemed to be transferred to the Person exercising the right to purchase hereunder on the record books of the Transfer Agent and the Company, and such Person shall be deemed to be the owner of all such Member Interests from and after the Purchase Date and shall have all rights as the owner of such Member Interests (including all rights as owner of such Member Interests pursuant to Article 4, Article 5, Article 6, and Article 10).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Member Interest subject to purchase as provided in this Section 13.1 may surrender his Certificate evidencing such Member Interest to the Transfer Agent in exchange for payment of the amount described in Section 13.1(a), therefor, without interest thereon.

(d) Upon the exercise by any Person of the right to purchase Member Interests granted pursuant to Section 13.1(a), no Member shall be entitled to dissenters’ rights of appraisal.

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Article 14

GENERAL PROVISIONS

Section 14.1 Addresses and Notices.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Member under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Member at the address described below. Any notice, payment or report to be given or made to a Member hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Company Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Company, regardless of any claim of any Person who may have an interest in such Company Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 14.1 executed by the Company, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Company is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Company of a change in his address) if they are available for the Member at the principal office of the Company for a period of one year from the date of the giving or making of such notice, payment or report to the other Members. Any notice to the Company shall be deemed given if received by the Secretary at the principal office of the Company designated pursuant to Section 2.3. The Board of Managers and the Officers may rely and shall be protected in relying on any notice or other document from a Member or other Person if believed by it to be genuine.

Section 14.2 Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 14.3 Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 14.4 Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 14.5 Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Company.

Section 14.6 Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 14.7 Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the

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same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Common Unit, upon accepting the Certificate evidencing such Common Unit.

Section 14.8 Applicable Law.

This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware without regard to principles of conflicts of laws.

Section 14.9 Invalidity of Provisions.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 14.10 Consent of Members.

Each Member hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Members, such action may be so taken upon the concurrence of less than all of the Members and each Member shall be bound by the results of such action.

[Remainder of page intentionally left blank.]

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.


CONSTELLATION ENERGY PARTNERS HOLDINGS, LLC

By:
Name:
Title:


CONSTELLATION HOLDINGS, INC.

By:
Name:
Title:

Index to Financial Statements

EXHIBIT A

to the Second Amended and

Restated Operating Agreement of

Constellation Energy Partners LLC

Certificate Evidencing Common Units

Representing Member Interests in

Constellation Energy Partners LLC

No. [ ] Common Units

In accordance with Section 4.1 of the Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC, as amended, supplemented or restated from time to time (the “Company Agreement”), Constellation Energy Partners LLC, a Delaware limited liability company (the “Company”), hereby certifies that [ ] (the “Holder”) is the registered owner of Common Units representing Class B Interests in the Company (the “Units”) transferable on the books of the Company, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Units are set forth in, and this Certificate and the Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Company Agreement. Copies of the Company Agreement are on file at, and will be furnished without charge on delivery of written request to the Company at, the principal office of the Company located at 111 Market Place, Baltimore, Maryland 21202 or such other address as may be specified by notice under the Company Agreement. Capitalized terms used herein but not defined shall have the meanings given them in the Company Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Member and to have agreed to comply with and be bound by and to have executed the Company Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Company Agreement, (iii) granted the powers of attorney provided for in the Company Agreement, and (iv) made the waivers and given the consents and approvals contained in the Company Agreement.

This Certificate shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to principles of conflict of laws thereof.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF THE COMPANY THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER. THE COMPANY MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF ANY GROUP MEMBER BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Exhibit A-1

Index to Financial Statements

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.


Dated:

Countersigned and Registered by:	Constellation Energy Partners LLC


as Transfer Agent and Registrar	By:

	Name:

	Title:	President


	By:

	Name:

	Title:	Secretary

Exhibit A-2

Index to Financial Statements

Reverse of Certificate

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM—	as tenants in common	UNIF GIFT/TRANSFERS MIN ACT

TEN ENT—	as tenants by the entireties		Custodian
		(Cust)		(Minor)
JT TEN—	as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF UNITS

CONSTELLATION ENERGY PARTNERS LLC

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto




(Please print or typewrite name and address of Assignee)				(Please insert Social Security or other identifying number of Assignee)

Units representing Member Interests evidenced by this Certificate, subject to the Company Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of Constellation Energy Partners LLC.



Date:						NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.



SIGNATURE(S) MUST BE GUARANTEED BY A MEMBER FIRM OF THE NATIONAL ASSOCIATION OF SECURITIES DEALERS, INC. OR BY A COMMERCIAL BANK OR TRUST COMPANY SIGNATURE(S) GUARANTEED
				(Signature)




				(Signature)

No transfer of the Units evidenced hereby will be registered on the books of the Company, unless the Certificate evidencing the Units to be transferred is surrendered for registration of transfer.

Exhibit A-3

Index to Financial Statements

APPENDIX B

GLOSSARY OF TERMS

Adjusted Operating Surplus for any period means:

(a) Operating Surplus generated with respect to that period; less

(b) any net increase in working capital borrowings with respect to that period (excluding any such borrowings to the extent the proceeds are distributed to the record holder of the Class D interests); less

(c) any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

(d) any net decrease in working capital borrowings with respect to that period; plus

(e) any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Available Cash means, for any quarter ending prior to liquidation:

(a) the sum of:

(i) all cash and cash equivalents of Constellation Energy Partners LLC and its subsidiaries (or the Company’s proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly owned) on hand at the end of that quarter; and

(ii) all additional cash and cash equivalents of Constellation Energy Partners LLC and its subsidiaries (or the Company’s proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly owned) on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of such quarter,

(b) less the amount of any cash reserves established by the board of managers (or the Company’s proportionate share of cash reserves in the case of subsidiaries that are not wholly owned) to

(i) provide for the proper conduct of the business of Constellation Energy Partners LLC and its subsidiaries (including reserves for future capital expenditures including drilling and acquisitions and for anticipated future credit needs) subsequent to such quarter,

(ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which Constellation Energy Partners LLC or any of its subsidiaries is a party or by which it is bound or its assets are subject; or

(iii) provide funds for distributions (1) to our unitholders or (2) in respect of our Class D interests or management incentive interests with respect to any one or more of the next four quarters;

provided, however, that the Board of Managers may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Company is unable to distribute the Initial Quarterly Distribution on all Common Units and Class A Units with respect to such Quarter; and provided further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if board of managers so determines.

Average Reserve Life. Our December 31, 2005 estimated proved reserves divided by our annualized production for the six months ended December 31, 2005.

Bcf. One billion cubic feet.

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Index to Financial Statements

Capital Surplus is generated by:

(a) borrowings other than working capital borrowings;

(b) sales of debt and equity securities; and

(c) sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as a part of normal retirements or replacements of assets.

Developed acres. Acres spaced or assigned to productive wells or units.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Exploitation. A drilling or other project which may target proved or unproved reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Mcf. One thousand cubic feet.

Mcf/d. One thousand cubic feet per day.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. One MMcf per day.

NYMEX. New York Mercantile Exchange.

Operating expenditures means all expenditures of Constellation Energy Partners LLC and its subsidiaries (or Constellation Energy Partners LLC’s proportionate share in the case of subsidiaries that are not wholly owned), including taxes, amounts paid for services under the management services agreement, payments made in the ordinary course of business under commodity hedge contracts (other than payments in connection with termination of same prior to its termination date), provided that with respect to amounts paid in connection with the initial purchase or placing of a commodity hedge contract, such amounts shall be amortized over the life of the applicable commodity hedge contract and upon its termination, if earlier, manager and officer compensation, compensation paid to our board of managers, repayment of working capital borrowings, debt service payments, and estimated maintenance capital expenditures, provided that operating expenditures will not include:

•

repayment of working capital borrowings deducted from operating surplus pursuant to subparagraph (h) of the definition of operating surplus when such repayment actually occurs;

•

payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;

•

capital expenditures made for acquisitions or for capital improvements, or expansion capital expenditures;

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Index to Financial Statements

•

actual maintenance capital expenditures;

•

investment capital expenditures;

•

payment of transaction expenses relating to interim capital transactions; or

•

distributions to members (including distributions in respect of our Class D interests and management incentive interests).

Where capital expenditures are made in part for acquisitions or for capital improvements and in part for other purposes, our board of managers, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each.

Operating surplus for any period means:

(a) $20.0 million (if we choose to distribute as operating surplus up to $20.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings); plus

(b) all of our cash receipts after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

(c) working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

(d) cash distributions paid on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that the group member enters into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service or the date that it is abandoned or disposed of; plus

(e) if the right to receive distributions (other than distributions in liquidation) on the Class D interests terminates before December 31, 2012, the excess of the amount of the original $8.0 million contribution by CHI for the Class D interests over the cumulative cash distributions paid on the Class D interests before such termination shall be included in operating surplus, such inclusion to occur over a series of quarters with the amount included in each quarter to be equal to the amount of the payment a group member makes to the Trust in respect of the NPI for such quarter that would not have been paid but for termination of the sharing arrangement; less

(f) our operating expenditures after the closing of this offering; less

(g) the amount of cash reserves established by our board of managers to provide funds for future operating expenditures; less

(h) all working capital borrowings not repaid within twelve months after having been incurred.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proppant. Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional natural gas expected to be obtained through the

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Index to Financial Statements

application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved reserves. Proved natural gas reserves are the estimated quantities of natural gas, crude oil and natural gas liquids which geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Proved natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. The completion for production of an existing wellbore in another formation than the one in which the well has been previously completed.

Refracture. The process of applying hydraulic pressure to an oil or natural gas bearing geological formation to crack the formation and stimulate the release of oil and natural gas.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Reservoir Rock. A subsurface body of rock having sufficient porosity and permeability to store and transmit fluids.

Source Rock. A rock rich in organic matter that, if heated sufficiently, will generate oil or natural gas.

Standardized Measure. The present value of estimated future net revenues to be generated from the production of proved reserves determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of the estimation) without giving effect to non-property related expenses such as general and administrative expenses and debt service expenses or to depreciation, depletion and amortization and discounted using an annual rate of 10%. Standardized Measure does not give effect to the derivative transactions and excludes reserves attributable to the NPI. We have excluded future income taxes from our standardized measure, as we are not a taxable entity.

Tcf. One trillion cubic feet.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

B-4

Index to Financial Statements

Working capital borrowings. Borrowings used solely for working capital purposes or to pay distributions to members made pursuant to a credit facility, commercial paper facility or other similar financing arrangement, provided that when it is incurred it is the intent of the borrower to repay such borrowings within 12 months from other than Working Capital Borrowings.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

B-5

Index to Financial Statements

6,275,000 Common Units

Representing Class B Limited Liability Company Interests

Constellation Energy Partners LLC

P R O S P E C T U S

, 2006

Citigroup

Lehman Brothers

UBS Investment Bank

Wachovia Securities

Scotia Capital

Index to Financial Statements

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the NASD filing fee and NYSE Arca listing fee, the amounts set forth below are estimates.


SEC registration fee	$	16,215

NASD filing fee		15,654

NYSE Arca listing fee		100,000

Printing and engraving expenses		400,000

Accounting and consulting fees and expenses		814,000

Legal fees and expenses		1,500,000

Transfer agent and registrar fees		12,000

Miscellaneous		367,131

Total	$	3,225,000

Item 14. Indemnification of Managers and Officers.

The section of the prospectus entitled “The Limited Liability Company Agreement—Indemnification” discloses that we will generally indemnify officers, managers and affiliates of our board of managers to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Act empowers a Delaware limited liability company to indemnify and hold harmless any member or other persons from and against all claims and demands whatsoever.

To the extent that the indemnification provisions of our limited liability company agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities.

In connection with our formation in February 2005, we issued to CCG in exchange for $100 a membership interest representing the right to receive an aggregate 100% of our distributions. The offering was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering.

II-1

Index to Financial Statements

Item 16. Exhibits and Financial Statement Schedules.

(a) The following documents are filed as exhibits to this registration statement:


Exhibit Number		Description

1.1*		– Form of Underwriting Agreement

3.1**		– Certificate of Formation of Constellation Energy Partners LLC

3.2**		– Amended and Restated Operating Agreement of Constellation Energy Partners LLC

3.3		– Form of Amended and Restated Limited Liability Company Agreement of Constellation Energy Partners LLC (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)

5.1		– Opinion of Andrews Kurth LLP as to the legality of the securities being registered

8.1*		– Opinion of Andrews Kurth LLP relating to tax matters

10.1		– Form of Credit Agreement by and among Constellation Energy Partners LLC, as borrower, The Royal Bank of Scotland plc, as administrative agent, RBS Securities Corporation, as lead manager and sole bookrunner, and the lenders from time to time party thereto

10.2		– Form of Management Services Agreement by and between Constellation Energy Partners LLC and Constellation Energy Partners Management, LLC

10.3		– Form of Omnibus Agreement by and among Constellation Energy Partners LLC, Constellation Energy Commodities Group, Inc., Robinson’s Bend II Production, LLC, Robinson’s Bend II Operating, LLC and Robinson’s Bend II Marketing, LLC

10.4		– Net Overriding Royalty Conveyance dated November 22, 1993 but effective as of October 1, 1993, from, pursuant to Part I thereof, Velasco Gas Company, L.P. and Torch Energy Advisors Incorporated and, pursuant to Part II thereof, from Torch Energy Advisors Incorporated to the Torch Energy Royalty Trust

10.5		– Oil and Gas Purchase Agreement dated October 1, 1993 by and between Torch Energy Marketing, Inc., Torch Royalty Company and Velasco Gas Co. Ltd.

10.6		– Letter agreement dated June 13, 2005 by and between Robinson’s Bend II Marketing, LLC and Torch Energy TM, Inc.

10.7		– International Swap Dealers Association, Inc. Master Agreement and Schedule, dated as of June 16, 2006, between The Royal Bank of Scotland, plc and Constellation Energy Resources LLC

10.8		– Confirmation, dated June 28, 2006, effective June 20, 2006, between The Royal Bank of Scotland, plc and Constellation Energy Resources LLC

10.9		– Asset Purchase and Sale Agreement dated May 12, 2005 by and between RB Marketing Company LLC, Robinson’s Bend Operating Company LLC and CBM Equity IV, LLC

10.10		– Letter agreement dated June 7, 2006 by and between The Investment Company LLC, Constellation Energy Resources LLC and Robinson’s Bend Production II, LLC

10.11		–Form of Trademark License Agreement by and between Constellation Energy Group, Inc. and Constellation Energy Partners LLC

21.1**		– List of subsidiaries of Constellation Energy Partners LLC

23.1		– Consent of PricewaterhouseCoopers LLP

23.2		– Consent of Netherland, Sewell & Associates, Inc.

23.3		– Consent of Andrews Kurth LLP (contained in Exhibit 5.1)

23.4*		– Consent of Andrews Kurth LLP (contained in Exhibit 8.1)

24.1		– Powers of Attorney (contained on page II-4)

To be filed by amendment.

Previously filed.

II-2

Index to Financial Statements

Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Constellation or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to Constellation or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-3

Index to Financial Statements

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Amendment No. 2 to Registration Statement No. 333-134995 to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Baltimore, State of Maryland, on September 28, 2006.


Constellation Energy Partners LLC

By:		/s/ FELIX J. DAWSON
Name:		Felix J. Dawson
Title:		Chief Executive Officer

POWER OF ATTORNEY

Each person whose signature appears below appoints Andrew C. Kidd and Lisa J. Mellencamp, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments thereto) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Amendment No. 2 to Registration Statement No. 333-134995 has been signed below by the following persons in the capacities and on the dates indicated.


Signature	Title	Date
/s/ FELIX J. DAWSON Felix J. Dawson	Chief Executive Officer (Principal Executive Officer) and Manager	September 28, 2006

/s/ ANGELA A. MINAS Angela A. Minas	Chief Financial Officer (Principal Financial Officer and Chief Accounting Officer (Principal Accounting Officer)	September 28, 2006

/s/ JOHN R. COLLINS John R. Collins	Manager	September 28, 2006

II-4

Index to Financial Statements

EXHIBIT INDEX



Exhibit Number		Description

1.1*		– Form of Underwriting Agreement

3.1**		– Certificate of Formation of Constellation Energy Partners LLC

3.2**		– Amended and Restated Operating Agreement of Constellation Energy Partners LLC

3.3		– Form of Amended and Restated Limited Liability Company Agreement of Constellation Energy Partners LLC (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)

5.1		– Opinion of Andrews Kurth LLP as to the legality of the securities being registered

8.1*		– Opinion of Andrews Kurth LLP relating to tax matters

10.1		– Form of Credit Agreement by and among Constellation Energy Partners LLC, as borrower, The Royal Bank of Scotland plc, as administrative agent, RBS Securities Corporation, as lead manager and sole bookrunner, and the lenders from time to time party thereto

10.2		– Form of Management Services Agreement by and between Constellation Energy Partners LLC and Constellation Energy Partners Management, LLC

10.3		– Form of Omnibus Agreement by and among Constellation Energy Partners LLC, Constellation Energy Commodities Group, Inc., Robinson’s Bend II Production, LLC, Robinson’s Bend II Operating, LLC and Robinson’s Bend II Marketing, LLC

10.4		– Net Overriding Royalty Conveyance dated November 22, 1993 but effective as of October 1, 1993, from, pursuant to Part I thereof, Velasco Gas Company, L.P. and Torch Energy Advisors Incorporated and, pursuant to Part II thereof, from Torch Energy Advisors Incorporated to the Torch Energy Royalty Trust

10.5		– Oil and Gas Purchase Agreement dated October 1, 1993 by and between Torch Energy Marketing, Inc., Torch Royalty Company and Velasco Gas Co. Ltd.

10.6		– Letter agreement dated June 13, 2005 by and between Robinson’s Bend II Marketing, LLC and Torch Energy TM, Inc.

10.7		– International Swap Dealers Association, Inc. Master Agreement and Schedule, dated as of June 16, 2006, between The Royal Bank of Scotland, plc and Constellation Energy Resources LLC

10.8		– Confirmation, dated June 28, 2006, effective June 20, 2006, between The Royal Bank of Scotland, plc and Constellation Energy Resources LLC

10.9		– Asset Purchase and Sale Agreement dated May 12, 2005 by and between RB Marketing Company LLC, Robinson’s Bend Operating Company LLC and CBM Equity IV, LLC

10.10		– Letter agreement dated June 7, 2006 by and between The Investment Company LLC, Constellation Energy Resources LLC and Robinson’s Bend Production II, LLC

10.11		–Form of Trademark License Agreement by and between Constellation Energy Group, Inc. and Constellation Energy Partners LLC

21.1**		– List of subsidiaries of Constellation Energy Partners LLC

23.1		– Consent of PricewaterhouseCoopers LLP

23.2		– Consent of Netherland, Sewell & Associates, Inc.

23.3		– Consent of Andrews Kurth LLP (contained in Exhibit 5.1)

23.4*		– Consent of Andrews Kurth LLP (contained in Exhibit 8.1)

24.1		– Powers of Attorney (contained on page II-4)

To be filed by amendment.

Previously filed.

Opinion of Andrews Kurth LLP - legality of securities

EXHIBIT 5.1

LOGO

600 Travis, Suite 4200

Houston, Texas 77002

713.220.4200 Phone

713.220.4285 Fax

andrewskurth.com

September 28, 2006

Constellation Energy Partners LLC

111 Market Place

Baltimore, Maryland 21202

Gentlemen:

We have acted as special counsel to Constellation Energy Partners LLC, a Delaware limited liability company (the “Company”) in connection with the registration under the Securities Act of 1933, as amended (the “Securities Act”), of the offering and sale by the Company of up to an aggregate of 7,216,250 common units representing Class B limited liability company interests in the Company (the “Units”).

As the basis for the opinion hereinafter expressed, we have examined such statutes, including the Delaware Limited Liability Company Act (the “Delaware LLC Act”), regulations, corporate records and documents, certificates of corporate and public officials, and other instruments and documents as we have deemed necessary or advisable for the purposes of this opinion. In making our examination, we have assumed that all signatures on documents examined by us are genuine, the authenticity of all documents submitted to us as originals and the conformity with the original documents of all documents submitted to us as certified, conformed or photostatic copies.

Based on the foregoing and on such legal considerations as we deem relevant, we are of the opinion that the Units, when issued and delivered on behalf of the Company against payment therefor as described in the Company’s Registration Statement on Form S-1 (Commission File No. 333-134995), as amended, relating to the Units (the “Registration Statement”), will be duly authorized, validly issued, fully paid and non-assessable.

We hereby consent to the reference to us under the heading “Validity of the Units” in the prospectus forming a part of the Registration Statement and to the filing of this opinion as an exhibit to the Registration Statement. In giving this consent, we do not thereby admit that we are included in the category of persons whose consent is required under Section 7 of the Securities Act or the rules and regulations of the Securities and Exchange Commission issued thereunder. This opinion speaks as of its date, and we undertake no, and hereby disclaim any, duty to advise as to changes of fact or law coming to our attention after the delivery hereof on such date.

The opinion expressed herein is limited exclusively to the Delaware LLC Act and the laws of the state of Delaware, and we are expressing no opinion as to the effect of the laws of any other jurisdiction.

Very truly yours,

/s/ ANDREWS KURTH LLP

Form of Credit Agreement

Exhibit 10.1

$200,000,000

CREDIT AGREEMENT

DATED AS OF OCTOBER [ ], 2006

AMONG

CONSTELLATION ENERGY PARTNERS LLC

AS BORROWER,

THE ROYAL BANK OF SCOTLAND plc

AS ADMINISTRATIVE AGENT,

RBS SECURITIES CORPORATION

AS LEAD ARRANGER AND SOLE BOOK RUNNER,

AND

THE LENDERS PARTY HERETO

TABLE OF CONTENTS


		PAGE
	ARTICLE I

	DEFINITIONS AND ACCOUNTING MATTERS

Section 1.01	Terms Defined Above	1
Section 1.02	Certain Defined Terms	1
Section 1.03	Terms Generally	20
Section 1.04	Accounting Terms and Determinations; GAAP	20

	ARTICLE II

	THE CREDITS

Section 2.01	Commitments	21
Section 2.02	Loans and Borrowings	21
Section 2.03	Requests for Borrowings	22
Section 2.04	Interest Elections	23
Section 2.05	Funding of Borrowing	24
Section 2.06	Termination and Reduction of Aggregate Maximum Credit Amounts	24
Section 2.07	Borrowing Base	25
Section 2.08	Letters of Credit	29

	ARTICLE III

	PAYMENTS OF PRINCIPAL AND INTEREST; PREPAYMENTS; FEES

Section 3.01	Repayment of Loans	34
Section 3.02	Interest	34
Section 3.03	Prepayments	35
Section 3.04	Fees	36

	ARTICLE IV

	PAYMENTS; PRO RATA TREATMENT; SHARING OF SET-OFFS.

Section 4.01	Payments Generally; Pro Rata Treatment; Sharing of Set-offs	37
Section 4.02	Presumption of Payment by the Borrower	38
Section 4.03	Certain Deductions by the Administrative Agent	38

	ARTICLE V

	INCREASED COSTS; BREAK FUNDING PAYMENTS; TAXES; ILLEGALITY

Section 5.01	Increased Costs	39
Section 5.02	Break Funding Payments	40
Section 5.03	Taxes	40
Section 5.04	Designation of Different Lending Office	41
Section 5.05	Illegality	41
Section 5.06	Replacement of a Lender	42



	ARTICLE VI

	CONDITIONS PRECEDENT

Section 6.01	Closing Date	43
Section 6.02	Each Credit Event	45

	ARTICLE VII

	REPRESENTATIONS AND WARRANTIES

Section 7.01	Organization; Powers	46
Section 7.02	Authority; Enforceability	46
Section 7.03	Approvals; No Conflicts	46
Section 7.04	Financial Statements	47
Section 7.05	Litigation	47
Section 7.06	Environmental Matters	47
Section 7.07	Compliance with the Laws and Agreements	48
Section 7.08	Investment Company Act	48
Section 7.09	Taxes	48
Section 7.10	ERISA	49
Section 7.11	Disclosure; No Material Misstatements	50
Section 7.12	Insurance	50
Section 7.13	Restriction on Liens	50
Section 7.14	Subsidiaries	50
Section 7.15	Location of Business and Offices	51
Section 7.16	Properties; Titles, Etc.	51
Section 7.17	Title	52
Section 7.18	Security Instruments.	53
Section 7.19	Maintenance of Properties	53
Section 7.20	Gas Imbalances, Prepayments	54
Section 7.21	Marketing of Production	54
Section 7.22	Swap Agreements	54
Section 7.23	Use of Loans and Letters of Credit	54
Section 7.24	Solvency	55

	ARTICLE VIII

	AFFIRMATIVE COVENANTS

Section 8.01	Financial Statements; Ratings Change; Other Information	55
Section 8.02	Notices of Material Events	58
Section 8.03	Existence; Conduct of Business	59
Section 8.04	Payment of Obligations	59
Section 8.05	Performance of Obligations under Loan Documents	59
Section 8.06	Operation and Maintenance of Properties	59
Section 8.07	Insurance	60
Section 8.08	Books and Records; Inspection Rights	60
Section 8.09	Compliance with Laws	60


Section 8.10	Environmental Matters	60
Section 8.11	Further Assurances	61
Section 8.12	Title Information	62
Section 8.13	Additional Collateral; Additional Guarantors	62
Section 8.14	ERISA Compliance	63
Section 8.15	Marketing Activities	64
Section 8.16	Title	64
Section 8.17	Board Composition	64

	ARTICLE IX

	NEGATIVE COVENANTS

Section 9.01	Financial Covenants	64
Section 9.02	Debt	65
Section 9.03	Liens	65
Section 9.04	Dividends, Distributions and Redemptions	66
Section 9.05	Investments, Loans and Advances	66
Section 9.06	Nature of Business	67
Section 9.07	Limitation on Leases	67
Section 9.08	Proceeds of Notes	67
Section 9.09	ERISA Compliance	68
Section 9.10	Sale or Discount of Receivables	69
Section 9.11	Mergers, Etc.	69
Section 9.12	Sale of Properties	69
Section 9.13	Transactions with Affiliates	69
Section 9.14	Subsidiaries	70
Section 9.15	Negative Pledge Agreements; Dividend Restrictions	70
Section 9.16	Gas Imbalances, Take-or-Pay or Other Prepayments	70
Section 9.17	Swap Agreements	70
Section 9.18	Tax Status as Partnership; Operating Agreements	71

	ARTICLE X

	EVENTS OF DEFAULT; REMEDIES

Section 10.01	Events of Default	71
Section 10.02	Remedies	73
Section 10.03	Disposition of Proceeds	74

	ARTICLE XI

	THE ADMINISTRATIVE AGENT

Section 11.01	Appointment; Powers	74
Section 11.02	Duties and Obligations of Administrative Agent	74
Section 11.03	Action by Agent	75
Section 11.04	Reliance by Agent	76
Section 11.05	Subagents	76
Section 11.06	Resignation or Removal of Agents	76

iii


Section 11.07	Agents and Lenders	76
Section 11.08	No Reliance	77
Section 11.09	Administrative Agent May File Proofs of Claim	77
Section 11.10	Authority of Administrative Agent to Release Collateral and Liens	78
Section 11.11	The Arrangers and the Syndication Agent	78

	ARTICLE XII

	MISCELLANEOUS

Section 12.01	Notices	78
Section 12.02	Waivers; Amendments	80
Section 12.03	Expenses, Indemnity; Damage Waiver	81
Section 12.04	Successors and Assigns	83
Section 12.05	Survival; Revival; Reinstatement	86
Section 12.06	Counterparts; Integration; Effectiveness	86
Section 12.07	Severability	87
Section 12.08	Right of Setoff	87
Section 12.09	GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS	87
Section 12.10	Headings	88
Section 12.11	Confidentiality	89
Section 12.12	Maximum Interest	89
Section 12.13	EXCULPATION PROVISIONS	90
Section 12.14	Collateral Matters; Swap Agreements	90
Section 12.15	No Third Party Beneficiaries	91
Section 12.16	USA Patriot Act Notice	91


Annex I		List of Maximum Credit Amounts

Exhibit A		Form of Note
Exhibit B		Form of Compliance Certificate
Exhibit C-1		Security Instruments
Exhibit C-2		Form of Guarantee and Pledge Agreement
Exhibit D		Form of Assignment and Assumption
Exhibit 2.03		Form of Borrowing Request
Exhibit 2.04(b)		Form of Interest Election Request
Exhibit 2.08(b)		Form of Notice of Letter of Credit Request

Schedule 7.05		Litigation
Schedule 7.14		Subsidiaries and Partnerships
Schedule 7.20		Gas Imbalances
Schedule 7.21		Marketing Contracts
Schedule 7.22		Swap Agreements

THIS CREDIT AGREEMENT dated as of October [ ], 2006, is among Constellation Energy Partners LLC, a limited liability company duly formed and existing under the laws of the State of Delaware (the “Borrower”), each of the Lenders from time to time party hereto, and The Royal Bank of Scotland plc (in its individual capacity, “RBS”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

RECITALS

WHEREAS, the Borrower has requested that the Lenders provide Loan Commitments (to include availability for Loans and Letters of Credit), pursuant to which Loans will be made from time to time prior to the Termination Date, and Letter of Credit Commitments, pursuant to which Letters of Credit will be issued from time to time prior to the Termination Date;

WHEREAS, the Lenders and the Issuer are willing, on the terms and subject to the conditions hereinafter set forth, to extend the Loan Commitments and make Loans to the Borrower and issue (or participate in) Letters of Credit; and

NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained and of the loans, extensions of credit and commitments hereinafter referred to, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS AND ACCOUNTING MATTERS

Section 1.01 Terms Defined Above. As used in this Agreement, each term defined above has the meaning indicated above.

Section 1.02 Certain Defined Terms. As used in this Agreement, the following terms have the meanings specified below:

“ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

“Acceptable Security Interest” in any Property means a Lien which (a) exists in favor of the Administrative Agent for the benefit of the Administrative Agent, the Issuer, the Lenders, and any Swap Counterparty, (b) is superior to all Liens or rights of any other Person in the Property encumbered thereby, other than Excepted Liens, (c) secures the Obligations, and (d) is perfected and enforceable.

“Adjusted EBITDA” means, for any period, the sum of Consolidated Net Income for such period plus the following expenses or charges to the extent deducted from Consolidated Net Income in such period: Interest Expense, depreciation, depletion, amortization, write off of deferred financing fees, impairment of long-lived assets, (gain) loss or sale of assets, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on natural gas derivatives and realized (gain) loss on cancelled natural gas derivatives, and other similar charges.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Advance” means any advance hereunder of monies by a Lender to the Borrower as part of a Borrowing and refers to a Base Rate Loan or a Eurodollar Loan.

“Affected Loans” has the meaning assigned such term in Section 5.05.

“Affiliate” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“Agents” means each of the Administrative Agent, the Syndication Agent, the Documentation Agent or any combination of them as the context requires and also includes any Person identified as “Bookrunner.”

“Aggregate Maximum Credit Amounts” at any time shall equal the sum of the Maximum Credit Amounts, as the same may be reduced or terminated pursuant to Section 2.06.

“Agreement” means this Credit Agreement, as the same may from time to time be amended, modified, supplemented or restated.

“Alternate Base Rate” means, on any date and with respect to all Base Rate Loans, a fluctuating rate of interest per annum (rounded upward, if necessary, to the next highest 1/16 of 1%) equal to the higher of

(a) the Base Rate in effect on such day; and

(b) the Federal Funds Effective Rate in effect on such day plus ¹/2 of 1%.

Changes in the rate of interest on that portion of any Loans maintained as Base Rate Loans will take effect simultaneously with each change in the Alternate Base Rate. The Administrative Agent will give notice promptly to the Borrower and the Lenders of changes in the Alternate Base Rate; provided that, the failure to give such notice shall not affect the Alternate Base Rate in effect after such change.

“Applicable Margin” means, for any day and with respect to all Loans maintained as LIBO Rate Loans or Base Rate Loans, the applicable percentage set forth below corresponding to the Borrowing Base Utilization Percentage:


Borrowing Base Utilization Percentage	LIBO Rate Loan		Base Rate Loan
less than 25%	1.250	%	0.250	%
greater than or equal to 25%, but less than 50%	1.500	%	0.500	%
greater than or equal to 50%, but less than 75%	1.750	%	0.750	%
greater than or equal to 75%, but less than 90%	1.875	%	0.875	%
greater than or equal to 90%	2.000	%	1.000	%

Each change in the Applicable Margin shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change, provided, however, that if at any time the Borrower fails to deliver a Reserve Report pursuant to Section 2.07, then the “Applicable Margin” means the rate per annum set forth on the grid when the Borrowing Base Utilization Percentage is at its highest level.

“Applicable Percentage” means, with respect to any Lender, the percentage of the Aggregate Maximum Credit Amounts represented by such Lender’s Maximum Credit Amount as such percentage is set forth on Annex I.

“Approved Counterparty” means (a) any Lender or any Affiliate of a Lender and (b) any other Person whose long term senior unsecured debt rating is A/A2 by S&P or Moody’s (or their equivalent) or higher.

“Approved Engineer” means Netherland, Sewell and Associates, Inc. or any other independent petroleum engineer satisfactory to the Administrative Agent in its sole and absolute discretion.

“Approved Fund” means any Person (other than a natural Person) that (a) is engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business, and (b) is administered or managed by a Lender, an Affiliate of a Lender or a Person or an Affiliate of a Person that administers or manages a Lender.

“Arranger” means RBS Securities Corporation, in its capacity as lead arranger and sole book runner hereunder.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 12.04(b)), and accepted by the Administrative Agent, in the form of Exhibit D or any other form approved by the Administrative Agent.

“Availability Period” means the period from and including the Closing Date to but excluding the Termination Date.

“Available Cash” means, with respect to any fiscal quarter ending prior to the Termination Date:

(a) the sum of (i) all cash and cash equivalents of the Borrower on hand at the end of such fiscal quarter; and (ii) all additional cash and cash equivalents of the Borrower on hand on the date of determination of Available Cash with respect to such fiscal quarter resulting from working capital borrowings made subsequent to the end of such fiscal quarter, less

(b) the amount of any cash reserves established by the board of managers of the Borrower to (i) provide for the proper conduct of the business of the Borrower (including reserves for future maintenance capital expenditures including drilling and for anticipated future credit needs of the Borrower), (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which the Borrower or a Consolidated Subsidiary is a party or by which it is bound or its assets are subject (including estimated NPI payments due and payable for the next two fiscal quarters based on the natural gas strip for such period) or (iii) provide funds for distributions with respect to any one or more of the next four fiscal quarters.

“Base Rate” means, at any time, the rate of interest then most recently established by the Administrative Agent in New York as its base rate for dollars loaned in the United States. The Base Rate is not necessarily intended to be the lowest rate of interest determined by the Administrative Agent in connection with extensions of credit.

“Base Rate Loan” means a Loan bearing interest at a fluctuating rate determined by reference to the Alternate Base Rate.

“Board” means the Board of Governors of the Federal Reserve System of the United States of America or any successor Governmental Authority.

“Borrowing” means Loans made or continued on the same date and as to which a single Interest Period is in effect.

“Borrowing Base” means an amount equal to the amount determined in accordance with Section 2.07, as the same may be redetermined and adjusted from time to time pursuant to Section 2.07, Section 8.12(c) or Section 9.12(d).

“Borrowing Base Deficiency” means the aggregate outstanding amount, if any, by which the sum of the Advances plus the Letter of Credit Exposure exceeds the lesser of the (i) Borrowing Base and (ii) the aggregate Commitments.

“Borrowing Base Utilization Percentage” means, as of any day, the fraction expressed as a percentage, the numerator of which is the sum of the Revolving Credit Exposures of the Lenders on such day, and the denominator of which is the Borrowing Base in effect on such day.

“Borrowing Request” means a request by the Borrower for a Borrowing in accordance with Section 2.03.

“Business Day” means any day that is not a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to remain closed; and if such day relates to a Borrowing or continuation of, a payment or prepayment of principal of or interest on, or the Interest Period for a Loan or a notice by the Borrower with respect to any such Borrowing or continuation, payment, prepayment, or Interest Period, any day which is also a day on which dealings in dollar deposits are carried out in the London interbank market.

“Capital Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, recorded as capital leases on the balance sheet of the Person liable (whether contingent or otherwise) for the payment of rent thereunder.

“Cash Collateral Account” has the meaning assigned such term in Section 2.08(j).

“Casualty Event” means any loss, casualty or other insured damage to, or any nationalization, taking under power of eminent domain or by condemnation or similar proceeding of, any Property of the Borrower or any of its Subsidiaries having a fair market value in excess of $100,000 in the aggregate for any calendar year.

“Change in Control” means the occurrence of both of the following events (i) the Permitted Holders shall be the legal or beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934, as amended) of 10% or less of the then outstanding membership interests (including all securities which are convertible into membership interests) of the Borrower and (ii) any Person or group of Persons acting in concert as a partnership or other group (a “Group of Persons”), other than one or more of the Permitted Holders, shall be the legal or beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934, as amended) of more than 35% of the then outstanding membership interests (including all securities which are convertible into membership interests) of the Borrower, provided, that a “Group of Persons” shall not include the underwriter in any firm underwriting undertaken in connection with any public offering of the Borrower.

“Change in Law” means (a) the adoption of any law, rule or regulation after the date of this Agreement, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender or the Issuer (or, for purposes of Section 5.01(b), by any lending office of such Lender or by such Lender’s or the Issuer’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement.

“Closing Date” means the date first written above.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

“Commitment Fee Rate” means 0.375%.

“Consolidated Net Income” means with respect to the Borrower and the Consolidated Subsidiaries, for any period, the aggregate of the net income (or loss) of the Borrower and the Consolidated Subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following (all determined in accordance with GAAP): (a) the net income of any Person in which the Borrower or a Consolidated Subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Borrower and the Consolidated Subsidiaries), except to the extent of the amount of dividends or distributions actually paid in cash during such period by such other Person to the Borrower or to a Consolidated Subsidiary, as the case may be; (b) the

net income (but not loss) during such period of any Consolidated Subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by that Consolidated Subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such Consolidated Subsidiary or is otherwise restricted or prohibited; (c) the net income (or loss) of any Person acquired in a pooling-of-interests transaction for any period prior to the date of such transaction; (d) any extraordinary gains or losses during such period; (e) non-cash gains, losses or adjustments under FASB Statement No. 133 as a result of changes in the fair market value of derivatives; (f) any gains or losses attributable to writeups or writedowns of assets, including ceiling test writedowns; (g) the one-time bonuses paid by the Borrower to employees in connection with its initial public offering and (h) non-cash share-based payments under FASB Statement No. 123R; and provided further that if the Borrower or any Consolidated Subsidiary shall acquire or dispose of any Property during such period, then Consolidated Net Income shall be calculated after giving pro forma effect to such acquisition or disposition, as if such acquisition or disposition had occurred on the first day of such period.

“Consolidated Subsidiaries” means each Subsidiary of the Borrower (whether now existing or hereafter created or acquired) the financial statements of which shall be (or should have been) consolidated with the financial statements of the Borrower in accordance with GAAP.

“Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. For the purposes of this definition, and without limiting the generality of the foregoing, any Person that owns directly or indirectly 10% or more of the Equity Interests having ordinary voting power for the election of the directors or other governing body of a Person will be deemed to “control” such other Person. “Controlling” and “Controlled” have meanings correlative thereto.

“Current Ratio” means the ratio of

(a) consolidated current assets of the Borrower and its Consolidated Subsidiaries but including any unused availability under the Borrowing Base and excluding therefrom any current non-cash asset (including in respect of Swap Agreements) described in or calculated pursuant to the requirements of Statement of Financial Accounting Standards 133 and 143, each as amended (provided that, for the avoidance of doubt, the calculation of consolidated current assets shall include any current assets in respect of the termination of any Swap Agreement)

(b) consolidated current liabilities of the Borrower and its Consolidated Subsidiaries but excluding therefrom any current non-cash liabilities (including in respect of Swap Agreements) described in or calculated pursuant to the requirements of Statement of Financial Accounting Standards 133 and 143, each as amended (provided that, for the avoidance of doubt, the calculation of consolidated current liabilities shall include any current liabilities in respect of the termination of any Swap Agreement).

“Debt” means, for any Person, the sum of the following (without duplication): (a) all obligations of such Person for borrowed money or evidenced by bonds, bankers’ acceptances, debentures, notes or other similar instruments; (b) all obligations of such Person (whether contingent or otherwise) in respect of letters of credit, surety or other bonds and similar instruments; (c) all accounts payable, accrued expenses, liabilities or other obligations of such Person, in each such case to pay the deferred purchase price of Property or services; (d) all obligations under Capital Leases; (e) all obligations under Synthetic Leases; (f) all Debt (as defined in the other clauses of this definition) of others secured by (or for which the holder of such Debt has an existing right, contingent or otherwise, to be secured by) a Lien on any Property of such Person, whether or not such Debt is assumed by such Person; (g) all Debt (as defined in the other clauses of this definition) of others guaranteed by such Person or in which such Person otherwise assures a creditor against loss of the Debt (howsoever such assurance shall be made) to the extent of the lesser of the amount of such Debt and the maximum stated amount of such guarantee or assurance against loss; (h) all obligations or undertakings of such Person to maintain or cause to be maintained the financial position or covenants of others or to purchase the Debt or Property of others; (i) obligations to deliver commodities, goods or services, including, without limitation, Hydrocarbons, in consideration of one or more advance payments, other than gas balancing arrangements in the ordinary course of business; (j) obligations to pay for goods or services whether or not such goods or services are actually received or utilized by such Person; (k) any Debt of a partnership for which such Person is liable either by agreement, by operation of law or by a Governmental Requirement but only to the extent of such liability; (l) Disqualified Capital Stock; (m) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment and (n) all obligations of such Person under Swap Agreements, excluding Swap Agreements with the Administrative Agent or any other Lender. The Debt of any Person shall include all obligations of such Person of the character described above to the extent such Person remains legally liable in respect thereof notwithstanding that any such obligation is not included as a liability of such Person under GAAP.

“Default” means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

“Disqualified Capital Stock” means any Equity Interest that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event, matures or is mandatorily redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock), pursuant to a sinking fund obligation or otherwise, or is convertible or exchangeable for Debt or redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is one year after the earlier of (a) the Maturity Date and (b) the date on which there are no Loans, Letter of Credit Exposure or other obligations hereunder outstanding and all of the Commitments are terminated.

“dollars” or “$” refers to lawful money of the United States of America.

“Domestic Subsidiary” means any Subsidiary that is organized under the laws of the United States of America or any state thereof or the District of Columbia.

“Eligible Assignee” means (a) a Lender; (b) an Affiliate of a Lender; (c) an Approved Fund; or (d) any other Person (other than a natural Person, the Borrower, any Affiliate of the Borrower or any other Person taking direction from, or working in concert with, the Borrower or any of the Borrower’s Affiliates) approved by the Administrative Agent and the Issuing Lender.

“Environmental Laws” means any and all Governmental Requirements pertaining in any way to health, safety the environment or the preservation or reclamation of natural resources, in effect in any and all jurisdictions in which the Borrower or any of its Subsidiaries is conducting or at any time has conducted business, or where any Property of the Borrower or any of its Subsidiaries is located, including without limitation, the Oil Pollution Act of 1990 (“OPA”), as amended, the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“CERCLA”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendments and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, applicable regulations of the State Oil and Gas Board of Alabama and applicable regulations of the Alabama Department of Environmental Management, and other environmental conservation or protection Governmental Requirements. The term “oil” shall have the meaning specified in OPA, the terms “hazardous substance” and “release” (or “threatened release”) have the meanings specified in CERCLA and the terms “solid waste” and “disposal” (or “disposed”) have the meanings specified in RCRA; provided, however, that (a) in the event either OPA, CERCLA or RCRA is amended so as to broaden the meaning of any term defined thereby, such broader meaning shall apply subsequent to the effective date of such amendment and (b) to the extent the laws of the state or other jurisdiction in which any Property of the Borrower or any of its Subsidiaries is located establish a meaning for “oil,” “hazardous substance,” “release,” “solid waste,” “disposal” or “oil and gas waste” which is broader than that specified in either OPA, CERCLA or RCRA, such broader meaning shall apply.

“Equity Interests” means shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity ownership interests in a Person, and any warrants, options or other rights entitling the holder thereof to purchase or acquire any such Equity Interest.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended, and any successor statute.

“ERISA Affiliate” means each trade or business (whether or not incorporated) which together with the Borrower or any of its Subsidiaries would be deemed to be a “single employer” within the meaning of section 4001(b)(1) of ERISA or subsections (b), (c), (m) or (o) of section 414 of the Code.

“ERISA Event” means (a) a “Reportable Event” described in section 4043 of ERISA and the regulations issued thereunder, (b) the withdrawal of the Borrower or any of its Subsidiaries or any ERISA Affiliate from a Plan during a plan year in which it was a “substantial employer” as defined in section 4001(a)(2) of ERISA, (c) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under section 4041 of ERISA, (d) the institution of proceedings to terminate a Plan by the PBGC, (e) receipt of a notice of withdrawal

liability pursuant to Section 4202 of ERISA or (f) any other event or condition which might constitute grounds under section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan.

“Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the LIBO Rate.

“Event of Default” has the meaning assigned such term in Section 10.01.

“Excepted Liens” shall mean: (i) Liens for taxes, assessments or other governmental charges or levies not yet due or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained; (ii) Liens in connection with workmen’s compensation, unemployment insurance or other social security, old age pension or public liability obligations not yet due or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (iii) operators’, vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of Oil and Gas Properties or statutory landlord’s liens, each of which is in respect of obligations that are not delinquent or which are being contested in good faith by appropriate proceedings and for which adequate reserves have been maintained in accordance with GAAP; (iv) contractual Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements which are usual and customary in the oil and gas business and are for claims which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP, provided that any such Lien referred to in this clause does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by the Borrower or any of its Subsidiaries or materially impair the value of such Property subject thereto; (v) encumbrances (other than to secure the payment of borrowed money or the deferred purchase price of Property or services), easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any rights of way or other Property of the Borrower or any Subsidiary for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, and defects, irregularities, zoning restrictions and deficiencies in title of any rights of way or other Property which in the aggregate do not materially impair the use of such rights of way or other Property for the purposes of which such rights of way and other Property are held by the Borrower or any Subsidiary or materially impair the value of such Property subject thereto; (vi) deposits of cash or securities to secure the performance of bids, trade contracts, leases, statutory obligations and other obligations of a like nature incurred in the ordinary course of business; (vii)

Liens permitted by the Security Instruments; (viii) burdens created by the NPI; and (ix) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board and no such deposit account is intended by the Borrower or any of its Subsidiaries to provide collateral to the depository institution.

“Excluded Taxes” means, with respect to the Administrative Agent, any Lender, any Issuer or any other recipient of any payment to be made by or on account of any obligation of the Borrower or any Guarantor hereunder or under any other Loan Document, (a) income or franchise taxes imposed on (or measured by) its net income by the United States of America or such other jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any other jurisdiction in which the Borrower or any Guarantor is located and (c) in the case of a Foreign Lender any withholding tax that is imposed on amounts payable to such Foreign Lender at the time such Foreign Lender becomes a party to this Agreement (or designates a new lending office) or is attributable to such Foreign Lender’s failure to comply with Section 5.03(e), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts with respect to such withholding tax pursuant to Section 5.03(a) or Section 5.03(c).

“Federal Funds Effective Rate” means, for any day, a fluctuating interest rate per annum equal for each day during such day to

(a) the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York; or

(b) if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Administrative Agent from three federal funds brokers of recognized standing selected by it.

“Financial Officer” means, for any Person, the chief financial officer, principal accounting officer, treasurer or controller of such Person. Unless otherwise specified, all references to a Financial Officer shall mean a Financial Officer of the Borrower.

“Financial Statements” means (a) the audited consolidated balance sheet of the Borrower and its Consolidated Subsidiaries as of December 31, 2005 and the related consolidated statement of income, members’ equity and cash flow of the Borrower and its Consolidated Subsidiaries for the fiscal year ended on such date and (b) the unaudited consolidated balance sheet of the Borrower and its consolidated Subsidiaries as of June 30, 2006 and the related Consolidated statement of income, members’ equity and cash flow of the Borrower and its Consolidated Subsidiaries for the fiscal quarter ended on such date.

“Foreign Lender” means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrower is located. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Foreign Subsidiary” means any Subsidiary that is not a Domestic Subsidiary.

“GAAP” means generally accepted accounting principles in the United States of America as in effect from time to time subject to the terms and conditions set forth in Section 1.04.

“Gas Purchase Contract” means the Gas Purchase Contract dated October 1, 1993 between Robinson’s Bend Marketing II, LLC and Robinson’s Bend Production II, LLC.

“Governmental Authority” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government over the Borrower or any of its Subsidiaries, any of their Properties, any Agent, any Issuer or any Lender.

“Governmental Requirement” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, whether now or hereinafter in effect, including, without limitation, Environmental Laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

“Guarantors” means Robinson’s Bend Operating II, LLC, a Delaware limited liability company, Robinson’s Bend Marketing II, LLC, a Delaware limited liability company and Robinson’s Bend Production II, LLC, a Delaware limited liability company and any additional Guarantors pursuant to Section 8.13.

“Guarantee Agreement” means an agreement executed by the Guarantors in form and substance reasonably satisfactory to the Administrative Agent unconditionally guarantying on a joint and several basis, payment of the Indebtedness, as the same may be amended, modified or supplemented from time to time.

“Highest Lawful Rate” means, with respect to each Lender, the maximum nonusurious interest rate, if any, that at any time or from time to time may be contracted for, taken, reserved, charged or received on the Notes or on other Indebtedness under laws applicable to such Lender which are presently in effect or, to the extent allowed by law, under such applicable federal laws which may hereafter be in effect and which allow a higher maximum nonusurious interest rate than applicable laws allow as of the date hereof.

“Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons, coal bed gas and occluded natural gas and all products refined or separated therefrom.

“Indebtedness” means any and all amounts owing or to be owing by the Borrower, any of its Subsidiaries or any Guarantor (whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising): (a) to the Administrative Agent, the Issuer or any Lender under any Loan Document; (b) to any Lender or any Affiliate of a Lender under any Swap Agreements among such Person and the Borrower or any Subsidiary or assigned to such Person while such Person (or in the case of its Affiliate, the Lender affiliated therewith) is a Lender hereunder and (c) all renewals, extensions and/or rearrangements of any of the above.

“Indemnified Taxes” means Taxes other than Excluded Taxes.

“Initial Reserve Report” means the reserve report concerning Oil and Gas Properties of Borrower and its Subsidiaries, prepared by Netherland, Sewell and Associates, Inc., issued on or after January 28, 2006 and dated as of December 31, 2005.

“Interest Election Request” means a request by the Borrower to continue a Borrowing in accordance with Section 2.04.

“Interest Expense” means, for any period, the sum (determined without duplication) of the aggregate gross interest expense of the Borrower and the Consolidated Subsidiaries for such period, including (a) to the extent included in interest expense under GAAP: (i) amortization of debt discount, (ii) capitalized interest and (iii) the portion of any payments or accruals under Capital Leases allocable to interest expense, plus the portion of any payments or accruals under Synthetic Leases allocable to interest expense whether or not the same constitutes interest expense under GAAP and (b) cash dividend payments by the Borrower in respect of any Disqualified Capital Stock; but excluding non-cash gains, losses or adjustments under FASB Statement No. 133 as a result of changes in the fair market value of derivatives.

“Interest Period” means with respect to any Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, three or six months thereafter, as the Borrower may elect; provided, that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (b) any Interest Period pertaining to a Borrowing that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

“Interim Redetermination” has the meaning assigned such term in Section 2.07(b).

“Investment” means, for any Person: (a) the acquisition (whether for cash, Property, services or securities or otherwise) of Equity Interests of any other Person or any agreement to make any such acquisition (including, without limitation, any “short sale” or any sale of any securities at a time when such securities are not owned by the Person entering into such short sale); (b) the making of any deposit for the purpose of acquisition of Equity Interests or Debt with, or advance, loan or capital contribution to, assumption of Debt of, purchase or other acquisition of any other Debt or equity participation or interest in, or other extension of credit to, any other Person (including the purchase of Property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such Property to such Person, but excluding any such advance, loan or extension of credit having a term not exceeding ninety (90) days representing the purchase price of inventory, equipment, or supplies sold by such Person in the ordinary course of business); (c) the purchase or acquisition (in one or a series of transactions) of Property of another Person that constitutes a business unit or (d) the entering into of any guarantee of, or other contingent obligation (including the deposit of any Equity Interests to be sold) with respect to, Debt or other liability of any other Person and (without duplication) any amount committed to be advanced, lent or extended to such Person.

“Issuer” means The Royal Bank of Scotland plc, in its capacity as an issuer of Letters of Credit hereunder, and its successors in such capacity as provided in Section 2.08(i).

“Lenders” means the Persons listed on Annex I, and any Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

“Letter of Credit” means any letter of credit issued pursuant to this Agreement.

“Letter of Credit Agreements” means all letter of credit applications and other agreements (including any amendments, modifications or supplements thereto) submitted by the Borrower, or entered into by the Borrower, with any Issuer relating to any Letter of Credit issued by such Issuer.

“Letter of Credit Commitment” at any time means Twenty Million Dollars ($20,000,000).

“Letter of Credit Disbursement” means a payment made by the Issuer pursuant to a Letter of Credit issued by the Issuer.

“Letter of Credit Exposure” means, at any time, the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time plus (b) the aggregate amount of all unpaid and outstanding Reimbursement Obligations. The Letter of Credit Exposure of any Lender at any time shall be its Applicable Percentage of the total Letter of Credit Exposure at such time.

“LIBO Rate” means, with respect to any Borrowing for any Interest Period, the rate appearing on Page BBAM of Bloomberg (or on any successor or substitute page of such Service, or any successor to or substitute for such Service, providing rate quotations comparable to those currently provided on such page of such Service, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar

deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the “LIBO Rate” with respect to such Borrowing for such Interest Period shall be the rate (rounded upwards, if necessary, to the next 1/16th of 1%) at which dollar deposits of $1,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

“Lien” means any interest in Property securing an obligation owed to, or a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including but not limited to (a) the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement, conditional sale or trust receipt or a financing lease, consignment or bailment for security purposes or (b) production payments and the like payable out of Oil and Gas Properties. The term “Lien” shall include easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations.

“Loan Commitment” means, with respect to each Lender, the commitment of such Lender to make Loans and to acquire participations in Letters of Credit hereunder, expressed as an amount representing the maximum aggregate amount of such Lender’s Revolving Credit Exposure hereunder, as such commitment may be (a) modified from time to time pursuant to Section 2.06 and (b) modified from time to time pursuant to assignments by or to such Lender pursuant to Section 12.04(b). The amount representing each Lender’s Loan Commitment shall at any time be the lesser of such Lender’s Maximum Credit Amount and such Lender’s Applicable Percentage of the then effective Borrowing Base.

“Loan Documents” means this Agreement, the Notes, the Letter of Credit Agreements, the Letters of Credit, any Swap Agreements with any Lender and the Security Instruments.

“Loans” means the loans made by the Lenders to the Borrower pursuant to this Agreement.

“Management Services Agreement” means that certain Management Services Agreement to be entered into by and between Borrower and Constellation Energy Partners Management, LLC in substantially the form filed with the SEC on September [28], 2006, or in a form otherwise satisfactory to Administrative Agent in its reasonable discretion.

“Managers” means the members of the Board of Managers or Board of Directors (however designated from time to time) of the Borrower as constituted from time to time.

“Material Adverse Effect” means a material adverse change in, or material adverse effect on (a) the business, operations, Property, liabilities (actual or contingent) or condition (financial or otherwise) of the Borrower and its Guarantors taken as a whole, (b) the ability of the Borrower, any of its Subsidiaries or any Guarantor to perform any of its obligations under any Loan Document to which it is a party, (c) the validity or enforceability of any Loan Document or (d) the rights and remedies of or benefits available to the Administrative Agent, any other Agent, the Issuer or any Lender under any Loan Document.

“Material Domestic Subsidiary” means, as of any date, any Domestic Subsidiary that (a) is a Wholly-Owned Subsidiary and (b) together with its Subsidiaries, owns Property having a fair market value of $1,000,000 or more.

“Material Indebtedness” means Debt (other than the Loans and Letters of Credit), or obligations in respect of one or more Swap Agreements, of any one or more of the Borrower and its Subsidiaries in an aggregate principal amount exceeding $1,000,000. For purposes of determining Material Indebtedness, the “principal amount” of the obligations of the Borrower or any of its Subsidiaries in respect of any Swap Agreement at any time shall be the maximum aggregate amount (giving effect to any netting agreements) that the Borrower or such Subsidiary would be required to pay if such Swap Agreement were terminated at such time.

“Material Swap Transaction” has the meaning assigned such term in Section 8.01(j).

“Maturity Date” means October [ ], 2010.

“Maximum Credit Amount” means, as to each Lender, the amount set forth opposite such Lender’s name on Annex I under the caption “Maximum Credit Amounts”, as the same may be (a) reduced or terminated from time to time in connection with a reduction or termination of the Aggregate Maximum Credit Amounts pursuant to Section 2.06(b) or (b) modified from time to time pursuant to any assignment permitted by Section 12.04(b).

“Moody’s” means Moody’s Investors Service, Inc. and any successor thereto that is a nationally recognized rating agency.

“Mortgaged Property” means any Property owned by the Borrower or any Guarantor which is subject to the Liens existing and to exist under the terms of the Security Instruments.

“Multiemployer Plan” means a Plan which is a multiemployer plan as defined in section 3(37) or 4001 (a)(3) of ERISA.

“Net Revenue Interest” means, with respect to any Property, the decimal or percentage share of production from or allocable to such Property, after deduction of all overriding royalties and other burdens (including lessor royalties), that an owner of a Working Interest is entitled to receive.

“Notes” means the promissory notes of the Borrower described in Section 2.02(d) and being substantially in the form of Exhibit A, together with all amendments, modifications, replacements, extensions and rearrangements thereof.

“NPI” means the net profits interest created by the Net Overriding Royalty Conveyance dated October 1, 1993 from Velasco Gas Company, Ltd. to Torch Energy Advisors Incorporated and from Torch Energy Advisors Incorporated to the Torch Energy Royalty Trust and recorded and filed for record in Book 1164, Page 320, Records of Tuscaloosa County, Alabama.

“Obligations” means (a) all principal, interest, fees, reimbursements, indemnifications, and other amounts payable by Borrower or any of its Subsidiaries to the Administrative Agent, the Issuing Lender or the Lenders under the Loan Documents, including without limitation, the Letter of Credit Exposure and (b) all obligations of Borrower or any of its Subsidiaries owing to any Swap Counterparty under any Swap Agreement.

“Oil and Gas Properties” means (a) Hydrocarbon Interests; (b) the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests (including but not limited to that certain Stipulation and Agreement of Compromise and Settlement, dated as of November 22, 2000, by and between H. Gregory Pearson, et. al. and Torchmark Corporation, et. al., as well as all proceeds deriving therefrom); (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“OPA” shall have the meaning set forth in the definition of “Environmental Laws”.

“Other Taxes” means any and all present or future stamp or documentary taxes or any other excise or Property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement and any other Loan Document.

“Participant” has the meaning set forth in Section 12.04(c)(i).

“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

“Permitted Holders” means Constellation Energy Partners Holdings, LLC, a Delaware limited liability company and Constellation Energy Partners Management, LLC, a Delaware limited liability company or any other wholly-owned Subsidiary of Constellation Energy Group, Inc.

“Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

“Plan” means any employee pension benefit plan, as defined in section 3(2) of ERISA, which (a) is currently or hereafter sponsored, maintained or contributed to by the Borrower, any of its Subsidiaries or an ERISA Affiliate or (b) was at any time during the six calendar years preceding the date hereof, sponsored, maintained or contributed to by the Borrower, any of its Subsidiaries or an ERISA Affiliate.

“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights (including but not limited to Swap Agreements).

“Proposed Borrowing Base” has the meaning assigned to such term in Section 2.07(b).

“Proved Developed Producing Properties” means Oil and Gas Properties which are categorized as “Proved Reserves” that are both “Developed” and “Producing”, as such terms are defined in the Definitions for Oil and Gas Reserves as promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Redemption” means with respect to any Debt, the repurchase, redemption, prepayment, repayment or defeasance or any other acquisition or retirement for value (or the segregation of funds with respect to any of the foregoing) of any such Debt. “Redeem” has the correlative meaning thereto.

“Register” has the meaning assigned such term in Section 12.04(b)(iv).

“Reimbursement Obligations” has the meaning assigned to such term in Section 2.08(f).

“Related Parties” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents and advisors (including attorneys, accountants and experts) of such Person and such Person’s Affiliates.

“Remedial Work” has the meaning assigned such term in Section 8.10(a).

“Required Lenders” means, at any time while no Loans or Letter of Credit Exposure is outstanding, Lenders having at least sixty-six and two-thirds percent (66-2/3%) of the Aggregate Maximum Credit Amounts; and at any time while any Loans or Letter of Credit Exposure is outstanding, Lenders holding at least sixty-six and two-thirds percent (66-2/3%) of the outstanding aggregate principal amount of the Loans or participation interests in Letters of Credit (without regard to any sale by a Lender of a participation in any Loan under Section 12.04(c)).

“Reserve Report” means the Initial Reserve Report and each other report setting forth, as of each January 1^st or July 1^st (or such other date as required pursuant to Section 2.07 and the other provisions of this Agreement), the oil and gas reserves attributable to the Oil and Gas

Properties of the Borrower and its Subsidiaries, together with a projection of the rate of production and future net income, severance and ad valorem taxes, operating expenses and capital expenditures with respect thereto as of such date, consistent with SEC reporting requirements at the time, provided that each such report hereafter delivered must (a) separately report on the Proved Developed Producing Reserves, Proved Developed Nonproducing Reserves and Proved Undeveloped Reserves of the Borrower and such Consolidated Subsidiaries, (b) take into account the Borrower’s actual experiences with leasehold operating expenses and other costs in determining projected leasehold operating expenses and other costs, (c) identify and take into account any “overproduced” or “under-produced” status under gas balancing arrangements, and (d) reflect recent information and analysis comparable in scope to that contained in the Initial Reserve Report.

“Responsible Officer” means, as to any Person, the Chief Executive Officer, the President or any Financial Officer of such Person. Unless otherwise specified, all references to a Responsible Officer herein shall mean a Responsible Officer of the Borrower.

“Restricted Payment” means any dividend or other distribution (whether in cash, securities or other Property) with respect to any Equity Interests in the Borrower, or any payment (whether in cash, securities or other Property), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Equity Interests in the Borrower or any option, warrant or other right to acquire any such Equity Interests in the Borrower.

“Revolving Credit Exposure” means, with respect to any Lender at any time, the sum of the outstanding principal amount of such Lender’s Loans and its Letter of Credit Exposure at such time.

“Rolling Period” means for any date of determination, the most recent four quarters ended on such date; provided, however, for any determination made prior to December 31, 2007, proforma financial information shall be used for any quarter for which financial information is not available.

“Security Instruments” means the Guarantee Agreement, if any, mortgages, deeds of trust and other agreements, instruments or certificates described or referred to in Exhibit C-1, and any and all other agreements, instruments, consents or certificates now or hereafter executed and delivered by the Borrower or any other Person in connection with, or as security for the payment or performance of the Obligations.

“S&P” means Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc., and any successor thereto that is a nationally recognized rating agency.

“Subsidiary” means: (a) any Person of which at least a majority of the outstanding Equity Interests having by the terms thereof ordinary voting power to elect a majority of the board of directors, manager or other governing body of such Person (irrespective of whether or not at the time Equity Interests of any other class or classes of such Person shall have or might have voting power by reason of the happening of any contingency) is at the time directly or indirectly owned or controlled by the Borrower or one or more of its Subsidiaries or by the Borrower and one or

more of its Subsidiaries and (b) any partnership of which the Borrower or any of its Subsidiaries is a general partner. Unless otherwise indicated herein, each reference to the term “Subsidiary” shall mean a Subsidiary of the Borrower.

“Swap Agreement” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or any of its Subsidiaries shall be a Swap Agreement.

“Swap Counterparty” means any Lender (or Affiliate of a Lender) that is party to a Swap Agreement with the Borrower or any of its Subsidiaries.

“Synthetic Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, treated as operating leases on the financial statements of the Person liable (whether contingently or otherwise) for the payment of rent thereunder and which were properly treated as indebtedness for borrowed money for purposes of U.S. federal income taxes, if the lessee in respect thereof is obligated to either purchase for an amount in excess of, or pay upon early termination an amount in excess of, 80% of the residual value of the Property subject to such operating lease upon expiration or early termination of such lease.

“Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority.

“Termination Date” means the earlier of the Maturity Date and the date of termination of the Commitments.

“Torch Energy Royalty Trust” means the trust created by and administered under the forms of the Trust Agreement by and among Torch Energy Advisors Incorporated, Torch Royalty Company, Velasco Gas Company Ltd. and Wilmington Trust Company dated as of October 1, 1993.

“Total Commitments” means the aggregate of all Commitments hereunder.

“Total Revolving Credit Exposure” means the aggregate of all Revolving Credit Exposure hereunder.

“Transactions” means, with respect to (a) the Borrower, the execution, delivery and performance by the Borrower of this Agreement, and each other Loan Document to which it is a party, the borrowing of Loans, the use of the proceeds thereof and the issuance of Letters of Credit hereunder, and the grant of Liens by the Borrower on Mortgaged Properties and other Properties pursuant to the Security Instruments and (b) any Guarantor, the execution, delivery and performance by such Guarantor of each Loan Document to which it is a party, the guaranteeing of the Indebtedness and the other obligations under the Guarantee Agreement by

such Guarantor and such Guarantor’s grant of the security interests and provision of collateral under the Security Instruments, and the grant of Liens by such Guarantor on Mortgaged Properties and other Properties pursuant to the Security Instruments.

“Type” means, relative to any Loan, the portion thereof, if any, being maintained as a Base Rate Loan or a LIBO Rate Loan.

“Wholly-Owned Subsidiary” means any Subsidiary of which all of the outstanding Equity Interests (other than any directors’ qualifying shares mandated by applicable law), on a fully-diluted basis, are owned by the Borrower or one or more of the Wholly-Owned Subsidiaries or are owned by the Borrower and one or more of the Wholly-Owned Subsidiaries.

“Working Interest” means the property interest which entitles the owner thereof to explore and develop certain land for oil and gas production purposes, whether under an oil and gas lease or unit, a compulsory pooling order or otherwise.

Section 1.03 Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth in the Loan Documents herein), (b) any reference herein to any law shall be construed as referring to such law as amended, modified, codified or reenacted, in whole or in part, and in effect from time to time, (c) any reference herein to any Person shall be construed to include such Person’s successors and assigns (subject to the restrictions contained in the Loan Documents herein), (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) with respect to the determination of any time period, the word “from” means “from and including” and the word “to” means “to and including” and (f) any reference herein to Articles, Sections, Annexes, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Annexes, Exhibits and Schedules to, this Agreement. No provision of this Agreement or any other Loan Document shall be interpreted or construed against any Person solely because such Person or its legal representative drafted such provision.

Section 1.04 Accounting Terms and Determinations; GAAP. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all determinations with respect to accounting matters hereunder shall be made, and all financial statements and certificates and reports as to financial matters required to be furnished to the Administrative Agent or the Lenders hereunder shall be prepared, in accordance with GAAP, applied on a basis consistent with the Financial Statements except for changes in which the Borrower’s independent certified public accountants concur and which are disclosed to Administrative Agent on the next date on which financial statements are required to be delivered to the Lenders pursuant to Section 8.01(a); provided that, unless the Borrower and the Required Lenders shall otherwise

agree in writing, no such change shall modify or affect the manner in which compliance with the covenants contained herein is computed such that all such computations shall be conducted utilizing financial information presented consistently with prior periods.

ARTICLE II

THE CREDITS

Section 2.01 Commitments. Subject to the terms and conditions set forth herein, each Lender agrees to make Loans to the Borrower during the Availability Period in an aggregate principal amount that will not result in (a) such Lender’s Revolving Credit Exposure exceeding such Lender’s Loan Commitment or (b) the Total Revolving Credit Exposures exceeding the Total Commitments. Within the foregoing limits and subject to the terms and conditions set forth herein, the Borrower may borrow, repay and reborrow the Loans.

Section 2.02 Loans and Borrowings.

(a) Borrowings; Several Obligations. Each Loan shall be made as part of a Borrowing consisting of Loans made by the Lenders ratably in accordance with their respective Commitments. The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

(b) Types of Loans. Subject to Section 3.03, each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request in accordance herewith. Each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement.

(c) Minimum Amounts; Limitation on Number of Borrowings. At the commencement of each Interest Period for any Borrowing, such Borrowing shall be in an aggregate amount that is an integral multiple of $500,000 and not less than $1,000,000. At the time that each ABR Borrowing is made, such Borrowing shall be in an aggregate amount that is an integral multiple of $250,000 and not less than $1,000,000; provided that an ABR Borrowing may be in an aggregate amount that is equal to the entire unused balance of the total Commitments or that is required to finance the reimbursement of a Letter of Credit Disbursement as contemplated by Section 2.08(e). Borrowings of more than one Type may be outstanding at the same time; provided that there shall not at any time be more than a total of twelve (12) Eurodollar Borrowings outstanding. Multiple Borrowings may be outstanding at the same time; provided that there shall not at any time be more than a total of three (3) Borrowings outstanding. Notwithstanding any other provision of this Agreement, the Borrower shall not be entitled to request, or to elect to continue, any Borrowing if the Interest Period requested with respect thereto would end after the Maturity Date.

(d) Notes. The Loans made by each Lender shall be evidenced by a single promissory note of the Borrower in substantially the form of Exhibit A, dated, in the case of (i)

any Lender party hereto as of the date of this Agreement, as of the date of this Agreement or (ii) any Lender that becomes a party hereto pursuant to an Assignment and Assumption, as of the effective date of the Assignment and Assumption, payable to the order of such Lender in a principal amount equal to its Maximum Credit Amount as in effect on such date, and otherwise duly completed. In the event that any Lender’s Maximum Credit Amount increases or decreases for any reason (whether pursuant to Section 2.06, Section 12.04(b) or otherwise), the Borrower shall deliver or cause to be delivered on the effective date of such increase or decrease, a new Note payable to the order of such Lender in a principal amount equal to its Maximum Credit Amount after giving effect to such increase or decrease, and otherwise duly completed and the affected Lender shall deliver the Note being replaced to the Borrower immediately. The date, amount, interest rate and Interest Period of each Loan made by each Lender, and all payments made on account of the principal thereof, shall be recorded by such Lender on its books for its Note, and, prior to any transfer, may be endorsed by such Lender on a schedule attached to such Note or any continuation thereof or on any separate record maintained by such Lender. Failure to make any such notation or to attach a schedule shall not affect any Lender’s or the Borrower’s rights or obligations in respect of such Loans or affect the validity of such transfer by any Lender of its Note.

Section 2.03 Requests for Borrowings. To request a Borrowing, the Borrower shall notify the Administrative Agent of such request by telephone not later than Noon, New York time, three Business Days before the date of the proposed Borrowing, in the case of Eurodollar Borrowings, or on the same Business Day, in the case of ABR Borrowings. Each such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Borrowing Request in the form attached hereto as Exhibit 2.03. Each such telephonic and written Borrowing Request shall specify the following information in compliance with Section 2.02:

(i) the aggregate amount of the requested Borrowing;

(ii) the date of such Borrowing, which shall be a Business Day;

(iii) in the case of Eurodollar Borrowings, the initial Interest Period to be applicable to such Borrowing, which shall be a period contemplated by the definition of the term “Interest Period”;

(iv) the amount of the then effective Borrowing Base, the current Total Revolving Credit Exposures (without regard to the requested Borrowing) and the pro forma Total Revolving Credit Exposures (giving effect to the requested Borrowing); and

(v) the location and number of the Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.05.

In the case of Eurodollar Borrowings, if no Interest Period is specified with respect to any requested Borrowing, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration. Each Borrowing Request shall constitute a representation that the amount of the requested Borrowing shall not cause the Total Revolving Credit Exposures to exceed the total Commitments (i.e., the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base).

Promptly following receipt of a Borrowing Request in accordance with this Section 2.03, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

Section 2.04 Interest Elections.

(a) Continuance. Each Borrowing initially shall have an initial Interest Period as specified in such Borrowing Request. Thereafter, the Borrower may elect to continue such Borrowing and may elect Interest Periods therefor, all as provided in this Section 2.04. The Borrower may elect different options with respect to different portions of the affected Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a separate Borrowing.

(b) Interest Election Requests. To make an election pursuant to this Section 2.04, the Borrower shall notify the Administrative Agent of such election by telephone by the time that a Borrowing Request would be required under Section 2.03. Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Interest Election Request in the form attached hereto as Exhibit 2.04(b) and signed by the Borrower.

(c) Information in Interest Election Requests. Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02:

(i) the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to Section 2.04(c)(iii) shall be specified for each resulting Borrowing);

(ii) the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day; and

(iii) the Interest Period to be applicable to such Borrowing after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period”.

If any such Interest Election Request does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.

(d) Notice to Lenders by the Administrative Agent. Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of each resulting Borrowing.

(e) Effect of Failure to Deliver Timely Interest Election Request and Events of Default and Borrowing Base Deficiencies on Interest Election. If the Borrower fails to deliver a timely Interest Election Request with respect to a Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be continued as a Loan having an Interest Period of one-month. Notwithstanding any contrary provision hereof, if an Event of Default or a Borrowing Base Deficiency has occurred and is continuing, then no outstanding Borrowing may be continued (and any Interest Election Request that requests the continuation of any Borrowing shall be ineffective).

Section 2.05 Funding of Borrowing.

(a) Funding by Lenders. Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds by 2:00 p.m., New York time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders. The Administrative Agent will make such Loans available to the Borrower by promptly crediting the amounts so received, in like funds, to an account of the Borrower and designated by the Borrower in the applicable Borrowing Request; provided that Loans made to finance the reimbursement of a Letter of Credit Disbursement as provided in Section 2.08(e) shall be remitted by the Administrative Agent to the Issuer that made such Letter of Credit Disbursement. Nothing herein shall be deemed to obligate any Lender to obtain the funds for its Loan in any particular place or manner or to constitute a representation by any Lender that it has obtained or will obtain the funds for its Loan in any particular place or manner.

(b) Presumption of Funding by the Lenders. Unless the Administrative Agent shall have received notice from a Lender prior to the proposed date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with Section 2.05(a) and may, in reliance upon such assumption, make available to the Borrower a corresponding amount. In such event, if a Lender has not in fact made its share of the applicable Borrowing available to the Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest rate applicable to Loans. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender’s Loan included in such Borrowing.

Section 2.06 Termination and Reduction of Aggregate Maximum Credit Amounts.

(a) Scheduled Termination of Commitments. Unless previously terminated, the Commitments shall terminate on the Maturity Date. If at any time the Aggregate Maximum Credit Amounts or the Borrowing Base is terminated or reduced to zero, then the Commitments shall terminate on the effective date of such termination or reduction.

(b) Optional Termination and Reduction of Aggregate Credit Amounts.

(i) The Borrower may at any time terminate, or from time to time reduce, the Aggregate Maximum Credit Amounts; provided that (A) each reduction of the Aggregate Maximum Credit Amounts shall be in an amount that is an integral multiple of $500,000 and not less than $1,000,000 and (B) the Borrower shall not terminate or reduce the Aggregate Maximum Credit Amounts if, after giving effect to any concurrent prepayment of the Loans in accordance with Section 3.03(c), the Total Revolving Credit Exposures would exceed the total Commitments.

(ii) The Borrower shall notify the Administrative Agent of any election to terminate or reduce the Aggregate Maximum Credit Amounts under Section 2.06(b)(i) at least three Business Days prior to the effective date of such termination or reduction, specifying such election and the effective date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the Lenders of the contents thereof. Each notice delivered by the Borrower pursuant to this Section 2.06(b)(ii) shall be irrevocable. Any termination or reduction of the Aggregate Maximum Credit Amounts shall be permanent and may not be reinstated. Each reduction of the Aggregate Maximum Credit Amounts shall be made ratably among the Lenders in accordance with each Lender’s Applicable Percentage.

Section 2.07 Borrowing Base.

(a) For the period from and including the Closing Date to but excluding the date of the first determination of the Borrowing Base pursuant to the further provisions of this Section 2.07, the initial amount of the Borrowing Base has been set by the Administrative Agent and acknowledged by the Borrower and agreed to by the Lenders to be $100,000,000.

(b) Promptly after January 1 of each calendar year, commencing January 1, 2007, and in any event prior to March 31 of each calendar year (commencing March 31, 2007), the Borrower shall furnish to the Administrative Agent a Reserve Report in form and substance reasonably satisfactory to the Administrative Agent, prepared by an Approved Engineer, which Reserve Report shall be dated as of January 1 of such calendar year together with additional data concerning pricing, hedging, quantities and purchasers of production, and other information and engineering and geological data as the Administrative Agent may reasonably request. Within fifteen (15) days after receipt of all such Reserve Report and information, the Administrative Agent shall make an initial determination of the new Borrowing Base (the “Proposed Borrowing Base”), which for purposes of this Section 2.07(b) is the semi-annual determination described in Section 2.07(c), and upon such initial determination shall promptly notify the Lenders in writing of its initial determination of the Proposed Borrowing Base. Such initial determinations made by the Administrative Agent shall be so made by the Administrative Agent in the exercise of its sole discretion in accordance with the Administrative Agent’s customary practices and standards for oil and gas lending as they exist at the particular time. In no event shall the Proposed Borrowing Base exceed the aggregate Loan Commitments of the Lenders. The Required Lenders shall approve or reject the Administrative Agent’s initial determinations of the Proposed Borrowing Base by written notice to the Administrative Agent within fifteen (15) days of the Administrative Agent’s notification of its initial determinations; provided, however that failure by any Lender to

confirm in writing, the Administrative Agent’s determination of the Proposed Borrowing Base shall be and shall be deemed an approval of the Proposed Borrowing Base. If the Required Lenders fail to approve any such determination of the Proposed Borrowing Base made by the Administrative Agent hereunder in such fifteen (15) day period, then the Administrative Agent shall poll the Lenders to ascertain the highest Proposed Borrowing Base then acceptable to the Required Lenders for purposes of this Section 2.07(b) and, subject to the last sentence of this Section 2.07(b), such amounts shall become the new Borrowing Base, effective on the date specified in this Section 2.07. Until such approval or deemed approval, the Borrowing Base in effect before the Proposed Borrowing Base shall remain in effect. Upon agreement by the Administrative Agent and the Required Lenders of the new Borrowing Base, the Administrative Agent shall, by written notice to the Borrower and the Lenders, designate the new Borrowing Base available to the Borrower. Such designation shall be effective as of the Business Day specified in such written notice (or, if no effective date is specified in such written notice, the next Business Day following delivery of such written notice) and such new Borrowing Base shall remain in effect until the next determination or redetermination of the Borrowing Base in accordance with this Agreement. Anything herein contained to the contrary notwithstanding, any determination or redetermination of the Borrowing Base resulting in any increase of the Borrowing Base in effect immediately prior to such determination or redetermination shall require the approval of all the Lenders in their sole discretion in accordance with their respective customary practices and standards for oil and gas lending as they exist at the particular time.

(c) In addition, within ninety (90) days after each June 30, commencing June 30, 2007, the Borrower shall furnish to the Administrative Agent a Reserve Report in form and substance satisfactory to the Administrative Agent, prepared by the Borrower’s petroleum engineers or on behalf of Borrower by petroleum engineers under the Management Services Agreement, which report shall be dated as of July 1 of such calendar year together with additional data concerning pricing, hedging, quantities and purchasers of production, and other information and engineering and geological data as the Administrative Agent may reasonably request. Within fifteen (15) days after receipt of all such Reserve Report and information, the Administrative Agent shall make an initial determination of a Proposed Borrowing Base, and upon such initial determination shall promptly notify the Lenders in writing of initial determination of the Proposed Borrowing Base. Such initial determination shall be made in the same manner and be subject to the same approvals as prescribed above with respect to the annual review, and likewise the Administrative Agent shall communicate the results of such initial determinations to the Lenders. The Required Lenders shall approve such determinations of the Proposed Borrowing Base by written notice to the Administrative Agent within fifteen (15) days of the giving of notice of such determinations by the Administrative Agent to such Lenders; provided, however that failure by any Lender to confirm in writing the Administrative Agent’s determination of the Proposed Borrowing Base shall be, and shall be deemed, an approval of the Proposed Borrowing Base. If the Required Lenders fail to approve any such determination of the Proposed Borrowing Base made by the Administrative Agent hereunder in such fifteen (15) day period, then the Administrative Agent shall poll the Lenders to ascertain the highest Proposed Borrowing Base then acceptable to the Required Lenders for purposes of this Section 2.07(c) and, subject to the last sentence of this Section 2.07(c), such amounts shall become the new Borrowing Base, effective on the date specified in this Section 2.07. Upon agreement by the Administrative Agent and the Required Lenders of the amount of credit to be made available to the Borrower hereunder, the Administrative Agent shall, by written notice to the Borrower and

the Lenders, designate the new Borrowing Base available to the Borrower. Such designation shall be effective as of the Business Day specified in such written notice (or, if no effective date is specified in such written notice, the next Business Day following delivery of such written notice) and such new Borrowing Base shall remain in effect until the next determination or redetermination of the Borrowing Base in accordance with this Agreement. Anything herein contained to the contrary notwithstanding, any determination or redetermination of the Borrowing Base resulting in any increase of the Borrowing Base in effect immediately prior to such determination or redetermination shall require the approval of all the Lenders in their sole discretion in accordance with their respective customary practices and standards for oil and gas lending as they exist at the particular time.

(d) In addition to the foregoing scheduled annual and semi annual determinations of the Borrowing Base, the Required Lenders shall have the right to redetermine the Borrowing Base at their sole discretion at any time and from time to time but not more often than two (2) times every calendar year. If the Required Lenders shall elect to make a discretionary redetermination of the Borrowing Base pursuant to the provisions of this Section 2.07(d), the Borrower shall within thirty (30) days of receipt of a request therefor from the Administrative Agent, deliver to the Administrative Agent a Reserve Report in form and substance satisfactory to the Administrative Agent, prepared by the Borrower’s petroleum engineers containing information similar to the Reserve Reports delivered pursuant to Section 2.07(c), together with such updated engineering, production, operating and other data as the Administrative Agent, the Issuer or any Lender may reasonably request. The Administrative Agent shall have fifteen (15) days following receipt of such requested information to make an initial redetermination of the Borrowing Base, and the Administrative Agent and the Required Lenders shall approve and designate the new Borrowing Base in accordance with the procedures and standards described in Section 2.07(b).

(e) In addition to the foregoing determinations of the Borrowing Base, the Borrower may request a redetermination of the Borrowing Base at any time and from time to time but not more often than two (2) times every calendar year, by delivering a written request to the Administrative Agent, together with (a) an engineering fee in the aggregate amount of $2,500 for the account of the Administrative Agent in immediately available funds, and (b) a Reserve Report in form and substance satisfactory to the Administrative Agent, prepared by the Borrower’s petroleum engineers containing information similar to the Reserve Reports delivered pursuant to Section 2.07(c), together with such other updated engineering, production, operating and other data as the Administrative Agent, the Issuer or any Lender may reasonably request. Each such discretionary redetermination of the Borrowing Base shall be made in the same manner and in accordance with the procedures and standards set forth above by adjusting the Borrowing Base then in effect. The Administrative Agent shall have fifteen (15) days following receipt of such requested information to make an initial redetermination of the Borrowing Base, and the Administrative Agent and the Required Lenders shall approve and designate the new Borrowing Base in accordance with the procedures and standards described in Section 2.07(b).

(f) In addition to the Borrower’s right to request a discretionary Borrowing Base redetermination as set forth in Section 2.07(e), the Borrower may request a redetermination of the Borrowing Base at any time and from time to time upon the acquisition by the Borrower of additional Oil and Gas Properties, by delivering a written request to the Administrative Agent,

together with (a) an engineering fee in the aggregate amount of $2,500 for the account of the Administrative Agent in immediately available funds, (b) with respect to Oil and Gas Properties represented in the existing Borrowing Base, a Reserve Report in form and substance satisfactory to the Administrative Agent, prepared and delivered in accordance with Section 2.07(c), and (c) with respect to Oil and Gas Properties acquired since the most recent redetermination of the Borrowing Base, a Reserve Report in form and substance satisfactory to the Administrative Agent, prepared and delivered in accordance with Section 2.07(b). Each such redetermination of the Borrowing Base under this Section 2.07(f) shall be made in the same manner and in accordance with the procedures and standards set forth above by adjusting the Borrowing Base then in effect. The Administrative Agent shall have fifteen (15) days following receipt of such requested information to make an initial redetermination of the Borrowing Base, and the Administrative Agent and the Required Lenders shall approve and designate the new Borrowing Base in accordance with the procedures and standards described in Section 2.07(b).

(g) Notwithstanding anything to the contrary contained herein, upon the termination of the Gas Purchase Contract or the consummation of a Material Swap Transaction, the Required Lenders shall have the right to redetermine the Borrowing Base using information available to them, and the redetermined Borrowing Base shall become the new Borrowing Base immediately upon notice by the Administrative Agent to the Borrower, effective and applicable to the Borrower, the Administrative Agent, and each Lender on such date until the next redetermination or modification thereof hereunder (subject to the reduction described in Section 2.07(i)). The Borrowing Base will also be redetermined or adjusted in accordance with the provisions of Section 8.12(c) or Section 9.12(d).

(h) With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent a certificate from a Responsible Officer certifying that, to the best of such Responsible Officer’s knowledge and in all material respects: (i) the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct, (ii) the Borrower or the Guarantors owns good and defensible title to the Oil and Gas Properties evaluated in such Reserve Report and such Properties are free of all Liens except for Liens permitted by Section 9.03, (iii) except as set forth on an exhibit to the certificate, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 7.20 with respect to their Oil and Gas Properties evaluated in such Reserve Report that would require the Borrower or any of its Subsidiaries to deliver Hydrocarbons either generally or produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor, (iv) none of their Oil and Gas Properties have been sold since the date of the last Borrowing Base determination except as set forth on an exhibit to the certificate, which certificate shall list all of its Oil and Gas Properties sold and in such detail as reasonably required by the Administrative Agent, (v) attached to the certificate is a list of all marketing agreements entered into subsequent to the later of the date hereof or the most recently delivered Reserve Report that the Borrower could reasonably be expected to have been obligated to list on Schedule 7.20 had such agreement been in effect on the date hereof and (vi) attached thereto is a schedule of the Oil and Gas Properties evaluated by such Reserve Report that are Mortgaged Properties and demonstrating the percentage of the present value that such Mortgaged Properties represent.

(i) Notwithstanding anything herein the contrary, in the event that the Borrower does not furnish any required Reserve Report within ten (10) days of date the required herein, the Administrative Agent and the Required Lenders may nonetheless designate the Borrowing Base from time to time thereafter until the Administrative Agent receives such Reserve Report, whereupon the Administrative Agent and the Required Lenders or all Lenders, as applicable, shall designate a new Borrowing Base in accordance with the general procedures outlined in Section 2.07(b).

Section 2.08 Letters of Credit.

(a) General. Subject to the terms and conditions set forth herein, the Borrower may request any Issuer to issue Letters of Credit for its own account or for the account of the Borrower or any of its Subsidiaries, in a form reasonably acceptable to the Administrative Agent and such Issuer, at any time and from time to time during the Availability Period; provided that the Borrower may not request the issuance, amendment, renewal or extension of Letters of Credit hereunder if a Borrowing Base Deficiency exists at such time or would exist as a result thereof. In the event of any inconsistency between the terms and conditions of this Agreement and the terms and conditions of any form of letter of credit application or other agreement submitted by the Borrower to, or entered into by the Borrower with, an Issuer relating to any Letter of Credit, the terms and conditions of this Agreement shall control.

(b) Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions. To request the issuance of a Letter of Credit (or the amendment, renewal or extension of an outstanding Letter of Credit), the Borrower shall deliver as permitted by Section 12.01(a) (or transmit by electronic communication, if arrangements for doing so have been approved by the Issuer) to any Issuer and the Administrative Agent (not less than five (5) Business Days in advance of the requested date of issuance, amendment, renewal or extension) a notice in the form of Exhibit 2.08(b):

(i) requesting the issuance of a Letter of Credit or identifying the Letter of Credit issued by such Issuer to be amended, renewed or extended;

(ii) specifying the date of issuance, amendment, renewal or extension (which shall be a Business Day);

(iii) specifying the date on which such Letter of Credit is to expire (which shall comply with Section 2.08(c));

(iv) specifying the amount of such Letter of Credit;

(v) specifying the name and address of the beneficiary thereof and such other information as shall be necessary to prepare, amend, renew or extend such Letter of Credit; and

(vi) specifying the amount of the then effective Borrowing Base and whether a Borrowing Base Deficiency exists at such time, the current Total Revolving Credit Exposures (without regard to the requested Letter of Credit or the requested amendment, renewal or extension of an outstanding Letter of Credit) and the pro forma Total Revolving Credit Exposures (giving effect to the requested Letter of Credit or the requested amendment, renewal or extension of an outstanding Letter of Credit).

Each notice shall constitute a representation that after giving effect to the requested issuance, amendment, renewal or extension, as applicable, (i) the Letter of Credit Exposure shall not exceed the Letter of Credit Commitment and (ii) the Total Revolving Credit Exposures shall not exceed the lesser of the Aggregate Maximum Credit Amounts and the then effective Borrowing Base.

If requested by any Issuer, the Borrower also shall submit a letter of credit application on such Issuer’s standard form in connection with any request for a Letter of Credit.

(c) Expiration Date. Each Letter of Credit shall expire at or prior to the close of business on the earlier of (i) the date one year after the date of the issuance of such Letter of Credit (or, in the case of any renewal or extension thereof, one year after such renewal or extension) and (ii) the date that is five Business Days prior to the Maturity Date.

(d) Participations. By the issuance of a Letter of Credit (or an amendment to a Letter of Credit increasing the amount thereof) and without any further action on the part of the Issuer that issues such Letter of Credit or the Lenders, each Issuer that issues a Letter of Credit hereunder hereby grants to each Lender, and each Lender hereby acquires from such Issuer, a participation in such Letter of Credit equal to such Lender’s Applicable Percentage of the aggregate amount available to be drawn under such Letter of Credit. In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of any Issuer that issues a Letter of Credit hereunder, such Lender’s Applicable Percentage of each Letter of Credit Disbursement made by such Issuer and not reimbursed by the Borrower on the date due as provided in Section 2.08(e), or of any reimbursement payment required to be refunded to the Borrower for any reason. Each Lender acknowledges and agrees that its obligation to acquire participations pursuant to this Section 2.08(d) in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including any amendment, renewal or extension of any Letter of Credit or the occurrence and continuance of a Default, the existence of a Borrowing Base Deficiency or reduction or termination of the Commitments, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

(e) Reimbursement. If any Issuer shall make any Letter of Credit Disbursement in respect of a Letter of Credit issued by such Issuer, the Borrower shall reimburse such Letter of Credit Disbursement by paying to the Administrative Agent an amount equal to such Letter of Credit Disbursement not later than 12:00 p.m., New York time, on the third day after such Letter of Credit Disbursement is made, if the Borrower shall have received notice of such Letter of Credit Disbursement prior to 10:00 a.m., New York time, on such date, or, if such notice has not been received by the Borrower prior to such time on such date, then not later than 2:00 p.m., New York time, on (i) the third day after the Borrower receives such notice, if such notice is received prior to 10:00 a.m., New York time, on the day of receipt, or (ii) the Business Day immediately following the third day after the Borrower receives such notice, if such notice is not received prior to such time on the day of receipt; provided that if such Letter of Credit Disbursement is not less than $1,000,000, the Borrower shall, subject to the conditions to

Borrowing set forth herein, be deemed to have requested, and the Borrower does hereby request under such circumstances, that such payment be financed with a Eurodollar Borrowing with an Interest Period of one month in an equivalent amount and, to the extent so financed, the Borrower’s obligation to make such payment shall be discharged and replaced by the resulting Eurodollar Borrowing. If the Borrower fails to make such payment when due, the Administrative Agent shall notify each Lender of the applicable Letter of Credit Disbursement, the payment then due from the Borrower in respect thereof and such Lender’s Applicable Percentage thereof. Promptly following receipt of such notice, each Lender shall pay to the Administrative Agent its Applicable Percentage of the payment then due from the Borrower, in the same manner as provided in Section 2.05 with respect to Loans made by such Lender (and Section 2.05 shall apply, mutatis mutandis, to the payment obligations of the Lenders), and the Administrative Agent shall promptly pay to the Issuer that issued such Letter of Credit the amounts so received by it from the Lenders. Promptly following receipt by the Administrative Agent of any payment from the Borrower pursuant to this Section 2.08(e), the Administrative Agent shall distribute such payment to the Issuer that issued such Letter of Credit or, to the extent that Lenders have made payments pursuant to this Section 2.08(e) to reimburse such Issuer, then to such Lenders and such Issuer as their interests may appear. Any payment made by a Lender pursuant to this Section 2.08(e) to reimburse any Issuer for any Letter of Credit Disbursement (other than the funding of ABR Loans as contemplated above) shall not constitute a Loan and shall not relieve the Borrower of its obligation to reimburse such Letter of Credit Disbursement. Any Letter of Credit Disbursement not reimbursed by the Borrower or funded as a Loan prior to 2:00 p.m., New York time, shall bear interest for such day at the ABR plus the Applicable Margin.

(f) Obligations Absolute. The obligation (a “Reimbursement Obligation”) of the Borrower to reimburse Letter of Credit Disbursements as provided in Section 2.08(e) shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement under any and all circumstances whatsoever and irrespective of (i) any lack of validity or enforceability of any Letter of Credit, any Letter of Credit Agreement or this Agreement, or any term or provision therein, (ii) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect, (iii) payment by any Issuer under a Letter of Credit issued by such Issuer against presentation of a draft or other document that does not comply with the terms of such Letter of Credit or any Letter of Credit Agreement, or (iv) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 2.08(f), constitute a legal or equitable discharge of, or provide a right of setoff against, the Borrower’s obligations hereunder. Neither the Administrative Agent, the Lenders nor any Issuer, nor any of their Related Parties shall have any liability or responsibility by reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or failure to make any payment thereunder (irrespective of any of the circumstances referred to in the preceding sentence), or any error, omission, interruption, loss or delay in transmission or delivery of any draft, notice or other communication under or relating to any Letter of Credit (including any document required to make a drawing thereunder), any error in interpretation of technical terms or any consequence arising from causes beyond the control of any Issuer; provided that the foregoing shall not be construed to excuse any Issuer from liability to the Borrower to the extent of any direct damages (as opposed to consequential damages, claims in respect of which are hereby waived by the Borrower to the extent permitted by

applicable law) suffered by the Borrower that are caused by such Issuer’s failure to exercise commercially reasonable care when issuing Letters of Credit and determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof or suffered by Borrower as a result of Issuer’s gross negligence or willful misconduct. The parties hereto expressly agree that, in the absence of gross negligence or willful misconduct on the part of any Issuer (as finally determined by a court of competent jurisdiction), such Issuer shall be deemed to have exercised all requisite care in each such determination. In furtherance of the foregoing and without limiting the generality thereof, the parties agree that, with respect to documents presented which appear on their face to be in substantial compliance with the terms of a Letter of Credit, the Issuer that issued such Letter of Credit may, in its sole discretion, either accept and make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit.

(g) Disbursement Procedures. Each Issuer shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit issued by such Issuer. Such Issuer shall promptly notify the Administrative Agent and the Borrower by telephone (confirmed by telecopy) of such demand for payment and whether such Issuer has made or will make a Letter of Credit Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve the Borrower of its obligation to reimburse such Issuer and the Lenders with respect to any such Letter of Credit Disbursement.

(h) Interim Interest. If any Issuer shall make any Letter of Credit Disbursement, then, until the Borrower shall have reimbursed such Issuer for such Letter of Credit Disbursement (either with its own funds or a Borrowing under Section 2.08(e)), the unpaid amount thereof shall bear interest, for each day from and including the date such Letter of Credit Disbursement is made to but excluding the date that the Borrower reimburses such Letter of Credit Disbursement, at the rate per annum then applicable to ABR Loans. Interest accrued pursuant to this Section 2.08(h) shall be for the account of such Issuer, except that interest accrued on and after the date of payment by any Lender pursuant to Section 2.08(e) to reimburse such Issuer shall be for the account of such Lender to the extent of such payment.

(i) Replacement of an Issuer. Any Issuer may be replaced or resign at any time by written agreement among the Borrower, the Administrative Agent, such resigning or replaced Issuer and, in the case of a replacement, the successor Issuer. The Administrative Agent shall notify the Lenders of any such resignation or replacement of an Issuer. At the time any such resignation or replacement shall become effective, the Borrower shall pay all unpaid fees accrued for the account of the resigning or replaced Issuer pursuant to Section 3.04(b). In the case of the replacement of an Issuer, from and after the effective date of such replacement, (i) the successor Issuer shall have all the rights and obligations of the replaced Issuer under this Agreement with respect to Letters of Credit to be issued thereafter and (ii) references herein to “Issuer” shall be deemed to refer to such successor or to any previous Issuer, or to such successor and all previous Issuers, as the context shall require. After the resignation or replacement of an Issuer hereunder, the resigning or replaced Issuer shall remain a party hereto and shall continue to have all the rights and obligations of an Issuer under this Agreement with respect to Letters of Credit issued by it prior to such resignation or replacement, but shall not be required to issue additional Letters of Credit.

(j) Cash Collateralization. If (i) any Event of Default shall occur and be continuing and the Borrower receives notice from the Administrative Agent or the Required Lenders demanding the deposit of cash collateral pursuant to this Section 2.08(j), or (ii) the Borrower is required to pay to the Administrative Agent the excess attributable to a Letter of Credit Exposure in connection with any prepayment pursuant to Section 3.03(c), then the Borrower shall deposit, in an account with the Administrative Agent), in the name of the Administrative Agent and for the benefit of the Lenders (such account, the “Cash Collateral Account”, an amount in cash equal to, in the case of an Event of Default, the Letter of Credit Exposure, and in the case of a payment required by Section 3.03(c), the amount of such excess as provided in Section 3.03(c), as of such date plus any accrued and unpaid interest thereon; provided that the obligation to deposit such cash collateral shall become effective immediately, and such deposit shall become immediately due and payable, without demand or other notice of any kind, upon the occurrence of any Event of Default with respect to the Borrower or any of its Subsidiaries described in Section 10.01(h) or Section 10.01(i). The Borrower hereby grants to the Administrative Agent, for the benefit of each Issuer and the Lenders, an exclusive first priority and continuing perfected security interest in and Lien on such account and all cash, checks, drafts, certificates and instruments, if any, from time to time deposited or held in such account, all deposits or wire transfers made thereto, any and all investments purchased with funds deposited in such account, all interest, dividends, cash, instruments, financial assets and other Property from time to time received, receivable or otherwise payable in respect of, or in exchange for, any or all of the foregoing, and all proceeds, products, accessions, rents, profits, income and benefits therefrom, and any substitutions and replacements therefor. The Borrower’s obligation to deposit amounts pursuant to this Section 2.08(j) shall be absolute and unconditional, without regard to whether any beneficiary of any such Letter of Credit has attempted to draw down all or a portion of such amount under the terms of a Letter of Credit, and, to the fullest extent permitted by applicable law, shall not be subject to any defense or be affected by a right of set-off, counterclaim or recoupment which the Borrower or any of its Subsidiaries may now or hereafter have against any such beneficiary, any Issuing Bank, the Administrative Agent, the Lenders or any other Person for any reason whatsoever. Such deposit shall be held as collateral securing the payment and performance of the Borrower’s and any Guarantor’s obligations under this Agreement and the other Loan Documents. The Administrative Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over such account; provided that investments of funds in such account in investments permitted by Section 9.05(c) or (e) may be made at the option of the Borrower at its direction, risk and expense. Interest or profits, if any, on such investments shall accumulate in such account. Moneys in such account shall be applied by the Administrative Agent to reimburse, on a pro rata basis, each Issuer for Letter of Credit Disbursements for which it has not been reimbursed and, to the extent not so applied, shall be held for the satisfaction of the reimbursement obligations of the Borrower for the Letter of Credit Exposure at such time or, if the maturity of the Loans has been accelerated, be applied to satisfy other obligations of the Borrower and the Guarantors, if any, under this Agreement or the other Loan Documents. If the Borrower is required to provide an amount of cash collateral hereunder as a result of the occurrence of an Event of Default, and the Borrower is not otherwise required to pay to the Administrative Agent the excess attributable to a Letter of Credit Exposure in connection with any prepayment pursuant to Section 3.03(c), then such amount (to the extent not applied as aforesaid) shall be returned to the Borrower within three Business Days after all Events of Default have been cured or waived.

ARTICLE III

PAYMENTS OF PRINCIPAL AND INTEREST; PREPAYMENTS; FEES

Section 3.01 Repayment of Loans . The Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each Lender the then unpaid principal amount of each Loan on the Termination Date.

Section 3.02 Interest.

(a) ABR Loans. Each ABR Loan comprising an ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Margin, but in no event to exceed the Highest Lawful Rate.

(b) Eurodollar Loans. Each Eurodollar Loan comprising a Eurodollar Borrowing shall bear interest at the LIBO Rate for the Interest Period in effect for such Eurodollar Loan plus the Applicable Margin, but in no event to exceed the Highest Lawful Rate.

(c) Post-Default and Borrowing Base Deficiency Rate. Notwithstanding the foregoing, (i) if an Event of Default has occurred and is continuing, or if any principal of or interest on any Loan or any fee or other amount payable by the Borrower or any Guarantor hereunder or under any other Loan Document is not paid when due (after giving effect to any applicable grace period) whether at stated maturity, upon acceleration or otherwise, and including any payments in respect of a Borrowing Base Deficiency under Section 3.03(c), then all Loans outstanding, in the case of an Event of Default, and such overdue amount, in the case of a failure to pay amounts when due, shall bear interest, after as well as before judgment, at the Alternate Base Rate plus two percent (2%), but in no event to exceed the Highest Lawful Rate, and (ii) following Administrative Agent’s notice of any Borrowing Base Deficiency pursuant to Section 3.03(c), the amount of such Borrowing Base Deficiency shall bear interest, after as well as before judgment, at the rate then applicable to such Loans, plus the Applicable Margin, if any, plus an additional two percent (2%), but in no event to exceed the Highest Lawful Rate.

(d) Interest Payment Dates. Accrued interest on each Loan shall be payable in arrears on: (i) with respect to any ABR Loan, the last day of each March, June, September and December; (ii) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and (iii) in any case, on the Termination Date; provided that (x) interest accrued pursuant to Section 3.02(c)(i) shall be payable on demand, (y) in the event of any repayment or prepayment of any Loan (other than an optional prepayment of an ABR Loan prior to the Termination Date), accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment, and (z) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e) Interest Rate Computations. All interest hereunder shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), except that interest computed by reference to the Alternate Base Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day). The applicable Alternate Base Rate or LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error, and be binding upon the parties hereto.

Section 3.03 Prepayments.

(a) Optional Prepayments. The Borrower shall have the right at any time and from time to time to prepay any Borrowing in whole or in part, subject to prior notice in accordance with Section 3.03(b).

(b) Notice and Terms of Optional Prepayment. The Borrower shall notify the Administrative Agent by telephone (confirmed by telecopy) of any prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than 1:00 pm, New York time, three Business Days before the date of prepayment, or (ii) in the case of prepayment of an ABR Borrowing, not later than 1:00 pm, New York time, one Business Day before the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Borrowing or portion thereof to be prepaid. Promptly following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise the Lenders of the contents thereof. Each partial prepayment of any Borrowing shall be in an amount that would be permitted in the case of an advance of a Borrowing of the same Type as provided in Section 2.02. Each prepayment of a Borrowing shall be applied ratably to the Loans included in the prepaid Borrowing. Prepayments shall be accompanied by accrued interest to the extent required by Section 3.02.

(i) Borrowing Base Deficiency. If a Borrowing Base Deficiency exists, then the Administrative Agent shall give the Borrower and the Lenders prompt written notice thereof. The Borrower shall, within ten (10) days after receipt of written notice of such condition from the Administrative Agent elect by written notice to the Administrative Agent to take one or more of the following actions to remedy the Borrowing Base deficiency:

(A) prepay Advances or, if the Advances have been repaid in full, Cash Collateralize the Letter of Credit Exposure in an aggregate amount equal to such deficiency within ten (10) days after the Borrower’s written election;

(B) add additional Oil and Gas Properties acceptable to the Administrative Agent, in its sole discretion, to the Borrowing Base such that the Borrowing Base Deficiency is cured within thirty (30) days after the Borrower’s written election; or

(C) pay the Borrowing Base Deficiency in three equal monthly installments for the prepayment of the Advances or, if the Advances have been repaid in full, make deposits into the Cash Collateral Account to provide cash collateral for the Letter of Credit Exposure such that the Borrowing Base Deficiency is eliminated in a period of three months, by irrevocably dedicating a portion of the monthly cash flow from the Borrower’s and its Subsidiaries’ Oil and Gas Properties to the prepayment of Advances or, if the Advances have been repaid in full, making deposits into the Cash Collateral Account to provide cash collateral for the Letter of Credit Exposure.

(ii) Reduction of Commitments. On the date of each reduction of the aggregate Maximum Credit Amounts pursuant to Section 2.06, the Borrower agrees to make a prepayment in respect of the outstanding amount of the Advances to the extent, if any, that the aggregate unpaid principal amount of all Advances plus the Letter of Credit Exposure exceeds the lesser of (A) the aggregate Maximum Credit Amounts, as so reduced and (B) the Borrowing Base.

(iii) Accrued Interest. Each prepayment under this Section 3.03(c) shall be accompanied by accrued interest on the amount prepaid to the date of such prepayment and amounts, if any, required to be paid pursuant to Section 5.02 as a result of such prepayment.

(d) No Premium or Penalty. Prepayments permitted or required under this Section 3.03 shall be without premium or penalty, except as required under Section 5.02.

Section 3.04 Fees.

(a) Commitment Fees. The Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee, which shall accrue at a rate per annum equal to the Commitment Fee Rate on the average daily amount of the unused amount of the Loan Commitment of such Lender during the period from and including the date of this Agreement to but excluding the Termination Date (the face amount of any issued and outstanding Letter of Credit shall count as usage for purposes hereof). Accrued commitment fees shall be payable in arrears on the last day of March, June, September and December of each year and on the Termination Date, commencing on the first such date to occur after the date hereof. All commitment fees shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(b) Letter of Credit Fees. The Borrower agrees to pay (i) to the Administrative Agent for the account of each Lender a participation fee with respect to its participations in Letters of Credit, which shall accrue at the same Applicable Margin used to determine the interest rate applicable to Eurodollar Loans on the average daily amount of such Lender’s Letter

of Credit Exposure (excluding any portion thereof attributable to unreimbursed Letter of Credit Disbursements) during the period from and including the date of this Agreement to but excluding the later of the date on which such Lender’s Commitment terminates and the date on which such Lender ceases to have any Letter of Credit Exposure; and (ii) to each Issuer, for its own account, its standard fees with respect to the amendment, renewal or extension of any Letter of Credit issued by such Issuer or processing of drawings thereunder. Participation fees accrued through and including the last day of March, June, September and December of each year shall be payable on the third Business Day following such last day, commencing on the first such date to occur after the date of this Agreement. Any other fees payable to an Issuer pursuant to this Section 3.04(b) shall be payable within 10 days after demand. All participation fees and fronting fees shall be computed on the basis of a year of 360 days, unless such computation would exceed the Highest Lawful Rate, in which case such fees shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and shall be payable for the actual number of days elapsed (including the first day but excluding the last day).

(c) Administrative Agent Fees. The Borrower agrees to pay to the Administrative Agent, for its own account, fees payable in the amounts and at the times separately agreed upon between the Borrower and the Administrative Agent.

ARTICLE IV

PAYMENTS; PRO RATA TREATMENT; SHARING OF SET-OFFS.

Section 4.01 Payments Generally; Pro Rata Treatment; Sharing of Set-offs.

(a) Payments by the Borrower. The Borrower shall make each payment required to be made by it hereunder (whether of principal, interest, fees or reimbursement of Letter of Credit Disbursements, or of amounts payable under Section 5.01, Section 5.02, Section 5.03 or otherwise) prior to 2:00 p.m., New York time, on the date when due (after giving effect to applicable grace periods) , in immediately available funds, without defense, deduction, recoupment, set-off or counterclaim. Fees, once paid, shall be fully earned and shall not be refundable under any circumstances. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the Administrative Agent at its offices specified in Section 12.01, except payments to be made directly to an Issuer as expressly provided herein and except that payments pursuant to Section 5.01, Section 5.02, Section 5.03 and Section 12.03 shall be made directly to the Persons entitled thereto. The Administrative Agent shall distribute any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof. If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments hereunder shall be made in dollars.

(b) Application of Insufficient Payments. If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, unreimbursed Letter of Credit Disbursements, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among

the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal and unreimbursed Letter of Credit Disbursements then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal and unreimbursed Letter of Credit Disbursements then due to such parties.

(c) Sharing of Payments by Lenders. If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans or participations in Letter of Credit Disbursements resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and participations in Letter of Credit Disbursements and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans and participations in Letter of Credit Disbursements of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans and participations in Letter of Credit Disbursements; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this Section 4.01(c) shall not be construed to apply to any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans or participations in Letter of Credit Disbursements to any assignee or participant, other than to the Borrower or any Consolidated Subsidiary thereof (as to which the provisions of this Section 4.01(c) shall apply). The Borrower consents to the foregoing and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

Section 4.02 Presumption of Payment by the Borrower. Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders or any Issuer that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders or such Issuer, as the case may be, the amount due. In such event, if the Borrower has not in fact made such payment, then each of the Lenders or such Issuer, as the case may be, severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender or such Issuer with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

Section 4.03 Certain Deductions by the Administrative Agent. If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.05(b), Section 2.08(d), Section 2.08(e) or Section 4.02 then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are fully paid.

ARTICLE V

INCREASED COSTS; BREAK FUNDING PAYMENTS; TAXES; ILLEGALITY

Section 5.01 Increased Costs.

(a) Eurodollar Changes in Law. If any Change in Law shall:

(i) impose, modify or deem applicable any reserve (including marginal, special, emergency or supplemental reserves), special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender for Eurocurrency liabilities under Regulation D of the Board (as the same may be amended, supplemented or replaced from time to time) or otherwise; or

(ii) impose on any Lender or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan) or to reduce the amount of any sum received or receivable by such Lender (whether of principal, interest or otherwise), then the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

(b) Capital Requirements. If any Lender or any Issuer determines that any Change in Law regarding capital requirements has or would have the effect of reducing the rate of return on such Lender’s or such Issuer’s capital or on the capital of such Lender’s or such Issuer’s holding company, if any, as a consequence of this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by such Issuer, to a level below that which such Lender or such Issuer or such Lender’s or such Issuer’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or such Issuer’s policies and the policies of such Lender’s or such Issuer’s holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender or such Issuer, as the case may be, such additional amount or amounts as will compensate such Lender or such Issuer or such Lender’s or such Issuer’s holding company for any such reduction suffered.

(c) Certificates. A certificate of a Lender or any Issuer setting forth in reasonable detail the basis of its request and the amount or amounts necessary to compensate such Lender or such Issuer or its holding company, as the case may be, as specified in Section 5.01(a) or (b) shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender or such Issuer, as the case may be, the amount shown as due on any such certificate within 10 days after receipt thereof.

(d) Effect of Failure or Delay in Requesting Compensation. Failure or delay on the part of any Lender or any Issuer to demand compensation pursuant to this Section 5.01 shall not constitute a waiver of such Lender’s or such Issuer’s right to demand such compensation, provided that no Lender may make any such demand more than 180 days after the Termination Date, nor for any amount which has accrued more than 270 days prior to such Lender or Issuer delivering the certificate required in Section 5.01(c).

Section 5.02 Break Funding Payments. In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan into an ABR Loan other than on the last day of the Interest Period applicable thereto, or (c) the failure to borrow, convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto, then, in any such event, the Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), over (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the eurodollar market.

A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section 5.02 shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.

Section 5.03 Taxes.

(a) Payments Free of Taxes. Any and all payments by or on account of any obligation of the Borrower or any Guarantor under any Loan Document shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if the Borrower or any Guarantor shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 5.03(a)), the Administrative Agent, Lender or Issuer (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower or such Guarantor shall make such deductions and (iii) the Borrower or such Guarantor shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

(b) Payment of Other Taxes by the Borrower. The Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c) Indemnification by the Borrower. The Borrower shall indemnify the Administrative Agent, each Lender and each Issuer, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent, such Lender or such Issuer, as the case may be, on or with respect to any payment by or on account of any obligation of the Borrower hereunder (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section 5.03) and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate of the Administrative Agent, a Lender or an Issuer as to the basis of such Indemnified Taxes and Other Taxes and the amount of such payment or liability under this Section 5.03 shall be delivered to the Borrower and shall be conclusive absent manifest error.

(d) Evidence of Payments. As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the Borrower or a Guarantor to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e) Foreign Lenders. Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which the Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement or any other Loan Document shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by the Borrower as will permit such payments to be made without withholding or at a reduced rate.

Section 5.04 Designation of Different Lending Office. If any Lender requests compensation under Section 5.01, or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 5.03, then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (a) would eliminate or reduce amounts payable pursuant to Section 5.01 or Section 5.03, as the case may be, in the future and (b) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

Section 5.05 Illegality. Notwithstanding any other provision of this Agreement, in the event that it becomes unlawful for any Lender or its applicable lending office to honor its obligation to make or maintain Eurodollar Loans either generally or having a particular Interest Period hereunder, then (a) such Lender shall promptly notify the Borrower and the Administrative Agent thereof and such Lender’s obligation to make such Eurodollar Loans shall be suspended (the “Affected Loans”) until such time as such Lender may again make and maintain such Eurodollar Loans and (b) all Affected Loans which would otherwise be made by

such Lender shall be made instead as ABR Loans (and, if such Lender so requests by notice to the Borrower and the Administrative Agent, all Affected Loans of such Lender then outstanding shall be automatically converted into ABR Loans on the date specified by such Lender in such notice) and, to the extent that Affected Loans are so made as (or converted into) ABR Loans, all payments of principal which would otherwise be applied to such Lender’s Affected Loans shall be applied instead to its ABR Loans.

Section 5.06 Replacement of a Lender. If any Lender (an “Affected Lender”) (a) makes a demand upon the Borrower for amounts pursuant to Section 5.01 (and the payment of such amounts are, and are likely to continue to be, materially more onerous in the reasonable judgment of the Borrower than with respect to the other Lenders) or (b) in connection with any proposed increase in the Borrowing Base pursuant to Section 2.07 refuses to consent to such increase, the Borrower may, within 30 days of receipt by the Borrower of such demand, give notice (a “Replacement Notice”) in writing to the Administrative Agent and such Affected Lender of its intention to cause such Affected Lender to sell all of its Loans, Loan Commitments and/or Notes to an Eligible Assignee (a “Replacement Lender”) designated in such Replacement Notice; provided, however, that no Replacement Notice may be given by the Borrower and no Lender may be replaced pursuant to this Section 5.06 if (i) such replacement conflicts with any applicable law or regulation, (ii) any Event of Default shall have occurred and be continuing at the time of such replacement or (iii) prior to any such replacement, such Affected Lender shall have taken any necessary action under Section 5.04 (if applicable) so as to eliminate the continued need for payment of amounts owing pursuant to Section 5.01 or shall have waived its right to payment of the specific amounts that give rise or would give rise to such Replacement Notice (it being understood for sake of clarity that the Affected Lender shall be under no obligation to waive such rights to payment and that such Affected Lender, if it is replaced in accordance with this Section 5.06, shall be entitled to be reimbursed for all breakage losses in connection with such replacement). If the Administrative Agent shall, in the exercise of its reasonable discretion and within 30 days of its receipt of such Replacement Notice, notify the Borrower and such Affected Lender in writing that the Replacement Lender is satisfactory to the Administrative Agent (such consent not being required where the Replacement Lender is already a Lender or an Affiliate of a Lender or an Eligible Assignee), then such Affected Lender shall, subject to the payment of any amounts due pursuant to Section 5.02, assign, in accordance with Section 12.04, all of its Loan Commitments, Loans, Notes (if any), and other rights and obligations under this Agreement and all other Loan Documents (including Reimbursement Obligations, if applicable) designated in the replacement notice to such Replacement Lender; provided, however, that (A) such assignment shall be without recourse, representation or warranty and shall be on terms and conditions reasonably satisfactory to such Affected Lender and such Replacement Lender, (B) the purchase price paid by such Replacement Lender shall be in the amount of such Affected Lender’s Loans designated in the Replacement Notice, and/or its Percentage of outstanding Reimbursement Obligations, as applicable, together with all accrued and unpaid interest and fees in respect thereof, plus all other amounts (including the amounts demanded and unreimbursed under Section 5.01) and (C) the Borrower shall pay to the Affected Lender and the Administrative Agent all reasonable out-of-pocket expenses incurred by the Affected Lender and the Administrative Agent in connection with such assignment and assumption (including the processing fees described in Section 12.04). If the Administrative Agent fails to notify Borrower within 30 days of its receipt of such Replacement Notice that such Replacement Lender is satisfactory, then such Replacement Lender shall be deemed satisfactory

to the Administrative Agent. Upon the effective date of an assignment described above, the Replacement Lender shall become a “Lender” for all purposes under the Loan Documents. Each Lender hereby grants to the Administrative Agent an irrevocable power of attorney (which power is coupled with an interest) to execute and deliver, on behalf of such Lender as assignor, any assignment agreement necessary to effectuate any assignment of such Lender’s interests hereunder in the circumstances contemplated by this Section 5.06.

ARTICLE VI

CONDITIONS PRECEDENT

Section 6.01 Closing Date. The obligations of the Lenders to make the initial Loans and of any Issuer to issue Letters of Credit in connection with the initial Borrowing hereunder shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 12.02), and the Lenders and the Issuer agree that each of the following conditions have been satisfied or waived as of the Closing Date:

(a) The Arranger, the Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the Closing Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder.

(b) The Administrative Agent shall have received a certificate of the Borrower and of each Guarantor setting forth (i) resolutions of the Managers, board of directors or other managing body with respect to the authorization of the Borrower or such Guarantor to execute and deliver the Loan Documents to which it is a party and to enter into the transactions contemplated in those documents, (ii) the individuals who are authorized to sign the Loan Documents to which the Borrower or such Guarantor is a party, (iii) specimen signatures of such authorized individuals, and (iv) the articles or certificate of incorporation or formation and bylaws, operating agreement or partnership agreement, as applicable, of the Borrower and each Guarantor, in each case, certified as being true and complete. The Administrative Agent and the Lenders may conclusively rely on such certificate until the Administrative Agent receives notice in writing from the Borrower to the contrary.

(c) The Administrative Agent shall have received certificates of the appropriate State agencies with respect to the existence, qualification and good standing of the Borrower and each Guarantor.

(d) The Administrative Agent shall have received a compliance certificate which shall be substantially in the form of Exhibit B, duly and properly executed by a Responsible Officer and dated as of the Closing Date.

(e) The Administrative Agent shall have received from each party hereto counterparts (in such number as may be requested by the Administrative Agent) of this Agreement signed on behalf of such party.

(f) The Administrative Agent shall have received duly executed Notes payable to the order of each Lender in a principal amount equal to its Maximum Credit Amount dated as of the date hereof.

(g) The Administrative Agent shall have received from each party thereto duly executed counterparts (in such number as may be requested by the Administrative Agent) of the Security Instruments, including the Guarantee Agreement and the other Security Instruments described on Exhibit C-1. In connection with the execution and delivery of the Security Instruments, the Administrative Agent shall be reasonably satisfied that the Security Instruments create first priority, perfected Liens (subject only to Excepted Liens) on at least 85% of the total value of the Oil and Gas Properties evaluated in the Initial Reserve Report.

(h) No event or circumstance that could cause a Material Adverse Effect shall have occurred.

(i) The Administrative Agent shall be satisfied in its sole discretion with the title to the Oil and Gas Properties included in the Borrowing Base.

(j) The Administrative Agent shall have received an opinion of (i) Andrews Kurth LLP, special New York counsel to the Borrower and Watson, Degraffenried & Tyra, LLP, special Alabama counsel to the Borrower, each, in form and substance satisfactory to the Administrative Agent, as to such matters incident to the Transactions as the Administrative Agent may reasonably request.

(k) An environmental consultant satisfactory to Administrative Agent will deliver to Lenders an environmental review satisfactory in form and substance to Administrative Agent in its sole discretion.

(l) The Administrative Agent shall have received a copy of the Initial Reserve Report.

(m) The Administrative Agent shall have received a certificate of insurance coverage of the Borrower evidencing that the Borrower is carrying insurance in accordance with Section 7.12.

(n) The Administrative Agent shall have received the Financial Statements.

(o) The Administrative Agent shall have received the annual financial and operational projections for the Borrower, by month, for the twelve month period immediately following the Closing Date prepared in good faith based on available information and estimates determined to be reasonable at the time such projections were prepared.

(p) The Administrative Agent shall have received a pro forma consolidated balance sheet of the Borrower as of the Closing Date prepared after giving effect to the Transaction as if the Transaction had occurred as of such date, which balance sheet shall be in form and substance reasonably acceptable to the Administrative Agent.

(q) The Administrative Agent shall have received appropriate UCC search certificates reflecting no prior Liens encumbering the Properties, the Borrower, and its Subsidiaries for each of the following jurisdictions: Alabama, Delaware and any other jurisdiction requested by the Administrative Agent; other than those being assigned or released on or prior to the Closing Date or Liens permitted by Section 9.03.

(r) There are no unpaid bills for improvements or services to the Properties operated by Borrower that could give rise to mechanic’s or materialmen’s liens or any other similar encumbrance arising by operation of applicable law.

(s) No suit or other proceeding is pending or threatened before any court or governmental agency seeking to restrain, enjoin or prohibit or declare illegal, or seeking damages from Borrower in connection with the transactions contemplated in this Agreement or alleging the breach of any material contract of the Borrower or any Guarantor.

(t) The Administrative Agent is satisfied, in its sole discretion, with the results of its due diligence examination of Borrower and the Properties, including Borrower’s proposed development of the Properties, the location discount/premium and transportation costs for all Hydrocarbons produced on the Properties, existing Hydrocarbon sales, the terms of the Management Services Agreement and all aspects of Borrower’s existing and contemplated Hydrocarbon marketing activities.

(u) The Administrative Agent shall have received such other documents as the Administrative Agent or special counsel to the Administrative Agent may reasonably request.

Section 6.02 Each Credit Event. The obligation of each Lender to make a Loan on the occasion of any Borrowing (including the initial funding), and of each Issuer to issue, amend, renew or extend any Letter of Credit, is subject to the satisfaction of the following conditions:

(a) At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, no Default shall have occurred and be continuing.

(b) At the time of and immediately after giving effect to such Borrowing or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, no Material Adverse Effect shall have occurred.

(c) The representations and warranties of the Borrower and the Guarantors, if any, set forth in this Agreement and in the other Loan Documents shall be true and correct on and as of the date of such Borrowing or the date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case such representations and warranties shall have been true and correct as of such specified earlier date.

(d) The making of such Loan or the issuance, amendment, renewal or extension of such Letter of Credit, as applicable, would not conflict with, or cause any Lender or any Issuer to violate or exceed, any applicable Governmental Requirement, and no Change in Law shall have occurred, and no litigation shall be pending or threatened, which does or, with respect to

any threatened litigation, seeks to, enjoin, prohibit or restrain, the making or repayment of any Loan, the issuance, amendment, renewal, extension or repayment of any Letter of Credit or any participations therein or the consummation of the transactions contemplated by this Agreement or any other Loan Document.

(e) The receipt by the Administrative Agent of a Borrowing Request in accordance with Section 2.03 or a request for a Letter of Credit in accordance with Section 2.08(b), as applicable.

(f) The receipt by the Administrative Agent of an executed copy of the Management Services Agreement, such copy to be certified by a Responsible Officer of the Borrower to be true, correct and complete.

Each request for a Borrowing and each issuance, amendment, renewal or extension of any Letter of Credit shall be deemed to constitute a representation and warranty by the Borrower on the date thereof as to the matters specified in Section 6.02(a) through (e).

ARTICLE VII

REPRESENTATIONS AND WARRANTIES

The Borrower represents and warrants to the Lenders that:

Section 7.01 Organization; Powers. Each of the Borrower and its Consolidated Subsidiaries is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has all requisite power and authority to own its assets and to carry on its business as now conducted, and is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required, except where failure to have such power, authority and qualifications could not reasonably be expected to have a Material Adverse Effect.

Section 7.02 Authority; Enforceability. The Transactions are within the Borrower’s and each Guarantor’s limited liability company powers and have been duly authorized by all necessary limited liability company and, if required, member action (including, without limitation, any action required to be taken by any class of directors of the Borrower or any other Person, whether interested or disinterested, in order to ensure the due authorization of the Transactions). When executed and delivered, each Loan Document to which the Borrower and any Guarantor is a party will have been duly executed and delivered by the Borrower and such Guarantor and will constitute a legal, valid and binding obligation of the Borrower and such Guarantor, as applicable, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

Section 7.03 Approvals; No Conflicts. The Transactions (a) do not require any consent, license, or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including the members or any class of directors of the Borrower or any other Person, whether interested or disinterested), except such as have been

obtained or made and are in full force and effect, and except for the filing and recording of Security Instruments to perfect the Liens created by such Security Instruments, (b) will not violate any applicable law or regulation or the charter, by-laws or other organizational documents of the Borrower or any of the Guarantors or any order of any Governmental Authority, (c) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or any of the Guarantors or their Properties, or give rise to a right thereunder to require any payment to be made by the Borrower or any of the Guarantors and (d) will not result in the creation or imposition of any Lien on any Property of the Borrower or any of the Guarantors (other than the Liens created by the Loan Documents). The Borrower and each of the Guarantors has obtained all consents, licenses and approvals required in connection with the execution, delivery and performance by the Borrower and the Guarantors and the validity against the Borrower and each of the Guarantors of the Loan Documents to which it is a party, and such consents, licenses and approvals are in full force and effect.

Section 7.04 Financial Statements.

(a) The Borrower has delivered to the Administrative Agent and the Lenders the Financial Statements, and the Financial Statements are correct and complete in all material respects and present fairly the consolidated financial condition of the Borrower and its Consolidated Subsidiaries as of their respective dates and for their respective periods in accordance with GAAP, applied on a consistent basis.

(b) Since June 30, 2006, (i) there has been no event, development or circumstance that has had or could reasonably be expected to have a Material Adverse Effect and (ii) the business of the Borrower and its Subsidiaries has been conducted only in the ordinary course consistent with past business practices.

Section 7.05 Litigation. Except as set forth on Schedule 7.05, there are no actions, suits, investigations or proceedings by or before any arbitrator or Governmental Authority pending against or, to the knowledge of the Borrower, threatened against or affecting the Borrower or any of its Subsidiaries (a) which could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect or (b) that involve any Loan Document or the Transactions. Since the date of this Agreement, there has been no change in the status of the matters disclosed in Schedule 7.05 that, individually or in the aggregate, has resulted in, or could reasonably be expected to result in a Material Adverse Effect.

Section 7.06 Environmental Matters. Except as could not be reasonably expected to have a Material Adverse Effect (or with respect to (c), (d) and (e) below, where the failure to take such actions could not be reasonably expected to have a Material Adverse Effect):

(a) neither any Property of the Borrower or any of its Consolidated Subsidiaries nor the operations conducted thereon violate any order or requirement of any court or Governmental Authority or any Environmental Laws.

(b) no Property of the Borrower or any of its Consolidated Subsidiaries nor the operations currently conducted thereon or, to the knowledge of the Borrower, by any prior owner or operator of such Property or operation, are in violation of or subject to any existing, pending or threatened action, suit, investigation, inquiry or proceeding by or before any court or Governmental Authority or to any remedial obligations under Environmental Laws.

(c) all notices, permits, licenses, exemptions, approvals or similar authorizations, if any, required to be obtained or filed in connection with the operation or use of any and all Property of the Borrower and each of its Subsidiaries, including, without limitation, past or present treatment, storage, disposal or release of a hazardous substance, oil and gas waste or solid waste into the environment, have been duly obtained or filed or requested, and the Borrower and each of its Consolidated Subsidiaries are in compliance with the terms and conditions of all such notices, permits, licenses and similar authorizations.

(d) the Borrower has taken all steps reasonably necessary to determine and has determined that except as set forth in the S-1 Registration Statement no oil, hazardous substances, solid waste or oil and gas waste, have been disposed of or otherwise released and there has been no threatened release of any oil, hazardous substances, solid waste or oil and gas waste on or to any Property of the Borrower or any of the Guarantors except in compliance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or welfare or the environment.

(e) to the extent applicable, all Property of the Borrower and each of the Guarantors currently satisfies all design, operation, and equipment requirements imposed by the OPA, and the Borrower does not have any reason to believe that such Property, to the extent subject to the OPA, will not be able to maintain compliance with the OPA requirements during the term of this Agreement.

(f) except as set forth in the S-1 Registration Statement, neither the Borrower nor any of its Consolidated Subsidiaries has any known contingent liability or Remedial Work in connection with any release or threatened release of any oil, hazardous substance, solid waste or oil and gas waste into the environment.

Section 7.07 Compliance with the Laws and Agreements. Each of the Borrower and its Consolidated Subsidiaries are in compliance with all Governmental Requirements applicable to it or its Property and all agreements and other instruments binding upon it or its Property, and possesses all licenses, permits, franchises, exemptions, approvals and other authorizations granted by Governmental Authorities necessary for the ownership of its Property and the present conduct of its business, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

Section 7.08 Investment Company Act. Neither the Borrower nor any of its Consolidated Subsidiaries are an “investment company” or a company “controlled” by an “investment company,” within the meaning of, or subject to regulation under, the Investment Company Act of 1940, as amended.

Section 7.09 Taxes. Each of the Borrower and its Consolidated Subsidiaries has timely filed or caused to be filed all Tax returns and reports required to have been filed and has paid or caused to be paid all Taxes required to have been paid by it, except Taxes that are being contested in good faith by appropriate proceedings and for which the Borrower or such

Consolidated Subsidiary, as applicable, has set aside on its books adequate reserves in accordance with GAAP. The charges, accruals and reserves on the books of the Borrower and its Consolidated Subsidiaries in respect of Taxes and other governmental charges are, in the reasonable opinion of the Borrower, adequate. No Tax Lien has been filed and, to the knowledge of the Borrower, no claim is being asserted with respect to any such Tax or other such governmental charge, except for Tax Liens or claims that could not reasonably be expected to have a Material Adverse Effect.

Section 7.10 ERISA.

(a) The Borrower and its Consolidated Subsidiaries have complied in all material respects with ERISA and, where applicable, the Code regarding each Plan, if any that they maintain.

(b) No act, omission or transaction has occurred that could result in imposition on the Borrower, any of its Subsidiaries or any ERISA Affiliate (whether directly or indirectly) of (i) either a civil penalty assessed pursuant to subsections (c), (i) or (l) of section 502 of ERISA or a tax imposed pursuant to Chapter 43 of Subtitle D of the Code or (ii) breach of fiduciary duty liability damages under section 409 of ERISA.

(c) No Plan (other than a defined contribution plan) or any trust created under any such Plan has been terminated since September 2, 1974. No liability to the PBGC (other than for the payment of current premiums which are not past due) by the Borrower, any of its Subsidiaries or any ERISA Affiliate has been or is expected by the Borrower, any of its Subsidiaries or any ERISA Affiliate to be incurred with respect to any Plan. No ERISA Event with respect to any Plan has occurred.

(d) Full payment when due has been made of all amounts which the Borrower, any of its Subsidiaries or any ERISA Affiliate is required under the terms of each Plan, if any, or applicable law to have paid as contributions to such Plan as of the date hereof, and no accumulated funding deficiency (as defined in section 302 of ERISA and section 412 of the Code), whether or not waived, exists with respect to any Plan.

(e) Each Plan subject to Title IV of ERISA satisfies the minimum funding requirements of Section 412 of the Code and Part 3 of Title I of ERISA.

(f) Neither the Borrower nor its Subsidiaries sponsors or maintains an employee welfare benefit plan, as defined in section 3(1) of ERISA that provides benefits to former employees of such entities.

(g) Neither the Borrower nor its Subsidiaries nor any ERISA Affiliate would be subject to any withdrawal liability under Part 1 of Subtitle E of Title IV of ERISA if the Borrower, its Subsidiaries or any ERISA Affiliate were to engage in a “complete withdrawal” (as defined in Section 4203 of ERISA) or a “partial withdrawal” (as defined in Section 4205 of ERISA) for any Multiemployer Plan.

(h) Neither the Borrower, its Subsidiaries nor any ERISA Affiliate is required to provide security under section 401(a)(29) of the Code due to a Plan amendment that results in an increase in current liability for any Plan.

Section 7.11 Disclosure; No Material Misstatements

(a) The Form S-1 Registration Statement, as amended by Amendment No. thereto, a copy of which has been provided to the Administrative Agent, described, as of the Closing Date, all Material Debt of the Borrower or any of its Consolidated Subsidiaries, and all obligations of the Borrower or any of its Consolidated Subsidiaries to issuers of surety or appeal bonds (other than operator’s bonds, plugging and abandonment bonds, and similar surety obligations obtained in the ordinary course of business) issued for the account of the Borrower or any of its Consolidated Subsidiaries.

(b) As of the Closing Date, none of the reports, Financial Statements, certificates, Reserve Reports or other information furnished by or on behalf of the Borrower or any of its Subsidiaries to the Administrative Agent, in connection with the negotiation of this Agreement or any other Loan Document or delivered hereunder or under any other Loan Document (as modified or supplemented by other information so furnished) contains any material misstatement of fact or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that, with respect to projected financial information, the Borrower represents only that such information was prepared in good faith based upon assumptions believed to be reasonable at the time.

Section 7.12 Insurance. The Borrower has, and has caused each of its Subsidiaries to, maintain, with financially sound and reputable insurance companies, insurance in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations. The loss payable clauses or provisions in said insurance policy or policies insuring any of the collateral for the Loans are endorsed in favor of and made payable to the Administrative Agent as its interests may appear and such policies name the Administrative Agent and the Lenders as “additional insureds” and provide that the insurer will give at least 30 days prior notice of any cancellation to the Administrative Agent.

Section 7.13 Restriction on Liens. Neither the Borrower nor any of the Guarantors is a party to any material agreement or arrangement, or subject to any order, judgment, writ or decree, which either restricts or purports to restrict its ability to grant Liens to the Administrative Agent and the Lenders on or in respect of their Properties to secure the Indebtedness and the Loan Documents.

Section 7.14 Subsidiaries. Except as set forth on Schedule 7.14 or as disclosed in writing to the Administrative Agent (which shall promptly furnish a copy to the Lenders), which shall be a supplement to Schedule 7.14, the Borrower has no Subsidiaries. The Borrower has no Foreign Subsidiaries.

Section 7.15 Location of Business and Offices. The Borrower’s jurisdiction of organization is Delaware; the name of the Borrower as listed in the public records of its jurisdiction of organization is Constellation Energy Partners LLC, and the organizational identification number of the Borrower in its jurisdiction of organization is 3922446 (or, in each case, as set forth in a notice delivered to the Administrative Agent pursuant to Section 8.01(n) in accordance with Section 12.01). The Borrower’s principal place of business and chief executive offices are located at the address specified in Section 12.01 (or as set forth in a notice delivered pursuant to Section 8.01(n) and Section 12.01(c)). Each Subsidiary’s jurisdiction of organization, name as listed in the public records of its jurisdiction of organization, organizational identification number in its jurisdiction of organization, and the location of its principal place of business and chief executive office is stated on Schedule 7.14 (or as set forth in a notice delivered pursuant to Section 8.01(n)).

Section 7.16 Properties; Titles, Etc.

(a) Subject to Excepted Liens, each of the Borrower and Guarantors have good and indefeasible title to all of its Oil and Gas Properties evaluated in the most recently delivered Reserve Report, free and clear of all Liens except for Excepted Liens. The Borrower has good and defensible title to all of the Equity Interests in the Subsidiaries listed on Schedule 7.14, except for Excepted Liens.

(b) The quantum and nature of the interest of the Borrower and Guarantors in and to their Hydrocarbon Interests as set forth in the most recent Reserve Report includes the entire interest of the Borrower and Guarantors in such Hydrocarbon Interests as of the date of such Reserve Report and are complete and accurate in all material respects as of the date of such Reserve Report, and other than the NPI, there are no “back-in” or “reversionary” interests held by third parties which could materially reduce the interest of the Borrower and Guarantors in such Hydrocarbon Interests except as taken into account in such Reserve Report. The Working Interests held by the Borrower and Guarantors in their Oil and Gas Properties shall not in any material respect obligate any of such Persons to bear the costs and expenses relating to the maintenance, development, and operations of such Oil and Gas Properties in an amount in excess of the working interest of such Person in each such Hydrocarbon Interest set forth in the most recent Reserve Report.

(c) All oil and gas leases and instruments and other similar agreements comprising the Borrower’s and its Consolidated Subsidiaries Oil and Gas Properties necessary for the conduct of business of the Borrower and its Consolidated Subsidiaries are valid and subsisting, in full force and effect and there exists no default or event of default or circumstance which with the giving of notice or lapse of time or both would give rise to a default under any such leases, instruments or agreements, in each case which would affect in any material respect the conduct of the business of the Borrower and its Subsidiaries. Neither Borrower, any of the Guarantors nor, to the knowledge of Borrower, any other party to any leases, instruments or agreements comprising its Oil and Gas Properties evaluated in the most recently delivered Reserve Report, has given or threatened to give written notice of any default under or inquiry into any possible default under, or action to alter, terminate, rescind or procure a judicial reformation of, any such lease, instrument or agreement.

(d) All of the Properties of the Borrower and its Consolidated Subsidiaries that are reasonably necessary for the operation of their business are in good repair, working order and condition in all material respects and have been maintained by Borrower and its Consolidated Subsidiaries as is customary in the oil and gas industry. Since the date of the most recent financial statements delivered pursuant to Section 8.01, neither the business nor the Properties of the Borrower and its Consolidated Subsidiaries have been materially and adversely affected as a result of any fire, explosion, earthquake, flood, drought, windstorm, accident, strike or other labor disturbance, embargo, requisition or taking of Property or cancellation of contracts, Permits, or concessions by a Governmental Authority, riot, activities of armed forces, or acts of God or of any public enemy.

(e) Except for Excepted Liens or as otherwise disclosed in writing to the Administrative Agent:

(i) In each case only with respect to any of the Borrower’s and Guarantors’ Oil and Gas Properties that have been assigned a discounted present value equal to or in excess of $2,000,000 in any Reserve Report, (A) all rentals, royalties, overriding royalties, shut-in royalties and other payments due under or with respect to any such Hydrocarbon Interests evaluated in any Reserve Report have been properly and timely paid in the ordinary course of business and (B) all material expenses payable under the terms of the contracts and agreements comprising such Oil and Gas Properties (other than those described above in clause (A)) have been properly and timely paid in the ordinary course of business, except in each case where such payments are being contested in good faith by appropriate proceedings and for which adequate reserves complying with GAAP have been made;

(ii) All of the proceeds from the sale of Hydrocarbons produced from the Borrower’s and its Consolidated Subsidiaries’ Hydrocarbon Interests are being properly and timely paid to the Borrower without suspense, other than the escrow mechanics associated with the Torch Energy Royalty Trust determinations and other than any such proceeds the late payment or non-payment of which could not reasonably be expected to materially adversely affect the value of the Collateral taken as a whole; and

(iii) No material amount of proceeds that has been received by the Borrower or any of its Consolidated Subsidiaries from the sale of Hydrocarbons produced from the Oil and Gas Properties evaluated in the most recently delivered Reserve Report is subject to any claim for any refund or refund obligation.

Section 7.17 Title. As of the Closing Date, the Administrative Agent shall have received title opinions, title reports or other title due diligence reflecting that the Borrower or the Guarantors have title reasonably satisfactory to the Administrative Agent in such Oil and Gas Properties of the Borrower and the Guarantors constituting 85% of the proved, developed, producing Hydrocarbon reserves and proved, developed, nonproducing Hydrocarbon reserves evaluated in the Initial Reserve Report.

Section 7.18 Security Instruments.

(a) The provisions of each of the Pledge Agreements delivered to the Administrative Agent are effective to create in favor of the Administrative Agent, for the ratable benefit of the Lenders, a legal, valid and enforceable security interest in the Pledged Collateral (as defined therein) and proceeds thereof and (i) when certificates, if any, representing or constituting the Pledged Collateral are delivered to the Administrative Agent and (ii) upon the filing of UCC-1 Financing Statements with the secretary of state of each jurisdiction of formation for each of the debtors party thereto, the Pledge Agreements shall constitute a first priority Acceptable Security Interest in, all right, title and interest of the Borrower and Guarantors, as applicable, in such Pledged Collateral and the proceeds thereof, subject to Excepted Liens.

(b) On the Closing Date, the Equity Interests listed on Schedule I to each of the Pledge Agreements will constitute all the issued and outstanding Equity Interests in the direct and indirect Material Domestic Subsidiaries of the Borrower; all such Equity Interests have been duly and validly issued and are fully paid and nonassessable; and the relevant pledgor of said shares is the record and beneficial owner of said shares.

(c) The provisions of the Mortgages will be effective to grant to the Administrative Agent, for the ratable benefit of the Lenders, legal, valid and enforceable mortgage liens on all of the right, title and interest of the Borrower and its Subsidiaries in the mortgaged property to the extent described therein. Once such Mortgages have been recorded in the appropriate recording office and all recording taxes have been paid with respect thereto, the Mortgages will constitute perfected first liens on, and security interest in, such mortgaged property, subject to Excepted Liens.

(d) On the Closing Date, all governmental actions and all other filings, recordings, registrations, third party consents and other actions which are necessary to create and perfect the Liens provided for in the Security Instruments will have been made, obtained and taken in all relevant jurisdictions. No other filings or recordings are required in order to perfect the security interests created under any Security Instruments.

Section 7.19 Maintenance of Properties. Except for such acts or failures to act as could not be reasonably expected to have a Material Adverse Effect, the Oil and Gas Properties (and Properties unitized therewith) have been maintained, operated and developed by the Borrower and the Guarantors in a good and workmanlike manner and in conformity with all Government Requirements and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties. Specifically in connection with the foregoing, except as could not reasonably be expected to have a Material Adverse Effect, (a) no Oil and Gas Property is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) and (b) none of the wells comprising a part of the Oil and Gas Properties (or Properties unitized therewith) is deviated from the vertical more than the maximum permitted by Government Requirements, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties (or in the case of wells located on Properties unitized therewith, such unitized Properties). All pipelines, wells, gas processing plants, platforms and other material improvements, fixtures and

equipment owned in whole or in part by the Borrower or any of its Subsidiaries that are necessary to conduct normal operations are being maintained in a state adequate to conduct normal operations, and with respect to such of the foregoing which are operated by the Borrower or any of its Subsidiaries, in a manner consistent with the Borrower’s or its Subsidiaries’ past practices (other than those the failure of which to maintain in accordance with this Section 7.17 could not reasonably be expect to have a Material Adverse Effect).

Section 7.20 Gas Imbalances, Prepayments. As of the date hereof, except as set forth on Schedule 7.20 or on the most recent certificate delivered pursuant to Section 2.07(c), on a net basis there are no gas imbalances, take or pay or other prepayments which would require the Borrower or any of its Subsidiaries to deliver, in the aggregate, three percent (3%) or more of the monthly production from Hydrocarbons produced from the Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor.

Section 7.21 Marketing of Production. Except for the Gas Purchase Contract and for contracts listed and in effect on the date hereof on Schedule 7.21, and thereafter either disclosed in writing to the Administrative Agent or included in the most recently delivered Reserve Report (with respect to all of which contracts the Borrower represents that it or the Guarantors are receiving a price for all production sold thereunder which is computed substantially in accordance with the terms of the relevant contract and are not having deliveries curtailed substantially below the subject Property’s delivery capacity), no material agreements exist which are not cancelable on 60 days notice or less without penalty or detriment for the sale of production from the Borrower’s or the Guarantors’ Hydrocarbons (including, without limitation, calls on or other rights to purchase, production, whether or not the same are currently being exercised) that pertain to the sale of production at a fixed price.

Section 7.22 Swap Agreements. Schedule 7.22, as of the date hereof, and after the date hereof, each report required to be delivered by the Borrower pursuant to Section 8.01(e), sets forth, a true and complete list of all Swap Agreements of the Borrower and each of its Subsidiaries, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net marked-to-market value thereof, all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.

Section 7.23 Use of Loans and Letters of Credit. The proceeds of the Loans and the Letters of Credit shall be used (a) for the acquisition, exploration, operation, maintenance and development of Oil and Gas Properties and related properties, facilities, rights and interests, (b) for general corporate purposes, including Restricted Payments, provided that if the Borrowing Base Utilization Percentage is equal to or exceeds 90% before or after giving effect to the requested Loan or Letter of Credit, then no proceeds of any Loan or any Letter of Credit may be used to fund Restricted Payments under Section 9.04, (c) for the payment of expenses incurred by the Borrower in connection with the Transactions, (d) to provide working capital, and (d) for the issuance of Letters of Credit. The Borrower and its Subsidiaries are not engaged principally, or as one of its or their important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of buying or carrying margin stock (within the meaning of Regulation T, U or X of the Board). No part of the proceeds of any Loan or Letter of Credit will be used for any purpose which violates the provisions of Regulations T, U or X of the Board.

Section 7.24 Solvency. After giving effect to the transactions contemplated hereby, (a) the aggregate assets (after giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement), at a fair valuation, of the Borrower and the Guarantors, taken as a whole, will exceed the aggregate Debt of the Borrower and the Guarantors on a consolidated basis, as the Debt becomes absolute and matures, (b) each of the Borrower and the Guarantors will not have incurred or intended to incur, and will not believe that it will incur, Debt beyond its ability to pay such Debt (after taking into account the timing and amounts of cash to be received by each of the Borrower and the Guarantors and the amounts to be payable on or in respect of its liabilities, and giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement) as such Debt becomes absolute and matures and (c) each of the Borrower and the Guarantors will not have (and will have no reason to believe that it will have thereafter) unreasonably small capital for the conduct of its business.

ARTICLE VIII

AFFIRMATIVE COVENANTS

Until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents shall have been paid in full and all Letters of Credit shall have expired or terminated and all Letter of Credit Disbursements shall have been reimbursed, the Borrower covenants and agrees with the Lenders that:

Section 8.01 Financial Statements; Ratings Change; Other Information. The Borrower will furnish to the Administrative Agent:

(a) Annual Financial Statements and Annual Budget. As soon as available, but in any event not later than 90 days after the end of each fiscal year, (i) Borrower’s audited consolidated balance sheet and related statements of operations, members’ equity and cash flows as of the end of and for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by independent public accountants of recognized national standing and reasonably acceptable to the Administrative Agent (without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements present fairly in all material respects the financial position and results of operations of the Borrower and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied and (ii) a budget for the then current fiscal year, including a pro forma balance sheet and income and cash flow projections.

(b) Quarterly Financial Statements. As soon as available, but in any event not later than 45 days after the end of each of the first three fiscal quarters of each fiscal year of the Borrower, its consolidated balance sheet and related statements of operations, members’ equity and cash flows as of the end of and for such quarter and the then elapsed portion of the fiscal

year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, all certified by a Financial Officer as presenting fairly in all material respects the financial position and results of operations of the Borrower and its Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes.

(c) Certificate of Financial Officer — Compliance. Concurrently with any delivery of financial statements under Section 8.01(a) or Section 8.01(b), a certificate of a Financial Officer in substantially the form of Exhibit B hereto (i) certifying as to whether a Default has occurred and, if a Default has occurred, specifying the details thereof and any action taken or proposed to be taken with respect thereto, (ii) setting forth reasonably detailed calculations demonstrating compliance with Section 9.01, (iii) stating whether any change in GAAP or in the application thereof has occurred since the Closing Date and, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate, and (iv) setting forth as of the last Business Day of such calendar month or fiscal year, a true and complete list of all Swap Agreements of the Borrower and each of its Consolidated Subsidiaries, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark-to-market value therefor, any new credit support agreements relating thereto not listed on Schedule 7.20, any margin required or supplied under any credit support document, and the counterparty to each such agreement.

(d) Certificate of Accounting Firm — Defaults. Concurrently with any delivery of financial statements under Section 8.01(a), a certificate of the accounting firm that reported on such financial statements stating whether they obtained knowledge during the course of their examination of such financial statements of any Default (which certificate may be limited to the extent required by accounting rules or guidelines).

(e) Certificate of Insurer — Insurance Coverage. Concurrently with any delivery of financial statements under Section 8.01(a), a certificate of insurance coverage from each insurer with respect to the insurance required by Section 8.07, in form and substance satisfactory to the Administrative Agent, and, if requested by the Administrative Agent or any Lender, all copies of the applicable policies.

(f) Other Accounting Reports. Within five Business Days after receipt thereof, a copy of each other written report or letter submitted to the Borrower or any of its Subsidiaries by independent accountants in connection with any annual, interim or special audit made by them of the books of the Borrower or any such Subsidiary, and a copy of any response by the Borrower or any such Subsidiary to such letter or report.

(g) Notices Under Material Instruments. Promptly after the furnishing thereof, copies of any financial statement, report or notice furnished to or by any Person pursuant to the terms of any preferred stock designation, indenture, loan or credit or other similar agreement, other than this Agreement and not otherwise required to be furnished to the Lenders pursuant to any other provision of this Section 8.01.

(h) Lists of Purchasers. Concurrently with the delivery of any Reserve Report to the Administrative Agent pursuant to Section 2.07, a list of all Persons purchasing Hydrocarbons from the Borrower or any of its Subsidiaries.

(i) Notice of Sales of Oil and Gas Properties. In the event the Borrower or any of its Subsidiaries intends to sell, transfer, assign or otherwise dispose of any Oil or Gas Properties included in the most recently delivered Reserve Report (or any Equity Interests in any Subsidiary owning interests in such Oil and Gas Properties) during any period between two successive Scheduled Redetermination Dates having a fair market value, individually or in the aggregate, in excess of $250,000, prior written notice of such disposition, the price thereof, the anticipated date of closing, and any other details thereof requested by the Administrative Agent.

(j) Notice of Swap Liquidation. In the event the Borrower or any of its Subsidiaries intends to liquidate any Swap Agreements having a fair market value, individually or in the aggregate, in excess of $250,000 (any such transaction a “Material Swap Transaction”), prompt (but in any event within five (5) days of such liquidation) written notice of such liquidation and the value thereof, and any other details thereof as requested by the Administrative Agent. In the event that the Borrower or any of its Subsidiaries consummates a Material Swap Transaction as described in the previous sentence, the Borrower shall retain, or cause its Subsidiaries to retain, as applicable, the proceeds of such transaction pending a redetermination of the Borrowing Base in accordance with the provisions of Section 2.07(g); provided that if any redetermination is not commenced within 15 days of such notice, no such retention shall be required.

(k) Notice of Casualty Events. Prompt written notice, and in any event within ten (10) Business Days, of the occurrence of any Casualty Event or the commencement of any action or proceeding that could reasonably be expected to result in a Casualty Event.

(l) Information Regarding Borrower and Guarantors. Prompt written notice (and in any event within ten (10) days prior thereto) of any change (i) in the Borrower or any Guarantor’s corporate name or in any trade name used to identify such Person in the conduct of its business or in the ownership of its Properties, (ii) in the location of the Borrower or any Guarantor’s chief executive office or principal place of business, (iii) in the Borrower or any Guarantor’s identity or corporate structure or in the jurisdiction in which such Person is incorporated or formed, (iv) in the Borrower or any Guarantor’s jurisdiction of organization or such Person’s organizational identification number in such jurisdiction of organization, and (v) in the Borrower or any Guarantor’s federal taxpayer identification number, if any.

(m) Production Report and Lease Operating Statements. Within 45 days after the end of each fiscal quarter, a report setting forth, for each calendar month during the then-current fiscal year to date, the volume of production and sales attributable to production (and the prices at which such sales were made and the revenues derived from such sales) for each such calendar month from the Oil and Gas Properties, and setting forth the related ad valorem, severance and production taxes and lease operating expenses attributable thereto and incurred for each such calendar month.

(n) Notices of Certain Changes. Promptly, but in any event within five (5) Business Days after the execution thereof, copies of any amendment, modification or supplement to the certificate or articles of incorporation, by-laws, any preferred stock designation or any other organizational document of the Borrower or any of the Guarantors.

(o) Dividends. Within fifteen (15) Business Days prior to making any dividend payment permitted pursuant to Section 9.04(c), Borrower shall provide the Administrative Agent with written notice of its intent to make such dividend payment, the amount thereof, and the anticipated date of such payment, together with the certificate of a Financial Officer certifying as to the calculation of Available Cash, including a detailed calculation of the amount of each of the cash and cash equivalents and amount of each of the cash reserves required to derive the amount of Available Cash.

(p) Other Requested Information. Promptly following any request therefor, such other information regarding the operations, business affairs and financial condition of the Borrower or any of its Subsidiaries (including, without limitation, any Plan or Multiemployer Plan and any reports or other information required to be filed under ERISA), or compliance with the terms of this Agreement or any other Loan Document, as the Administrative Agent or any Lender may reasonably request.

Section 8.02 Notices of Material Events. The Borrower will furnish to the Administrative Agent and each Lender, promptly after the Borrower obtains knowledge thereof, written notice of the following:

(a) the occurrence of any Default;

(b) (i) the filing or commencement of, or the threat in writing of, any action, suit, investigation, inquiry, arbitration or proceeding by or before any arbitrator or Governmental Authority against or affecting the Borrower, any Subsidiary thereof or any of their Properties; (ii) any material adverse development in any action, suit, proceeding, investigation or arbitration (whether or not previously disclosed to the Lenders); (iii) any demand or lawsuit by any landowner or other third party threatened in writing against the Borrower, any Subsidiary thereof or any of their Properties in connection with any Environmental Laws (excluding routine testing and corrective action) that, in the case of each of clauses (i) through (iii) of this subsection, if adversely determined, could reasonably be expected to result in liability in excess of $500,000;

(c) the occurrence of any ERISA Event that, alone or together with any other ERISA Events that have occurred, could reasonably be expected to result in liability of the Borrower and its Subsidiaries in an aggregate amount exceeding $500,000; and

(d) any other development that results in, or could reasonably be expected to result in, a Material Adverse Effect.

Each notice delivered under this Section 8.02 shall be accompanied by a statement of a Responsible Officer setting forth the details of the event or development requiring such notice and any action taken or proposed to be taken with respect thereto.

Section 8.03 Existence; Conduct of Business. The Borrower will, and will cause each of its Consolidated Subsidiaries to, do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of its business and maintain, if necessary, its qualification to do business in each other jurisdiction in which any of its Oil and Gas Properties is located or the ownership of its Properties requires such qualification, except where the failure to so qualify could not reasonably be expected to have a Material Adverse Effect; provided that the foregoing shall not prohibit any merger, consolidation, liquidation or dissolution permitted under Section 9.12.

Section 8.04 Payment of Obligations. The Borrower will, and will cause each of its Consolidated Subsidiaries to, pay its obligations, including Tax liabilities of the Borrower and all of its Consolidated Subsidiaries before the same shall become delinquent or in default, except where (a) the validity or amount thereof is being contested in good faith by appropriate proceedings, (b) the Borrower or such Subsidiary has set aside on its books adequate reserves with respect thereto in accordance with GAAP and (c) the failure to make payment pending such contest could not reasonably be expected to result in a Material Adverse Effect or result in the seizure or levy of any Property of the Borrower or any of its Consolidated Subsidiaries.

Section 8.05 Performance of Obligations under Loan Documents. The Borrower will pay the Notes according to the reading, tenor and effect thereof, and the Borrower will, and the Borrower will cause each of its Subsidiaries to do and perform every act and discharge all of the Obligations, including, without limitation, this Agreement, at the time or times and in the manner specified.

Section 8.06 Operation and Maintenance of Properties. The Borrower will, and will cause each of its Consolidated Subsidiaries to:

(a) operate its Oil and Gas Properties and other material Properties or cause such Oil and Gas Properties and other material Properties to be operated in accordance with prudent industry practices and in compliance with all applicable contracts and agreements and in compliance with all Governmental Requirements, including, without limitation, applicable proration requirements and Environmental Laws, and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom, except, in each case, where the failure to comply could not reasonably be expected to have a Material Adverse Effect.

(b) keep and maintain all Property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material Properties, including, without limitation, all material equipment, machinery and facilities.

(c) promptly pay and discharge, or make reasonable and customary efforts to cause to be paid and discharged, all delay rentals, royalties, expenses and indebtedness accruing under the leases or other agreements affecting or pertaining to its Oil and Gas Properties and will do all other things necessary to keep unimpaired their rights with respect thereto and prevent any forfeiture thereof or default thereunder.

(d) promptly perform or make reasonable and customary efforts to cause to be performed, in accordance with industry standards and in all material respects, the obligations required by each and all of the assignments, deeds, leases, sub-leases, contracts and agreements affecting its interests in its Oil and Gas Properties and other material Properties.

(e) to the extent the Borrower or one of its Subsidiaries is not the operator of any Property, the Borrower shall use reasonable efforts to cause the operator to comply with this Section 8.06.

Section 8.07 Insurance. The Borrower will, and will cause each of its Subsidiaries to, maintain, with financially sound and reputable insurance companies, insurance in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations. The loss payable clauses or provisions in said insurance policy or policies insuring any of the collateral for the Loans shall be endorsed in favor of and made payable to the Administrative Agent as its interests may appear and such policies shall name the Administrative Agent and the Lenders as “additional insureds” and provide that the insurer will give at least 30 days prior notice of any cancellation to the Administrative Agent.

Section 8.08 Books and Records; Inspection Rights. The Borrower will, and will cause each of its Subsidiaries to, keep proper books of record and account in which full, true and correct entries are made of all dealings and transactions in relation to its business and activities. The Borrower will, and will cause each of its Subsidiaries to, permit any representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice, to visit and inspect its Properties, to examine and make extracts from its books and records, and to discuss its affairs, finances and condition with its officers and independent accountants, all at such reasonable times and as often as reasonably requested.

Section 8.09 Compliance with Laws. The Borrower will, and will cause each of its Subsidiaries to, comply with all laws, rules, regulations and orders of any Governmental Authority applicable to them or their Property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

Section 8.10 Environmental Matters.

(a) Except as could reasonably be expected to result in a Material Adverse Effect, the Borrower shall, and shall cause each of its Subsidiaries to: (i) comply, and shall cause its Properties and operations and each of its Subsidiaries and each Subsidiary’s Properties and operations to comply, with all applicable Environmental Laws; (ii) not dispose of or otherwise release, and shall cause each Subsidiary not to dispose of or otherwise release, any oil, oil and gas waste, hazardous substance, or solid waste on, under, about or from any of the Borrower’s or its Subsidiaries’ Properties or any other Property to the extent caused by the Borrower’s or any of its Subsidiaries’ operations except in compliance with applicable Environmental Laws; (iii) timely obtain or file, and shall cause each of its Subsidiaries to timely obtain or file, all notices,

permits, licenses, exemptions, approvals, registrations or other authorizations, if any, required under applicable Environmental Laws to be obtained or filed in connection with the operation or use of the Borrower’s or its Subsidiaries’ Properties; (iv) promptly commence and diligently prosecute to completion, and shall cause each of its Subsidiaries to promptly commence and diligently prosecute to completion, any assessment, evaluation, investigation, monitoring, containment, cleanup, removal, repair, restoration, remediation or other remedial obligations (collectively, the “Remedial Work”) in the event any Remedial Work is required under applicable Environmental Laws because of or in connection with the actual or suspected past, present or future disposal or other release of any oil, oil and gas waste, hazardous substance or solid waste on, under, about or from any of the Borrower’s or the Guarantors’ Properties; and (v) establish and implement, and shall cause each of its Subsidiaries to establish and implement, such procedures as may be reasonably necessary to continuously determine and assure that the Borrower’s and the Guarantors’ obligations under this Section 8.10(a) are timely and fully satisfied.

(b) The Borrower will, and will cause each of the Guarantors to, provide environmental audits and tests in accordance with American Society of Testing Materials standards upon request by the Administrative Agent (or as otherwise required to be obtained by the Administrative Agent by any Governmental Authority), in connection with any future acquisitions of Oil and Gas Properties to the extent such Oil and Gas Properties are included as collateral for the Borrowing Base.

Section 8.11 Further Assurances.

(a) The Borrower at its sole expense will, and will cause each of the Guarantors to, promptly execute and deliver to the Administrative Agent all such other documents, agreements and instruments reasonably requested by the Administrative Agent to comply with, cure any defects or accomplish the conditions precedent, covenants and agreements of the Borrower or any of the Guarantors, as the case may be, in the Loan Documents, including the Notes, or to further evidence and more fully describe the collateral intended as security for the Indebtedness, or to correct any omissions in this Agreement or the Security Instruments, or to state more fully the obligations secured therein, or to perfect, protect or preserve any Liens created pursuant to this Agreement or any of the Security Instruments or the priority thereof, or to make any recordings, file any notices or obtain any consents, all as may be reasonably necessary or appropriate, in the sole discretion of the Administrative Agent, in connection therewith.

(b) The Borrower hereby authorizes the Administrative Agent to file one or more financing or continuation statements, and amendments thereto, relative to all or any part of the Mortgaged Property. A carbon, photographic or other reproduction of the Security Instruments or any financing statement covering the Mortgaged Property or any part thereof shall be sufficient as a financing statement where permitted by law. The Administrative Agent will promptly send the Borrower any financing or continuation statements it files and the Administrative Agent will promptly send the Borrower the filing or recordation information with respect thereto.

Section 8.12 Title Information.

(a) On or before the delivery to the Administrative Agent and the Lenders of each Reserve Report required by Section 2.07(b), to the extent requested by the Administrative Agent, the Borrower will deliver title information in form and substance acceptable to the Administrative Agent covering enough of the Oil and Gas Properties evaluated by such Reserve Report that were not included in the immediately preceding Reserve Report, so that the Administrative Agent shall have received together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 85% of the total value of the Oil and Gas Properties evaluated by such Reserve Report.

(b) If the Borrower has provided title information for additional Properties under Section 2.07(b), the Borrower shall, within 60 days of notice from the Administrative Agent that title defects or exceptions exist with respect to such additional Properties, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) which are not permitted by Section 9.03 raised by such information, (ii) substitute acceptable Mortgaged Properties with no title defects or exceptions except for Excepted Liens (other than Excepted Liens described in clauses (e), (g) and (h) of such definition) having an equivalent value or (iii) deliver title information in form and substance reasonably acceptable to the Administrative Agent so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, reasonably satisfactory title information on at least 85% of the value of the Oil and Gas Properties evaluated by such Reserve Report.

(c) If the Borrower is unable to cure any title defect requested by the Administrative Agent or the Lenders to be cured within the 60-day period or the Borrower does not comply with the requirements to provide acceptable title information covering 85% of the value of the Oil and Gas Properties evaluated in the most recent Reserve Report, such default shall not be a Default, but instead the Administrative Agent and/or the Required Lenders shall have the right to exercise the following remedy in their sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by the Administrative Agent or the Lenders. To the extent that the Administrative Agent or the Required Lenders are not reasonably satisfied with title to any Mortgaged Property after the 60-day period has elapsed, such unacceptable Mortgaged Property shall not count towards the 85% requirement, and the Administrative Agent may send a notice to the Borrower and the Lenders that the then outstanding Borrowing Base shall be reduced by an amount as determined by the Required Lenders to cause the Borrower to be in compliance with the requirement to provide acceptable title information on 85% of the value of the Oil and Gas Properties. This new Borrowing Base shall become effective immediately after receipt of such notice.

Section 8.13 Additional Collateral; Additional Guarantors.

(a) In connection with each redetermination of the Borrowing Base, the Borrower shall review the Reserve Report and the list of current Mortgaged Properties to ascertain whether the Mortgaged Properties represent at least 85% of the total value of the Oil and Gas Properties evaluated in the most recently completed Reserve Report after giving effect to exploration and production activities, acquisitions, dispositions and production. In the event that the Mortgaged Properties do not represent at least 85% of such total value, then the

Borrower shall, and shall cause its Subsidiaries to, grant to the Administrative Agent or its designee as security for the Indebtedness a first-priority Lien interest (provided the Excepted Liens of the type described in clauses (a) to (d) and (f) of the definition thereof may exist, but subject to the provisos at the end of such definition) on additional Oil and Gas Properties not already subject to a Lien of the Security Instruments such that after giving effect thereto, the Mortgaged Properties will represent at least 85% of such total value. All such Liens will be created and perfected by and in accordance with the provisions of deeds of trust, security agreements and financing statements or other Security Instruments, all in form and substance reasonably satisfactory to the Administrative Agent or its designee and in sufficient executed (and acknowledged where necessary or appropriate) counterparts for recording purposes. In order to comply with the foregoing, if any Subsidiary places a Lien on its Oil and Gas Properties and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with Section 8.13(b).

(b) In the event that (i) the Borrower determines that any Subsidiary is a Material Domestic Subsidiary or (ii) any Domestic Subsidiary incurs or guarantees any Debt, then the Borrower shall promptly cause such Subsidiary to guarantee the Indebtedness pursuant to the Guarantee Agreement. In connection with any such guaranty, the Borrower shall, or shall cause such Subsidiary to, (A) execute and deliver a supplement to the Guarantee Agreement executed by such Subsidiary, (B) pledge all of the Equity Interests of such Subsidiary (including, without limitation, delivery of original stock certificates evidencing the Equity Interests of such Subsidiary (if such interests are certificated), together with an appropriate undated stock powers for each certificate duly executed in blank by the registered owner thereof) and (C) execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent or its designee.

Section 8.14 ERISA Compliance. The Borrower will promptly furnish, and will cause its Subsidiaries to promptly furnish, to the Administrative Agent (a) promptly after the filing thereof with the United States Secretary of Labor, the Internal Revenue Service or the PBGC, copies of each annual and other report with respect to each Plan, if any, or any trust created thereunder, (b) immediately upon becoming aware of the occurrence of any ERISA Event or of any “prohibited transaction,” as described in section 406 of ERISA or in section 4975 of the Code, in connection with any Plan or any trust created thereunder, a written notice signed by the President or the principal Financial Officer of the Borrower or its Subsidiaries, as the case may be, specifying the nature thereof, what action the Borrower, its Subsidiaries or the ERISA Affiliate is taking or proposes to take with respect thereto, and, when known, any action taken or proposed by the Internal Revenue Service, the Department of Labor or the PBGC with respect thereto, and (c) immediately upon receipt thereof, copies of any notice of the PBGC’s intention to terminate or to have a trustee appointed to administer any Plan. With respect to each Plan, if any (other than a Multiemployer Plan), the Borrower will, and the Borrower will cause each of its Subsidiaries to, (i) satisfy in full and in a timely manner, without incurring any late payment or underpayment charge or penalty and without giving rise to any lien, all of the contribution and funding requirements of section 412 of the Code (determined without regard to subsections (d), (e), (f) and (k) thereof) and of section 302 of ERISA (determined without regard to sections 303, 304 and 306 of ERISA), and (ii) pay, or cause to be paid, to the PBGC in a timely manner, without incurring any late payment or underpayment charge or penalty, all premiums required pursuant to sections 4006 and 4007 of ERISA.

Section 8.15 Marketing Activities. The Borrower will not, and will not permit any of its Subsidiaries to, engage in marketing activities for any Hydrocarbons or enter into any contracts related thereto other than (a) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from their Oil and Gas Properties during the period of such contract, (b) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from Oil and Gas Properties of third parties during the period of such contract associated with the Oil and Gas Properties of the Borrower and its Subsidiaries that the Borrower or one of its Subsidiaries has the right to market pursuant to joint operating agreements, unitization agreements or other similar contracts that are usual and customary in the oil and gas business and (c) other contracts for the purchase and/or sale of Hydrocarbons of third parties (i) which have generally offsetting provisions (i.e. corresponding pricing mechanics, delivery dates and points and volumes) such that no “position” is taken and (ii) for which appropriate credit support has been taken to alleviate the material credit risks of the counterparty thereto.

Section 8.16 Title. With respect to Oil and Gas Properties acquired after the Closing Date or not previously included in the Borrowing Base, and to the extent necessary to allow the Administrative Agent to achieve the percentage described in the preceding sentence, the Borrower shall from time to time upon the reasonable request of the Administrative Agent, take such actions and execute and deliver such documents and instruments as the Administrative Agent shall require to ensure that the Administrative Agent shall, at all times, have received satisfactory title opinions (including, if requested, supplemental or new title opinions addressed to it), title reports, or other title due diligence, which title diligence shall be in form and substance reasonably acceptable to the Administrative Agent and shall include information regarding the before payout and after payout ownership interests held by the Borrower and its Subsidiaries, for all wells located on the Oil and Gas Properties shown in the most recent Reserve Report.

Section 8.17 Board Composition. The Permitted Holders shall at all times have the right to appoint all of the Class A Managers pursuant to Section 11.8(d) of the Second Amended and Restated Operating Agreement of the Borrower as filed with the SEC on September [28], 2006.

ARTICLE IX

NEGATIVE COVENANTS

Until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents have been paid in full and all Letters of Credit have expired or terminated and all Letter of Credit Disbursements shall have been reimbursed, the Borrower covenants and agrees with the Lenders that:

Section 9.01 Financial Covenants.

(a) Current Ratio. The Borrower will not permit, as of the last day of any fiscal quarter, its Current Ratio to be less than 1.0 to 1.0.

(b) Maximum Total Debt to Adjusted EBITDA. As of the end of any fiscal quarter, commencing with the fiscal quarter ending December 31, 2006 or first full quarter after IPO, Borrower will not permit its ratio of (i) Debt of Borrower and its Consolidated Subsidiaries (for each Rolling Period ending on such date) to (ii) Adjusted EBITDA to be greater than the 3.50 to 1.0.

(c) Ratio of Adjusted EBITDA to Interest Expense. The Borrower will not, as of the last day of any fiscal quarter commencing June 30, 2006, permit its ratio of Adjusted EBITDA for the fiscal quarter then ending to Cash Interest Expense for such fiscal quarter to be less than 4.5 to 1.0.

Section 9.02 Debt. Neither the Borrower nor any of its Subsidiaries will incur, create, assume or suffer to exist any Debt, except:

(a) the Notes or other Indebtedness arising under the Loan Documents or any guaranty of or suretyship arrangement for the Notes or other Indebtedness arising under the Loan Documents.

(b) accounts payable and other accrued expenses, liabilities or other obligations to pay (for the deferred purchase price of Property or services) from time to time incurred in the ordinary course of business which are not greater than ninety (90) days past the date of invoice or delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP.

(c) intercompany Debt between the Borrower and any of its Subsidiaries or between Subsidiaries to the extent permitted by Section 9.05(g); provided that such Debt is not held, assigned, transferred, negotiated or pledged to any Person other than the Borrower or one of their Wholly-Owned Subsidiaries, and, provided further, that any such Debt owed by either the Borrower or a Guarantor shall be subordinated to the Indebtedness on terms set forth in the Guarantee Agreement.

(d) endorsements of negotiable instruments for collection in the ordinary course of business.

(e) other Debt not to exceed $5,000,000 in the aggregate at any one time outstanding.

Section 9.03 Liens. Neither the Borrower nor any of its Subsidiaries will create, incur, assume or permit to exist any Lien on any of its Properties (now owned or hereafter acquired), except:

(a) Liens securing the payment of any Indebtedness.

(b) Excepted Liens.

(c) Liens on Property not constituting collateral for the Indebtedness and not otherwise permitted by the foregoing clauses of this Section 9.03; provided that the aggregate principal or face amount of all Debt secured under this Section 9.03(c) shall not exceed $100,000 at any time.

Section 9.04 Dividends, Distributions and Redemptions. The Borrower will not, and will not permit any of its Subsidiaries to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital to its stockholders or make any distribution of their Property to their respective Equity Interest holders, except (i) the Borrower may declare and pay dividends or distributions with respect to its Equity Interests payable solely in additional shares of its Equity Interests (other than Disqualified Capital Stock but including cash in lieu of fractional Equity Interests to the extent of Available Cash), (ii) Subsidiaries may declare and pay dividends or distributions ratably with respect to their Equity Interests and (iii) so long as no Borrowing Base Deficiency, Default or Event of Default has occurred and is continuing or would result therefrom, after giving effect to such dividend or distributions, and any redetermination of the Borrowing Base as a result of such dividend, the Borrower would have at least 10% of unused availability under the Borrowing Base, and subject to the proviso in Section 7.23, the Borrower may declare and pay quarterly cash dividends to its members of Available Cash.

Section 9.05 Investments, Loans and Advances. Neither the Borrower nor any of its Subsidiaries will make or permit to remain outstanding any Investments in or to any Person, except that the foregoing restriction shall not apply to:

(a) Investments reflected in the Financial Statements.

(b) accounts receivable arising in the ordinary course of business.

(c) direct obligations of the United States or any agency thereof, or obligations guaranteed by the United States or any agency thereof, in each case maturing within one year from the date of creation thereof.

(d) commercial paper maturing within one year from the date of creation thereof rated in the highest grade by S&P or Moody’s.

(e) deposits maturing within one year from the date of creation thereof with, including certificates of deposit issued by, any Lender or any office located in the United States of any other bank or trust company which is organized under the laws of the United States or any state thereof, has capital, surplus and undivided profits aggregating at least $250,000,000 (as of the date of such bank or trust company’s most recent financial reports) and has a short term deposit rating of no lower than A2 or P2, as such rating is set forth from time to time, by S&P or Moody’s, respectively.

(f) deposits in money market funds investing exclusively in Investments described in Section 9.05(c), Section 9.05(d) or Section 9.05(e).

(g) Investments (i) made by the Borrower in or to the Guarantors, (ii) made by any Subsidiary in or to the Borrower or any Guarantor, and (iii) made by the Borrower or any Guarantor in Subsidiaries that are not Guarantors, provided that the aggregate of all Investments made by the Borrower and the Guarantors in or to all Subsidiaries that are not Guarantors shall not exceed $2,000,000 at any time.

(h) Investments (including, without limitation, capital contributions) in general or limited partnerships or other types of entities (each a “venture”) entered into by the Borrower or any of its Subsidiaries with others in the ordinary course of business; provided that (i) the interest in such venture is acquired in the ordinary course of business and on fair and reasonable terms and (ii) such venture interests acquired and capital contributions made (valued as of the date such interest was acquired or the contribution made) do not exceed, in the aggregate at any time outstanding an amount equal to $2,000,000.

(i) subject to the limits in Section 9.06, Investments in direct ownership interests in additional Oil and Gas Properties and gas gathering systems related thereto or related to farm-out, farm-in, joint operating, joint venture or area of mutual interest agreements, gathering systems, pipelines or other similar arrangements which are usual and customary in the oil and gas exploration and production business located within the geographic boundaries of the United States of America.

(j) loans or advances to employees, officers or directors in the ordinary course of business of the Borrower or any of its Subsidiaries, in each case only as permitted by applicable law, including Section 402 of the Sarbanes Oxley Act of 2002, but in any event not to exceed $250,000 in the aggregate at any time.

(k) Investments in stock, obligations or securities received in settlement of debts arising from Investments permitted under this Section 9.05 owing to the Borrower or any of its Subsidiaries as a result of a bankruptcy or other insolvency proceeding of the obligor in respect of such debts or upon the enforcement of any Lien in favor of the Borrower or any of its Subsidiaries; provided that the Borrower shall give the Administrative Agent prompt written notice in the event that the aggregate amount of all investments held at any one time under this Section 9.05(i) exceeds $250,000.

Section 9.06 Nature of Business. The Borrower will not, and will not permit any of its Subsidiaries to, operate its business outside the boundaries of the United States and its adjoining waters, including, without limitation, the Gulf of Mexico.

Section 9.07 Limitation on Leases. Neither the Borrower nor any of its Subsidiaries will create, incur, assume or suffer to exist any obligation for the payment of rent or hire of Property of any kind whatsoever (real or personal but excluding leases of Hydrocarbon Interests), under leases or lease agreements which would cause the aggregate amount of all payments made by the Borrower and its Subsidiaries pursuant to all such leases or lease agreements, including, without limitation, any residual payments at the end of any lease, to exceed $2,000,000 in any period of twelve consecutive calendar months during the life of such leases.

Section 9.08 Proceeds of Notes. The Borrower will not permit the proceeds of the Notes to be used for any purpose other than those permitted by Section 7.23. Neither the Borrower nor any Person acting on behalf of the Borrower has taken or will take any action which might cause any of the Loan Documents to violate Regulations T, U or X or any other regulation of the Board or to violate Section 7 of the Securities Exchange Act of 1934 or any rule or regulation thereunder, in each case as now in effect or as the same may hereinafter be in

effect. If requested by the Administrative Agent, the Borrower will furnish to the Administrative Agent and each Lender a statement to the foregoing effect in conformity with the requirements of FR Form U-1 or such other form referred to in Regulation U, Regulation T or Regulation X of the Board, as the case may be.

Section 9.09 ERISA Compliance. The Borrower and its Subsidiaries will not at any time:

(a) engage in any transaction in connection with which the Borrower or any of its Subsidiaries could be subjected to either a civil penalty assessed pursuant to subsections (c), (i) or (l) of section 502 of ERISA or a tax imposed by Chapter 43 of Subtitle D of the Code.

(b) terminate any Plan in a manner, or take any other action with respect to any Plan, which could result in any liability of the Borrower or any of its Subsidiaries to the PBGC.

(c) fail to make full payment when due of all amounts which, under the provisions of any Plan, agreement relating thereto or applicable law, the Borrower or any of its Subsidiaries is required to pay as contributions thereto.

(d) permit to exist any accumulated funding deficiency within the meaning of section 302 of ERISA or section 412 of the Code, whether or not waived, with respect to any Plan.

(e) permit the actuarial present value of the benefit liabilities under any Plan that is regulated under Title IV of ERISA to exceed the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities. The term “actuarial present value of the benefit liabilities” shall have the meaning specified in section 4041 of ERISA.

(f) contribute to or assume an obligation to contribute to any Multiemployer Plan.

(g) acquire an interest in any Person that causes such Person to become an ERISA Affiliate with respect to the Borrower or any of its Subsidiaries if such Person sponsors, maintains or contributes to (i) any Multiemployer Plan, if such Person would, if it withdrew from such plan, be subject to withdrawal liability under Part 1 of Subtitle E of Title IV of ERISA in excess of $1,000,000, or (ii) any other Plan that is subject to Title IV of ERISA under which the projected benefit obligation under the Plan exceeds the fair market value of the Plan’s assets by $1,000,000.

(h) incur a liability to or on account of a Plan under sections 515, 4062, 4063, 4064, 4201 or 4204 of ERISA.

(i) contribute to or assume an obligation to contribute to any employee welfare benefit plan, as defined in section 3(1) of ERISA maintained to provide benefits to former employees of such entities that the Borrower or its Subsidiaries reasonably believes may not be terminated by such entities in their sole discretion at any time without any material liability.

(j) amend a Plan resulting in an increase in current liability such that the Borrower or any of its Subsidiaries is required to provide security to such Plan under section 401(a)(29) of the Code.

Section 9.10 Sale or Discount of Receivables. Except for receivables obtained by the Borrower or any of its Subsidiaries out of the ordinary course of business or the settlement of joint interest billing accounts in the ordinary course of business or discounts granted to settle collection of accounts receivable or the sale of defaulted accounts arising in the ordinary course of business in connection with the compromise or collection thereof and not in connection with any financing transaction, neither the Borrower nor any of its Subsidiaries will discount or sell (with or without recourse) any of its notes receivable or accounts receivable.

Section 9.11 Mergers, Etc. Neither the Borrower nor any of its Subsidiaries will merge into or with or consolidate with any other Person, or sell, lease or otherwise dispose of (whether in one transaction or in a series of transactions) all or substantially all of its Property to any other Person, except that any Wholly-Owned Subsidiary may merge with any other Wholly-Owned Subsidiary and that the Borrower may merge with any Wholly-Owned Subsidiary so long as the Borrower is the survivor.

Section 9.12 Sale of Properties. The Borrower will not, and will not permit any of the Guarantors to, sell, assign, farm-out, convey or otherwise transfer any Property except for: (a) the sale of Hydrocarbons in the ordinary course of business; (b) farmouts of undeveloped acreage and assignments in connection with such farmouts; (c) the sale or transfer of equipment that is no longer necessary for the business of the Borrower or such Subsidiary or is replaced by equipment of at least comparable value and use; (d) sales or other dispositions (excluding Casualty Events) of Oil and Gas Properties or any interest therein or Subsidiaries owning Oil and Gas Properties; provided that (i) 100% of the consideration received in respect of such sale or other disposition shall be cash and/or publicly traded securities, (ii) the consideration received in respect of such sale or other disposition shall be equal to or greater than the fair market value of the Oil and Gas Property, interest therein or Subsidiary subject of such sale or other disposition (as reasonably determined by the board of directors of the Borrower and, if requested by the Administrative Agent, the Borrower shall deliver a certificate of a Responsible Officer of the Borrower certifying to that effect), (iii) if such sale or other disposition of Oil and Gas Property or Subsidiary owning Oil and Gas Properties included in the most recently delivered Reserve Report during any period between two successive Scheduled Redetermination Dates has a fair market value (as determined by the Administrative Agent), individually or in the aggregate, in excess of $5,000,000, the Borrowing Base shall be reduced, effective immediately upon such sale or disposition, by an amount equal to the value, if any, assigned such Property as determined by the Required Lenders assigned such Property in the most recently delivered Reserve Report and (iv) if any such sale or other disposition is of a Subsidiary owning Oil and Gas Properties, such sale or other disposition shall include all the Equity Interests of such Subsidiary; and (e) sales and other dispositions of Properties not regulated by Section 9.12(a) to (d) having a fair market value not to exceed $250,000 during any 12-month period.

Section 9.13 Transactions with Affiliates. Except as provided in the Management Services Agreement, the Borrower will not, and will not permit any Subsidiary to, enter into any transaction, including, without limitation, any purchase, sale, lease or exchange of Property or

the rendering of any service, with any Affiliate (other than the Guarantors and Wholly-Owned Subsidiaries of the Borrower) unless such transactions are otherwise permitted under this Agreement and are upon fair and reasonable terms no less favorable to it than it would obtain in a comparable arm’s length transaction with a Person not an Affiliate.

Section 9.14 Subsidiaries. The Borrower shall not, and shall not permit its Subsidiaries to, create or acquire any additional Subsidiary unless the Borrower complies with Section 8.13(b). Except as otherwise permitted herein, the Borrower shall not, and shall not permit any of its Subsidiaries to, sell, assign or otherwise dispose of any Equity Interests in any of the Guarantors. The Borrower shall have no Foreign Subsidiaries.

Section 9.15 Negative Pledge Agreements; Dividend Restrictions. Neither the Borrower nor any of its Subsidiaries will create, incur, assume or suffer to exist any contract, agreement or understanding (other than this Agreement or the Security Instruments) that in any way prohibits or restricts the granting, conveying, creation or imposition of any Lien on any of its Property in favor of the Administrative Agent and the Lenders or restricts any Subsidiary from paying dividends or making distributions to the Borrower or any Guarantor, or which requires the consent of or notice to other Persons in connection therewith.

Section 9.16 Gas Imbalances, Take-or-Pay or Other Prepayments. The Borrower will not, and will not permit any of its Subsidiaries to, allow gas imbalances, take-or-pay or other prepayments with respect to the Oil and Gas Properties of the Borrower or any of its Subsidiaries that would require the Borrower or such Subsidiary to deliver, in the aggregate, [three percent (3%)] or more of the monthly production of Hydrocarbons at some future time without then or thereafter receiving full payment therefor.

Section 9.17 Swap Agreements. Neither the Borrower nor any of its Subsidiaries will enter into any Swap Agreements with any Person other than (a) Swap Agreements in respect of commodities (i) with an Approved Counterparty, (ii) the notional volumes for which (when aggregated with other commodity Swap Agreements then in effect other than basis differential swaps on volumes already hedged pursuant to other Swap Agreements) do not exceed, as of the date such Swap Agreement is executed, 90% of the reasonably anticipated projected production from Proved Developed Producing Properties for each month during the period during which such Swap Agreement is in effect for each of crude oil and natural gas, calculated separately, on a rolling twelve (12) month period and 85% of the reasonably anticipated projected production from Proved Developed Producing Properties for each month during the period during which such Swap Agreement is in effect for each of crude oil and natural gas, calculated separately, on a rolling thirteen (13) to sixty (60) month period, and (iii) the notional volumes for which do not exceed the current net monthly production (regardless of projected production levels) at the time such Swap Agreement is executed, calculated separately for each of crude oil and natural gas, and (b) Swap Agreements in respect of interest rates with an Approved Counterparty, which effectively convert interest rates from floating to fixed, the notional amounts of which (when aggregated with all other Swap Agreements of the Borrower and its Subsidiaries then in effect effectively converting interest rates from floating to fixed) do not exceed 75% of the then outstanding principal amount of the Borrower’s Debt for borrowed money which bears interest at a floating rate. In no event shall any Swap Agreement contain any requirement, agreement or covenant for the Borrower or any of its Subsidiaries to post collateral or margin to secure their obligations under such Swap Agreement or to cover market exposures.

Section 9.18 Tax Status as Partnership; Operating Agreements. The Borrower shall not alter its status as a partnership for purposes of United States Federal Income taxes. The Borrower shall not, and shall not permit any Subsidiary to, amend or modify any provision of its articles, bylaws, or partnership or limited liability company organization or operating documents or agreements, or any agreements with Affiliates of the type referred to in Section 9.13, if such amendment or modification could reasonably be expected to have a Material Adverse Effect.

ARTICLE X

EVENTS OF DEFAULT; REMEDIES

Section 10.01 Events of Default. One or more of the following events shall constitute an “Event of Default”:

(a) the Borrower shall fail to pay any principal of any Loan or any reimbursement obligation in respect of any Letter of Credit Disbursement when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof or otherwise.

(b) the Borrower shall fail to pay any interest on any Loan or any fee or any other amount (other than an amount referred to in Section 10.01(a)) payable under any Loan Document, when and as the same shall become due and payable, and such failure shall continue unremedied for a period of three Business Days.

(c) any representation or warranty made or deemed made by or on behalf of the Borrower or any of its Subsidiaries in or in connection with any Loan Document or any amendment or modification of any Loan Document or waiver under such Loan Document, or in any report, certificate, financial statement or other document furnished pursuant to or in connection with any Loan Document or any amendment or modification thereof or waiver thereunder, shall prove to have been incorrect when made or deemed made.

(d) the Borrower or any of its Subsidiaries shall fail to observe or perform any covenant, condition or agreement contained in, Section 8.01(n), Section 8.02, Section 8.03, Section 8.17 or in ARTICLE IX.

(e) the Borrower or any of its Subsidiaries shall fail to observe or perform any covenant, condition or agreement contained in this Agreement (other than those specified in Section 10.01(a), Section 10.01(b) or Section 10.01(d)) or any other Loan Document, and such failure shall continue unremedied for a period of 30 days after the earlier to occur of (i) notice thereof from the Administrative Agent to the Borrower (which notice will be given at the request of any Lender) or (ii) a Responsible Officer of the Borrower or any of its Subsidiaries otherwise becoming aware of such default.

(f) any event or condition occurs (after giving effect to any notice or cure period) that results in any Material Indebtedness becoming due prior to its scheduled maturity or that enables or permits (with or without the giving of notice, the lapse of time or both) the holder or holders of any Material Indebtedness or any trustee or agent on its or their behalf to cause any Material Indebtedness to become due, or to require the Redemption thereof or any offer to Redeem to be made in respect thereof, prior to its scheduled maturity or require the Borrower or any of its Subsidiaries to make an offer in respect thereof.

(g) an involuntary proceeding shall be commenced or an involuntary petition shall be filed seeking (i) liquidation, reorganization or other relief in respect of the Borrower or any of its Subsidiaries or its debts, or of a substantial part of its assets, under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any of its Subsidiaries or for a substantial part of its assets, and, in any such case, such proceeding or petition shall continue undismissed for 90 days or an order or decree approving or ordering any of the foregoing shall be entered.

(h) the Borrower or any of its Subsidiaries shall (i) voluntarily commence any proceeding or file any petition seeking liquidation, reorganization or other relief under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or petition described in Section 10.01(h), (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any of its Subsidiaries or for a substantial part of its assets, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing; or any member of the Borrower shall make any request or take any action for the purpose of calling a meeting of the members of the Borrower to consider a resolution to dissolve and wind-up the Borrower’s affairs.

(i) the Borrower or any of its Subsidiaries shall become unable, admit in writing its inability or fail generally to pay its debts as they become due.

(j) (i) one or more final judgments for the payment of money in an aggregate amount in excess of $1,000,000 (to the extent not covered by independent third party insurance provided by insurers of the highest claims paying rating or financial strength as to which the insurer does not dispute coverage and is not subject to an insolvency proceeding) or (ii) any one or more non monetary judgments that have, or could reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect, shall be rendered against the Borrower, any of its Subsidiaries or any combination thereof and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to attach or levy upon any assets of the Borrower or any of its Subsidiaries to enforce any such judgment.

(k) the Loan Documents after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with their terms against the Borrower or a Guarantor party thereto or

shall be repudiated by them, or cease to create a valid and perfected Lien of the priority required thereby on any of the collateral purported to be covered thereby, except to the extent permitted by the terms of this Agreement, or the Borrower or any of its Subsidiaries shall so state in writing.

(l) an ERISA Event shall have occurred that, in the opinion of the Required Lenders, when taken together with all other ERISA Events that have occurred, could reasonably be expected to result in liability of the Borrower and its Subsidiaries in an aggregate amount exceeding $1,000,000 in any year.

(m) a Change in Control shall occur.

Section 10.02 Remedies.

(a) In the case of an Event of Default other than one described in Section 10.01(h), Section 10.01(i) or Section 10.01(j), at any time thereafter during the continuance of such Event of Default, the Administrative Agent, at the request of the Required Lenders, shall, by notice to the Borrower, take either or both of the following actions, at the same or different times: (i) terminate the Commitments, and thereupon the Commitments shall terminate immediately, and (ii) declare the Notes and the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including, without limitation, the payment of cash collateral to secure the Letter of Credit Exposure as provided in Section 2.08(j)), shall become due and payable immediately, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor; and in case of an Event of Default described in Section 10.01(h), Section 10.01(i) or Section 10.01(j), the Commitments shall automatically terminate and the Notes and the principal of the Loans then outstanding, together with accrued interest thereon and all fees and the other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents (including, without limitation, the payment of cash collateral to secure the Letter of Credit Exposure as provided in Section 2.08(j)), shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor.

(b) In the case of the occurrence of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

(c) All proceeds realized from the liquidation or other disposition of collateral or otherwise received after maturity of the Notes, whether by acceleration or otherwise, shall be applied: first, to reimbursement of expenses and indemnities provided for in this Agreement and the Security Instruments; second, to accrued interest on the Notes; third, to fees; fourth, pro rata to principal outstanding on the Notes and Indebtedness referred to in Clause (b) of the definition of Indebtedness owing to a Lender or an Affiliate of a Lender; fifth, to any other Indebtedness; sixth, to serve as cash collateral to be held by the Administrative Agent to secure the Letter of Credit Exposure; and any excess shall be paid to the Borrower or as otherwise required by any Governmental Requirement.

Section 10.03 Disposition of Proceeds. The Security Instruments contain an assignment by the Borrower and/or the Guarantors unto and in favor of the Administrative Agent for the benefit of the Lenders of all of the Borrower’s or each Guarantor’s interest in and to production and all proceeds attributable thereto which may be produced from or allocated to the Mortgaged Property. The Security Instruments further provide in general for the application of such proceeds to the satisfaction of the Indebtedness and other obligations described therein and secured thereby. Notwithstanding the assignment contained in such Security Instruments, except after the occurrence and during the continuance of an Event of Default, (a) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the Borrower and its Subsidiaries and (b) the Lenders hereby authorize the Administrative Agent to take such actions as may be necessary to cause such proceeds to be paid to the Borrower and/or its Subsidiaries.

ARTICLE XI

THE ADMINISTRATIVE AGENT

Section 11.01 Appointment; Powers. Each of the Lenders and each Issuer hereby irrevocably appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof and the other Loan Documents, together with such actions and powers as are reasonably incidental thereto.

Section 11.02 Duties and Obligations of Administrative Agent. The Administrative Agent shall have no duties or obligations except those expressly set forth in the Loan Documents. Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing (the use of the term “agent” herein and in the other Loan Documents with reference to the Administrative Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law; rather, such term is used merely as a matter of market custom, and is intended to create or reflect only an administrative relationship between independent contracting parties), (b) the Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except as provided in Section 11.03, and (c) except as expressly set forth herein, the Administrative Agent shall have no duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity. The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by the Borrower or a Lender, and shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document

delivered hereunder or under any other Loan Document or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or in any other Loan Document, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, (v) the satisfaction of any condition set forth in ARTICLE VI or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent, (vi) the existence, value, perfection or priority of any collateral security or the financial or other condition of the Borrower and its Subsidiaries or any other obligor or guarantor, or (vii) any failure by the Borrower or any other Person (other than itself) to perform any of its obligations hereunder or under any other Loan Document or the performance or observance of any covenants, agreements or other terms or conditions set forth herein or therein. For purposes of determining compliance with the conditions specified in ARTICLE VI, each Lender shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received written notice from such Lender prior to the proposed closing date specifying its objection thereto.

Section 11.03 Action by Agent. The Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Administrative Agent is required to exercise in writing as directed by the Required Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02) and in all cases the Administrative Agent shall be fully justified in failing or refusing to act hereunder or under any other Loan Documents unless it shall (a) receive written instructions from the Required Lenders or the Lenders, as applicable, (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02) specifying the action to be taken and (b) be indemnified to its satisfaction by the Lenders against any and all liability and expenses which may be incurred by it by reason of taking or continuing to take any such action. The instructions as aforesaid and any action taken or failure to act pursuant thereto by the Administrative Agent shall be binding on all of the Lenders. If a Default has occurred and is continuing, then the Administrative Agent shall take such action with respect to such Default as shall be directed by the requisite Lenders in the written instructions (with indemnities) described in this Section 11.03, provided that, unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default as it shall deem advisable in the best interests of the Lenders. In no event, however, shall the Administrative Agent be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement, the Loan Documents or applicable law. If a Default has occurred and is continuing, the Syndication Agent shall have no obligation to perform any act in respect thereof. No Agent shall be liable for any action taken or not taken by it with the consent or at the request of the Required Lenders or the Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02), and otherwise the Administrative Agent shall not be liable for any action taken or not taken by it hereunder or under any other Loan Document or under any other document or instrument referred to or provided for herein or therein or in connection herewith or therewith INCLUDING ITS OWN ORDINARY NEGLIGENCE, except for its own gross negligence or willful misconduct.

Section 11.04 Reliance by Agent. Each Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person. Each Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon and each of the Borrower, the Lenders and each Issuer hereby waives the right to dispute such Agent’s record of such statement, except in the case of gross negligence or willful misconduct by such Agent. Each Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts. The Agents may deem and treat the payee of any Note as the holder thereof for all purposes hereof unless and until a written notice of the assignment or transfer thereof permitted hereunder shall have been filed with the Administrative Agent.

Section 11.05 Subagents. The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by the Administrative Agent. The Administrative Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties. The exculpatory provisions of the preceding Sections of this ARTICLE XI shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Agent.

Section 11.06 Resignation or Removal of Agents. Subject to the appointment and acceptance of a successor Agent as provided in this Section 11.06, any Agent may resign at any time by notifying the Lenders, each Issuer and the Borrower, and any Agent may be removed at any time with or without cause by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right, subject to the consent of the Borrower, such consent not to be unreasonably withheld or delayed, to appoint a successor. If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation or removal of the retiring Agent, then the retiring Agent may, on behalf of the Lenders and each Issuer, appoint a successor Agent. Upon the acceptance of its appointment as Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the Agent’s resignation hereunder, the provisions of this ARTICLE XI and Section 12.03 shall continue in effect for the benefit of such retiring Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Agent.

Section 11.07 Agents and Lenders. Each bank serving as an Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the

same as though it were not an Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if it were not an Agent hereunder.

Section 11.08 No Reliance. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, any other Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and each other Loan Document to which it is a party. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, any other Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document, any related agreement or any document furnished hereunder or thereunder. The Agents shall not be required to keep themselves informed as to the performance or observance by the Borrower or any of its Subsidiaries of this Agreement, the Loan Documents or any other document referred to or provided for herein or to inspect the Properties or books of the Borrower or its Subsidiaries. Except for notices, reports and other documents and information expressly required to be furnished to the Lenders by the Administrative Agent hereunder, no Agent and no Arranger shall have any duty or responsibility to provide any Lender with any credit or other information concerning the affairs, financial condition or business of the Borrower (or any of its Affiliates) which may come into the possession of such Agent or any of its Affiliates. In this regard, each Lender acknowledges that Pillsbury Winthrop Shaw Pittman LLP is acting in this transaction as special counsel to the Administrative Agent only, except to the extent otherwise expressly stated in any legal opinion or any Loan Document. Each other party hereto will consult with its own legal counsel to the extent that it deems necessary in connection with the Loan Documents and the matters contemplated therein.

Section 11.09 Administrative Agent May File Proofs of Claim. In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Borrower or any of its Subsidiaries, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a) to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Indebtedness that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Section 12.03) allowed in such judicial proceeding; and

(b) to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same; and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event

that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Section 12.03.

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

Section 11.10 Authority of Administrative Agent to Release Collateral and Liens. Each Lender and each Issuer hereby authorizes the Administrative Agent to release any collateral that is permitted to be sold or released pursuant to the terms of the Loan Documents. Each Lender and each Issuer hereby authorizes the Administrative Agent to execute and deliver to the Borrower, at the Borrower’s sole cost and expense, any and all releases of Liens, termination statements, assignments or other documents reasonably requested by the Borrower in connection with any sale or other disposition of Property to the extent such sale or other disposition is permitted by the terms of Section 9.12 or is otherwise authorized by the terms of the Loan Documents.

Section 11.11 The Arrangers and the Syndication Agent. The Arrangers and the Syndication Agent shall have no duties, responsibilities or liabilities under this Agreement and the other Loan Documents other than its duties, responsibilities and liabilities in its capacity as a Lender hereunder to the extent it is a party to this Agreement as a Lender.

ARTICLE XII

MISCELLANEOUS

Section 12.01 Notices.

(a) Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to Section 12.01(b)), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

(i) if to the Borrower, to it at

Constellation Energy Partners LLC

111 Market Place

Baltimore, Maryland 21202

Telephone 410-468-3500

Attn: Legal Department

with a copy to:

Constellation Energy Group, Inc.

111 Market Place

Baltimore, Maryland 21202

Telephone 410-468-3500

Attn: Treasurer

(ii) if to the Administrative Agent, to it at

The Royal Bank of Scotland plc

101 Park Avenue

New York, NY 10178

Attention: Adrian Cioinige or Matt Wilson

Telephone: (212) 250-1312 or (212) 401-1412

Facsimile: (212) 797-0406 or (212) 401-1478

With a copy to:

600 Travis Street, Suite 6500

Houston, Texas 77002

Attention: David Elmer

Telephone: (713) 221-2432

Facsimile: (713) 221-2428

(iii) if to any other Lender, in its capacity as such, or any other Lender in its capacity as an Issuer, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

(b) Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to ARTICLE II, ARTICLE III, ARTICLE IV and ARTICLE V unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c) Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt.

Section 12.02 Waivers; Amendments.

(a) No failure on the part of the Administrative Agent, any other Agent, any Issuer or any Lender to exercise and no delay in exercising, and no course of dealing with respect to, any right, power or privilege, or any abandonment or discontinuance of steps to enforce such right, power or privilege, under any of the Loan Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege under any of the Loan Documents preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies of the Administrative Agent, any other Agent, each Issuer and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or any other Loan Document or consent to any departure by the Borrower therefrom shall in any event be effective unless the same shall be permitted by Section 12.02(b), and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan or issuance of a Letter of Credit shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent, any other Agent, any Lender or any Issuer may have had notice or knowledge of such Default at the time.

(b) Neither this Agreement nor any provision hereof nor any Security Instrument nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Required Lenders or by the Borrower and the Administrative Agent with the consent of the Required Lenders; provided that no such agreement shall (i) increase the Maximum Credit Amount of any Lender without the written consent of such Lender, (ii) increase the Borrowing Base without the written consent of each Lender, decrease or maintain the Borrowing Base without the consent of the Required Lenders, or modify in any manner Section 2.07 without the consent of each Lender, (iii) reduce the principal amount of any Loan or Letter of Credit Disbursement or reduce the rate of interest thereon, or reduce any fees payable hereunder, or reduce any other Indebtedness hereunder or under any other Loan Document, without the written consent of each Lender affected thereby, (iv) postpone the scheduled date of payment of the principal amount of any Loan or Letter of Credit Disbursement, or any interest thereon, or any fees payable hereunder, or any other Indebtedness hereunder or under any other Loan Document, or reduce the amount of, waive or excuse any such payment, or postpone or extend the Termination Date or the Maturity Date without the written consent of each Lender affected thereby, (v) change Section 4.01(b) or Section 4.01(c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, (vi) waive or amend Section 6.01, Section 10.02(c) or Section 8.13 or change the definition of the terms “Domestic Subsidiary”, “Foreign Subsidiary”, “Material Domestic Subsidiary” or “Subsidiary”, without the written consent of each Lender, (vii) release any Guarantor (except as set forth in the Guarantee Agreement), release all or substantially all of the collateral (other than as provided in Section 11.09), or reduce the percentage set forth in Section 8.13(a) to less than 80%, without the written consent of each Lender, or (viii) change any of the provisions of this Section 12.02(b) or the definition of “Required Lenders” or any other provision hereof specifying the number or percentage of

Lenders required to waive, amend or modify any rights hereunder or under any other Loan Documents or make any determination or grant any consent hereunder or any other Loan Documents, without the written consent of each Lender; provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent, any other Agent, or any Issuer hereunder or under any other Loan Document without the prior written consent of the Administrative Agent, such other Agent or such Issuer, as the case may be. Notwithstanding the foregoing, any supplement to Schedule 7.14 (Subsidiaries) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

Section 12.03 Expenses, Indemnity; Damage Waiver.

(a) The Borrower shall pay (i) all reasonable out-of-pocket expenses incurred by the Administrative Agent, including, without limitation, the reasonable fees, charges and disbursements of counsel and other outside consultants for the Administrative Agent, the reasonable travel, photocopy, mailing, courier, telephone and other similar expenses and, in connection with the syndication of the credit facilities provided for herein, the preparation, negotiation, execution, delivery and administration (both before and after the execution hereof and including advice of counsel to the Administrative Agent as to the rights and duties of the Administrative Agent and the Lenders with respect thereto) of this Agreement and the other Loan Documents and any amendments, modifications or waivers of or consents related to the provisions hereof or thereof (whether or not the transactions contemplated hereby or thereby shall be consummated), (ii) all out-of-pocket costs, expenses, Taxes, assessments and other charges incurred by any Agent or any Lender in connection with any filing, registration, recording or perfection of any security interest contemplated by this Agreement or any Security Instrument or any other document referred to therein, (iii) all reasonable out-of-pocket expenses incurred by each Issuer in connection with the amendment of any Letter of Credit issued by such Issuer or any demand for payment thereunder, (iv) all reasonable out-of-pocket expenses incurred by any Agent, any Issuer or any Lender, including the fees, charges and disbursements of one (1) legal counsel for Agent, Issuer and Lenders, in connection with the enforcement or protection of its rights in connection with this Agreement or any other Loan Document, including its rights under this Section 12.03, or in connection with the Loans made or Letters of Credit issued hereunder, including, without limitation, all such reasonable out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans or Letters of Credit; provided, however, Borrower shall be obligated to pay such expenses for only one counsel.

(b) THE BORROWER SHALL INDEMNIFY EACH AGENT, THE ARRANGERS, EACH ISSUER AND EACH LENDER, AND THE AFFILIATES, DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS OF ANY OF THE FOREGOING PERSONS (EACH SUCH PERSON BEING CALLED AN “INDEMNITEE”) AGAINST, AND HOLD EACH INDEMNITEE HARMLESS FROM, ANY AND ALL LOSSES, CLAIMS, DAMAGES, LIABILITIES AND RELATED EXPENSES, INCLUDING THE REASONABLE FEES, AND DISBURSEMENTS OF ANY COUNSEL FOR ANY INDEMNITEE, INCURRED BY OR ASSERTED AGAINST ANY INDEMNITEE ARISING OUT OF, IN CONNECTION WITH, OR AS A RESULT OF (i) THE EXECUTION OR DELIVERY OF THIS

AGREEMENT OR ANY OTHER LOAN DOCUMENT CONTEMPLATED HEREBY, THE PERFORMANCE BY THE PARTIES HERETO OR THE PARTIES TO ANY OTHER LOAN DOCUMENT OF THEIR RESPECTIVE OBLIGATIONS HEREUNDER OR THEREUNDER OR THE CONSUMMATION OF THE TRANSACTIONS CONTEMPLATED HEREBY OR BY ANY OTHER LOAN DOCUMENT, (ii) THE FAILURE OF THE BORROWER OR ANY OF ITS SUBSIDIARIES TO COMPLY WITH THE TERMS OF ANY LOAN DOCUMENT, INCLUDING THIS AGREEMENT, OR WITH ANY GOVERNMENTAL REQUIREMENT, (iii) ANY INACCURACY OF ANY REPRESENTATION OR ANY BREACH OF ANY WARRANTY OR COVENANT OF THE BORROWER OR ANY GUARANTOR SET FORTH IN ANY OF THE LOAN DOCUMENTS OR ANY INSTRUMENTS, DOCUMENTS OR CERTIFICATIONS DELIVERED IN CONNECTION THEREWITH, (iv) ANY LOAN OR LETTER OF CREDIT OR THE USE OF THE PROCEEDS THEREFROM, INCLUDING, WITHOUT LIMITATION, ANY REFUSAL BY ANY ISSUER TO HONOR A DEMAND FOR PAYMENT UNDER A LETTER OF CREDIT ISSUED BY SUCH ISSUER IF THE DOCUMENTS PRESENTED IN CONNECTION WITH SUCH DEMAND DO NOT STRICTLY COMPLY WITH THE TERMS OF SUCH LETTER OF CREDIT, (v) THE OPERATIONS OF THE BUSINESS OF THE BORROWER AND ITS SUBSIDIARIES BY THE BORROWER AND ITS SUBSIDIARIES, (vi) ANY ASSERTION BY A THIRD PARTY THAT THE LENDERS WERE NOT ENTITLED TO RECEIVE THE PROCEEDS RECEIVED PURSUANT TO THE SECURITY INSTRUMENTS, (iii) THE BREACH OR NON-COMPLIANCE BY THE BORROWER OR ANY OF ITS SUBSIDIARIES WITH ANY ENVIRONMENTAL LAW APPLICABLE TO THE BORROWER OR ANY OF ITS SUBSIDIARIES, (iv) THE PRESENCE, USE, RELEASE, STORAGE, TREATMENT, DISPOSAL, GENERATION, THREATENED RELEASE, TRANSPORT, ARRANGEMENT FOR TRANSPORT OR ARRANGEMENT FOR DISPOSAL OF OIL, OIL AND GAS WASTES, SOLID WASTES OR HAZARDOUS SUBSTANCES ON OR AT ANY OF THE PROPERTIES OWNED OR OPERATED BY THE BORROWER OR ANY OF ITS SUBSIDIARIES IN VIOLATION OF ENVIRONMENTAL LAWS OR ANY ACTUAL OR ALLEGED PRESENCE OR RELEASE OF HAZARDOUS MATERIALS ON OR FROM ANY PROPERTY OWNED OR OPERATED BY THE BORROWER OR ANY OF ITS SUBSIDIARIES IN VIOLATION OF ENVIRONMENTAL LAWS, (v) ANY ENVIRONMENTAL LIABILITY RELATED IN ANY WAY TO THE BORROWER OR ANY OF ITS SUBSIDIARIES, OR (vi) ANY OTHER VIOLATION OF ENVIRONMENTAL LAWS OR LAWS RELATING TO ANY HEALTH OR SAFETY CONDITION IN CONNECTION WITH THE LOAN DOCUMENTS, OR (vii) ANY ACTUAL OR PROSPECTIVE CLAIM, LITIGATION, INVESTIGATION OR PROCEEDING RELATING TO ANY OF THE FOREGOING, WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY AND REGARDLESS OF WHETHER ANY INDEMNITEE IS A PARTY THERETO, AND SUCH INDEMNITY SHALL EXTEND TO EACH INDEMNITEE NOTWITHSTANDING THE SOLE OR CONCURRENT NEGLIGENCE OF EVERY KIND OR CHARACTER WHATSOEVER, WHETHER ACTIVE OR PASSIVE, WHETHER AN AFFIRMATIVE ACT OR AN OMISSION, INCLUDING WITHOUT LIMITATION, ALL TYPES OF NEGLIGENT CONDUCT IDENTIFIED IN THE RESTATEMENT (SECOND) OF TORTS OF ONE OR MORE OF THE INDEMNITEES OR BY REASON OF STRICT LIABILITY IMPOSED WITHOUT FAULT ON ANY ONE OR MORE OF THE INDEMNITEES; PROVIDED THAT SUCH INDEMNITY SHALL NOT, AS TO ANY INDEMNITEE, BE AVAILABLE TO THE

EXTENT THAT SUCH LOSSES, CLAIMS, DAMAGES, LIABILITIES OR RELATED EXPENSES ARE DETERMINED BY A COURT OF COMPETENT JURISDICTION BY FINAL AND NONAPPEALABLE JUDGMENT TO HAVE RESULTED FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE.

(c) To the extent that the Borrower fails to pay any amount required to be paid by it to such Agent or any Issuer under Section 12.03(a) or (b), each Lender severally agrees to pay to such Agent or such Issuer, as the case may be, such Lender’s Applicable Percentage (determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against such Agent or such Issuer in its capacity as such.

(d) To the extent permitted by applicable law, the Borrower shall not assert, and hereby waives, any claim against any Indemnitee, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Loan Document or any agreement or instrument contemplated hereby or thereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.

(e) All amounts due under this Section 12.03 shall be payable within ten (10) Business Days of written demand therefor.

Section 12.04 Successors and Assigns.

(a) The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of any Issuer that issues any Letter of Credit), except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 12.04. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of any Issuer that issues any Letter of Credit), Participants (to the extent provided in Section 12.04(c)) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, each Issuer and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b) (i) Subject to the conditions set forth in Section 12.04(b)(ii), any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement to an Eligible Assignee (including all or a portion of its Commitment and the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld) of:

(A) the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender or an Affiliate of a Lender or, if an Event of Default has occurred and is continuing, to any other Eligible Assignee; and

(B) the Administrative Agent, provided that no consent of the Administrative Agent shall be required for an assignment to an assignee that is a Lender or any Affiliate of a Lender, immediately prior to giving effect to such assignment.

(ii) Assignments shall be subject to the following additional conditions:

(A) except in the case of an assignment to a Lender or an Affiliate of a Lender or an assignment of the entire remaining amount of the assigning Lender’s Commitment, the amount of the Commitment of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 unless each of the Borrower and the Administrative Agent otherwise consent, provided that no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing;

(B) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; and

(D) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(iii) Subject to Section 12.04(b)(iv) and the acceptance and recording thereof, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 5.01, Section 5.02, Section 5.03 and Section 12.03). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.04 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 12.04(c).

(iv) The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at one of its offices a copy of each Assignment and Assumption

delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Maximum Credit Amount of, and principal amount of the Loans and Letter of Credit Disbursements owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, and the Borrower, the Administrative Agent, each Issuer and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower, any Issuer and any Lender, at any reasonable time and from time to time upon reasonable prior notice. In connection with any changes to the Register, if necessary, the Administrative Agent will reflect the revisions on Annex I and forward a copy of such revised Annex I to the Borrower, each Issuer and each Lender.

(v) Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in Section 12.04(b) and any written consent to such assignment required by Section 12.04(b), the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this Section 12.04(b).

(c) (i) Any Lender may, without the consent of the Borrower the Administrative Agent or any Issuer, sell participations to one or more banks or other entities (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent, each Issuer and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the proviso to Section 12.02 that affects such Participant. In addition such agreement must provide that the Participant be bound by the provisions of Section 12.03. Subject to Section 12.04(c)(ii), the Borrower agrees that each Participant shall be entitled to the benefits of Section 5.01, Section 5.02 and Section 5.03 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.04(b). To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 12.08 as though it were a Lender, provided such Participant agrees to be subject to Section 4.01(c) as though it were a Lender.

(ii) A Participant shall not be entitled to receive any greater payment under Section 5.01 or Section 5.03 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent. A

Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 5.03 unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 5.03(e) as though it were a Lender.

(d) Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section 12.04(d) shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

Section 12.05 Survival; Revival; Reinstatement.

(a) All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent, any other Agent, any Issuer or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid or any Letter of Credit is outstanding and so long as the Commitments have not expired or terminated. The provisions of Section 5.01, Section 5.02, Section 5.03 and Section 12.03 and ARTICLE XI shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans, the expiration or termination of the Letters of Credit and the Commitments or the termination of this Agreement, any other Loan Document or any provision hereof or thereof.

(b) To the extent that any payments on the Indebtedness or proceeds of any collateral are subsequently invalidated, declared to be fraudulent or preferential, set aside or required to be repaid to a trustee, debtor in possession, receiver or other Person under any bankruptcy law, common law or equitable cause, then to such extent, the Indebtedness so satisfied shall be revived and continue as if such payment or proceeds had not been received and the Administrative Agent’s and the Lenders’ Liens, security interests, rights, powers and remedies under this Agreement and each Loan Document shall continue in full force and effect. In such event, each Loan Document shall be automatically reinstated and the Borrower shall take such action as may be reasonably requested by the Administrative Agent and the Lenders to effect such reinstatement.

Section 12.06 Counterparts; Integration; Effectiveness.

(a) This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.

(b) This Agreement, the other Loan Documents and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and thereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof and thereof. THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

(c) Except as provided in Section 6.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page of this Agreement by telecopy shall be effective as delivery of a manually executed counterpart of this Agreement.

Section 12.07 Severability . Any provision of this Agreement or any other Loan Document held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

Section 12.08 Right of Setoff . If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations (of whatsoever kind, including, without limitations obligations under Swap Agreements) at any time owing by such Lender or Affiliate to or for the credit or the account of the Borrower or any of its Subsidiaries against any of and all the obligations of the Borrower or any of its Subsidiaries owed to such Lender now or hereafter existing under this Agreement or any other Loan Document, irrespective of whether or not such Lender shall have made any demand under this Agreement or any other Loan Document and although such obligations may be unmatured. The rights of each Lender under this Section 12.08 are in addition to other rights and remedies (including other rights of setoff) which such Lender or its Affiliates may have.

Section 12.09 GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS.

(a) THIS AGREEMENT AND THE NOTES SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK EXCEPT TO THE EXTENT THAT UNITED STATES FEDERAL LAW PERMITS ANY LENDER TO CONTRACT FOR, CHARGE, RECEIVE, RESERVE OR TAKE INTEREST AT THE RATE ALLOWED BY THE LAWS OF THE STATE WHERE SUCH LENDER IS LOCATED.

(b) ANY LEGAL ACTION OR PROCEEDING WITH RESPECT TO THE LOAN DOCUMENTS MAY BE BROUGHT IN THE COURTS OF THE STATE OF NEW YORK OR OF THE UNITED STATES OF AMERICA, AND, BY EXECUTION AND DELIVERY OF THIS AGREEMENT, EACH PARTY HEREBY ACCEPTS FOR ITSELF AND (TO THE EXTENT PERMITTED BY LAW) IN RESPECT OF ITS PROPERTY, GENERALLY AND UNCONDITIONALLY, THE JURISDICTION OF THE AFORESAID COURTS. EACH PARTY HEREBY IRREVOCABLY WAIVES ANY OBJECTION, INCLUDING, WITHOUT LIMITATION, ANY OBJECTION TO THE LAYING OF VENUE OR BASED ON THE GROUNDS OF FORUM NON CONVENIENS, WHICH IT MAY NOW OR HEREAFTER HAVE TO THE BRINGING OF ANY SUCH ACTION OR PROCEEDING IN SUCH RESPECTIVE JURISDICTIONS. THIS SUBMISSION TO JURISDICTION IS NON-EXCLUSIVE AND DOES NOT PRECLUDE A PARTY FROM OBTAINING JURISDICTION OVER ANOTHER PARTY IN ANY COURT OTHERWISE HAVING JURISDICTION.

(c) EACH PARTY IRREVOCABLY CONSENTS TO THE SERVICE OF PROCESS OF ANY OF THE AFOREMENTIONED COURTS IN ANY SUCH ACTION OR PROCEEDING BY THE MAILING OF COPIES THEREOF BY REGISTERED OR CERTIFIED MAIL, POSTAGE PREPAID, TO IT AT THE ADDRESS SPECIFIED IN SECTION 12.01 OR SUCH OTHER ADDRESS AS IS SPECIFIED PURSUANT TO SECTION 12.01 (OR ITS ASSIGNMENT AND ASSUMPTION), SUCH SERVICE TO BECOME EFFECTIVE THIRTY (30) DAYS AFTER SUCH MAILING. NOTHING HEREIN SHALL AFFECT THE RIGHT OF A PARTY OR ANY HOLDER OF A NOTE TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR TO COMMENCE LEGAL PROCEEDINGS OR OTHERWISE PROCEED AGAINST ANOTHER PARTY IN ANY OTHER JURISDICTION.

(d) EACH PARTY HEREBY (i) IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN; (ii) IRREVOCABLY WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LITIGATION ANY SPECIAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES, OR DAMAGES OTHER THAN, OR IN ADDITION TO, ACTUAL DAMAGES; (iii) CERTIFIES THAT NO PARTY HERETO NOR ANY REPRESENTATIVE OR AGENT OF COUNSEL FOR ANY PARTY HERETO HAS REPRESENTED, EXPRESSLY OR OTHERWISE, OR IMPLIED THAT SUCH PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVERS, AND (iv) ACKNOWLEDGES THAT IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT, THE LOAN DOCUMENTS AND THE TRANSACTIONS CONTEMPLATED HEREBY AND THEREBY BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS CONTAINED IN THIS SECTION 12.09.

Section 12.10 Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

Section 12.11 Confidentiality. Each of the Agents, each Issuer and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) to any other party to this Agreement or any other Loan Document, (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any suit, action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section 12.11, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any Swap Agreement relating to the Borrower and their obligations, (g) with the consent of the Borrower or (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section 12.11 or (ii) becomes available to the Administrative Agent, any Issuer or any Lender on a nonconfidential basis from a source other than the Borrower. For the purposes of this Section 12.11, “Information” means all information received from the Borrower or any of its Subsidiaries relating to the Borrower or any of its Subsidiaries and their businesses, other than any such information that is available to the Administrative Agent, any Issuer or any Lender on a nonconfidential basis prior to disclosure by the Borrower or any of its Subsidiaries; provided that, in the case of information received from the Borrower, or any of its Subsidiaries after the date hereof, such information is clearly identified at the time of delivery as confidential. Any Person required to maintain the confidentiality of Information as provided in this Section 12.11 shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.

Section 12.12 Maximum Interest. It is the intention of the parties hereto to conform strictly to applicable usury laws and, anything herein to the contrary notwithstanding, the Obligations of the Borrower to each Lender under this Agreement shall be subject to the limitation that payments of interest shall not be required to the extent that receipt thereof would be contrary to provisions of law applicable to such Lender limiting rates of interest that may be charged or collected by such Lender. Accordingly, if the transactions contemplated hereby would be usurious under applicable law (including the Federal and state laws of the United States of America, or of any other jurisdiction whose laws may be mandatorily applicable) with respect to a Lender, then, in that event, notwithstanding anything to the contrary in this Agreement, it is agreed as follows: (a) the provisions of this Section 12.12 shall govern and control; (b) the aggregate of all consideration that constitutes interest under applicable law that is contracted for, charged or received under this Agreement, or under any other Loan Document or otherwise in connection with this Agreement by such Lender shall under no circumstances exceed the maximum amount of interest allowed by applicable law (such maximum lawful interest rate, if any, with respect to such Lender herein called the “Highest Lawful Rate”), and any excess shall be credited to the Borrower by such Lender (or, if such consideration shall have been paid in full, such excess promptly refunded to the Borrower); (c) all sums paid, or agreed to be paid, to such Lender for the use, forbearance and detention of the indebtedness of the

Borrower to such Lender hereunder shall, to the extent permitted by applicable law, be amortized, prorated, allocated and spread throughout the full term of such indebtedness until payment in full so that the actual rate of interest is uniform throughout the full term thereof; and (d) if at any time the interest provided pursuant to Section 3.02, together with any other fees and expenses payable pursuant to this Agreement and the other Loan Documents and deemed interest under applicable law, exceeds that amount that would have accrued at the Highest Lawful Rate, then the amount of interest and any such fees to accrue to such Lender pursuant to this Agreement shall be limited, notwithstanding anything to the contrary in this Agreement, to that amount that would have accrued at the Highest Lawful Rate, but any subsequent reductions, as applicable, shall not reduce the interest to accrue to such Lender pursuant to this Agreement below the Highest Lawful Rate until the total amount of interest accrued pursuant to this Agreement and such fees deemed to be interest equals the amount of interest that would have accrued to such Lender if a varying rate per annum equal to the interest provided pursuant to Section 3.02 had at all times been in effect, plus the amount of fees that would have been received but for the effect of this Section 12.12.

Section 12.13 EXCULPATION PROVISIONS. EACH OF THE PARTIES HERETO SPECIFICALLY AGREES THAT IT HAS A DUTY TO READ THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS AND AGREES THAT IT IS CHARGED WITH NOTICE AND KNOWLEDGE OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; THAT IT HAS IN FACT READ THIS AGREEMENT AND IS FULLY INFORMED AND HAS FULL NOTICE AND KNOWLEDGE OF THE TERMS, CONDITIONS AND EFFECTS OF THIS AGREEMENT; THAT IT HAS BEEN REPRESENTED BY INDEPENDENT LEGAL COUNSEL OF ITS CHOICE THROUGHOUT THE NEGOTIATIONS PRECEDING ITS EXECUTION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND HAS RECEIVED THE ADVICE OF ITS ATTORNEY IN ENTERING INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND THAT IT RECOGNIZES THAT CERTAIN OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS RESULT IN ONE PARTY ASSUMING THE LIABILITY INHERENT IN SOME ASPECTS OF THE TRANSACTION AND RELIEVING THE OTHER PARTY OF ITS RESPONSIBILITY FOR SUCH LIABILITY. EACH PARTY HERETO AGREES AND COVENANTS THAT IT WILL NOT CONTEST THE VALIDITY OR ENFORCEABILITY OF ANY EXCULPATORY PROVISION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS ON THE BASIS THAT THE PARTY HAD NO NOTICE OR KNOWLEDGE OF SUCH PROVISION OR THAT THE PROVISION IS NOT “CONSPICUOUS.”

Section 12.14 Collateral Matters; Swap Agreements. The benefit of the Security Instruments and of the provisions of this Agreement relating to any collateral securing the Indebtedness shall also extend to and be available to those Lenders or their Affiliates which are counterparties to any Swap Agreement with the Borrower or any of its Subsidiaries on a pro rata basis in respect of any obligations of the Borrower or any of its Subsidiaries which arise under any such Swap Agreement while such Person or its Affiliate is a Lender, but only while such Person or its Affiliate is a Lender, including any Swap Agreements between such Persons in existence prior to the date hereof. No Lender or any Affiliate of a Lender shall have any voting rights under any Loan Document as a result of the existence of obligations owed to it under any such Swap Agreements.

Section 12.15 No Third Party Beneficiaries. This Agreement, the other Loan Documents, and the agreement of the Lenders to make Loans and the Issuer to issue, amend, renew or extend Letters of Credit hereunder are solely for the benefit of the Borrower, and no other Person (including, without limitation, any Subsidiary of the Borrower, any obligor, contractor, subcontractor, supplier or materialsman) shall have any rights, claims, remedies or privileges hereunder or under any other Loan Document against the Administrative Agent, any other Agent, the Issuer or any Lender for any reason whatsoever. There are no third party beneficiaries.

Section 12.16 USA Patriot Act Notice. Each Lender hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender to identify the Borrower in accordance with the Act.

[SIGNATURES BEGIN NEXT PAGE]

The parties hereto have caused this Agreement to be duly executed as of the day and year first above written.


BORROWER:		CONSTELLATION ENERGY PARTNERS LLC

		By:
		Name:
		Title:

SIGNATURE PAGE 1

CREDIT AGREEMENT

Schedule 7.22


THE ROYAL BANK OF SCOTLAND plc, as Administrative Agent and a Lender

By:
Name:		Phillip R. Ballard
Title:		Managing Director

SIGNATURE PAGE 2

CREDIT AGREEMENT


[ , as a Lender

By:
Name:
Title:

SIGNATURE PAGE 3

CREDIT AGREEMENT


[ , as a Lender

By:
Name:
Title:

SIGNATURE PAGE 4

CREDIT AGREEMENT

Form of Management Services Agreement

Exhibit 10.2

MANAGEMENT SERVICES AGREEMENT

THIS MANAGEMENT SERVICES AGREEMENT (the “Agreement”), made as of the day of , 2006, is by and among Constellation Energy Partners Management, LLC, a Delaware limited liability company (“CEPM”), and Constellation Energy Partners LLC, a Delaware limited liability company (the “Company”).

WHEREAS, subject to the terms hereof, the Company desires to engage CEPM, and CEPM desires to be engaged, to provide or cause to be provided the services described herein relating to the management of the Company’s business.

NOW, THEREFORE, in consideration of the mutual covenants herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto (each, a “Party” and together, the “Parties”) agree as follows:

ARTICLE I

DEFINITIONS

1.1 Defined Terms. Capitalized terms used, but not defined herein, shall have the meanings given them in the LLC Agreement. As used in this Agreement, the following terms shall have the respective meanings set forth below:

“Acquisition” means any acquisition or series of acquisitions by the Company or any of its subsidiaries of (i) all or substantially all of the interest in any company or business (whether by a purchase of assets, purchase of stock, merger or otherwise); or (ii) any oil or natural gas properties or interests, including any related assets, acquired after the date of this Agreement.

“Acquisition Information” means any and all information provided by or on behalf of CEPM to the Company in the performance of the Services relating to potential Acquisitions.

“Acquisition Services” means those Optional Services in respect of potential and consummated Acquisitions.

“Affiliate” means, with respect to a Person, any other Person controlling, controlled by or under common control with such Person.

“Agreement” means this Agreement, as it may be amended from time to time.

“Applicable Time” means the period commencing on the date of this Agreement and ending on the later of (i) December 31, 2007 and (ii) the end of the Consolidation Period.

“Board” means the Company’s Board of Managers.

“Business Day” means any day that is not a Saturday, Sunday or day on which banks are authorized by law to close in the States of Maryland or Texas.

“CEPM Expenses” has the meaning given that term in Section 4.1.

“Closing Date” means the date of the closing of the initial public offering, pursuant to the Prospectus, of common units representing Class B limited liability company interests in the Company.

“Company” has the meaning set forth in the above preamble.

“Confidential Information” means all information (i) furnished to CEPM or its representatives by or on behalf of the Company or (ii) prepared by or at the direction of the Company (in each case irrespective of the form of communication and whether such information is furnished before, on or after the date hereof), and all analyses, compilations, data, studies, notes, interpretations, memoranda or other documents prepared by CEPM or its representatives containing or based in whole or in part on any such furnished information.

“Conflicts Committee” has the meaning given such term in the LLC Agreement.

“Consolidation Period” means that period that commences on the date of this Agreement and ends on the first date as of which the Company and its consolidated subsidiaries cease to be consolidated with Constellation and its consolidated subsidiaries for US GAAP purposes.

“Constellation” means Constellation Energy Group, Inc.

“Exclusive Services” means those Services described in Exhibit A under the caption “Exclusive Services.”

“Governmental Authority” has the meaning given such term in the LLC Agreement.

“LLC Agreement” means the Second Amended and Restated Operating Agreement of the Company, dated as of the Closing Date, as such agreement is in effect on the Closing Date, to which reference is hereby made for all purposes of this Agreement. An amendment or modification to the LLC Agreement subsequent to the Closing Date shall be given effect for the purposes of this Agreement only if it has received the approval that would be required pursuant to Section 9.10 hereof if such amendment or modification were an amendment or modification of this Agreement.

“Optional Services” means those Services described in Exhibit A under the caption “Optional Services.”

“Person” means any individual, corporation, partnership, business trust, limited liability company, joint venture, association, joint-stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“Proceedings” means all proceedings, actions, claims, suits and notices of investigations by or before any arbitrator or Governmental Authority.

“Properties” means the oil and gas properties now owned or hereafter acquired by the Company, including oil and gas leases, mineral interests, royalty interests, overriding royalty

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interests, pipelines, flow lines, gathering lines, gathering systems, compressors, dehydration units, separators, meters, injection facilities, salt water disposal wells and facilities, plants, wells, downhole and surface equipment, fixtures, improvements, easements, rights-of-way, surface leases, licenses, permits and other surface rights, and other real or personal property appurtenant thereto or used in conjunction therewith.

“Prospectus” means the final prospectus, dated October __, 2006, relating to the initial public offering of common units representing Class B limited liability company interests in the Company, as filed with Securities and Exchange Commission pursuant to Rule 424(b) under the Securities Act of 1933.

“Requested Services” means those Services described in Exhibit A under the caption “Requested Services.”

“Services” means the services and items provided (or to be provided) by or on behalf of CEPM pursuant to this Agreement.

“Tax Authority” means any Governmental Authority having jurisdiction over the assessment, determination, collection or imposition of any Tax.

“Tax Return” means any report, return, election, document, estimated tax filing, declaration or other filing provided to any Tax Authority, including any amendments thereto.

“Taxes” means (i) all taxes, assessments, charges, duties, levies, imposts or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, excise, severance, windfall profits, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental (including taxes under Code section 59A), alternative minimum, add-on, value-added, withholding and other taxes, assessments, charges, duties, levies, imposts or other similar charges of any kind whatsoever (whether payable directly or by withholding and whether or not requiring the filing of a Tax Return), and all estimated taxes, deficiency assessments, additions to tax, additional amounts imposed by any Governmental Authority, penalties and interest, but excluding any and all taxes based on net income, net worth, capital or profit; (ii) any liability for the payment of any amount of the type described in the immediately preceding clause (i) as a result of being a member of a consolidated, affiliated, unitary, combined, or similar group with any other corporation or entity at any time on or prior to the Closing Date; and (iii) any liability for the payment of any amount of the type described in the preceding clauses (i) or (ii) whether as a result of contractual obligations to any other Person or operation of law.

“Third Party” means any Person other than the Company or CEPM, or any of their respective Affiliates, or any member of the Company.

“US GAAP” means those generally accepted accounting principles and practices that are recognized as such by the Financial Accounting Standards Board (or any generally recognized successor).

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1.2 Other Definitions. Words not otherwise defined herein that have well-known and generally accepted technical or trade meanings in the oil and gas industry are used herein in accordance with such recognized meanings.

1.3 Construction. As used in this Agreement, unless expressly stated otherwise, references to “includes” and its derivatives mean “includes, but is not limited to,” and corresponding derivative expressions. Unless otherwise specified, all references in this Agreement to “Sections” and “Exhibits” are references to the corresponding sections in and exhibits attached to this Agreement; all such exhibits are incorporated herein by reference.

ARTICLE II

PROVISION OF SERVICES

2.1 Exclusive Services. During the Applicable Time, CEPM shall provide, or, with the approval of the Board, cause another Person or Persons to provide, the Exclusive Services to the Company. The Company covenants that, during the Applicable Time, it will use the Exclusive Services provided by or on behalf of CEPM, and will refrain from employing, engaging or using any other Person to perform such services without the prior written consent of CEPM.

2.2 Requested Services. CEPM shall, upon the Company’s request, provide or, with the approval of the Board, cause another Person or Persons to provide, any Requested Services in the manner so requested and at the direction of the Company.

2.3 Optional Services. CEPM may, but shall not be obligated to, provide or, with the approval of the Board, cause another Person or Persons to provide, Optional Services, including Acquisition Services, upon the request of the Company in the manner so requested and at the direction of the Company.

2.4 CEPM Information. It is contemplated by the Parties that, during the term of this Agreement, the Company will be required to provide certain notices, information and data necessary for CEPM to perform the Services and its obligations under this Agreement. CEPM shall be permitted to rely on any information or data provided by the Company to CEPM in connection with the performance of its duties and provision of Services under this Agreement, except to the extent that CEPM has actual knowledge that such information or data is inaccurate or incomplete.

ARTICLE III

STANDARD OF CARE

3.1 Standard of Care. CEPM shall perform the Services in an honest and good faith manner, with that degree of care, diligence and skill that a reasonably prudent advisor and manager would exercise in comparable circumstances, and in compliance with applicable laws, regulations, contracts, leases, orders, security instruments and other agreements to which the Company is a party or by which the Company or any of its Properties are bound.

3.2 Procurement of Goods and Services. To the extent that CEPM is permitted to arrange for contracts with Third Parties for goods and services in connection with the provision

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of the Services, CEPM shall use commercially reasonable efforts (i) to obtain such goods and services at rates competitive with those otherwise generally available in the area in which services or materials are to be furnished, and (ii) to obtain from such Third Parties such customary warranties and guarantees as may be reasonably required with respect to the goods and services so furnished.

3.3 Protection from Liens. In the course of providing the Services, CEPM shall not permit any liens, encumbrances or charges upon any of the Properties arising from the provision of Services or materials under this Agreement except as approved, or consented to, by the Company.

3.4 Commingling of Assets. To the extent CEPM shall have charge or possession of any of the Company’s assets in connection with the provision of the Services, CEPM shall separately maintain, and not commingle, the assets of the Company with those of CEPM or any other Person.

3.5 Insurance. CEPM shall obtain and maintain during the term of this Agreement, from insurers who are reliable and acceptable to the Company and authorized to do business in the state or states or jurisdictions in which Services are to be performed by CEPM, insurance coverages in the types and minimum limits as the Parties determine to be appropriate and as is consistent with standard industry practice. CEPM agrees upon the Company’s request from time to time or at any time to provide the Company with certificates of insurance evidencing such insurance coverage and, upon request of the Company, shall furnish copies of such policies. Except with respect to workers’ compensation coverage, the policies shall name the Company as an additional insured and shall contain waivers by the insurers of any and all rights of subrogation to pursue any claims or causes of action against the Company. The policies shall provide that they will not be cancelled or reduced without giving the Company at least 30 days’ prior written notice of such cancellation or reduction.

3.6 Third-Party Intellectual Property. If CEPM uses or licenses intellectual property owned by Third Parties in the performance of the Services, CEPM shall obtain and maintain any such licenses and authorizations necessary to authorize its use of such intellectual property in connection with the Services.

3.7 Competition. Subject to ARTICLE VI, each of CEPM, Constellation and their respective Affiliates is and shall be free to engage in any business activity whatsoever, including those that may be in direct competition with the Company and its Affiliates.

ARTICLE IV

CEPM REIMBURSEMENT; CONTINUING OBLIGATIONS

4.1 CEPM Expenditures. On or before the 45th day following each calendar quarter during the term hereof, the Company shall pay CEPM, in the manner provided in Section 4.3, with respect to any Services provided by CEPM hereunder during such calendar quarter, the general, administrative and similar allocable overhead costs, as well as any costs of services or goods purchased from Third Parties, incurred by CEPM in the performance of such Services (the “CEPM Expenses”). The CEPM Expenses shall be charged to the Company without mark-up,

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interest or other profit to CEPM or its Affiliates. Should CEPM commence providing Acquisition Services with respect to a particular project, the Company shall reimburse CEPM for all CEPM Expenses incurred in connection with such Acquisition Services to the extent related to such project regardless of whether the Company completes such project acquisition.

4.2 Reporting. On or before the 15th day following each calendar quarter during the term hereunder, CEPM shall provide the Company with an invoice for the aggregate CEPM Expenses relating to such calendar quarter. CEPM’s invoice therefor shall also provide reasonably detailed documentation supporting such CEPM Expenses.

4.3 Manner of Payment. All payments required under this ARTICLE IV shall be made by wire of immediately available funds or check as follows:

If by wire:

Such account information to be provided by CEPM

If by check:

Constellation Energy Partners Management, LLC

111 Market Place

Baltimore, Maryland 21202

Attn: Treasury Department

4.4 Taxes. The Company shall be responsible for all applicable Taxes levied on items, goods or services that are sold, purchased or obtained pursuant to this Agreement, including the Services.

4.5 Disputed Charges. THE COMPANY MAY, WITHIN 120 DAYS AFTER RECEIPT OF A CHARGE FROM CEPM, TAKE WRITTEN EXCEPTION TO SUCH CHARGE, ON THE GROUND THAT THE SAME WAS NOT A REASONABLE COST INCURRED BY CEPM IN CONNECTION WITH THE SERVICES. THE COMPANY SHALL NEVERTHELESS PAY CEPM IN FULL WHEN DUE THE FULL INVOICED AMOUNT. SUCH PAYMENT SHALL NOT BE DEEMED A WAIVER OF THE RIGHT OF THE COMPANY TO RECOUP ANY CONTESTED PORTION OF ANY AMOUNT SO PAID. HOWEVER, IF THE AMOUNT AS TO WHICH SUCH WRITTEN EXCEPTION IS TAKEN, OR ANY PART THEREOF, IS ULTIMATELY DETERMINED NOT TO BE A REASONABLE COST INCURRED BY CEPM IN CONNECTION WITH ITS PROVIDING THE SERVICES HEREUNDER, SUCH AMOUNT OR PORTION THEREOF (AS THE CASE MAY BE) SHALL BE REFUNDED BY CEPM TO THE COMPANY TOGETHER WITH INTEREST THEREON AT THE LESSER OF THE PRIME RATE PER ANNUM ESTABLISHED BY CITIBANK, NA AS IN EFFECT ON THE DATE OF THIS AGREEMENT OR THE MAXIMUM LAWFUL RATE DURING THE PERIOD FROM THE DATE OF PAYMENT BY THE COMPANY TO THE DATE OF REFUND BY CEPM.

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ARTICLE V

INDEMNIFICATION; LIMITATIONS

5.1 Indemnification by CEPM. CEPM hereby agrees to DEFEND, INDEMNIFY AND HOLD HARMLESS the Company and its officers, managers, members, partners, directors, employees, agents and Affiliates (collectively, the “Company Indemnitees”) from any and all threatened or actual claims, demands, causes of action, suits, proceedings, losses, damages, fines, penalties, liabilities, costs and expenses of any nature, including attorneys’ fees and court costs (collectively, “Liabilities”), sustained by, incurred by, arising in favor of or asserted by any Third Parties, employees, agents and representatives of CEPM, or any contractors or subcontractors of CEPM, in any way relating to the performance of Services hereunder (including any claims for personal injury, property loss or damage, bodily injury, illness or death), excluding, in all cases, Company Claims.

5.2 Indemnification by the Company. The Company hereby agrees to DEFEND, INDEMNIFY AND HOLD HARMLESS CEPM and its officers, managers, members, partners, directors, employees, agents and Affiliates (collectively, the “CEPM Indemnitees”) from any and all threatened and actual Liabilities sustained by, incurred by, arising in favor of or asserted by any Third Parties, employees, agents and representatives of the Company, or any contractors or subcontractors of the Company, in any way relating to the Company’s gross negligence, willful misconduct, breach of this Agreement or violation of applicable law (each, a “Company Claim”).

5.3 Negligence; Strict Liability. EXCEPT AS EXPRESSLY PROVIDED IN SECTIONS 5.1 AND 5.2, THE DEFENSE AND INDEMNITY OBLIGATIONS IN SECTIONS 5.1 AND 5.2 SHALL APPLY REGARDLESS OF CAUSE OR OF ANY NEGLIGENT ACTS OR OMISSIONS (INCLUDING SOLE NEGLIGENCE, CONCURRENT NEGLIGENCE OR STRICT LIABILITY), BREACH OF DUTY (STATUTORY OR OTHERWISE), VIOLATION OF LAW OR OTHER FAULT OF ANY INDEMNIFIED PARTY, OR ANY PRE-EXISTING DEFECT; PROVIDED, HOWEVER, THAT THIS PROVISION SHALL IN NO WAY LIMIT OR ALTER ANY QUALIFICATIONS SET FORTH IN SUCH DEFENSE AND INDEMNITY OBLIGATIONS EXPRESSLY RELATING TO GROSS NEGLIGENCE, INTENTIONAL MISCONDUCT OR BREACH OF THIS AGREEMENT. BOTH PARTIES AGREE THAT THIS STATEMENT COMPLIES WITH THE REQUIREMENT KNOWN AS THE ‘EXPRESS NEGLIGENCE RULE’ TO EXPRESSLY STATE IN A CONSPICUOUS MANNER AND TO AFFORD FAIR AND ADEQUATE NOTICE THAT THIS ARTICLE HAS PROVISIONS REQUIRING ONE PARTY TO BE RESPONSIBLE FOR THE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF ANOTHER PARTY.

5.4 Exclusion of Damages; Disclaimers.

(a) NO PARTY SHALL BE LIABLE TO ANY OTHER PARTY HERETO FOR EXEMPLARY, PUNITIVE, CONSEQUENTIAL, SPECIAL, INDIRECT OR INCIDENTAL DAMAGES, EVEN IF ADVISED OF THE POSSIBILITY OF SUCH DAMAGES AND REGARDLESS OF THE FORM IN WHICH ANY ACTION IS BROUGHT.

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(b) CEPM DISCLAIMS ANY AND ALL WARRANTIES, CONDITIONS OR REPRESENTATIONS (EXPRESS OR IMPLIED, ORAL OR WRITTEN) WITH RESPECT TO THE SUBJECT MATTER HEREOF, OR ANY PART THEREOF, INCLUDING ANY AND ALL IMPLIED WARRANTIES OF NON-INFRINGEMENT, MERCHANTABILITY OR FITNESS OR SUITABILITY FOR ANY PURPOSE (WHETHER CEPM KNOWS, HAS REASON TO KNOW, HAS BEEN ADVISED, OR IS OTHERWISE IN FACT AWARE OF ANY SUCH PURPOSE) WHETHER ALLEGED TO ARISE BY LAW, BY REASON OF CUSTOM OR USAGE IN THE TRADE OR BY COURSE OF DEALING.

5.5 Survival. The provisions of this ARTICLE V shall survive the termination of this Agreement.

ARTICLE VI

CONFIDENTIALITY

6.1 Confidential Information.

(a) Non-disclosure. CEPM shall maintain the confidentiality of all Confidential Information; provided, however, that CEPM may disclose such Confidential Information (i) to Constellation Energy Commodities Group, Inc. to the extent deemed by CEPM to be reasonably necessary or desirable to enable it to perform the Services; (ii) in any judicial or alternative dispute resolution Proceeding to resolve disputes between CEPM and the Company arising hereunder; (iii) to the extent disclosure is legally required under applicable laws (including applicable securities and tax laws) or any agreement to which CEPM is a party or by which it is bound; provided, however, that prior to making any legally required disclosures in any judicial, regulatory or dispute resolution Proceeding, CEPM shall, if requested by the Company, seek a protective order or other relief to prevent or reduce the scope of such disclosure; (iv) to CEPM’s existing or potential lenders, investors, joint interest owners, purchasers or other parties with whom CEPM may enter into contractual relationships, to the extent deemed by CEPM to be reasonably necessary or desirable to enable it to perform the Services; provided, however, that CEPM shall require such Third Parties to agree to maintain the confidentiality of the Confidential Information so disclosed; (v) if authorized by the Company; and (vi) to the extent such Confidential Information becomes publicly available other than through a breach by CEPM of its obligation arising under this Section 6.1(a). CEPM acknowledges and agrees that the Confidential Information is being furnished to CEPM for the sole and exclusive purpose of enabling it to perform the Services, and the Confidential Information may not be used by it for any other purpose.

(b) Remedies and Enforcement. CEPM acknowledges and agrees that a breach by it of its obligations under this ARTICLE VI would cause irreparable harm to the Company and that monetary damages would not be adequate to compensate the Company. Accordingly, CEPM agrees that the Company shall be entitled to immediate equitable relief, including a temporary or permanent injunction, to prevent any threatened, likely or ongoing violation by CEPM, without the necessity of posting bond or other security. The Company’s right to equitable relief shall be in addition to other rights and remedies available to the Company, for monetary damages or otherwise.

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6.2 Acquisition Information.

(a) Non-disclosure. Except as provided in Section 6.2(b), the Company shall maintain the confidentiality of all Acquisition Information. The Company acknowledges and agrees that the Acquisition Information is being furnished to the Company for the sole and exclusive purpose of enabling it to make Acquisitions, and the Acquisition Information may not be used by it for any other purpose.

(b) Exceptions. The Company may disclose such Acquisition Information (i) in any judicial or alternative dispute resolution Proceeding to resolve disputes between the Company and CEPM arising hereunder; (ii) to the extent disclosure is legally required under applicable laws (including applicable securities and tax laws) or any agreement to which the Company is a party or by which it is bound; provided, however, that prior to making any legally required disclosures in any judicial, regulatory or dispute resolution Proceeding, the Company shall, if requested by CEPM, seek a protective order or other relief to prevent or reduce the scope of such disclosure; (iv) if authorized by the Company; and (v) to the extent such Acquisition Information becomes publicly available other than through a breach by the Company of its obligation arising under Section 6.2(a).

(c) Remedies and Enforcement. The Company acknowledges and agrees that a breach by it of its obligations under this ARTICLE VI would cause irreparable harm to CEPM and that monetary damages would not be adequate to compensate CEPM. Accordingly, the Company agrees that CEPM shall be entitled to immediate equitable relief, including a temporary or permanent injunction, to prevent any threatened, likely or ongoing violation by the Company, without the necessity of posting bond or other security. CEPM’s right to equitable relief shall be in addition to other rights and remedies available to CEPM, for monetary damages or otherwise.

6.3 Survival. The provisions of this ARTICLE VI shall survive the termination of this Agreement.

ARTICLE VII

TERM AND TERMINATION

7.1 Term.

(a) Unless sooner terminated in accordance with the provisions of Section 7.1(b), this Agreement shall remain in force and effect through December 31, 2007 (the “Initial Term”), and shall thereafter continue on a year-to-year basis.

(b) Notwithstanding anything stated herein to the contrary, this Agreement may be terminated by either Party at any time prior to the expiration of the Initial Term, or, as the case may be, prior to the expiration of any applicable annual term thereafter, upon any of the following:

(i) six months’ notice to the other Party; provided, however, that the no Party may terminate this Agreement pursuant to this Section 7.1(b)(i) prior to December 31, 2007 other than in accordance with Section 7.1(b)(ii) or Section 7.1(b)(iii);

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(ii) by CEPM upon the Company’s material breach of this Agreement, if such (a) breach is not remedied within 60 days (or 30 days in the event of material breach arising out of a failure to make payment hereunder) after the Company’s receipt of written notice thereof, or such longer period as is reasonably required to cure such breach, provided that the Company commences to cure such breach within the applicable period and proceeds with due diligence to cure such breach and (b) such breach is continuing at the time notice of termination is delivered to the Company; or

(iii) by the Company upon CEPM’s material breach of this Agreement, if (a) such breach is not remedied within 60 days after CEPM’s receipt of the Company’s written notice thereof, or such longer period as is reasonably required to cure such breach, provided that CEPM commences to cure such breach within such 60-day period and proceeds with due diligence to cure such breach and (b) such breach is continuing at the time notice of termination is delivered to CEPM.

7.2 Survival. The provisions of ARTICLE IV (with respect to unpaid amounts due hereunder), Section 4.5, ARTICLE V and ARTICLE VI shall survive any termination of this Agreement.

ARTICLE VIII

AUDIT RIGHTS

At any time during the term of this Agreement, the Company shall have the right to review and, at the Company’s expense, to copy the books and records maintained by CEPM relating to the Services. In addition, to the extent necessary to verify the performance by CEPM of its obligations under this Agreement, the Company shall have the right, at the Company’s expense, to audit, examine and make copies of or extracts from the books and records of CEPM (the “Audit Right”). The Company may exercise the Audit Right through such auditors as the Company may determine in its sole discretion. The Company shall (i) exercise the Audit Right only upon reasonable written notice to CEPM and during normal business hours and (ii) use its reasonable efforts to conduct the Audit Right in such a manner as to minimize the inconvenience and disruption to CEPM.

ARTICLE IX

MISCELLANEOUS PROVISIONS

9.1 Notices. All notices or advices required or permitted to be given by or pursuant to this Agreement, shall be given in writing. All such notices and advices shall be (i) delivered personally, (ii) delivered by facsimile or delivered by U.S. registered or certified mail, return receipt requested mail, or (iii) delivered for overnight delivery by a nationally recognized overnight courier service. Such notices and advices shall be deemed to have been given (i) on the date of delivery if delivered personally or by facsimile, (ii) on the third Business Day

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following the date of mailing if mailed by U.S. registered or certified mail, return receipt requested, or (iii) on the date of receipt if delivered for overnight delivery by a nationally recognized overnight courier service. All such notices and advices and all other communications related to this Agreement shall be given as follows:

If to CEPM:

Constellation Energy Partners Management, LLC

Attn: Legal Department

111 Market Place

Baltimore, Maryland 21202

Telephone: (410) 468-3500

Fax: (410) 468-3499

If to the Company:

Constellation Energy Partners LLC

Attn: Legal Department

111 Market Place

Baltimore, Maryland 21202

Telephone: (410) 468-3500

Fax: (410) 468-3499

or to such other address as the party may have furnished to the other parties in accordance herewith, except that notice of change of addresses shall be effective only upon receipt.

9.2 Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the State of New York, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each Party hereby submits to the non-exclusive jurisdiction of the federal courts in the State of New York and to venue in New York, New York.

9.3 Entire Agreement. This Agreement is the entire Agreement of the Parties respecting the subject matter hereof. There are no other agreements, representations or warranties, whether oral or written, respecting the subject matter hereof, and this Agreement supersedes and replaces any such prior agreements, representations or warranties.

9.4 Jointly Drafted. This Agreement, and all the provisions of this Agreement, shall be deemed drafted by both of the Parties, and shall not be construed against either Party on the basis of that Party’s role in drafting this Agreement.

9.5 Further Assurances. In connection with this Agreement, each Party shall execute and deliver any additional documents and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement.

9.6 Assignment. This Agreement may not be assigned by any Party without the prior written consent of the other Party. This Agreement shall be binding upon and shall inure to the benefit of the Parties and their respective successors and permitted assigns.

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9.7 No Third-Party Beneficiaries. Nothing in this Agreement (except as specifically provided in ARTICLE V) shall provide any benefit to any Third Party or entitle any Third Party to any claim, cause of action, remedy or right of any kind, it being the intent of the Parties that this Agreement shall not be construed as a third-party beneficiary contract.

9.8 Relationship of the Parties. Nothing in this Agreement shall be construed to create a partnership or joint venture or give rise to any fiduciary or similar relationship of any kind.

9.9 Effect of Waiver or Consent. No waiver or consent, express or implied, by any Party to or of any breach or default by any Person in the performance by such Person of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a Party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such Party of its rights hereunder until the applicable statute of limitations period has run.

9.10 Amendment or Modification. This Agreement may be amended, restated or modified from time to time only by the written agreement of both of the Parties; provided, however, that the Company may not, without the prior approval of the Conflicts Committee, agree to any amendment or modification of this Agreement that will adversely affect the holders of Common Units. Each such instrument shall be reduced to writing and shall be designated on its face an “Amendment,” “Addendum” or a “Restatement” to this Agreement.

9.11 Severability. If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

9.12 Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if both of the signatory Parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument.

9.13 Withholding or Granting of Consent. Except as expressly provided to the contrary in this Agreement, each Party may, with respect to any consent or approval that it is entitled to grant pursuant to this Agreement, grant or withhold such consent or approval in its sole and uncontrolled discretion, with or without cause, and subject to such conditions as it shall deem appropriate.

9.14 Laws and Regulations. Notwithstanding any provision of this Agreement to the contrary, no Party shall be required to take any act, or fail to take any act, under this Agreement if the effect thereof would be to cause such Party to be in violation of any applicable law, statute, rule or regulation.

9.15 Negation of Rights of Members, Assignees and Third Parties. The provisions of this Agreement are enforceable solely by the Parties, and no member or assignee of the Company, or other Person shall have the right, separate and apart from the Company, to enforce any provision of this Agreement or to compel any Party to comply with the terms of this Agreement.

9.16 No Recourse Against Officers, Directors, Managers or Employees. For the avoidance of doubt, the provisions of this Agreement shall not give rise to any right of recourse against any officer, director, manager or employee of CEPM, the Company or any of their respective Affiliates.

[SIGNATURE PAGES FOLLOWS]

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IN WITNESS WHEREOF, the Parties have executed this Agreement on, and to be effective as of, the Closing Date.


“CEPM”

CONSTELLATION ENERGY PARTNERS MANAGEMENT, LLC

By:
Name:
Title:
Date:

“COMPANY”

CONSTELLATION ENERGY PARTNERS LLC

By:
Name:
Title:
Date:

EXHIBIT A

Description of Services

EXCLUSIVE SERVICES

(a)

Accounting;

(b)

Audit;

(c)

Legal;

(d)

Risk Management; and

(e)

Tax.

REQUESTED SERVICES

(a)

Benefits, Compensation and Human Resources Administration;

(b)

Bonds (performance, appeal, environmental and surety);

(c)

Cash Management;

(d)

Consulting;

(e)

Corporate Finance;

(f)

Credit and Debt Administration;

(g)

Employee Health and Safety;

(h)

Engineering;

(i)

Environmental;

(j)

Financial, Planning and Analysis;

(k)

Geological and Geophysical;

(l)

Government and Public Relations;

(m)

Hedging and Derivatives;

(n)

Information Technology;

(o)

Insurance;

(p)

Investor Relations;

(q)

Land Administration;

(r)

Payroll;

(s)

Property Management;

(t)

Purchasing and Materials Management;

(u)

Reservoir Engineering;

(v)

Security;

(w)

Technical;

(x)

Travel;

(y)

Treasury; and

(z)

from and after the termination of the Applicable Time, the Exclusive Services.

OPTIONAL SERVICES

Any other services agreed by the Parties to be provided by CEPM or its designee, including Acquisition Services.

EXH-A-1

Form of Omnibus Agreement

Exhibit 10.3

OMNIBUS AGREEMENT

AMONG

CONSTELLATION ENERGY COMMODITIES GROUP, INC.

CONSTELLATION ENERGY PARTNERS LLC

ROBINSON’S BEND II PRODUCTION, LLC

ROBINSON’S BEND II OPERATING, LLC

AND

ROBINSON’S BEND II MARKETING, LLC

OMNIBUS AGREEMENT

THIS OMNIBUS AGREEMENT is entered into on, and effective as of, the Closing Date, among Constellation Energy Commodities Group, Inc., a Delaware corporation (“CCG”), Constellation Energy Partners LLC, a Delaware limited liability company (the “Company”), Robinson’s Bend II Production, LLC, a Delaware limited liability company (“Production”), Robinson’s Bend II Operating, LLC, a Delaware limited liability company (“Operating”) and Robinson’s Bend II Marketing, LLC, a Delaware limited liability company (“Marketing”). The above-named entities are sometimes referred to in this Agreement each as a “Party” and collectively as the “Parties.”

WHEREAS, the Parties desire by their execution of this Agreement to evidence their understanding, as more fully set forth in Article 2 of this Agreement, with respect to certain indemnification obligations of CCG.

NOW, THEREFORE, in consideration of the premises and the covenants, conditions and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

ARTICLE 1

Construction

Section 1.1 Definitions. Capitalized terms used, but not defined herein, shall have the meanings given them in the LLC Agreement. As used in this Agreement, the following terms shall have the respective meanings set forth below:

“Agreement” means this Omnibus Agreement, as it may be amended, modified or supplemented from time to time in accordance with the terms hereof.

“CCG Entity” means any of CCG and Persons controlled by CCG, in each case other than the members of the Company Group.

“Claim Notice” has the meaning provided such term in Section 2.3(a).

“Closing Date” means the date of the closing of the initial public offering, pursuant to the Prospectus, of Common Units.

“Common Units” has the meaning given such term in the LLC Agreement.

“Company” has the meaning given such term in the preamble to this Agreement.

“Company Group” means the Company, Production, Operating, Marketing and any Subsidiary of any such Person.

“Conflicts Committee” has the meaning given such term in the LLC Agreement.

“Constellation” means Constellation Energy Group, Inc.

“control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of Voting Securities, by contract or otherwise.

“Covered Counsel” has the meaning given such term in Section 2.3(b).

“Direct Claim” has the meaning given such term in Section 2.3(d).

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

“Expiration Date” has the meaning given such term in Section 2.1.

“Floyd Shale Rights” means all right, title and interest in certain oil, gas and mineral leases insofar as such leases cover depths below 100 feet below the stratigraphic equivalent of the base of the “J” Coal Group of the Pottsville Formation, as seen in the Density Log for the Holman 8-11 #1 well located in Section 8 of Township 22 South, Range 11 West, Tuscaloosa County, Alabama, in all cases as such right, title and interest is conveyed pursuant to the Partial Assignment of Oil, Gas and Mineral Leases, dated as of the day of , 2006, from Production to CEP Equity II, LLC, a Delaware limited liability company.

“Indemnified Parties” shall have the meaning assigned to such term in Section 2.2.

“Indemnified Party” has the meaning given such term in Section 2.3(a).

“LLC Agreement” means the Second Amended and Restated Operating Agreement of the Company, dated as of the Closing Date, as such agreement is in effect on the Closing Date, to which reference is hereby made for all purposes of this Agreement. An amendment or modification to the LLC Agreement subsequent to the Closing Date shall be given effect for the purposes of this Agreement only if it has received the approval that would be required pursuant to Section 3.5 hereof if such amendment or modification were an amendment or modification of this Agreement.

“Losses” means all actual liabilities, losses, damages, awards, costs and expenses (including reasonable fees and expenses of counsel, consultants, experts and other professional fees and any and all costs and expenses (including reasonable legal fees and accounting fees)); provided, however, that Losses shall not include any punitive, exemplary or consequential damages or any lost profits, loss of enterprise, value, diminution in value of any business, damage to reputation or loss to goodwill; provided, further, however, that the preceding proviso shall not apply to the extent a Party is required to pay such damages to a third party (who at the time such obligation to pay arises is not an Affiliate of such indemnified party) in connection with a matter for which such Party is entitled to indemnification under Article 2.

“NPI” means the “Net Royalty Interest” as that term is defined in the Net Profits Overriding Royalty Conveyance, dated November 22, 1993, but effective as of October 1, 1993,

from, pursuant to Part I thereof, Velasco Gas Company, L.P. to Torch Energy Advisors Incorporated and, pursuant to Part II thereof, from Torch Energy Advisors Incorporated to the Trust.

“Person” means a natural person, corporation, partnership, joint venture, trust, limited liability company, unincorporated organization or any other entity.

“Prospectus” means the final prospectus, dated September , 2006, relating to the initial public offering of common units representing Class B limited liability company interests in the Company, as filed with Securities and Exchange Commission pursuant to Rule 424(b) under the Securities Act of 1933.

“Subsidiary” has the meaning given such term in the LLC Agreement.

“Tax Authority” means any Governmental Authority having jurisdiction over the assessment, determination, collection or imposition of any Tax.

“Tax Returns” means any report, return, election, document, estimated tax filing, declaration or other filing provided to any Tax Authority, including any amendments thereto.

“Taxes” means (i) all taxes, assessments, charges, duties, levies, imposts or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, excise, severance, windfall profits, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental (including taxes under Code section 59A), alternative minimum, add-on, value-added, withholding and other taxes, assessments, charges, duties, levies, imposts or other similar charges of any kind whatsoever (whether payable directly or by withholding and whether or not requiring the filing of a Tax Return), and all estimated taxes, deficiency assessments, additions to tax, additional amounts imposed by any Governmental Authority, penalties and interest, but excluding any and all ad valorem, property or similar taxes; (ii) any liability for the payment of any amount of the type described in the immediately preceding clause (i) as a result of being a member of a consolidated, affiliated, unitary, combined, or similar group with any other corporation or entity at any time on or prior to the Closing Date; and (iii) any liability for the payment of any amount of the type described in the preceding clauses (i) or (ii) whether as a result of contractual obligations to any other Person or operation of law.

“Third-Party Claim” has the meaning provided such term in Section 2.3(a).

“Trust” means Torch Energy Royalty Trust.

“Voting Securities” means securities of any class of Person entitling the holders thereof to vote in the election of members of the board of directors or other similar governing body of the Person.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references

to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “include” or “includes” means includes, without limitation, and “including” means including, without limitation.

ARTICLE 2

Indemnification

Section 2.1 Survival. Any right of indemnification or reimbursement pursuant to this Article 2 shall expire with respect to (a) Losses arising from any matters covered by Section 2.2(a), at the close of business New York, NY time on the date that is six years and 30 days after the Closing Date; and (b) Losses arising from any matters covered by Section 2.2(d) at the close of business New York, NY time on the first anniversary of the Closing Date, (the “Expiration Date”), unless on or prior to the applicable Expiration Date, CCG has received written notice in good faith from the Indemnified Party of such breach, inaccuracy or non-fulfillment, in which case the Indemnified Party may continue to pursue its right to indemnification or reimbursement hereunder beyond the applicable Expiration Date with respect to the matter as to which CCG has so received such written notice. The rights of the Indemnified Parties to indemnification or reimbursement for Losses arising from matters covered by Section 2.2(b) or Section 2.2(c) shall survive the Closing indefinitely.

Section 2.2 Indemnification. Subject to the provisions of this Article 2 (including the provisions of Section 2.4), from and after the Closing Date, CCG shall indemnify, defend and hold harmless each member of the Company Group and their respective successors and permitted assigns (the “Indemnified Parties”) from and against all Losses incurred or suffered by them as a result of, relating to or arising out of (a) any and all Taxes that relate to or result from the income, business or operations of any member of the Company Group prior to the Closing Date; (b) legal actions pending as of the Closing Date against Constellation or any member of the Company Group or that are pending as of the Closing Date and involve the properties or business of any member of the Company Group; (c) events and conditions associated with the ownership by Constellation or any of its Affiliates (other than the Company Group) of the Floyd Shale Rights that relate to periods after the Closing Date; and (d) any miscalculation in the amount owed to the Trust in respect of the NPI to the extent relating to any period no more than four years prior to the Closing Date.

Section 2.3 Indemnification Procedures. Claims for indemnification under this Agreement shall be asserted and resolved as follows:

(a) If any of the Indemnified Parties (each, an “Indemnified Party”) receives notice of the assertion or commencement of any claim, demand, action, suit or proceeding made or brought by any third party (a “Third-Party Claim”) against such Indemnified Party with respect to which CCG is obligated to provide indemnification under this Agreement, the Indemnified Party will give CCG reasonably prompt written notice thereof (“Claim Notice”), but in no event later than 30 days after such Indemnified Party’s receipt of such notice of such Third-Party Claim. The Claim Notice by the Indemnified Party will describe the Third-Party Claim in reasonable detail, will include copies of all available material written evidence thereof and will indicate the estimated amount, if reasonably practicable, of the Losses that have been or may be sustained by the Indemnified Party. Failure to timely provide such Claim Notice shall not affect the right of the Indemnified Party to indemnification hereunder, except to the extent CCG is prejudiced by such delay or omission.

(b) CCG shall have the right to defend the Indemnified Party against such Third-Party Claim. If CCG notifies the Indemnified Party in writing that CCG elects to assume the defense of the Third-Party Claim (such election to be without prejudice to the right of CCG to dispute whether such claim is an indemnifiable Loss under this Article 2), then CCG shall have the right to defend such Third-Party Claim with counsel selected by CCG (who shall be reasonably satisfactory to the Indemnified Party), by all appropriate proceedings, to a final conclusion or settlement at the discretion of CCG in accordance with this Section 2.3(b); provided, however, that the Indemnified Party may employ separate counsel, and CCG will bear the reasonable expenses of such separate counsel (a ”Covered Counsel”), if, in the written opinion of counsel to the Indemnified Party, use of counsel of CCG’s choice would be expected to give rise to a conflict of interest. Subject to the proviso of the preceding sentence, CCG shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided that CCG shall not enter into any settlement agreement without the written consent of the Indemnified Party (which consent shall not be unreasonably withheld, conditioned or delayed), provided further, that such consent shall not be required if (i) the settlement agreement contains a complete and unconditional general release by the third party asserting the Third-Party Claim in favor of all Indemnified Parties affected by such claim, (ii) CCG has assumed all liability (without deduction) with regard to such settlement, and (iii) the settlement agreement does not contain any sanction or restriction upon the conduct of any business by the Indemnified Party or its Affiliates. If requested by CCG, the Indemnified Party agrees, at the sole cost and expense of CCG, to cooperate with CCG and its counsel in contesting any Third-Party Claim that CCG elects to contest, including the making of any related counterclaim against the Person asserting the Third-Party Claim or any cross-complaint against any Person. The Indemnified Party may participate in, but not control, any defense or settlement of any Third-Party Claim controlled by CCG pursuant to this Section 2.3(b), and the Indemnified Party shall bear its own costs and expenses with respect to such participation except with respect to any Covered Counsel.

(c) If CCG does not notify the Indemnified Party that CCG elects to defend the Indemnified Party pursuant to Section 2.3(b), then the Indemnified Party shall have the right to defend, and be reimbursed for its reasonable cost and expense (but only if the Indemnified Party is actually entitled to indemnification hereunder) with respect to the Third-Party Claim with counsel selected by the Indemnified Party (who shall be reasonably satisfactory to CCG), by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnified Party. In such circumstances, the Indemnified Party shall defend any such Third-Party Claim in good faith and have full control of such defense and proceedings; provided, however, that the Indemnified Party may not enter into any compromise or settlement of such Third-Party Claim if indemnification is to be sought hereunder, without CCG’s consent (which consent shall not be unreasonably withheld, conditioned or delayed). CCG may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 2.3(c), and CCG shall bear its own costs and expenses with respect to such participation.

(d) Subject to the other provisions of this Article 2, a claim for indemnification for any matter not involving a Third-Party Claim (a “Direct Claim”) may be asserted by written notice to CCG. Such notice by the Indemnified Party will describe the Direct Claim in

reasonable detail, will include copies of all available material written evidence thereof and will indicate the estimated amount, if reasonably practicable, of Losses that have been or may be sustained by the Indemnified Party. CCG will have a period of 30 days within which to respond in writing to such Direct Claim. If CCG does not so respond within such 30-day period, CCG will be deemed to have rejected such claim, in which event the Indemnified Party will be free to pursue such remedies as may be available to the Indemnified Party on the terms and subject to the provisions of this Agreement.

(e) In the event an Indemnified Party shall recover Losses in respect of a claim of indemnification under this Article 2, no other Indemnified Party shall be entitled to recover the same Losses in respect of a claim for indemnification.

Section 2.4 Limitations on Liability. Notwithstanding anything to the contrary herein:

(a) in no event shall CCG’s aggregate liability arising out of or relating to the matters specified in Section 2.2(d) exceed $500,000.00; and

(b) no Indemnified Party shall be entitled to indemnification under this Article 2 for any Losses to the extent that such Person has received insurance proceeds or reimbursement payments from any third party in respect of such Loss. Each member of the Company Group agrees to use its commercially reasonable best efforts to realize any applicable insurance proceeds or to recover any amounts under contractual indemnity or reimbursement rights available to such Person.

Section 2.5 Exclusive Remedy.

(a) Notwithstanding anything to the contrary herein, the indemnity provisions in this Article 2 shall constitute the sole and exclusive remedies of all Indemnified Parties under or by reason of any of the matters specified in Section 2.2(a), Section 2.2(b), Section 2.2(c) and Section 2.2(d).

(b) NOTWITHSTANDING ANYTHING TO THE CONTRARY HEREIN, CCG SHALL NOT BE LIABLE FOR PUNITIVE, EXEMPLARY OR CONSEQUENTIAL DAMAGES, LOST PROFITS OR LOST BENEFITS, LOSS OF ENTERPRISE VALUE, DIMINUTION IN VALUE OF ANY BUSINESS, DAMAGES TO REPUTATION OR LOSS TO GOODWILL, WHETHER BASED ON CONTRACT, TORT, STRICT LIABILITY, OTHER LAW OR OTHERWISE AND WHETHER OR NOT ARISING FROM ANY OTHER PARTY’S SOLE, JOINT OR CONCURRENT NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT; PROVIDED, HOWEVER, THAT THIS SECTION 2.5 SHALL NOT LIMIT A PARTY’S RIGHT TO RECOVERY UNDER THIS ARTICLE 2 FOR ANY SUCH DAMAGES TO THE EXTENT SUCH PARTY IS REQUIRED TO PAY SUCH DAMAGES TO A THIRD PARTY IN CONNECTION WITH A MATTER FOR WHICH SUCH PARTY IS OTHERWISE ENTITLED TO INDEMNIFICATION UNDER THIS ARTICLE 2.

ARTICLE 3

Miscellaneous

Section 3.1 Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the State of New York, excluding any conflicts-of-law

rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each Party hereby submits to the non-exclusive jurisdiction of the federal courts in the State of New York and to venue in New York, New York.

Section 3.2 Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the Person to be notified, postpaid and registered or certified with return receipt requested or by delivering such notice in person or by fax to such Party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by fax shall be effective upon actual receipt if received during the recipient’s normal business hours, or at the beginning of the recipient’s next business day after receipt if not received during the recipient’s normal business hours. All notices to be sent to a Party pursuant to this Agreement shall be sent to or made at the address set forth below such Party’s signature to this Agreement, or at such other address as such Party may provide to the other Parties in the manner provided in this Section 3.2.

Section 3.3 Entire Agreement. This Agreement constitutes the entire agreement of the Parties relating to the matters contained herein, superseding all prior contracts or agreements, whether oral or written, relating to the matters contained herein.

Section 3.4 Effect of Waiver or Consent. No waiver or consent, express or implied, by any Party to or of any breach or default by any Person in the performance by such Person of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a Party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such Party of its rights hereunder until the applicable statute of limitations period has run.

Section 3.5 Amendment or Modification. This Agreement may be amended, restated or modified from time to time only by the written agreement of all the Parties; provided, however, that no member of the Company Group may, without the prior approval of the Conflicts Committee, agree to any amendment or modification of this Agreement that will adversely affect the holders of Common Units. Each such instrument shall be reduced to writing and shall be designated on its face an “Amendment,” “Addendum” or a “Restatement” to this Agreement.

Section 3.6 Assignment. No Party shall have the right to assign its rights or obligations under this Agreement without the prior written consent of all of the other Parties.

Section 3.7 Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory Parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument.

Section 3.8 Severability. If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent by a court or regulatory body of competent jurisdiction, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

Section 3.9 Withholding or Granting of Consent. Except as expressly provided to the contrary in this Agreement, each Party may, with respect to any consent or approval that it is entitled to grant pursuant to this Agreement, grant or withhold such consent or approval in its sole and uncontrolled discretion, with or without cause, and subject to such conditions as it shall deem appropriate.

Section 3.10 Laws and Regulations. Notwithstanding any provision of this Agreement to the contrary, no Party shall be required to take any act, or fail to take any act, under this Agreement if the effect thereof would be to cause such Party to be in violation of any applicable law, statute, rule or regulation.

Section 3.11 Rights of CCG, Members, Assignees and Third Parties. The provisions of this Agreement are enforceable solely by each of the Parties, their successors and permitted assigns, and no other Person shall have the right, separate and apart from the Parties, their successors and permitted assigns, to enforce any provision of this Agreement or to compel any Party to comply with the terms of this Agreement. For the avoidance of doubt, the provisions of this Agreement shall not give rise to any right of recourse against any employee, officer, director or agent of any CCG Entity or any member of the Company Group.

[SIGNATURE PAGES FOLLOWS]

IN WITNESS WHEREOF, the Parties have executed this Agreement on, and effective as of, the Closing Date.


CONSTELLATION ENERGY COMMODITIES GROUP, INC.

By:
		Stuart Rubenstein
		Chief Operating Officer

Address for Notice:

111 Market Place
Baltimore, Maryland 21202
Phone: (410) 468-3500
Fax: (410) 468-3499
Attention: General Counsel

CONSTELLATION ENERGY PARTNERS LLC

By:
		Mr. Felix J. Dawson
		Chief Executive Officer

Address for Notice:

111 Market Place
Baltimore, Maryland 21202
Phone: (410) 468-3500
Fax: (410) 468-3499
Attention: Legal Counsel


ROBINSON’S BEND II PRODUCTION, LLC

By:
Name:
Title:

Address for Notice:

111 Market Place
Baltimore, Maryland 21202
Phone: ( )
Fax: ( )
Attention: Legal Counsel

ROBINSON’S BEND II OPERATING, LLC

By:
Name:
Title:

Address for Notice:

111 Market Place
Baltimore, Maryland 21202
Phone: ( )
Fax: ( )
Attention: Legal Counsel

ROBINSON’S BEND II MARKETING, LLC

By:
Name:
Title:

Address for Notice:

111 Market Place
Baltimore, Maryland 21202
Phone: ( )
Fax: ( )
Attention: Legal Counsel

Net Overriding Royalty Conveyance

Exhibit 10.4

NET OVERRIDING ROYALTY CONVEYANCE

(Torch Energy Royalty Trust)

(Alabama)


STATE OF ALABAMA		§
		§
COUNTY OF TUSCALOOSA		§

This Net Overriding Royalty Conveyance (this “Conveyance”), in two Parts,

Part I being a conveyance from VELASCO GAS COMPANY, LTD., a Texas limited partnership (“Velasco”), of which the general partner is Torch Energy Corporation, the address of which is 1221 Lamar, Suite 1600, Houston, Texas 77010, to TORCH ENERGY ADVISORS INCORPORATED, a Delaware corporation (“TEAI”), the address of which is 1221 Lamar, Suite 1600, Houston, Texas 77010, and

Part II being a conveyance from TEAI to the TORCH ENERGY ROYALTY TRUST, a Delaware business trust (the “Trust”), the mailing address of which is c/o Wilmington Trust Company, Rodney Square North, 1100 North Market Street, Wilmington, Delaware 19890-0001, Attn: Torch Energy Royalty Trust,

WITNESSETH:

DEFINITIONS APPLICABLE THROUGHOUT THIS CONVEYANCE

As used herein, the following words, terms or phrases have the following meanings (other defined terms may be found elsewhere in this Conveyance):

“Affiliate” means, as to the party specified, any Person controlling, controlled by or under common control with such Person, with the concept of control in such context meaning the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise.

“Business Day” means any day that is not a Saturday, Sunday, a holiday determined by the New York Stock Exchange, Inc. as “affecting” ‘ex’ dates, or any other day on which the principal office of the Trustee is closed as authorized or required by law.

“Closing Date” means the date of the closing of the sale of the Firm Units as defined in the underwriting agreement contemplated by that certain Registration Statement on Form S-1 (Securities and Exchange Commission File No. 33-68688).

“Credits to Production Costs”, for any Quarter, means amounts paid, reimbursed or credited to Velasco during such Quarter as any of the following: (a) proceeds from insurance or from judgments or settlements of litigation or claims for loss or damage to any of the Wells or the Subject Interests or personal injury or death arising out of or related to the ownership or operation thereof, but only to the extent of the amount (if any) charged to Production Costs on account of such loss, damage, personal injury or death (including amounts so charged for repair or replacement of loss of or damage to property); (b) payments by owners of interests in properties or depths other than those included in the Subject Lands for the drilling or deferring of any well or other operations on the Subject Lands (including dry and bottom hole payments and payments for refraining from drilling an offset well); (c) adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests or upon enlargement or reduction of any unit to which any of the Subject Interests may be subject; (d) sale or transfer off the Subject Lands of lease and well fixtures, equipment and personal property in, on, used or obtained in connection with the Wells or Subject Interests, with respect to such property existing at the Effective Time or (to the extent of the amount, if any, charged to Production Costs) acquired thereafter; (e) rent and other consideration for use of the surface of the Subject Lands or for subsurface reservoir use of the Subject Lands; (f) damage caused to the surface or subsurface of the Subject Lands; and (g) amounts representing downward adjustments or corrections made in such Quarter to Production Costs for any prior Quarter to the extent such adjustments or corrections result from errors or inaccuracies made in the accounting for such costs.

“Effective Time” means 7:00 o’clock A.M., local time in effect at the location of each Subject Interest, on October 1, 1993.

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“Entitled Volume” means, in any Quarter, the volume of Gas (in MMBtu’s) which is produced and saved from the Subject Lands during such Quarter and which is attributable to the Subject Interests (regardless of (i) any Gas imbalance or (ii) the volume of the Gas which is actually taken and sold by Velasco) less the volume of Gas attributable to Existing Burdens.

“Entitled Volume Amount” means, for any Quarter, an amount calculated by multiplying the Entitled Volume for such Quarter times the weighted average Monthly Gas Price under the Purchase Contract.

“Environmental Laws” means all applicable federal, state and local laws (including case law), regulations, ordinances, rules, orders, permits and governmental restrictions relating to the environment, the effect of the environment on human health or safety, pollutants, contaminants, hazardous substances or hazardous wastes, whether now or hereafter in effect.

“Excess Infill Costs” means, for any Quarter, an amount equal to the excess, if any, of Infill Costs for such Quarter (including any carried forward from any preceding Quarter) over Infill Proceeds for such Quarter.

“Excess Maximum Gas Volume Costs” means, for any Quarter, an amount equal to the excess, if any, of Maximum Gas Volume Costs for such Quarter (including any carried forward from any preceding Quarter) over Maximum Gas Volume Proceeds for such Quarter.

“Excess NPI Costs” means, for any Quarter, an amount equal to the excess, if any, of NPI Costs for such Quarter (including any carried forward from any preceding Quarter) over NPI Proceeds for such Quarter.

“Excess Pre-1980 Costs” means, for any Quarter, an amount equal to the excess, if any, of Pre-1980 Costs for such Quarter (including any carried forward from any preceding Quarter) over Pre-1980 Proceeds for such Quarter.

“Existing Burdens” means all royalties, overriding royalties, production payments, net profits payments, and other payments out of or measured by production that are existing and of record as of the Effective Time, to the extent such payments are payable out of

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production attributable to the Subject Interests, as the same shall be enlarged or diminished by the discharge or imposition of any payments out of production or by the removal or imposition of any charges or encumbrances to which any of the same are subject pursuant to existing Instruments.

“Gas” has the meaning ascribed to it in the Purchase Contract.

“Gross Proceeds” means, for any Quarter, (i) with respect to Gas, the Entitled Volume Amount for such Quarter, and (ii) with respect to the Subject Hydrocarbons other than Gas the amounts received during such Quarter by Velasco from the sale of such Subject Hydrocarbons under the Purchase Contract, as such amounts may be adjusted or corrected in such Quarter for any prior Quarter as a result of errors or inaccuracies (including, but not limited to, those made in measurement or computation), and provided that the following shall apply:

(a) If, for any reason (including failure of TEMI to purchase the quantity of Hydrocarbons which TEMI is obligated to purchase pursuant to the Purchase Contract), TEMI at any time does not make payments to Velasco during such Quarter, as required by the Purchase Contract, for Hydrocarbons which TEMI is obligated to purchase and pay Velasco for during such Quarter, Gross Proceeds shall nevertheless be calculated during such Quarter as if Velasco had actually received during such Quarter the payments to which it is entitled under the Purchase Contract.

(b) There shall not be included in Gross Proceeds any Property Taxes which are deducted or excluded from proceeds of sale received by Velasco.

(c) There shall not be included in Gross Proceeds any amount for Subject Hydrocarbons attributable to nonconsent operations conducted with respect to the Subject Interests (or any portion thereof) as to which Velasco shall be a nonconsenting party and which is dedicated to the recoupment or reimbursement of costs and expenses of the consenting party or parties by the terms of the relevant Instrument providing

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for such nonconsent operations. Velasco agrees that its election not to participate in such operations shall be made in conformity with the provisions of Section 6.02 of this Conveyance, but third persons shall not be under any duty to determine that such election so conformed.

(d) There shall not be included in Gross Proceeds any amount which Velasco shall receive as any of the following: consideration for transfer or sale of any of the Subject Interests (subject to the Royalty Interests) or sale or transfer off the Subject Lands of lease and well fixtures, equipment and personal property (provided that amounts received from such sales or transfers shall be included in Credits to Production Costs to the extent provided in the definition of such term); and amounts received by Velasco as a loan.

(e) There shall not be included in Gross Proceeds any amount for Subject Hydrocarbons lost in the production or delivery thereof to the Delivery Points (which term as used herein has the same meaning as in the Purchase Contract) or used by Velasco or its operator in conformity with ordinary or prudent practices for drilling and production operations.

(f) There shall not be included in Gross Proceeds amounts which are included in Credits to Production Costs.

“Hydrocarbons” means oil, Gas and other minerals produced in association with oil or Gas, but excluding all other minerals, whether similar or dissimilar.

“Infill Costs” means, for any Quarter, those Production Costs attributable to Infill Wells, or the production of Subject Hydrocarbons therefrom, or the Subject Interests attributable thereto, plus:

(a) Excess Infill Costs as determined at the end of the preceding Quarter; and

(b) interest on the amount of Excess Infill Costs existing at the end of the preceding Quarter calculated from the last day of the preceding Quarter to the last day of the Quarter for which Infill Costs are being determined at the Prime Rate.

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“Infill Net Proceeds” means, for any Quarter, an amount equal to the excess, if any, of Infill Proceeds for such Quarter over Infill Costs for such Quarter.

“Infill Net Royalty Interest” means a net overriding royalty interest in and to the Hydrocarbons in and under the Subject Lands that may be produced and saved from the Infill Wells equal to twenty percent (20%) of the Infill Net Proceeds, all as more fully provided in this Conveyance.

“Infill Proceeds” means, for any Quarter, that portion of Gross Proceeds for such Quarter attributable to production of Subject Hydrocarbons from Infill Wells.

“Infill Wells” means all wells drilled on the Subject Lands, commenced after the Closing Date, whether or not any such well is drilled to a formation from which a Well or Wells previously drilled are then producing or capable of producing and whether or not any such well is drilled on a drilling or spacing unit previously containing a Well or Wells then producing or capable of producing, together with any replacement well for an Infill Well, but such term shall not include (a) a well drilled to replace an NPI Well or a Pre-1980 Well which is no longer capable of producing in paying quantities by reason of damage, destruction or other physical cause and not by reason of depletion of reserves, or (b) an NPI Well or a Pre-1980 Well which is reworked, recompleted, deepened, plugged back or sidetracked.

“Instrument” means an oil, gas or mineral lease, pooling or unitization agreement or order, operating agreement, division order, transfer order, and any other type of agreement, conveyance, assignment or other instrument or evidence of title relating to any of the Subject Interests.

“Maximum Gas Volume” means the MMBtu equivalent of 730.0 MMcf of Gas for any Quarter before January 1, 1995, and 912.5 MMcf of Gas for any Quarter thereafter (such Gas meeting the quality standards of the Purchase Contract and measured as provided in the

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Purchase Contract) produced and saved from the NPI Wells during such Quarter, regardless of how much of such volume is produced on any day and whether or not such volume is actually so produced and saved. In the event Velasco assigns a part of or interest in (but less than all) the Subject Interests insofar as they include the NPI Wells, a pro rata share of the Maximum Gas Volume (based on production) shall be allocated by the assignor and assignee to such part or interest therein.

“Maximum Gas Volume Costs” means, for any Quarter, that fraction of NPI Costs for such Quarter of which the numerator is the Maximum Gas Volume for such Quarter (in MMcf) and of which the denominator is the volume of Gas in MMcf (determined in the same manner as the Maximum Gas Volume) produced and saved from the NPI Wells during such Quarter and attributable to the Subject Interests (provided that such computation shall not result in an amount which exceeds the amount of NPI Costs for such Quarter), plus Excess Maximum Gas Volume Costs as determined at the end of the preceding Quarter and interest on the amount of Excess Maximum Gas Volume Costs existing at the end of the preceding Quarter, calculated from the last day of the preceding Quarter to the last day of the Quarter for which Maximum Gas Volume Costs are being determined at the Prime Rate, provided that, for purposes of this definition NPI Costs shall include only the following portion of Production Costs attributable to NPI Wells, or the production of Subject Hydrocarbons therefrom, or the Subject Interests attributable thereto:

(a) the Property Tax Accrual for such Quarter; and

(b) any amounts paid by Velasco (or on its behalf) during such Quarter, whether as refund, interest or penalty, to any governmental agency or other Person because the amount initially received by Velasco as sales price under the Purchase Contract was more or allegedly more than permitted by the terms of the Purchase Contract or any applicable statute, regulation, order, decree or other obligation; provided such amounts (in the case of a refund), or the amounts with respect to which the interest or penalty was paid, were previously included in Maximum Gas Volume Proceeds.

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“Maximum Gas Volume Net Proceeds” means, for any Quarter, an amount equal to the excess, if any, of Maximum Gas Volume Proceeds for such Quarter over Maximum Gas Volume Costs for such Quarter.

“Maximum Gas Volume Proceeds” means, for any Quarter, the product of the Maximum Gas Volume for such Quarter times the weighted average Monthly Gas Price during such Quarter under the Purchase Contract.

“MMBtu” means one million British thermal units.

“MMcf” means one million cubic feet.

“Net Royalty Interest” means, for each Quarter, a net overriding royalty interest in and to the Hydrocarbons in and under the Subject Lands that may be produced and saved from the NPI Wells equal to the lesser of (a) ninety-five percent (95%) of the NPI Net Proceeds for such Quarter or (b) the Maximum Gas Volume Net Proceeds for such Quarter, all as more fully provided in this Conveyance.

“Non-Affiliate” means, as to the party specified, any Person who is not an Affiliate of such party.

“NPI Costs” means, for any Quarter, those Production Costs attributable to NPI Wells, or the production of Subject Hydrocarbons therefrom, or the Subject Interests attributable thereto, plus:

(a) Excess NPI Costs as determined at the end of the preceding Quarter; and

(b) interest on the amount of Excess NPI Costs existing at the end of the preceding Quarter, calculated from the last day of the preceding Quarter to the last day of the Quarter for which NPI Costs are being determined at the Prime Rate;

provided that Second Category Costs shall not be included in NPI Costs for Quarters prior to January 1, 2003.

“NPI Net Proceeds” means, for any Quarter, an amount equal to the excess, if any, of NPI Proceeds for such Quarter over NPI Costs for such Quarter.

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“NPI Proceeds” means, for any Quarter, that portion of Gross Proceeds for such Quarter attributable to production of Subject Hydrocarbons from NPI Wells.

“NPI Wells” means all wells and boreholes, except Infill Wells and Pre-1980 Wells, located on the Subject Lands, whether or not they produce in paying quantities, including without implied limitation any well temporarily abandoned, any well or borehole which is reworked, deepened, plugged back, sidetracked or recompleted at the same or a different depth, and any replacement well for any such well.

“Person” means any individual, corporation, partnership, trust, estate, limited liability company or other entity, organization or association.

“Pre-1980 Costs” means, for any Quarter, those Production Costs attributable to Pre-1980 Wells, or the production of Subject Hydrocarbons therefrom, or the Subject Interests attributable thereto, plus:

(a) Excess Pre-1980 Costs as determined at the end of the preceding Quarter; and

(b) interest on the amount of Excess Pre-1980 Costs existing at the end of the preceding Quarter, calculated from the last day of the preceding Quarter to the last day of the Quarter for which Pre-1980 Costs are being determined at the Prime Rate;

provided that Second Category Costs shall not be included in Pre-1980 Costs for Quarters prior to January 1, 2003.

“Pre-1980 Net Proceeds” means, for any Quarter, an amount equal to the excess, if any, of Pre-1980 Proceeds for such Quarter over Pre-1980 Costs for such Quarter.

“Pre-1980 Net Royalty Interest” means a net overriding royalty interest in and to the Hydrocarbons in and under the Subject Lands that may be produced and saved from the Pre-1980 Wells equal to ninety-five percent (95%) of the Pre-1980 Net Proceeds, all as more fully provided in this Conveyance.

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“Pre-1980 Proceeds” means, for any Quarter, that portion of Gross Proceeds for such Quarter attributable to production of Subject Hydrocarbons from Pre-1980 Wells.

“Pre-1980 Wells” means all wells located on the Subject Lands that produced marketable quantities (as such term is used for Federal income tax purposes) of Hydrocarbons prior to the year 1980.

“Prime Rate” means the lesser of (a) a rate of interest per annum, compounded Quarterly, equal to the rate announced publicly by Citibank, N.A. (or its successor) in New York, New York, from time to time as its “prime rate” in effect at its principal office in New York City (each change in the Prime Rate to be effective on the date such change is publicly announced), with the understanding that such bank’s “prime rate” may be one of several base rates and may serve as a basis upon which effective rates are from time to time calculated for loans making reference thereto or (b) the maximum nonusurious interest rate permitted by applicable law.

“Production Costs” means, for any Quarter, the amounts (whether capital or non-capital in nature) in any way related to (i) the Wells, (ii) the production of Hydrocarbons therefrom or (iii) the Subject Interests, for periods from and after the Effective Time, to the extent such amounts are attributable to the Subject Interests and were not the subject of reductions to or exclusions from Gross Proceeds, and without duplication, equal to the sum of the following “First Category Costs” and the following “Second Category Costs”. “First Category Costs” means the following:

(a) all amounts paid by Velasco (or on its behalf) during such Quarter for the following: delay rental; shut-in gas well royalty or payment; minimum royalty; payments to owners of interests in properties other than those included in the Subject Lands for refraining from drilling an offset well; rent and other consideration for use of the surface or for subsurface reservoir use; and damage caused to the surface or subsurface;

(b) the Property Tax Accrual for such Quarter;

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(c) any amounts paid by Velasco (or on its behalf) during such Quarter, whether as refund, interest or penalty, to a purchaser or any governmental agency or other Person because the amount initially received by Velasco as sales price under the Purchase Contract was more or allegedly more than permitted by the terms of the Purchase Contract or any applicable statute, regulation, order, decree or other obligation; provided such amounts (in the case of a refund), or the amounts with respect to which the interest or penalty was paid, were previously included in Gross Proceeds;

(d) additional tax or other charges (including any interest and penalty) paid by Velasco (or on its behalf) during such Quarter as a result of any audit by any federal or state agency or body or other interested Person relating to operation of the Subject Interests or sale of production therefrom to the extent such tax or other charge would otherwise constitute First Category Costs hereunder;

(e) any amount paid by Velasco (or on its behalf) during such Quarter for losses associated with property damage, personal injury or death that relate to the operation of the Subject Interests, provided that Velasco has not breached Section 6.01 hereof;

(f) any other amounts paid by Velasco (or on its behalf) during such Quarter, whether such amounts are paid as refund, fine, judgment or settlement amount (including any interest or penalty amounts), in connection with litigation or settlement of threatened litigation or claims that arise on or after the Closing Date or in connection with order of a governmental agency or body that is issued on or after the Closing Date, to the extent such refund, fine, judgment or settlement amount would otherwise constitute First Category Costs hereunder and provided that in each case Velasco has not breached Section 6.01 hereof;

(g) amounts paid by Velasco (or on its behalf) during such Quarter to comply with Environmental Laws for acts or

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omissions occurring on or under, or in connection with, the Subject Lands or the Wells on or after the Closing Date, or conditions on or under the Subject Lands or the Wells that arise on or after the Closing Date; and

(h) amounts representing upward adjustments or corrections made in such Quarter to First Category Costs for any prior Quarter to the extent such adjustments or corrections result from errors or inaccuracies made in the accounting for such First Category Costs.

“Second Category Costs” means the following:

(a) the aggregate costs paid by Velasco (or on its behalf) during such Quarter under any joint operating agreement applicable to the Subject Interests to which Velasco and one or more Non-Affiliates are parties, except Property Taxes and except such of the foregoing costs as are First Category Costs;

(b) the aggregate costs paid by Velasco (or on its behalf) during such Quarter under Exhibit C attached hereto with respect to any Subject Interest not subject to a joint operating agreement between Velasco and a Non-Affiliate, except Property Taxes and except such of the foregoing costs as are First Category Costs;

(c) all other costs, expenses and liabilities (except those provided for in (a) and (b) above and except Property Taxes) paid by Velasco (or on its behalf) during such Quarter for locating, drilling, completing and plugging and abandoning any Well, including title examination and curative expenses, operating and producing Subject Hydrocarbons, including without implied limitation costs paid by Velasco (or on its behalf) for: equipping, maintaining, plugging back, reworking, recompleting and sidetracking of any Well on the Subject Lands; and secondary or other enhanced recovery, pressure maintenance, repressuring, cycling and other operations conducted for the purpose of enhancing production; provided that the costs and expenses paid by Velasco to an Affiliate of

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Velasco or TEAI for performing the operations or services referred to in this paragraph (c) and chargeable under this paragraph (c) shall not exceed competitive contract charges prevailing in the area for such operations or services;

(d) any amounts paid by Velasco (or on its behalf) during such quarter, whether such amounts are paid as refund, fine, judgment or settlement amount (including any interest or penalty amounts), in connection with litigation or settlement of threatened litigation or claims that arise on or after the Closing Date or in connection with order of a governmental agency or body that is issued on or after the Closing Date, relating to operation of the Subject Interests and which are not included in First Category Costs, provided that Velasco has not breached Section 6.01 hereof;

(e) all consideration hereafter paid and costs and expenses hereafter incurred and paid by Velasco (or on its behalf) during such Quarter for any renewals or extensions of leases and other Instruments which are included in the definition herein of Subject Interests, unless the interest which lapsed or expired did so as a result of violation by Velasco of the standard set out in Section 6.01 hereof;

(f) all amounts paid by Velasco (or on its behalf) during such Quarter for adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests or upon enlargement or reduction of any unit to which any of the Subject Interests may be subject; and

(g) any amounts paid by Velasco (or on its behalf) during such Quarter for defending or asserting claims, including litigation, concerning title to the Subject Interests or brought by Velasco to protect the Subject Interests.

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However, notwithstanding anything to the contrary in the foregoing First Category Costs and Second Category Costs, in no event shall Production Costs include any of the following (all of which shall be borne solely by Velasco):

(a) any amount that would otherwise be included in Production Costs, but that is attributable to periods prior to the Effective Time;

(b) any amount (including any amount paid by way of indemnity of the Trustee under the Trust Agreement) arising out of or in connection with liabilities under Environmental Laws to the extent such amount arises out of or relates to acts or omissions occurring on or under, or in connection with, the Subject Lands or the Wells prior to the Closing Date, or conditions existing on or under the Subject Lands or the Wells prior to the Closing Date;

(c) amounts borne by Velasco as an overproduced party and paid to an underproduced party in order to settle in whole or in part a gas balancing account in lieu of balancing in kind; and

(d) amounts which would otherwise be included in Production Costs for any Quarter equal to the amounts which are included in Credits to Production Costs for such Quarter, so that such Credits to Production Costs shall operate to reduce Production Costs.

“Property Taxes” means the sum of all general property (ad valorem), production, severance, sales, gathering and excise taxes and other taxes (whether state, federal or otherwise and whether presently in effect or hereafter levied), except income, franchise and other similar taxes, assessed or levied on or in connection with the Subject Interests, the Royalty Interests or the production therefrom or equipment on the Subject Lands, or against Velasco as owner of the Subject Interests or TEAI or the Trust (as its assignee in Part II hereof) as owner of the Royalty Interests, taking into account any applicable credits, exemptions, moratoria or other benefits.

“Property Tax Accrual” means, for any Quarter, an amount that may be set aside by Velasco as an accrual to be applied against Property Taxes other than those which are deducted or excluded from proceeds of sale received by Velasco, which accrual shall be adjusted if and to the extent actual Property Taxes differ from such accrual.

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“Purchase Contract” means the Oil and Gas Purchase Contract between Torch Royalty Company, Velasco, TEAI and Torch Energy Marketing Incorporated (“TEMI”) dated as of October 1, 1993, together with all amendments and modifications to, or replacements for, such contract.

“Quarter” means a calendar quarter.

“Royalty Interests” means, collectively, the Net Royalty Interest, the Infill Net Royalty Interest and the Pre-1980 Net Royalty Interest.

“Section 29 Coal Seam Tax Credits” means those tax credits for non-conventional fuels production allowed pursuant to Section 29 of the Internal Revenue Code of 1986, as amended.

“Subject Hydrocarbons” means all Hydrocarbons in and under, and which may be produced and saved from, and which are attributable to, the Subject Interests, less the portion of such Hydrocarbons which are attributable to Existing Burdens.

“Subject Interests” means (a) all of the interest in and to those of the Subject Properties described in Part One of Exhibit A attached hereto and (b) an undivided twenty-five percent (25%) interest in and to those of the Subject Properties described in Part Two of Exhibit A attached hereto.

“Subject Properties” means every kind and character of right, title, claim or interest which Velasco has at the Effective Time in or under each Instrument (including units created by any Instrument) relating to the Subject Lands (including but not limited to the Instruments described or referred to in Exhibit A), insofar as they cover the Subject Lands, and all other right, title, claim or interest which Velasco has on the Effective Time in and to the Subject Lands, whether such right, title, claim or interest be under and by virtue of an Instrument or under any other type of claim or title, legal or equitable, recorded or unrecorded, even though Velasco’s interests be incorrectly or incompletely described in, or a description thereof be omitted from, Exhibit A,

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all as the same shall be enlarged or diminished by the discharge or imposition of any payments out of production or by the removal or imposition of any charges or encumbrances to which any of the same are subject pursuant to existing Instruments, and any and all renewals and extensions of any of the same (to the extent provided for below), but subject to all Existing Burdens to which Velasco’s such right, title, claim or interest is subject (while same remains so subject), limited, however, if Velasco’s interest in any Subject Interest should terminate at any time, to the period to which Velasco’s interest in such Subject Interest is limited. There shall be excluded from the term “Subject Interests” any interest hereafter acquired by Velasco in and to any of the Subject Lands, except any interest acquired through non-participation in operations by third parties and any other interest acquired pursuant to existing agreements for no new consideration and renewals or extensions of leases and other such agreements. For purposes of this Conveyance “renewals or extensions” of any lease or other such agreement shall be limited to renewals or extensions of an existing lease or other such agreement obtained by the present owner thereof (or such owner’s successors in interest) while such lease is in force or within six months after such lease or other such agreement terminates. Velasco shall be under no duty to seek renewals or extensions of any lease or other such agreement.

“Subject Lands” means the lands in which Velasco has a right, title, claim or interest and which are described in or which are subject to the Instruments described in Exhibit A attached hereto, provided that (a) there are excepted from each parcel of the Subject Lands described in Exhibit A attached hereto and retained by Velasco all its right, title and interest in all depths deeper than one hundred feet (100’) below the base of the lowest depth, formation or reservoir from which, on the Effective Date, a Well drilled on or producing from such parcel or land pooled or unitized therewith is producing or capable of producing Hydrocarbons, (b) where the description in Exhibit A excepts land or refers to an

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Instrument insofar only as it covers certain land, no interest in such excepted land or in land other than to which such reference is limited shall be included in the terms “Subject Lands” and (c) if Exhibit A described an Instrument but does not limit such description to certain land, then “Subject Lands” shall include all land covered by such Instrument in which Velasco has an interest (subject to the depth limitation in (a) above). If allocation of acreage to any Well is required by governmental authority or existing Instrument for spacing or allowable or other purposes in order to comply with governmental authority or existing Instrument, Velasco shall have the right to select such allocated acreage from the Subject Lands provided that such allocation shall not reduce the quantity of Hydrocarbons that may be lawfully produced from an NPI Well on the Subject Lands or cause such NPI Well to violate applicable spacing rules or regulations. If permitted by governmental authority or existing Instrument, the acreage so allocated to an Infill Well or a Pre-1980 Well shall be limited to the depths, formations or reservoirs from which the Infill Well or Pre-1980 Well is producing or capable of producing Hydrocarbons. In the case of Subject Lands which are pooled or unitized, if an Infill Well is drilled on a pooled or unitized tract from which a well on the Subject Lands which is not an Infill Well is producing or capable of producing Hydrocarbons and the method of allocating pooled or unitized production to such tract (under the pooling or unitization Instrument providing for such allocation) does not provide for an allocation between different interests in two or more wells on such tract, then such allocation shall be made between Infill Wells and wells which are not Infill Wells producing from the same tract on the basis of their relative actual monthly production of Hydrocarbons.

“Trust Agreement” means the Trust Agreement of the Trust entered into by and among TEAI, Torch Royalty Company, Velasco and Trustee, effective as of October 1, 1993, as amended from time to time.

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“Trustee” means Wilmington Trust Company, a banking corporation organized under the laws of the State of Delaware with its principal office in Wilmington, Delaware, and its successors and permitted assigns.

“Wells” means, collectively, the NPI Wells, the Infill Wells and the Pre-1980 Wells, and the fixtures, equipment and personal property in, on, used or obtained in connection therewith.

PART I

ARTICLE I

GRANT

Section 1.01. Royalty Interests. For and in consideration of good and valuable consideration paid to Velasco, the receipt and sufficiency of which are hereby acknowledged, Velasco does hereby BARGAIN, SELL, GRANT, CONVEY, TRANSFER and ASSIGN unto TEAI the Net Royalty Interest, the Infill Net Royalty Interest and the Pre-1980 Net Royalty Interest.

Section 1.02. Habendum Clause. TO HAVE AND TO HOLD the Net Royalty Interest, the Infill Net Royalty Interest and the Pre-1980 Net Royalty Interest, together with all and singular the rights and appurtenances thereto in anywise belonging, unto TEAI, subject, however, to the terms and provisions of this Conveyance.

Section 1.03. Nature of Interests. The Royalty Interests conveyed hereby are nonoperating, nonexpense-bearing variable royalty interests in and to the Subject Lands, and this Conveyance is an absolute conveyance of interests in real property.

ARTICLE II

RECORDS AND REPORTS

Section 2.01. Books and Records. Velasco shall at all times maintain true and correct books and records sufficient to determine the amounts payable hereunder to the Trust (as assignee of TEAI under the following Part II), including, but not limited to, (a) a NPI Net Proceeds account to which NPI Proceeds and NPI Costs attributable to the NPI Wells are credited and charged, (b) an Infill Net Proceeds account to which Infill Proceeds and Infill Costs attributable to the Infill Wells are credited and charged, (c) a Pre-1980 Net Proceeds account to which Pre-1980 Proceeds and

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Pre-1980 Costs attributable to the Pre-1980 Wells are credited and charged and (d) a Maximum Gas Volume Net Proceeds account to which Maximum Gas Volume Proceeds and Maximum Gas Volume Costs are credited and charged.

Section 2.02. Inspections. The books and records referred to in Section 2.01 hereof shall be open for inspection by the Trustee and its designated representatives, on behalf of the Trust (as assignee of TEAI under the following Part II) , at the office of Velasco during normal business hours and upon reasonable notice; provided, however, that the Trustee and its designated representatives shall have no right to review books and records that pertain to calendar years for which the period for raising objections under Section 2.05 has expired unless such books and records are necessary to prepare a response by a holder or former holder of units in the Trust in connection with an administrative or legal proceeding by the Internal Revenue Service.

Section 2.03. Quarterly Statements. On or before the last Business Day preceding the fiftieth (50th) day following the last day of each Quarter, Velasco shall deliver to the Trustee, on behalf of the Trust (as assignee of TEAI under the following Part II), an unaudited statement showing (a) the computation of NPI Net Proceeds, Infill Net Proceeds, Pre-1980 Net Proceeds and Maximum Gas Volume Net Proceeds for such Quarter and all amounts payable to the Trust for such Quarter, and (b) the Section 29 Coal Seam Tax Credit production volumes attributable to the Net Royalty Interest for the preceding Quarter (as such volumes are determined in accordance with Velasco’s interpretation of the applicable provisions of the Internal Revenue Code of 1986, as amended). On or before the sixty-fifth (65th) day following the last day of each of the first three Quarters of each calendar year, Velasco shall deliver to the Trustee, on behalf of the Trust (as assignee of TEAI under the following Part II), an unaudited statement showing revenues and direct operating expenses in such Quarter attributable to the Subject Interests.

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Section 2.04. Annual Statements. On or before the sixtieth (60th) day following December 31, 1993, Velasco shall deliver to the Trustee, on behalf of the Trust (as assignee of TEAI under the following Part II), an unaudited statement showing the Section 29 Coal Seam Tax Credit production volumes attributable to the Net Royalty Interest for the Quarter ending December 31, 1993 (as such volumes are determined in accordance with Velasco’s interpretation of the applicable provisions of the Internal Revenue Code of 1986, as amended). On or before the sixtieth (60th) day following the close of each calendar year after 1993, Velasco shall deliver to the Trustee, on behalf of the Trust (as assignee of TEAI under the following Part II), an unaudited statement showing the Section 29 Coal Seam Tax Credit production volumes attributable to the Net Royalty Interest for each Quarter of such calendar year (as such volumes are determined in accordance with Velasco’s interpretation of the applicable provisions of the Internal Revenue Code of 1986, as amended). On or before the ninetieth (90th) day following the close of each calendar year, Velasco shall deliver to the Trustee, on behalf of the Trust (as assignee of TEAI under the following Part II), a statement audited by an independent accounting firm selected by Velasco showing the computation of NPI Net Proceeds, Infill Net Proceeds, Pre-1980 Net Proceeds and Maximum Gas Volume Net Proceeds for each Quarter of such calendar year and all amounts payable to the Trust (as assignee of TEAI under the following Part II) for such calendar year.

Section 2.05. Objections to Quarterly and Annual Statements. If the Trust (as assignee of TEAI under the following Part II) objects to any item or items included in the quarterly or annual statements provided by Velasco, the Trustee shall notify Velasco in writing, setting forth in such notice the specific items included in such statement to which the Trust objects. With respect to the objections that are justified, an adjustment will be made. With respect to any audited annual statement delivered by Velasco under Section 2.04, if the Trustee fails to give Velasco notice of any objection to such audited annual statement (or the other quarterly or annual statements provided by Velasco for such year) within 180

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days after such annual statement is delivered to the Trustee, then all statements for such calendar year shall be deemed to be correct for all purposes, and the Trustee and the Trust shall be deemed to have waived any objection to such statements.

ARTICLE III

PAYMENT

Section 3.01. Payment. On or before the last day of the second month following each Quarter (or, if such day is not a Business Day, the first Business Day thereafter), beginning with the Quarter ending December 31, 1993, Velasco shall pay to the Trust (as assignee of TEAI under the following Part II), in respect of the Royalty Interests, the sum of (a) an amount equal to the lesser of ninety-five percent (95%) of the NPI Net Proceeds for such Quarter or the Maximum Gas Volume Net Proceeds for such Quarter, (b) an amount equal to ninety-five percent (95%) of the Pre-1980 Net Proceeds for such Quarter and (c) an amount equal to twenty percent (20%) of the Infill Net Proceeds for such Quarter.

Section 3.02. Interest on Payments. Gross Proceeds shall not include any interest on proceeds received by Velasco prior to the payment dates provided for in Section 3.01, but any amount not paid by Velasco to the Trust (as assignee of TEAI under the following Part II) when due shall bear interest from such due date until such amount is paid at the Prime Rate.

Section 3.03. Overpayment. If at any time Velasco pays the Trust more than the amount due for any reason, the Trust will not be obligated to return any such overpayment, but the amount otherwise payable to the Trust in respect of the Royalty Interests for any subsequent Quarters will be reduced by an amount equal to such overpayment, plus an amount equal to interest at the Prime Rate on the unrecouped balance of such overpayment from the date of such overpayment until Velasco has recovered such overpayment plus such interest.

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ARTICLE IV

SALE OF SUBJECT HYDROCARBONS

Section 4.01. Disposition of Production. The Subject Hydrocarbons are subject to the Purchase Contract, which shall govern the disposition thereof to the extent provided in the Purchase Contract. Any quantity of Hydrocarbons not sold by Velasco to TEMI and not purchased by TEMI from Velasco under the Purchase Contract shall be marketed by Velasco. The parties agree that the prices paid or payable under the Purchase Contract for Hydrocarbons are the wellhead value of such Hydrocarbons.

Section 4.02. Reliance by Third Party. As to any Person, the acts of Velasco under the Purchase Contract will be binding on the Trust (as assignee of TEAI under the following Part II). Velasco reserves the right to execute any division or transfer order and the Purchase Contract without necessity of joinder by or consent of TEAI or the Trust. Proceeds from the sale of the Subject Hydrocarbons shall be paid by the purchasers thereof directly to Velasco without necessity of joinder by or consent of TEAI or the Trust.

ARTICLE V

NON-LIABILITY OF TEAI, TRUSTEE AND THE TRUST

In no event will TEAI (in its capacity as assignee in Part I or as assignor in Part II hereof), the Trust (as assignee of TEAI under Part II hereof) or the Trustee be personally or individually liable, or responsible in any way, for payment of any costs or liabilities incurred by Velasco or others attributable to the Wells, the Subject Interests or the Subject Hydrocarbons, except to the extent (in the case of TEAI) of TEAI’s obligations set out in the Standby Performance Agreement between TEAI, Velasco and Torch Royalty Company.

ARTICLE VI

OPERATION OF SUBJECT INTERESTS

Section 6.01. Reasonably Prudent Operator Standard. To the extent it has the legal right to do so under the terms of any Instrument affecting or pertaining to the Subject Interests or the Wells (or any portion thereof), Velasco shall exercise such rights with respect to the maintenance and operation of the Subject Interests and the Wells in a good and workmanlike manner and as

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would a reasonably prudent operator under the same or similar circumstances, without regard to the existence or burden of the Royalty Interests or the direct or indirect effect, financial or otherwise, on Velasco or TEMI or any of their Affiliates, of the Purchase Contract.

Section 6.02. Nonconsents. Nothing in Section 6.01 shall be deemed to prevent or restrict Velasco from electing not to participate in any operation to be conducted under the terms of any Instruments affecting or pertaining to the Subject Interests or any of the Wells, and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Velasco in accordance with the reasonably prudent operator standard set forth in Section 6.01, without regard to the existence or burden of the Royalty Interests or the direct or indirect effect, financial or otherwise, on Velasco or TEMI or any of their Affiliates, of the Purchase Contract. By way of example and not by way of limitation, if such operation relates to an NPI Well and if Velasco reasonably concludes that the cost of such operation (as if such cost were included in First Category Costs, even though such cost shall not be) is likely to result in Excess NPI Costs, or if such operation relates to an Infill Well or a Pre-1980 Well and if Velasco reasonably concludes that the cost of such operation (which would be included in Production Costs) is likely to result in Excess Infill Costs or Excess Pre-1980 Costs, in each case for an unreasonable period of time under the circumstances, then its election not to participate in such operation shall be deemed not to breach the standard in Section 6.01. Similarly, if Velasco does or does not undertake any operation on a Subject Property (other than in a consent or non-consent context, such as where Velasco owns 100% of the operating interest in such Subject Property), then its election to undertake or not to undertake such operation shall be deemed not to breach the standard in Section 6.01 if the same criteria are followed as in the foregoing consent or non-consent example. If Velasco elects not to participate in an operation, with the result that any of the Subject Interests are relinquished

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(for a period of time or permanently) to the Persons electing to participate, such interest so relinquished shall (for such period of time) not be part of the Subject Interests or burdened by the Royalty Interests, and the costs (including the costs of conducting such operation) related thereto shall not be Production Costs. If Velasco elects to participate in an operation and another party elects not to participate, with the result that all or a part of such third party’s interest is relinquished (for a period of time or permanently) to Velasco, such interest so relinquished shall (for such period of time) become a part of the Subject Interests and the costs (including the costs of conducting such operation) attributable to such interest shall be Production Costs.

Section 6.03. Limitation on Liability. NOTWITHSTANDING ANYTHING ELSEWHERE HEREIN TO THE CONTRARY, VELASCO SHALL NOT BE LIABLE TO TEAI, THE TRUST (as assignee of TEAI under the following Part II) OR THE TRUSTEE FOR THE MANNER IN WHICH VELASCO PERFORMS ITS RIGHTS AND DUTIES HEREUNDER, SO LONG AS VELASCO ACTS IN ACCORDANCE WITH THE REASONABLY PRUDENT OPERATOR STANDARD SET FORTH IN SECTION 6.01. VELASCO EXPRESSLY DISCLAIMS AND TEAI AND THE TRUST AGREE THAT THE VELASCO DOES NOT HAVE ANY FIDUCIARY DUTY OR FIDUCIARY OBLIGATION IN FAVOR OF TEAI OR THE TRUST.

Section 6.04. Abandonment of Properties. Nothing herein contained shall obligate Velasco as a working interest owner of any Well (whether or not Velasco is the designated operator) to continue to operate such Well, to continue to participate in the operation of such Well or to maintain in force or attempt to maintain in force any of the Subject Interests attributable to such Well when, in Velasco’s judgment (reasonably exercised), such Well is no longer capable of producing Hydrocarbons in paying quantities and a reasonably prudent operator (without regard to the existence or burden of the Royalty Interests or the direct or indirect effect, financial or otherwise, on Velasco or TEMI or any of their Affiliates, of the Purchase Contract) in similar circumstances would not undertake reworking operations to restore production.

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Section 6.05. Insurance. Velasco is not obligated under this Conveyance to carry insurance on any Well or the Subject Interests or covering any risks with respect thereto. Provided that Velasco has not breached Section 6.01 hereof, Velasco shall not be liable to TEAI or the Trust (as assignee of TEAI under the following Part II) or the Trustee on account of any losses sustained that are not covered by insurance. In the event Velasco elects to carry insurance purchased from a third party on any Well or the Subject Interests or operation thereof, the premiums for such insurance shall be included in Production Costs.

ARTICLE VII

POOLING AND UNITIZATION

Section 7.01. Pooled Subject Interests. Some of the Subject Interests have been heretofore pooled, unitized or communitized for the production of Hydrocarbons. Such Subject Interests are and shall be subject to the terms and provisions of the Instruments governing such pooling, unitization or communitization, and the Royalty Interest in each such Subject Interest shall apply to and affect only the production from such units which accrues to such Subject Interest under and by virtue of the applicable pooling, unitization or communitization Instruments.

Section 7.02. Right to Pool. Velasco shall have the exclusive right and power (as between TEAI and the Trust as assignee of TEAI under the following Part II), exercisable only during the period provided in Section 7.03 hereof, to pool, unitize or communitize any of the Subject Interests and to alter, change or amend or terminate any pooling, unitization or communitization orders or Instruments heretofore or hereafter entered into, as to all or any part of the land covered hereby, as to any one or more of the formations or horizons hereunder, and as to any one or more Hydrocarbons, upon such terms and provisions as Velasco shall in its sole discretion determine. If and whenever through the exercise of such right and power, or pursuant to any law hereafter enacted or any rule, regulation or order of any governmental body or official hereafter promulgated, any of the Subject Interests are pooled, unitized or communitized in any manner, the Royalty

– 25 –

Interest insofar as it affects such Subject Interest shall also be pooled, unitized or communitized, and in any such event such Royalty Interest in such Subject Interest shall apply to and affect only the production which accrues to such Subject Interest under and by virtue of the pooling, unitization or communitization, and it shall not be necessary for TEAI or the Trust (as assignee of TEAI under the following Part II) to agree to, consent to, ratify, confirm or adopt any exercise of such right and power by Velasco.

Section 7.03. Applicable Period. Velasco’s power and rights in Section 7.02 shall be exercisable only during the period of the life of the last survivor of the descendants of the signers of the Declaration of Independence living on the date of execution hereof, plus twenty-one (21) years after the death of such last survivor.

ARTICLE VIII

GOVERNMENT REGULATION

All obligations of Velasco hereunder are subject to all present and future valid federal, state and local laws, statutes, codes and orders; and all applicable rules, orders, regulations and decisions of every court, governmental agency, body or authority having jurisdiction over Velasco, the Wells, the Subject Interests or the Subject Hydrocarbons.

ARTICLE IX

ASSIGNMENTS

Section 9.01. Assignment by Velasco. Velasco shall have the right to assign, sell, transfer, convey, mortgage or pledge the Subject Interests, or any part thereof or interest therein, to any third party, including an Affiliate of Velasco, subject to the Royalty Interests and to the terms and provisions of this Conveyance; provided that such assignment shall be subject to the conditions and the notice requirements of Section 12.08 of the Trust Agreement. From and after the effective date of any such assignment, sale, transfer or conveyance by Velasco, the assignee thereunder shall succeed to all the rights and duties of Velasco hereunder as to the interests in the Subject Interests so acquired by such assignee, and, if such assignee expressly assumes all

– 26 –

duties of Velasco hereunder as to the interests so acquired, Velasco shall be relieved of such duties, except to the extent such relate to periods prior to effective date of such assignment. If Velasco assigns a part of or interest in (but less than all) the Subject Interests, then, from and after the effective date of any such assignment, in determining the Royalty Interests payable with respect to the part or interest so assigned, the Royalty Interests shall be computed and determined by the assignee in the aggregate as to the assigned interests owned by such assignee, separate from and not aggregated with the computation and determination made by Velasco as to unassigned interests.

Section 9.02. Assignment by TEAI and the Trust. TEAI shall have the right to assign and convey the Royalty Interests only to the Trust (as is done in the following Part II), and the Trust shall not assign or convey the Royalty Interests except as provided under the Trust Agreement. In making conveyances or assignments of any of the Subject Interests (to the extent permitted hereunder), the Trust need not vest in its grantee or assignee all of the rights of TEAI or the Trust hereunder with respect to the interest in the Subject Interests so conveyed or assigned.

Section 9.03. Change in Ownership. No change in ownership or right to receive payment of the Royalty Interests, or of any part thereof, however accomplished, shall be binding upon Velasco until notice thereof shall have been furnished by the Person claiming the benefit thereof, and then only with respect to payments thereafter made. Notice of sale or assignment shall consist of a certified copy of the recorded instrument accomplishing the same; notice of change of ownership or right to receive payment accomplished in any other manner (for example by reason of incapacity, death or dissolution) shall consist of certified copies of recorded documents and complete proceedings legally binding and conclusive of the rights of all parties. Until such notice accompanied by such documentation shall have been furnished Velasco as above provided, the payment or tender of all sums payable on the Royalty Interests may be made in the manner provided herein precisely as if

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no such change in interest or ownership or right to receive payment had occurred, or (at Velasco’s election) Velasco shall have the right to suspend payment of such sums without interest in the event of such change until such documentation is furnished. The kind of notice herein provided shall be exclusive, and no other kind, whether actual or constructive, shall be binding on Velasco. Assignment by the Trust shall not affect the method of computing the Royalty Interests, and if more than one Person becomes entitled to participate in the Royalty Interests, Velasco may withhold from such other Person payments to which such Person would otherwise be entitled hereunder and the furnishing of any data or information which Velasco is required by the terms hereof to furnish TEAI or the Trust until Velasco is furnished a recordable instrument executed by or binding upon all Persons interested in the Royalty Interests designating one Person who is to receive such payments, data and information.

Section 9.04. Rights of Mortgagee. If the Trust (as assignee of TEAI under the following Part II) should at any time execute a mortgage or deed of trust or security interest covering all or part of the Royalty Interests, the mortgagee or trustee therein named or the holder of any obligation secured thereby shall be entitled, to the extent such mortgage, deed of trust or security agreement so provides, to exercise all the rights, remedies, powers and privileges conferred upon the Trust by the terms of this Conveyance and to give or withhold all consents required to be obtained hereunder by the Trust, but the provisions of this Section 9.04 shall in no way be deemed or construed to impose upon Velasco any obligation or liability undertaken by the Trust under such mortgage, deed of trust or security agreement or under the obligation secured thereby.

PART II

ARTICLE X

GRANT

Section 10.01. Royalty Interests. For and in consideration of good and valuable consideration paid to TEAI, the receipt and

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sufficiency of which are hereby acknowledged, TEAI does hereby BARGAIN, SELL, GRANT, CONVEY, TRANSFER and ASSIGN unto the Trust the Net Royalty Interest, the Infill Net Royalty Interest and the Pre-1980 Net Royalty Interest, which were vested in TEAI under Part I of this Conveyance.

Section 10.02. Habendum Clause. TO HAVE AND TO HOLD the Net Royalty Interest, the Infill Royalty Interest and the Pre-1980 Net Royalty Interest, together with all and singular the rights and appurtenances thereto in anywise belonging, unto the Trust, subject to and entitled to all the benefits of the terms and provisions of this Conveyance.

Section 10.03. Nature of Interests. The Royalty Interests conveyed hereby are nonoperating, nonexpense-bearing variable royalty interests in and to the Subject Lands, and this Conveyance is an absolute conveyance of interests in real property.

THE FOLLOWING PROVISIONS SHALL BE DEEMED TO BE INCORPORATED IN BOTH PARTS OF THIS CONVEYANCE.

ARTICLE XI

MISCELLANEOUS

Section 11.01. Controlling Document. This Conveyance and any terms contained herein shall control over any other document between the parties hereto with respect to the conveyance of the Royalty Interests.

Section 11.02. Proportionate Reduction. In the event of failure or deficiency in title to any of the Subject Interests not in breach of the warranty as to title in Section 11.06 hereof, the portion of the production from such Subject Interest out of which the Royalty Interests attributable to such Subject Interest shall be payable shall be reduced in the same proportion that such Subject Interest is reduced.

Section 11.03. Notices. Any notice, request, consent, demand, statement, payment or other communication required or permitted between the parties to this Conveyance shall be in writing and shall be deemed to have been duly given on the date of service, if served personally on the party or parties to whom such notice is

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directed, or on the date of receipt, if mailed to the party or parties to whom the notice is directed by registered or certified mail, return receipt requested, postage prepaid, and properly addressed as follows:


VELASCO GAS COMPANY, LTD.
1221 Lamar
Suite 1600
Houston, Texas 77010
Attention:		Roland E. Sledge
		Senior Vice President and General Counsel

TORCH ENERGY ADVISORS INCORPORATED
1221 Lamar
Suite 1600
Houston, Texas 77010
Attention:		Roland E. Sledge
		Senior Vice President and General Counsel

and

TORCH ENERGY ROYALTY TRUST
c/o Wilmington Trust Company
Rodney Square North
1100 North Market Street
Wilmington, Delaware 19890-0001
Attention:		Torch Energy Royalty Trust

Any party may change its address for purposes of this paragraph by giving the other parties hereto written notice of the new address in the manner set forth above.

Section 11.04. Binding Effect. This Conveyance shall bind and inure to the benefit of the successors and assigns of the parties hereto.

Section 11.05. Governing Law. This Conveyance shall be governed by the laws of the State of Alabama, without regard to the conflict of laws principles thereof.

Section 11.06. Warranty as to Title to Subject Interests. This Conveyance, in Part I and Part II, is made with warranty of title against every person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Velasco (in Part I) and TEAI (in Part II) and its and their Affiliates, but not otherwise, except as provided in Section 11.08 below. Velasco warrants to the Trust, and its successors and assigns, by, through or under Velasco and its Affiliates, but not otherwise, that Velasco and its Affiliates (i) have not taken any action or (ii) failed to take any action, with respect to the Subject Interests covering or attributable to each Well identified on

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Exhibit B attached hereto, which, in either case, pursuant to the terms of the Instruments by which title is held, (i) would result in a Net Revenue Interest (as such term is defined in Exhibit B) in each Well which is less than the Net Revenue Interest specified in Exhibit B for that Well, or (ii) would result in a Working Interest (as such term is defined in Exhibit B) in each Well which is greater than the Working Interest specified in Exhibit B for that Well. TEAI (under Part I) and the Trust (under Part II) each accepts the Royalty Interests conveyed hereby in an AS IS, WHERE IS condition. SUBJECT TO THE FOREGOING, EACH OF VELASCO AND TEAI MAKES NO WARRANTIES, EITHER EXPRESS, IMPLIED OR STATUTORY, WITH RESPECT TO ANY OF THE SUBJECT INTERESTS, THE WELLS OR THE ROYALTY INTERESTS, AND EACH OF VELASCO AND TEAI SPECIFICALLY DISCLAIMS ANY EXPRESS, IMPLIED OR STATUTORY WARRANTY REGARDING THE CONDITION OF THE SUBJECT INTERESTS, THE WELLS AND THE ROYALTY INTERESTS, THE MERCHANTABILITY THEREOF OR THE FITNESS THEREOF FOR A PARTICULAR PURPOSE. Except as expressly set forth above, each of TEAI and the Trust acknowledges and agrees that VELASCO (in Part I) and TEAI (in Part II) MAKES NO WARRANTIES EITHER EXPRESS, IMPLIED OR STATUTORY WITH RESPECT TO ANY PERSONAL PROPERTY OR FIXTURES LOCATED ON OR SERVING ANY OF THE SUBJECT INTERESTS, AND EACH OF VELASCO AND TEAI SPECIFICALLY DISCLAIMS ANY EXPRESS, IMPLIED OR STATUTORY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR OTHERWISE REGARDING THE CONDITION OF ANY SUCH PERSONAL PROPERTY OR FIXTURE.

Section 11.07. Substitution of Warranty. This instrument is made with full substitution and subrogation of TEAI and the Trust, as assignee of TEAI under the foregoing Part II, in and to all covenants of warranty by others heretofore given or made with respect to the Subject Interests, or any part thereof, or interest therein.

Section 11.08. Consents and Waivers. For purposes of Section 11.06, it shall be considered a breach of Velasco’s warranty of title if any necessary consent or approval has not been obtained or if any preferential purchase right has not been waived, in each case, where the failure to obtain any such consent, approval or

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waiver renders (i) any conveyance of the Subject Interests by an Affiliate of Velasco to another Affiliate of Velasco, (ii) the conveyance of the Subject Interests by an Affiliate of Velasco to Velasco or (iii) the conveyance of the Royalty Interests to TEAI and then to the Trust, void or results in a valid action for breach of contract as a result of the failure to obtain such consent, approval or waiver.

Section 11.09. Arbitration. ANY DISPUTE, CONTROVERSY OR CLAIM THAT MAY ARISE UNDER THIS CONVEYANCE SHALL BE GOVERNED BY AND SUBJECT TO THE ARBITRATION PROVISIONS SET FORTH IN ARTICLE XI OF THE TRUST AGREEMENT.

Section 11.10. Counterpart Execution. This Conveyance may be executed in several counterparts, all of which are identical and each of which will be an original. All of such counterparts together shall constitute one and the same instrument.

Section 11.11. Further Assurances. Velasco and TEAI agree to execute and deliver all additional instruments, agreements and other documents as may be necessary or appropriate to effectuate fully the terms and conditions hereto, including, but not limited to, such other additional instruments, agreements and other documents as may be necessary to correct or more fully describe and identify the properties and interests herein intended to be assigned and conveyed, or such other instruments as may be required by the appropriate governmental agencies or bodies having jurisdiction over such Federal, State or Indian lands as are covered by this Conveyance.

Section 11.12. Filing. Velasco shall file this Conveyance in the real property records of the Counties in which the Subject Interests are located as shown by the recitations in Exhibit A attached hereto and shall make all other appropriate filings with Federal, State and Indian agencies as determined appropriate by Velasco.

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Section 11.13. Construction. In construing this Conveyance, the following principles shall be followed:

(a) no consideration shall be given to the captions of the articles or sections, which are inserted for convenience in locating the provisions of this Conveyance and not as an aid in its construction;

(b) the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions;

(c) a defined term has its defined meaning throughout this Conveyance and in each exhibit, attachment and schedule to this Conveyance, regardless of whether it appears before or after the place where it is defined; and

(d) each exhibit, attachment and schedule to this Conveyance is a part of this Conveyance, but if there is any conflict or inconsistency between the main body of this Conveyance and any exhibit, attachment or schedule, the provisions of the main body of this Conveyance shall prevail.

IN WITNESS WHEREOF, each of the parties hereto has caused this Conveyance to be executed in its name and behalf and delivered on the 22nd day of November, 1993, effective as of the Effective Time.


VELASCO GAS COMPANY, LTD.

By:		TORCH ENERGY COMPANY, its general partner

By:		/s/ Sue Ann Craddock
Name:		Sue Ann Craddock
Title:		Vice President

TORCH ENERGY ADVISORS INCORPORATED

By:		/s/ Sue Ann Craddock
Name:		Sue Ann Craddock
Title:		Vice President

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TORCH ENERGY ROYALTY TRUST
By		WILMINGTON TRUST COMPANY, its Trustee

By:		/s/ Jim Lawler
Name:		Jim Lawler
Title:		Vice President


STATE OF TEXAS		§
		§
COUNTY OF HARRIS		§

I, the undersigned, a Notary Public in and for said county and state, hereby certify that Sue Ann Craddock, whose name as Vice President of Torch Energy Company, a corporation, as general partner of VELASCO GAS COMPANY, LTD., a limited partnership, is signed to the foregoing conveyance, and who is known to me, acknowledged before me on this day that, being informed of the contents of the conveyance, she, in her capacity as aforesaid, and with full authority, executed the same voluntarily for and as the act of said corporation as such general partner on the day the same bears date.

Given under my hand this 22nd day of November, A.D. 1993.

/s/ Barbara Ward

Notary Public in and for

the State of Texas


My Commission Expires:
May 16, 1995	[NOTARY SEAL]	BARBARA WARD Notary Public STATE OF TEXAS My Comm. Exp. May 16, 1995


STATE OF TEXAS		§
		§
COUNTY OF HARRIS		§

I, the undersigned, a Notary Public in and for said county and state, hereby certify that Sue Ann Craddock, whose name as Vice President of Torch Energy Advisors Incorporated, a Delaware corporation, is signed to the foregoing conveyance and who is known to me, acknowledged before me on this day that, being informed of the contents of the conveyance, she, as such officer and with full authority, executed the same voluntarily and for and as the act of said corporation.

Given under my hand this 22nd day of November, A.D. 1993.

/s/ Barbara Ward

Notary Public in and for

the State of Texas


My Commission Expires:
May 16, 1995	[NOTARY SEAL]	BARBARA WARD Notary Public STATE OF TEXAS My Comm. Exp. May 16, 1995

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STATE OF TEXAS		§
		§
COUNTY OF HARRIS		§

I, the undersigned, a Notary Public in and for said county and state, hereby certify that JIM LAWLER whose name as VICE PRESIDENT of Wilmington Trust Company, as Trustee of TORCH ENERGY ROYALTY TRUST, a Delaware Business Trust, is signed to the foregoing conveyance, and who is known to me, acknowledged before me on this day that, being informed of the contents of the conveyance, he, in his capacity as aforesaid, and with full authority, executed the same voluntarily for and as the act of said Wilmington Trust Company as such trustee on the day the same bears date.

Given under my hand this 22nd day of NOVEMBER, A.D. 1993.

/s/ Barbara Ward

Notary Public in and for

STATE OF TEXAS


My Commission Expires:
May 16, 1995	[NOTARY SEAL]	BARBARA WARD Notary Public STATE OF TEXAS My Comm. Exp. May 16, 1995

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Oil and Gas Purchase Agreement

Exhibit 10.5

OIL AND GAS PURCHASE CONTRACT

This Oil and Gas Purchase Contract (the “Contract”) is made and entered into as of the 1st day of October, 1993, by and between TORCH ENERGY MARKETING, INC., a Delaware corporation (hereinafter referred to as “Buyer”), and TORCH ROYALTY COMPANY, a Delaware corporation, and VELASCO GAS COMPANY LTD., a Texas limited partnership (hereinafter collectively referred to as “Seller”).

RECITALS

WHEREAS, Seller has a supply of Oil and Gas to be produced from the Subject Interests (as hereinafter defined) which Seller desires to sell; and

WHEREAS, the parties hereto intend to provide for and desire to enter into a contract for the sale by Seller and the purchase by Buyer of Oil and Gas produced from the Subject Interests pursuant to the provisions of this Contract:

NOW THEREFORE, in consideration of the foregoing premises and the mutual promises, agreements and covenants herein set forth, Seller and Buyer agree as follows:

I. DEFINITIONS

The following terms, where used and whether or not capitalized in this Contract, and all recitals, exhibits, and appendices contained in or attached to this Contract have the following meanings:

“Applicable Hub Price” has the meaning set forth in Section 4.06.

“Applicable Hub Price-NYMEX Differential” for each production Month and for each Field during such Month, means (in dollars per MMBtu) (i) the average of the last three days’ settlement prices for the corresponding Natural Gas futures contract on the New York Mercantile Exchange first nearby contracts (i.e. settlement prices for the month of June are the settlement prices for the June futures contracts on the last three days in May during which such June futures contracts are traded) minus (ii) the Applicable Hub Price for such Field for such Month.

“Austin Chalk Fields” means the Subject Interests identified as the Austin Chalk Fields in the Conveyances.

“Barrel” means a barrel of Oil equal to 42 U.S. gallons at 60 degrees Fahrenheit.

“Btu” means British thermal unit. As used herein, Btu content of an Mcf of gas will be calculated on a dry basis. MMBtu means 1,000,000 Btu.

“Chalkley Field” means the Subject Interests identified as the Chalkley Field in the Conveyances.

“Contract Year” means the period beginning on January 1 and continuing thereafter for a period of 365 days (or 366 days in the case of a leap year) and each succeeding 365 day (or 366 day as the case may be) period thereafter, except for the first Contract year, which shall commence on October 1, 1993 and end December 31, 1993.

“Conveyances” means the Net Overriding Royalty Conveyances to the Royalty Trust dated as of November 22, 1993.

“Cotton Valley Fields” means the Subject Interests identified as the Cotton Valley Fields in the Conveyances.

“Day” means the period of time defined as “day” or “daily” in the effective tariff or other operating rules, policies or procedures of the Receiving Pipeline.

“Deductible Costs” means for each Month for each Field the amount, on a per MMBtu basis, specified on Exhibit A as deductible costs for such Field.

“Existing Burdens” has the meaning assigned to that term in the Conveyances.

“FERC” or “Commission” means Federal Energy Regulatory Commission or any successor thereto, having jurisdiction.

“Fields” means, collectively, the Chalkley Field, the Robinson’s Bend Field, the Cotton Valley Fields and the Austin Chalk Fields.

“Field Price” shall have the meaning set forth in Section 4.14.

“Field Price-NYMEX Differential” for each production Month during the term of this Contract and for each Field during such Month means (in dollars per Barrel) (i) the average during such Month of the daily settlement prices of the first nearby futures contracts for West Texas Intermediate Crude Oil on the New York Mercantile Exchange minus (ii) the Field Price for such Field for such Month.

“Gas” means any mixture of hydrocarbons or of hydrocarbons and noncombustible gases, in a gaseous state, consisting essentially of methane and including gas produced in association with oil and commonly known as casinghead gas. Gas shall include, but shall not be limited to, methane produced from coal beds.

“Gas Gathering Agreement” shall mean the Gas Gathering Agreement, dated June 30, 1990, as amended, between Buyer, as “Shipper,” and Bahia Gas Gathering Ltd., a Texas limited partnership, as “Gatherer.”

“Mainline Point” means the location specified for each Field on Exhibit A.

“Maximum Volume” shall mean, prior to January 1, 1995, the Btu equivalent of 730 MMcf of Seller’s Gas produced from the Robinson’s Bend Field during any quarter, and thereafter the Btu equivalent of 912.5 MMcf of Seller’s Gas produced from the Robinson’s Bend Field during any Quarter.

“Month” means the period of time defined as “Month” or “Monthly” in the effective tariff or other operating rules, policies or procedures of the Receiving Pipeline.

“Oil” means crude oil and condensate.

“Producer Price Index” shall mean the Producer Price Index published by the Bureau of Labor Statistics of the United States Department of Labor.

“Production Deficiency” means, for any Month, the amount (expressed in MMBtu’s) by which the total production of Seller’s Gas from the Robinson’s Bend Field during such Month is, for any month ending prior to January 1, 1995, less than the Btu equivalent of 243,334 Mcf, and for any month ending thereafter, is less than the Btu equivalent of 304,167 Mcf.

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“Weighted Average Field Price” for each Month during the term of this Contract, means (in dollars per Barrel) the average of the Field Price for each Field, weighted for Oil production from each such Field.

“Weighted Average Hub Price” for each Month during the term of this Contract, means (in dollars per MMBtu) the result of (i) total Seller’s Gas production from each Field multiplied by the Applicable Hub Price for such Field, divided by (ii) total Seller’s Gas production from the Fields during the Month.

“Weighted Average Specified Gas Price” for each Month means (in dollars per MMBtu) the average of the difference between the Specified Price for Gas for such Month minus the Applicable Hub Price-NYMEX Differential for each Field during such Month, weighted for Seller’s Gas production from such Field during such Month.

“Weighted Average Specified Oil Price” for each Month means (in dollars per Barrel) the average of the difference between the Specified Price for Oil for such Month minus the Field Price-NYMEX Differential for the Month for each Field during such Month, weighted for Seller’s Oil production from such Field during such Month.

“Wells” means any well described on Exhibit B, including any infill or replacement wells drilled and completed after the date of this Contract which produce Seller’s Oil or Seller’s Gas from the Fields.

“Working Day” means a calendar day Monday through Friday and excludes Saturday, Sunday and nationally recognized holidays.

II. QUANTITY; COMMITMENT, RESERVATION

2.01 Quantity: Subject to the terms and conditions herein, (i) Seller agrees to sell and deliver to Buyer and Buyer agrees to purchase and accept from Seller all of Seller’s Gas produced from the Wells, subject to applicable operating and Gas balancing agreements covering the Wells; and (ii) Seller agrees to sell and deliver to Buyer and Buyer agrees to purchase and accept from Seller all of Seller’s Oil produced from the Wells, subject to applicable operating agreements covering the Wells.

2.02 Commitment: Seller hereby commits and dedicates to the performance of this Contract all of Seller’s Oil and Seller’s Gas.

2.03 Reservations: Seller specifically reserves and excepts the following quantities of Seller’s Gas from the quantities to be delivered under the terms of this Contract:

a. All Seller’s Gas which Seller may require for fuel for operation and development of the Subject Interests and all free gas which Seller is obligated to furnish under any operating agreements or leases which grant Seller the right to drill for, produce or dispose of Seller’s Gas in, under and from the Subject Interests.

b. All volumes of Seller’s Gas which are contractually committed as of the date hereof for delivery to others under the existing terms of leases or applicable operating agreements, provided that for purposes hereof, Buyer shall be deemed to purchase and Seller shall be deemed to sell all committed Seller’s Gas for the Monthly Gas Price and to immediately resell such Seller’s Gas pursuant to such contractual commitments.

c. Subject to the terms of the Conveyances, the right to operate or manage leases in such manner as Seller, in Seller’s sole discretion, may deem advisable and, acting as a prudent operator or working interest owner, to drill new Wells, repair or rework old Wells, renew or extend, in whole or in

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part, any lease or unit subject to this contract and abandon any Well or surrender, release or terminate any lease not deemed by Seller capable of producing Gas in commercial quantities.

d. The right to use Seller’s Gas for cycling, repressuring and pressure maintenance on the Subject Interests or Units to which the Subject Interests are or shall be committed; however, Seller’s Gas so used shall be tendered by Seller to Buyer for purchase hereunder when such Gas becomes available for delivery.

e. Seller’s Gas reasonably necessary for gas-lifting of oil produced on or attributable to leases; provided, however, if Seller uses substantial volumes of Seller’s Gas for such gas-lifting operations Seller shall deliver such Gas pursuant to the terms hereof at the conclusion of each operation, or as it is produced, at a pressure sufficient to enable such Gas to enter the system of the Receiving Pipeline at the pressure then existing therein.

2.04 Processing: Seller’s Gas will be delivered hereunder before any processing occurs, and the right to process, or cause the processing of, all Seller’s Gas delivered hereunder, for the extraction of ethane, propane, butanes, pentanes and heavier hydrocarbons belongs to Buyer (which bears so much methane as is necessarily removed in the employment of customary processes for the extraction of all such components and such Gas as is required for fuel or is otherwise lost in such extraction process), and all right, title, and interest to all such components extracted belongs to Buyer (which bears all Seller’s Gas used or otherwise lost in such extraction process).

2.05 Verification: Upon written request from Buyer, Seller shall furnish Buyer, as available, all information concerning engineering, tests and basic geological data on all Wells. Such data shall include, but is not limited to, all production data and flow potential data now or hereafter in existence. Seller shall furnish Buyer information concerning production allowables and proration status with respect to each Well connected under this Contract.

III. DELIVERY OF OIL AND GAS

3.01 Delivery Point: The delivery point, for Seller’s Gas produced from each Field, shall be the point described as the Delivery Point on Exhibit A or such other point or points as the parties may agree upon in writing from time to time (the “Delivery Point”). The Delivery Point for Seller’s Oil is the point of transfer to Buyer or its designee from the lease tanks or other base measuring facility located on the Underlying Properties.

3.02 Transportation: Seller shall be responsible for all arrangements necessary to deliver Seller’s Oil and Gas sold hereunder to the Delivery Point and Buyer shall be responsible for all arrangements necessary to receive Seller’s Oil and Gas purchased hereunder at the Delivery Point.

3.03 Delivery Pressure, Quality, and Measurement: Seller’s Gas delivered by Seller shall be of the same quality and heating value for the Gas as specified in the effective tariff or other operating rules, policies or procedures of the Receiving Pipeline at the Mainline Point. Measurement shall be performed by the Receiving Pipeline.

3.04 Title: Title, ownership and risk of loss of Seller’s Oil and Seller’s Gas sold hereunder shall pass from Seller and vest in Buyer upon delivery and acceptance of such Oil and Gas at the Delivery Points.

3.05 Delivery Rate: In connection with deliveries of Seller’s Gas hereunder, both parties shall be obligated to use reasonable efforts to avoid causing pipeline imbalances and to determine the cause of any pipeline imbalances for which a charge or penalty may be imposed. The party responsible for such imbalance

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charge or penalty shall be obligated to pay such imbalance charge or penalty regardless of whether it is the shipper on the subject pipeline.

IV. PRICE FOR OIL AND GAS

4.01 Gas Purchase Price:. Subject to Section 4.06 and subject to adjustment as provided in Section 4.02, the Monthly purchase price for Seller’s Gas (“Monthly Gas Price”) per MMBtu delivered to the Delivery Point and sold by Seller and purchased by Buyer shall be the greater of (i) $1.70 per MMBtu (the “Minimum Price”) and (ii) the Index Price. The Index Price for any Month shall equal 97% of the result of the following for such Month: (i) the Weighted Average Hub Price multiplied times the Variable Gas Ratio, plus (ii) the Weighted Average Specified Gas Price multiplied times the Specified Gas Ratio.

4.02 Primary Term: For the period commencing October 1, 1993 through December 31, 2001 (“Primary Term”), the Monthly Gas Price for Seller’s Gas shall be subject to the following:

a. In the event the Index Price in any Month is greater than $2.10 per MMBtu (the “Sharing Price”), then the Monthly Gas Price shall be an amount equal to the following: the Sharing Price per MMBtu plus fifty percent of the difference between the Index Price and the Sharing Price (such portion of the difference being the “Price Differential”); provided Buyer has no accrued Price Credits (defined in paragraph 4.02b below) in the Price Credit Account (defined in paragraph 4.02b below).

b. In the event the Index Price in any Month is less than the Minimum Price per MMBtu, then the Monthly Gas Price shall be equal to the Minimum Price per MMBtu and Buyer shall receive a credit (“Price Credit”) from Seller equal to the difference between the Index Price and the Minimum Price for each MMBtu of gas sold during such Month which shall be credited (dollar for dollar) to an account (“Price Credit Account”) to be established by Buyer, for each MMBtu of Seller’s Gas so purchased by Buyer. No Price Credits will accrue in respect of production purchased by TEMI prior to January 1, 1994.

c. Notwithstanding paragraphs a and b of this Section 4.02, if Buyer has any accrued Price Credits in the Price Credit Account, the Monthly Gas Price for each MMBtu of Seller’s Gas purchased by Buyer will be reduced (but not below the Minimum Price) such that Buyer shall receive, with respect to Seller’s Gas purchased by Buyer during such Month, an offset (dollar for dollar) against any Price Credits in the Price Credit Account.

4.03 Remaining Term: Following the expiration of the Primary Term and for the remaining term of this Agreement, Buyer shall have the option (the “Option”) to cause the Monthly Gas Price to equal the Index Price for the remaining term of the contract. Buyer shall exercise the Option not later than fifteen Days prior to the expiration of the Primary Term and, thereafter during the remaining term, not later than fifteen Days prior to the expiration of a Contract Year by notifying Seller in writing of Buyer’s election to exercise the Option. In the event Buyer exercises the Option, Buyer shall be precluded from recovering any remaining Price Credits from the Price Credit Account after the purchase of Seller’s Gas at the Index Price becomes effective. The Option granted herein once exercised shall be effective on the next following first Day of January. This Option shall not be exercised more than once during the term of this Agreement. If Buyer does not exercise the Option, then the Minimum Price and the Sharing Price shall be increased for inflation based on the Producer Price Index on January 1 of each year commencing January 1, 2002.

4.04 Included Costs Prior to the Delivery Point: Buyer may deduct from the price paid for Seller’s Oil or Gas hereunder all Taxes, expenses and costs arising or attributable to Seller’s Oil or Seller’s Gas prior to its delivery to the Delivery Point to the extent (if any) incurred by Buyer. If Buyer makes any such deductions, Buyer shall assume the obligation of applying the amounts so deducted to those entitled thereto. If

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Buyer does not deduct royalties, Seller assumes the obligation, if any, to pay proceeds due royalty owners or any other persons entitled thereto.

4.05 Robinson’s Bend field: Notwithstanding the provisions of Sections 4.01 and 4.02, the purchase price for Seller’s Gas produced in the Robinson’s Bend field during any Month within a Quarter shall be subject to the following:

a. If, during any Quarter, there is no Production Deficiency in any Month during such Quarter, with respect to production from the Robinson’s Bend Field, Buyer shall be deemed to purchase and Seller shall be deemed to sell, one third of the Maximum Volume during each Month in such Quarter, for the Monthly Gas Price for such Month.

b. If, during any Quarter, there is a Production Deficiency in one (but only one) Month during such Quarter, with respect to production from the Robinson’s Bend Field, Buyer shall be deemed to purchase and Seller shall be deemed to sell (i) one third of the Maximum Volume during each of the Months during which there is no Production Deficiency for the Monthly Gas Price for such Month, (ii) all production during the Month during which there was a Production Deficiency at the Monthly Gas Price for such Month, and (iii) an amount of Seller’s Gas equal to the lesser of the Production Deficiency and the aggregate Production Excess for the Quarter at a weighted average price computed based on the Monthly Gas Price and amount of Production Excess for the Months in such Quarter during which there was no Production Deficiency.

c. If during any Quarter, there is a Production Deficiency in two (but only two) Months during such Quarter, with respect to production from the Robinson’s Bend field, Buyer shall be deemed to purchase and Seller shall be deemed to sell (i) one third of the Maximum Volume during the Month in which there was no Production Deficiency for the Monthly Gas Price for such Month, (ii) all production during each Month for which there was a Production Deficiency at the Monthly Gas Price during such Month, and (iii) an amount of Seller’s Gas equal to the lesser of the aggregate Production Deficiency for such Quarter and the Production Excess for the Quarter at the Monthly Gas Price for the Month during such Quarter in which there was no Production Deficiency.

d. If during any Quarter, there is a Production Deficiency in each Month during such Quarter, with respect to production from the Robinson’s Bend field, Buyer shall be deemed to purchase and Seller shall be deemed to sell all production during each Month at the Monthly Gas Price during such Month.

4.06 Applicable Hub Prices: The Applicable Hub Price for each Field during the Month shall be the “Index Price” as published in the first issue during such Month of Inside FERC’s Gas Market Report for the referenced pipeline and/or market hubs set forth below:


Chalkley Field		Tennessee Gas Pipeline; Louisiana & Offshore Southern National Gas Co., Louisiana

Robinson’s Bend Field Cotton Valley Fields		Natural Gas Pipeline Co., Texas (Gulf Coast Line)

Austin Chalk Fields		Houston Ship Channel; Index (large packages only)

provided that gas production from the Austin Chalk Fields shall be 83% of the Applicable Hub Price. In the event the publishers of Inside FERC’s Gas Market Report determine there is insufficient data to publish an

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Applicable Hub Price for any Field, and Inside FERC’s Gas Market Report instead publishes a range of prices at such hub, then the average of the range of prices shall be the Applicable Hub Price for the Field.

4.07 Replacement Applicable Hub Price: In the event the publisher of the Applicable Hub Price or any Replacement Hub Price (defined below) ceases publication of any of the foregoing referenced indices, substantially alters the method by which any of the foregoing referenced indices are calculated, substantially alters the source of data utilized in calculating any of the foregoing referenced indices or otherwise substantially alters any of the foregoing referenced indices, then in that event Buyer and Seller shall promptly notify the other in writing of such event and shall mutually agree in writing on an index price to replace the Applicable Hub Price or the replacement (“Replacement Hub Price”) within 30 Working Days (herein referred to as the “Negotiation Period”) following the date of such written notice. In the event that Buyer and Seller are unable to agree on a Replacement Hub Price within the Negotiation Period, then in that event the parties shall submit the determination of such Replacement Hub Price to arbitration as provided for in Sections 4.08 through 4.12 below.

4.08 Selection of the Arbitrator: Not later than ten Working Days following expiration of the Hub Negotiation Period provided for in Section 4.07 above, Buyer and Seller shall mutually select and appoint a qualified neutral third party as arbitrator not having any prior, current or future affiliation or association with Seller or Buyer, to determine a Replacement Hub Price. If at the end of such ten Working Day period the arbitrator has not been selected and appointed, then upon written request of either party an arbitrator shall be promptly selected by the American Arbitration Association (“AA”), which shall select and appoint an arbitrator (such third party whether appointed by the parties or by the AA herein referred to as “Arbitrator”) with the following minimum qualifications:

a. A minimum of ten years (immediately prior to the appointment) general experience in the purchase and sale of natural gas.

b. A minimum of three years experience pricing natural gas in the Henry Hub area.

4.09 Arbitration: Upon selection and appointment of the Arbitrator each party shall deliver to the other party and to the Arbitrator within ten Working Days of the appointment of the Arbitrator a written proposal stating a proposed Replacement Hub Price together with supporting materials and documentation. The other party may submit its written counterproposal together with supporting materials and documentation within ten Working Days of receipt of the written proposal from the Party initiating arbitration, to both the party and the Arbitrator. The Arbitrator may request additional information or documentation from either party, which information or documentation shall be timely provided. Upon receipt of each parties proposal the Arbitrator shall determine the Replacement Hub Price to be used in accordance with the following instructions, unless the parties agree in writing upon other instructions:

a. The Replacement Hub Price selected for a Field shall be representative of the Spot Market price for Gas delivered to the Mainline Point for such Field.

b. “Spot Market” shall mean the market price per MMBtu of Gas sold and purchased for a period of thirty Days (or a lesser term if Monthly indices are not published).

c. The Replacement Hub Price shall be reported on a Monthly basis in a publication of general circulation or dissemination.

d. The Arbitrator shall determine the Replacement Hub Price no later than sixty Working Days after the Arbitrator’s appointment.

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4.10 Price Payable Prior to and During Arbitration: In the event arbitration is invoked pursuant to Sections 4.07 through 4.08 of this Contract, then during the Negotiation Period through and until the Arbitrator has determined the Replacement Hub Price the price to be paid for all Seller’s Gas covered by this Contract shall be the last price in effect before arbitration was invoked. Upon the conclusion of the arbitration the price shall be adjusted retroactively to the date the applicable index was altered or ceased publication and each party shall pay to the other such amounts due under the Replacement Hub Price within twenty Working Days following the Arbitrator’s decision.

4.11 Finality of Award;Costs of Arbitration: The determination of the Arbitrator shall be final and binding on the parties, save in the event of manifest material error or misconduct by the Arbitrator. Each party shall bear its own costs and expenses and share equally the costs and expenses of the Arbitrator and the arbitration.

4.12 Supplemental Arbitration Rules: In the event that the procedures or rules for arbitration set forth above are inadequate to arbitrate the matters described above, or in the event of the absence of procedures or rules necessary to arbitrate the matter then the foregoing procedures and rules shall be supplemented by and the arbitration shall be conducted in accordance with the Commercial Arbitration Rules of the AA.

4.13 Purchase Price for Oil: The purchase price paid for each Barrel of Seller’s Oil purchased during each Month under the Contract shall be 97% of the following: (i) the Weighted Average Specified Oil Price for such Month multiplied times the Specified Oil Ratio plus (ii) the Weighted Average Field Price for such Month multiplied times the Variable Oil Ratio for such Month.

4.14 Field Price: The Field Price for Seller’s Oil produced each Month from each Field will be the average of Koch Oil Company’s daily posted prices for the Month for production from such Field of like kind, quality and area, with applicable adjustments for gravity and transportation. In the event Koch Oil Company postings are not available, then another purchasing company’s posting will be chosen by mutual agreement between the Buyer and Seller.

V. EFFECTIVE DATE AND TERM

5.01 Term: This Contract shall become effective on the date hereof and shall continue through December 31, 2012 or the earlier termination of the Royalty Trust.

VI. BILLING AND PAYMENT

6.01 Billing: Buyer shall obtain from the Receiving Pipeline information on the quantity of Seller’s Gas delivered hereunder. A statement setting forth and accounting for the quantity of Seller’s Gas delivered to Buyer and the allocation of the Monthly Gas Price shall be furnished to Seller at the time of the payment set forth in paragraph 6.02 below. If a discrepancy occurs between Seller’s documentation and Buyer’s documentation, Buyer will render payment on the undisputed volume. Upon agreement as to volume between Seller, Buyer and the Receiving Pipeline, the parties shall remit and/or refund payments to make such adjustments as are necessary. The records of the Receiving Pipeline shall control in the event of a difference or dispute between Seller’s records and Buyer’s records.

6.02 Payment: Buyer shall render the payment to Seller by wire transfer for Seller’s Oil and Gas delivered during any Month on the last Day of the second Month following the end of the calendar quarter during which the Oil and Gas was delivered.

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6.03 Auditing: Each party shall have the right at reasonable hours to examine the records of the other party to the extent necessary to verify the accuracy of any statement made hereunder. In the event of any inaccuracy, any necessary adjustments in the billing shall be promptly made; provided that no adjustment for any billing and payment shall be made after the lapse of two years from the rendition thereof.

VII. TAXES AND CHARGES

Seller shall pay, or cause to be paid, all Taxes or other sums due on production or severance of Seller’s Gas prior to delivery to Buyer at the Delivery Point. All such Taxes shall be paid by Seller directly to the taxing authority unless Buyer is required by law to collect and remit such Taxes, in which event Buyer shall withhold from payments to Seller an amount required to be collected and remitted by Buyer. In those states in which Buyer, as the first purchaser, is required to remit Taxes or file a response, Seller shall, upon the request of Buyer, provide Buyer with any necessary additional information. If any such Tax is claimed, assessed or levied on Buyer, then Seller shall reimburse Buyer for the amount of such Tax. Buyer is entitled to purchase Seller’s Oil and Gas free from sales, use or gross receipts Taxes arising upon delivery of such Oil and Gas and Buyer shall, upon request of Seller, furnish Seller with any applicable exemption certificates.

VIII. WARRANTY OF TITLE

Seller warrants title to all Seller’s Oil and Gas delivered hereunder, that it has the right to sell and transfer title to the same and that said Oil and Gas is free and clear of all liens, claims and encumbrances. In the event of any adverse claim being asserted against Seller’s Oil and Gas, Buyer shall have the right to withhold payment, of sums due hereunder up to the amount of the claim until such claim shall have been finally determined or until Seller shall have furnished other adequate security to Buyer. Seller shall indemnify, defend and hold Buyer harmless from and against any loss, damage, cost or expense including court costs, witness and attorney fees and expenses arising out of breach of the foregoing warranties.

IX. INDEMNITY

Buyer shall indemnify, defend and hold Seller harmless from and against all loss, cost and expense, including court costs and attorney fees, for any claims, suits, judgments, demands actions or liabilities growing out of the operations conducted or performance hereunder by Buyer or arising while Seller’s Oil and Gas is in Buyer’s exclusive control and possession. Seller shall indemnify, defend and hold Buyer harmless from and against any loss, cost and expense, including court costs and attorney fees, for any claims, suits, judgments, demands, actions or liabilities growing out of Seller’s operation hereunder or arising while Seller’s Oil and Gas is in Seller’s exclusive control and possession.

X. FORCE MAJEURE

10.01 General: Neither party shall be responsible for any loss or damage to the other party resulting from any delay in performing or failure to perform any obligation under this Contract (other than Buyer’s obligation to pay Seller for Seller’s Gas purchased and accepted hereunder) to the extent such failure or delay is caused by Force Majeure.

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10.02 Defined: “Force Majeure” means any event that, directly or indirectly, renders a party unable, wholly or in part, to perform or comply with any obligation or condition of this Contract to the extent that the event, or the adverse effects of the event, could not have been prevented by the affected party with reasonable foresight, at reasonable cost, and by exercise of reasonable diligence, including the following events (to the extent they otherwise satisfy the foregoing definition):

a. Acts of God, landslides, lightning, earthquakes, fires, explosions, and other casualties.

b. Strikes, lockouts and other industrial disturbances.

c. Acts of the public enemy, wars, blockades, insurrections, riots, epidemics, arrests or restraints of government (federal, state, local, civil, tribal or military) or people, civil disturbances, national emergencies, and acts, orders or regulations of governmental agencies, or the affected party’s compliance therewith, or any governmental proration or priority.

d. The inability of the affected party to acquire, or delay on the part of the affected party in acquiring, materials, supplies, machinery, equipment, servitudes, rights-of-way, easements, permits, licenses, or approvals or authorizations of regulatory bodies needed to enable that party to perform its obligations under this Contract.

e. The physical constraint or restriction, or breakage, freezing, rupture, accident or blockage of or to, equipment or lines of pipe.

f. Interruption of any of Buyer’s gathering, treating, processing or transportation arrangements.

10.03 Notice: The party affected by Force Majeure shall give the other party notice of the occurrence of the Force Majeure as soon as reasonably practicable after such occurrence.

10.04 Remedy of Force Majeure: The party affected by Force Majeure shall use reasonable efforts to remedy each event of Force Majeure and resume full performance under this Contract as soon as reasonably practicable, except that the settlement of strikes, lockouts, and other labor disputes shall be entirely within the discretion of the affected party.

XI. REGULATORY AUTHORITY

11.01 Laws and Regulations: This Contract and each provision hereof shall be subject to all valid applicable federal, state, county, municipal and tribal laws and to the orders, rules and regulations of any duly constituted federal, state, county, municipal or tribal regulatory body or authority having jurisdiction. Either party shall have the right to contest the validity of any such law, order, rule or regulation and neither acquiescence therein or compliance therewith for any period of time shall be construed as a waiver of such right.

11.02 Natural Gas Regulation: Seller represents to Buyer that all Seller’s Gas sold to Buyer hereunder has never been committed or dedicated to interstate commerce pursuant to the Natural Gas Act, or that if any Seller’s Gas sold hereunder has ever been so committed or dedicated, it has been duly abandoned from such commitment or dedication pursuant to a rule, regulation or order of the FERC or it is no longer so committed or dedicated by operation of the Natural Gas Wellhead Decontrol Act of 1989. Seller further represents that the sale(s) by Seller to Buyer under this Contract qualify as a first sale(s) as defined in Natural Gas Policy Act of 1978, Section 2(21).

XII. SUCCESSORS AND ASSIGNS

This Contract shall be binding upon and inure to the benefit of the respective successors and assigns of the parties hereto, provided that this Contract shall not be transferred or assigned, by operation of law or

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otherwise, by either party without the other party’s prior written consent which consent shall not be unreasonably withheld.

XIII. NOTICES

Any notice, request, demand or statement provided for in this Contract shall be in writing and directed to the address of Buyer or Seller as set forth below, or at such other address as Seller or Buyer shall designate in writing from time to time and shall be deemed given when actually delivered in person or by a public or private mail delivery service or upon receipt of a telecopy or other electronic transmission to the following addresses and numbers designated below:


SELLER:		BUYER:

For Payment: Torch Royalty Company P.O. Box 200021 Houston, Texas 77216-0021		For Billing Inquiries: Torch Energy Marketing, Inc. 1221 Lamar, Suite 1600 Houston, Texas 77010-3039 Attn: TEMI

For All Other Matters: Torch Royalty Company 1221 Lamar, Suite 1600 Houston, Texas 77010-3039 Attn: Gas Contract Admin.		For All Other Matters: Torch Energy Marketing, Inc. 1221 Lamar, Suite 1600 Houston, Texas 77010-3039 Attn: Director, Gas Marketing

TEAI:

For All Matters: Torch Energy Advisors Incorporated 1221 Lamar, Suite 1600 Houston, Texas 77008 Attn: General Counsel

XIV. MISCELLANEOUS

14.01 Relationship: It is not the purpose of the parties hereto to create a partnership, joint venture or association, or the relationship of agency or employer-employee and neither this Contract nor any of the operations hereunder shall be construed or considered as creating any such relationship.

14.02 Choice of Law: THIS CONTRACT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF TEXAS (EXCLUDING APPLICABLE CHOICE OF LAW RULES) AND VENUE SHALL BE IN THE STATE OF TEXAS.

14.03 Attorney Fees: If it becomes necessary for either party to either initiate legal action to enforce or obtain compliance with any provision of this Contract or to defend any legal action initiated by a party, the prevailing party in such action shall be entitled to recovery of all of its costs and expenses incurred in

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such legal proceeding, including reasonable attorney fees and expenses, court costs, and expert witness, and consulting fees and expenses. The provisions of this Section 14.03 do not apply to the determination of a Replacement Hub Price pursuant to Sections 4.07 through 4.12 above.

14.04 Changes: Any change, modification, amendment, or alteration of this Contract shall be in writing and signed by the parties hereto and no course of dealing between the parties prior or subsequent to the date of this Contract shall be construed to change, modify, amend, alter or waive the terms hereof. Seller and Buyer shall not make any amendment that would materially reduce the revenues received by Seller which, in turn, would adversely impact the revenues paid by Seller to the Royalty Trust unless the Trustee approves such amendment.

14.05 Waivers: No waiver by a party of its rights or of any default by the other party under this Contract shall operate or be construed as a continuing waiver of such rights or a waiver of any future default, whether of a like or different character.

14.06 Headings: The headings or captions in this Contract are for the convenience of the parties in identification of the provisions hereof and shall not be considered when interpreting or construing the provisions of this Contract, or determining the rights, obligations or liabilities of any party hereto.

14.07 Recitals: The recitals contained herein form a part of this Contract and should be considered when determining the rights, obligations or liabilities of any party hereto.

14.08 Context of Words: In this Contract, unless there is something in the subject matter or context inconsistent herewith (i) words importing the singular shall include the plural and vice versa; (ii) words importing gender shall include the masculine, feminine and neuter genders, and (iii) references to the Contract shall include all exhibits attached hereto.

14.09 Severability: In the event that any of the non-material provisions of this Contract are determined to be invalid, illegal or unenforceable in any respect, the validity, legality or enforceability of the remaining Provisions contained herein shall not in any way be affected or impaired thereby.

14.10 Limit of Liability: NEITHER PARTY SHALL BE LIABLE FOR ANY INCIDENTAL OR CONSEQUENTIAL, SPECIAL, EXEMPLARY, PUNITIVE OR SIMILAR DAMAGES INCLUDING, WITHOUT LIMITATION, DAMAGES TO THE WELLS, THE RESERVOIR, THE RESERVES OR PRODUCTION FROM THE WELLS.

14.11 Exhibits: The exhibits referenced in this Contract are incorporated and made a part of this Contract as if fully set forth herein.

14.12 Dispute Resolution: The parties agree in the event of a dispute (other than the determination of a Replacement Hub Price as provided in Sections 4.07 through 4.12 above) to negotiation and submission of such dispute to alternative dispute resolution (“ADR”) before pursuing litigation.

14.13 Entire Contract: Unless otherwise provided herein, this Contract constitutes the entire agreement of the parties. Seller and Buyer covenant and agree that this Contract shall be deemed and considered for all purposes as prepared through the joint efforts of the parties and shall not be interpreted or construed against one party or the other as a result of the preparation, submittal or other event of a party or the negotiation, drafting or execution hereof.

14.14 Intended Beneficiaries: Seller’s Oil and Seller’s Gas have been dedicated to purchase under this Contract, and Buyer and Seller each agree that the terms of this Contract are intended to induce Royalty Trust to accept the Conveyances and issue units of beneficial interests therefor, and that the Royalty Trust is

-12-

intended to rely on and be a beneficiary of each of the terms and provisions of this Contract. The Royalty Trust and Trustee shall be third party beneficiaries of this Contract, entitled to enforce this agreement against Buyer as if a party hereto.

IN WITNESS WHEREOF, the parties have executed the foregoing as of the day and year first above set forth.


WITNESSES	BUYER:

/s/ illegible	TORCH ENERGY MARKETING, INC.

/s/ illegible	By:	/s/ Michael D. Watford
	Name:	Michael D. Watford
	Title:	President

WITNESSES	SELLER:

/s/ illegible	TORCH ROYALTY COMPANY

/s/ illegible	By:	/s/ Roland E. Sledge
	Name:	Roland E. Sledge
	Title:	Vice President

WITNESSES	VELASCO GAS COMPANY LTD.

/s/ illegible	By:	/s/ Roland E. Sledge
	Name:	Roland E. Sledge
/s/ illegible	Title:	Vice President of Torch Energy Company, its general partner

-13-

Letter Agreement dated June 13, 2005

Exhibit 10.6

June 13, 2005

Robinson’s Bend Marketing II, LLC

111 Market Place, Suite 500

Baltimore, MD 21202

Re:

Marketing Authorization for Gas and Natural Liquid Sales from Robinson’s Bend Marketing II, LLC

Ladies and Gentlemen:

THIS AGREEMENT (the “Agreement”) IS MADE AND ENTERED INTO by and between Torch Energy TM, Inc., herein referred to as “TETM” and Robinson’s Bend Marketing II, LLC, herein referred to as “RB Marketing.”

WHEREAS, RB Marketing desires to designate TETM as its manager for the provision of natural gas marketing services as set forth herein and TETM desires to serve in such capacity;

NOW, THEREFORE, in consideration of the promises and mutual covenants herein contained, TETM and RB Marketing do hereby agree as follows:

1. Term. The initial term of this Agreement shall commence on June 13, 2005 (the “Effective Date”) and shall continue for a term expiring on June 30, 2007 (the “Term”). At any time during the Term hereof, RB Marketing shall have the option, but not the obligation, to terminate this Agreement for convenience. RB Marketing shall exercise its termination for convenience option by delivering written notice of termination identifying the termination date (which shall be at least thirty (30) days after the delivery of such notice). If such termination occurs prior to June 30, 2007, TETM shall be paid a termination fee equal to $720,000 less an amount equal to $30,000 multiplied by the number of months this Agreement will have been effective prior to the termination date, pro rated for any partial months.

2. Services. During the Term of this Agreement, TETM shall be RB Marketing’s manager and provide to RB Marketing the services described in Schedule A attached hereto (the “Services”) with respect to the Oil and Gas Properties (as such term is defined in that certain Asset Purchase and Sale Agreement effective as of May 1, 2005 by and among Everlast Energy LLC, RB Marketing Company LLC, Robinson’s Bend Operating Company, LLC and CBM Equity IV, LLC (P&S Agreement”)), such Oil and Gas Properties being additionally identified on Schedule C attached hereto. The rights, duties and obligations of TETM as RB Marketing’s

Robinson’s Bend Marketing II, LLC

June 13, 2005

Page 2

manager shall be controlled by this Agreement, the schedules hereto, and any applicable amendments hereto or thereto.

3. Charges for the Services. TETM shall be compensated for the Services as set forth in Schedule B attached hereto.

4. Indemnification. RB Marketing hereby covenants and agrees to and does hereby indemnify, defend, protect, save and hold harmless the Indemnitee (as such term is hereinafter defined) from and against any and all Claims (as such term is hereinafter defined) asserted against the Indemnitee arising out of this Agreement or on account of the Services, including without limitation, any negligent acts or negligent omissions of the Indemnitee, or other alleged or adjudicated wrongful act or omission, default or breach of whatever kind or nature, whatsoever arising; provided, however, that RB Marketing shall have no obligation under this Section 4 if such Claims arise due to the gross negligence or willful misconduct of TETM or its representatives in the performance of the Services. As used herein, the term “Indemnitee” shall mean TETM, any affiliate of TETM, and any officer, director, employee, agent, attorney, joint venturer, partner (limited or general), servant, representative, trustee, successor, assign or shareholder of TETM. As used herein, the term “Claims” shall mean allegations, actions, claims, liabilities, demands, debts, actions, causes of action, suits, dues, reckonings, controversies, promises, rights of indemnity and contribution, and all attorneys’ fees and costs of court related to or incurred in connection therewith, of any kind or character whatsoever, known or unknown, suspected or unsuspected, in contract or in tort or otherwise, at law or in equity, whether heretofore or hereafter existing or accruing. The provisions of this Section 4 shall survive any termination of this Agreement. NO PARTY SHALL BE LIABLE FOR CONSEQUENTIAL DAMAGES (INCLUDING WITHOUT LIMITATION, DAMAGES FOR LOST REVENUE AND/OR PROFITS) OR ANY EXEMPLARY OR PUNITIVE DAMAGES, REGARDLESS OF THE FORM OF ACTIONS, WHETHER IN CONTRACT, TORT OR OTHERWISE, AND EVEN IF SUCH PARTY HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES.

5. Relationships. TETM, in furnishing services to RB Marketing hereunder, is providing such services only as an independent contractor. This Agreement does not create, and shall not be construed to create, any employer-employee, joint venture or partnership relationship between the parties hereto or their respective affiliates, and no party hereto, or their respective affiliates, shall at any time be deemed to be an employee, servant, agent or contractor of the other party or its affiliates for any purpose whatsoever.

6. Governing Law. THIS AGREEMENT, AND ALL QUESTIONS RELATING TO ITS VALIDITY, INTERPRETATION, PERFORMANCE AND ENFORCEMENT (INCLUDING, WITHOUT LIMITATION, PROVISIONS CONCERNING LIMITATIONS OF

Robinson’s Bend Marketing II, LLC

June 13, 2005

Page 3

ACTION), SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF TEXAS NOTWITHSTANDING ANY CONFLICT-OF-LAWS DOCTRINES OF SUCH STATE OR OTHER JURISDICTION TO THE CONTRARY. ANY PROCEEDINGS ARISING OUT OF AND/OR RELATING TO THIS AGREEMENT SHALL BE RESOLVED BY A JUDGE TRIAL WITHOUT A JURY AND THE RIGHT TO A JURY TRIAL IS WAIVED TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW.

7. Force Majeure.

(a) Subject to clause (b) below, neither party shall be liable for any failure or delay in the performance of its obligations, other than payment obligations, under this Agreement to the extent such failure or delay is caused, directly or indirectly, without fault by such party, by any cause beyond the reasonable control of such party (“Force Majeure Event”). Force Majeure Events shall include, but not be limited to, disruptions caused by third party failures of public utilities, building facilities, communications facilities or public safety functions.

(b) Upon the occurrence of a Force Majeure Event, the non-performing party shall be excused from any further performance or observance of the affected obligation(s) for as long as such circumstances prevail and so long as such party continues to attempt to recommence performance or observance whenever and to whatever extent possible without delay. Any party so delayed in its performance will immediately notify the other by telephone or by the most timely means otherwise available (to be confirmed in writing within two (2) business days of the inception of such delay) and describe in reasonable detail the circumstance causing such delay.

8. Entire Agreement. This Agreement, together with the attached schedules hereto and any other writings referred to herein or delivered pursuant hereto, constitute the entire agreement between the parties hereto with respect to the subject matter hereof and supersede all prior agreements and understandings, both written and oral, between the parties with respect to the subject matter hereof.

9. Amendments and Waivers. Any changes, modifications or amendments of this Agreement shall be in writing and signed by each of the parties hereto. No waiver by a party of its rights or of any default by the other party under this Agreement shall operate or be construed as a continuing waiver of such rights or a waiver of any future default, whether of a like or different character.

10. Severability. If any provision of this Agreement is held to be unenforceable, this Agreement shall be considered divisible and such provision shall be deemed inoperative to the extent it is deemed unenforceable, and in all other respects, this Agreement shall remain in full force and effect.

Robinson’s Bend Marketing II, LLC

June 13, 2005

Page 4

11. Assignment. This Agreement shall be binding upon and inure to the benefit of the respective successors and assigns of the parties hereto, provided that this Agreement shall not be transferred or assigned, by operation of law or otherwise, by either party without the other party’s prior written consent, which consent shall not be unreasonably withheld.

12. Notices. Any notice, request, demand or other communication required or permitted to be made under this Agreement shall be in writing and shall be delivered personally or shall be sent by facsimile transmission. Any such notice, request, demand or other communication shall be deemed given when so delivered personally or sent by facsimile transmission (and confirmed to have been received) to the address set forth below (or to any other address subsequently furnished in writing by either party, in accordance with this Section 12). Such notice, request, demand or other communication will be deemed to have been given as of the date so delivered personally or sent by facsimile.


To:	RB Marketing:	TETM:

Correspondence	Robinson’s Bend Marketing II, LLC 111 Market Place, Suite 500 Baltimore, Maryland 21202 Attention: Legal Facsimile: (410) 468-3499	Torch Energy TM, Inc. 1221 Lamar, Suite 1175 Houston, Texas 77010 Attention: Marketing Facsimile: (713) 759-0805

Invoices	Robinson’s Bend Marketing II, LLC 111 Market Place, Suite 500 Baltimore, Maryland 21202 Attention: Operations	Torch Energy TM, Inc. 1221 Lamar, Suite 1175 Houston, Texas 77010 Attention: Gas Marketing Accounting

Payments	Robinson’s Bend Marketing II, LLC Bank: M&T Bank, Baltimore, Maryland ABA: 0220-0004-6 ACCT: 191-9007-8	Torch Energy TM, Inc. Amegy Bank of Texas Houston, Texas ABA: 113011258 ACCT: 127833

13. Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed an original, and all of which shall constitute collectively, one instrument.

Robinson’s Bend Marketing II, LLC

June 13, 2005

Page 5


Very Truly Yours,

TORCH ENERGY TM, INC.

By:		/s/ John Lendrum III
Name:		John Lendrum III
Title:		President

[SIGNATURE PAGE TO MARKETING AUTHORIZATION LETTER]

Robinson’s Bend Marketing II, LLC

June 13, 2005

Page 6


Accepted and agreed to this 13^th day of June, 2005.

ROBINSON’S BEND MARKETING II, LLC

By:		/s/ Stuart R. Rubenstein
		Stuart R. Rubenstein
		Chief Operating Officer

[SIGNATURE PAGE TO MARKETING AUTHORIZATION LETTER]

SCHEDULE A

I.	NATURAL GAS MARKETING SERVICES

TETM shall provide natural gas marketing services for RB Marketing to purchasers approved by RB Marketing as described below:

Monitor and analyze monthly markets

Maintain up-to-date market information from daily periodicals, various financial services and downstream natural gas users/buyers.

Evaluate monthly spot/term markets, including basis differentials, in order to maximize wellhead value.

Participate in regulatory review of FERC proposed rules and opinions which may effect revenue and operations.

Develop natural gas marketing strategy with the guidance of RB Marketing.

Communicate with field operations personnel to maintain smooth flow of production to marketing (sales).

Market future production

Survey the market and present market data to RB Marketing for RB Marketing’s determination of parties to whom gas will be sold. No sales shall be made without RB Marketing’s prior approval. TETM and RB Marketing will develop an approved list of parties with RB Marketing’s credit requirements for each.

Review drilling data provided by RB Marketing to identify upcoming production with respect to the Oil and Gas Properties.

Participate in routine drilling and operations meetings as requested by RB Marketing.

Study price reports, forecasts and statistics.

Research pipeline logistics for marketing of natural gas production

Management of pipeline and producer imbalances when RB Marketing advises and provides imbalance information

Natural gas control

Daily contact through computer bulletin boards of pipelines to confirm nominations and flow of natural gas.

Resolve metering difference between pipelines and field operations.

Provide allocations of natural gas sales.

II.

CONTRACT ADMINISTRATION

TETM shall provide administrative services for RB Marketing as described below:

Monitor contracts for compliance of terms

Maintain natural gas marketing contract files and database

Coordinate contracts, deal sheets, and memos for communication of marketing information to RB Marketing

Includes calculations of royalty adjustments for special circumstances.

Assistance to RB Marketing to ensure collection of monies on natural gas sales and resolution of pricing discrepancies.

Obtain executed confirmations from purchasers and approve by initialing, then forward to RB Marketing for execution for all natural gas sales

Review and approve by initialing original contracts, then forward to RB Marketing for execution

Provide documentation of changes in purchasers and/or transporters of natural gas production

III.

REPORTING/PRICING SERVICES

TETM shall provide reporting and pricing services for RB Marketing as described below:

Provide pricing reports on the Oil and Gas Properties (as such term is defined in the P&S Agreement) as requested by RB Marketing

Provide pricing tables, spreadsheet applications, basis differential comparison and charts upon reasonable request on current production properties

Provide pricing for reserve reports (on request)

Provide monthly Nymex prices, including natural gas spot month close and average for final three days of contracts

IV.

MANAGEMENT OF SUPPORT SERVICES

TETM shall attend management, bankers and other special meetings at RB Marketing’s reasonable request.

SCHEDULE B

CHARGES

NATURAL GAS MARKETING SERVICES AGREEMENT

A. Base Charge. RB Marketing shall pay to TETM a Base Charge of $30,000.00 per calendar month, commencing with payment for the month of July 2005 and continuing each calendar month thereafter for the Term of this Agreement.

B. Variable Charge. In addition to the Base Charge, RB Marketing shall pay to TETM a Variable Charge each calendar month, commencing with payment for the month of July 2005 and continuing each calendar month thereafter for the Term of this Agreement. The Variable Charge shall be calculated according to the following formula:

50% x A x (B - C), where

A = Volume of Applicable Gas (MMBTu),

B = Weighted Average Price Received ($/MMBTu),

C = Monthly Index Price ($/MMBTu)

For the purpose of the calculation of the Variable Charge, the Monthly Index Price for the applicable month shall be the Index Price per MMBTu for “Prices of Spot Gas Delivered to Pipelines (per MMBTu dry): Southern Natural Gas Co.: Louisiana: Index” as published in the first issue during such month of Inside FERC’s Gas Market Report.

For the purpose of the calculation of the Variable Charge, the Weighted Average Price Received for the applicable month shall be equal to the revenue received, net of transportation costs, from approved third-party purchasers for the Applicable Gas for such month divided by the total volume of Applicable Gas sold in such month, rounded to the nearest hundredth of a cent. The term “Applicable Gas” as used herein shall mean only gas sold from RB Marketing’s working interests in the Oil and Gas Properties.

If in any month, the Monthly Index Price is greater than or equal to the Weighted Average Price Received, the Variable Charge for such month shall be $0.

C. Expenses. All entertainment expenses incurred by TETM personnel in providing the normal and routine business of marketing gas production shall be borne by TETM. All other out-of-pocket expenses incurred at RB Marketing’s request will be reimbursed by RB Marketing.

D. Payment. Following the end of each calendar month, TETM shall deliver to RB Marketing a monthly invoice for the preceding month, to the address specified in Section 12 of the Agreement, for the Base Charge and the Variable Charge as shown in reasonable detail. RB Marketing shall remit the amount due by wire transfer in immediately available funds within thirty (30) business days after the date the invoice is delivered to RB Marketing, provided that if the payment date is not a business day, payment is due on the next business day following such date. In the event any payments are due to RB Marketing hereby, payment to RB Marketing shall be made in accordance with this section.

SCHEDULE C

DESCRIPTION OF OIL AND GAS PROPERTIES

PART 1

ALL RIGHT, TITLE, ESTATE, CLAIM AND INTEREST OF ROBINSON’S BEND PRODUCTION II, LLC (“RBPII”) IN AND TO THE FOLLOWING “OIL AND GAS PROPERTIES” SITUATED IN THE ROBINSON’S BEND COAL DEGASIFICATION FIELD, TUSCALOOSA COUNTY, ALABAMA, INCLUDING, BUT NOT LIMITED TO, ALL RIGHT, TITLE, ESTATE, CLAIM AND INTEREST OF RBPII IN AND TO ALL OF THE “LEASES” AND THE “LANDS” DESCRIBED IN OR BY THE FOLLOWING INSTRUMENTS:

Assignment, Conveyance and Bill of Sale dated effective as of 11:59 p.m. on December 31, 2002, executed by Velasco Gas Company, L.P., as grantor, in favor of Everlast Energy LLC, as grantee, recorded on January 7, 2003, in the Office of the Probate Judge of Tuscaloosa County, Alabama in Deed Book 2003, Page 269.

Assignment, Conveyance and Bill of Sale executed on January 6, 2003, effective as of 7:00 a.m. on October 15, 2002, executed by Torch E & P Company, Torch Energy Services, Inc., TEAI Oil & Gas Company, and Torch Energy Marketing, Inc., collectively as grantor, in favor of Everlast Energy LLC, as grantee, recorded on January 7, 2003, in the Office of the Probate Judge of Tuscaloosa County, Alabama in Deed Book 2003, Page 245, and re-recorded in Deed Book 2005, Page 12305.

SCHEDULE C

DESCRIPTION OF OIL AND GAS PROPERTIES

PART 2


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Acker, Jr., James B.	Everlast Energy LLC	2004/5208	November 14, 2003	Section 12, T21S, R11W

Acker, Morris R. and wife, Beatrice R. Acker	Everlast Energy LLC	2003/22877	September 23, 2003	Section 33, T20S, R11W

Acker, Opal P., Individually and as Executrix of the Estate of Lester E. Acker	Everlast Energy LLC	2004/5342	November 12, 2003	Section 12, T21S, R11W

Allen, Darby Jack and wife, Sharon D. Allen	Everlast Energy LLC	2004/5188	October 26, 2003	Section 12, T21S, R11W

Amos, Lavon	EVERLAST ENERGY LLC	2005/1884		Sections 21 & 22, T22S, R11W

Amos, Jr., Robert	EVERLAST ENERGY LLC	2005/1881	November 30, 2004	Sections 21 & 22, T22S, R11W

Amos, Ronald	EVERLAST ENERGY LLC	2005/1878	November 30, 2004	Sections 21 & 22, T22S, R11W

Anders, Ronald and wife Sue	Everlast Energy LLC	2004/5186	September 17, 2003	Section 14, T21S, R11W

Arrowood, James H. and wife, Heidi Renee Arrowood	EVERLAST ENERGY LLC	2004/446	October 22, 2003	Section 13, T22S, R12W

Bailey, Connie V.	Everlast Energy LLC	2004/3542	October 26, 2003	Section 12, T21S, R11W

Bailey, David Clark and wife, Traci Lynne Pate Bailey	Everlast Energy LLC	2004/3512	September 12, 2003	Section 17, T21S, R11W

Baird, Connie Jannine	EVERLAST ENERGY LLC	2005/1805	November 1, 2004	Section 28, T22S, R11W

Baisden, Carroll Lee and wife, Jackie N. Baisden	Everlast Energy LLC	2004/27080	August 10, 2004	Section 1, T21S, R12W

Ball, Margie P.	Everlast Energy LLC	2004/5230	December 9, 2003	Sections 4 & 9, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Bane Family Partnership, LTD	Everlast Energy LLC	2003/24555	September 17, 2003	Sections 19 & 31, T20S, R11W; Sections 24, 25 & 36, T20S, R12W; Section 6, T12S, R11W; Section 23, T22S, R11W

Banks, Hannah	Everlast Energy LLC	2004/23287	August 11, 2004	Section 20 & 22, T22S, R11W

Banks, Rodger Dale and wife, Carolyn Banks	EVERLAST ENERGY LLC	2004/5232	November 26, 2003	Section 3, T21S, R11W

Barksdale, Arlis and wife, Jennifer	Everlast Energy LLC	2004/28137	August 16, 2004	Section 5, T21S, R11W

Barton, Eddie	Everlast Energy LLC	2003/21495	July 26, 2003	Section 32, T20S, R11W

Barton, Eddie Joe	Everlast Energy LLC	2003/24560	September 16, 2003	Section 17, T21S, R11W

Barton, Harold	Everlast Energy LLC	2003/21500	July 26, 2003	Section 32, T20S, R11W

Beck Bobby R. and wife, Earline B. Beck	EVERLAST ENERGY LLC	2005/1746	October 5, 2004	Section 31, T22S, R11W

Beck, J.D. and wife, Sarah H. Beck	EVERLAST ENERGY LLC	2004/28139	October 5, 2004	Section 31, T22S, R11W

Beck, Rebecca Celeste Scales	Everlast Energy LLC	2003/21503	August 8, 2003	Sections 5 & 6, T21S, R11W

Bell, Jr., Charles Russell	Everlast Energy LLC	2004/10381	December 30, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Beverly-Baker, LLC	EVERLAST ENERGY LLC	2004/5206	November 25, 2003	Section 22, T22S, R12W

Biggs, William Joseph and wife, Linda Sue Biggs	Everlast Energy LLC	2004/12221	November 24, 2003	Sections 26 & 34, T20S, R11W

Bigham, Troy C. and wife, Sue H. Bigham	Everlast Energy LLC	2004/5203	October 6, 2003	Section 11, T21S, R11W

Blackburn, Jr., Cleo and wife, Roamelia Willis Blackburn	EVERLAST ENERGY LLC	2005/6376	September 23, 2004	Section 13, T22S, R12W

Bobo, Hazel L.	Everlast Energy LLC	2004/428	September 3, 2003	Section 10, T21S, R11W

Bonner, Riley Gary and wife, Nancy Utley Bonner	Everlast Energy LLC	2004/27083	August 12, 2004	Section 1, T21S, R12W

Bonner, Ronald W. and wife, Minnie L. Bonner	Everlast Energy LLC	2004/438	October 26, 2003	Section 12, T21S, R11W

Booker, Joseph Washington	EVERLAST ENERGY LLC	2005/12370	January 10, 2005	Section 30, T22S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Booth, Arliss	Everlast Energy LLC	2004/5184	October 26, 2003	Section 12, T21S, R11W

Booth, Aubrey Raiford	Everlast Energy LLC	2004/23289	July 7, 2004	Section 34, T21S,R12W

Booth Aubrey Raiford	Everlast Energy LLC	2005/1876	July 21, 2004	Section 26, T21S, R12W

Booth, Derrill & Irene H. Booth	Everlast Energy LLC	2004/5305	November 1, 2003	Section 4, T21S, R11W

Booth, Donald	Everlast Energy LLC	2003/24563	August 16, 2003	Section 34, T21S, R12W

Booth, Faye Ellen, Individually & As A/F for Leon C. Booth	Everlast Energy LLC	2004/5200	November 11, 2003	Section 1, T21S, R11W

Booth, Harold Eugene	Everlast Energy LLC	2003/21505	August 13, 2003	Sections 23 & 26, T21S, R12W

Booth, Irene H.	Everlast Energy LLC	2004/5307	November 4, 2003	Section 4, T21S, R11W

Booth, James L. Jr.	EVERLAST ENERGY LLC	2004/27085	September 1, 2004	Section 23, T22S,R12W

Booth, Jerone Sr., and wife, Wilma L. Booth	Everlast Energy LLC		June 24, 2004	Section 34, T21S, R12W

Booth, Ronald and wife Patty L. Booth	Everlast Energy LLC	2005/1802	October 14, 2004	Section 36, T20S,R12W

Booth, Jr., Ronald	Everlast Energy LLC	2004/12228	October 21, 2003	Section 4, T21S, R11W

Booth, Mary I.	Everlast Energy LLC	2004/12226	October 23, 2003	Section 12, T21S, R11W

Booth, Randy Ray	Everlast Energy LLC	2005/1873	July 22, 2004	Section 26, T21S, R12W

Booth, Randy Ray	Everlast Energy LLC	2004/28142	July 22, 2004	Section 34, T21S, R12W

Booth, Jr. Robert	Everlast Energy LLC	2004/19479	June 7, 2004	Section 34, T21S, R12W

Booth, Ronald	Everlast Energy LLC	2004/5621	November 4, 2003	Section 4, T21S, R11W

Booth, Roy Eugene	Everlast Energy LLC	2004/12230	October 28, 2003	Section 12, T21S, R11W

Boothe, Joseph D. and wife, Janet S. Boothe	Everlast Energy LLC	2004/12232	September 14, 2003	Section 17, T21S, R11W

Boothe, Kenneth Wayne	Everlast Energy LLC	2003/21508	August 13, 2003	Section 20, T21S, R11W

Boothe, Waldo E. and Betty Crawford	Everlast Energy LLC	2004/5197	November 22, 2003	Section 3, T21S, R11W

Boothe, William Howard and wife, Kathleen Boothe	Everlast Energy LLC	2004/5182	October 1, 2003	Section 35, T20S, R12W

Boothe, William Howard Ind. and as Independent Executor under the Will of Irene O’Hanion Boothe	Everlast Energy LLC	2004/5194	October 1, 2003	Section 35, T20S, R12W & Section 2, T21S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Boothe, Woodrow and wife, Rosa White Boothe	Everlast Energy LLC	2004/5312	February 17, 2004	Sections 19 & 20, T22S, R11W

Brand, Anthony P. and wife, Rhonda	Everlast Energy LLC	2004/3514	August 10, 2003	Section 5, T21S, R11W

Brasher, David T. and wife, Mary Brasher	Everlast Energy LLC	2004/5178	November 25, 2003	Section 12, T21S, R11W

Bresnahan, Tonnie O. and wife, Faustine P.	Everlast Energy LLC	2004/12235	December 8, 2003	Section 4, T21S, R11W

Bresnahan, Tonnie O. and wife, Faustine P.	Everlast Energy LLC	2004/431	September 24, 2003	Section 4, T21S, R11W

Brewer, Phillip S. and wife, Haley M. Brewer	Everlast Energy LLC	2004/12238	December 12, 2003	Section 12, T21S, R11W

Broughton, Felicia K.	Everlast Energy LLC	2004/5303	November 7, 2003	Section 4, T21S, R11W

Broughton, Glen A. and wife, Betty Ann Broughton	Everlast Energy LLC	2003/21512	July 29, 2003	Sections 4 & 5, T21S, R11W

Broughton, Glen A. and wife, Betty Ann Broughton	Everlast Energy LLC	2003/24436	October 7, 2003	Section 4, T21S, R11W

Brown, Arbelene	EVERLAST ENERGY LLC	2005/1871	August 25, 2004	Section 20, T22S, R11W

Brown Ardelia	EVERLAST ENERGY LLC	2005/1980	January 7, 2005	Section 30, T22S, R11W

Brown, David S and Danny Junkin	Everlast Energy LLC	2004/10421	November 20, 2003	Section 2, T21S, R12W

Brown, Joseph C.	Everlast Energy LLC	2004/10386	November 24, 2003	Section 2, T21S, R12W

Brown, Roy Archie and wife, Maggie V. Brown	Everlast Energy LLC	2004/5362	November 6, 2003	Section 3, T21S, R11W

Burge, Walton D. and wife, Candice W. Burge	Everlast Energy LLC	2004/5180	November 16, 2003	Section 12, T21S, R11W

Burke, Jr., William C. and wife, Lola E. Burke and William C. Burke, III	Everlast Energy LLC	2004/3544	October 28, 2003	Section 9, T21S, R11W

Burkhalter, William T. and wife, Jeanetta C. Burkhalter	Everlast Energy LLC	2003/24566	September 3, 2003	Section 10, T21S, R11W

Burroughs A. R.	Everlast Energy LLC	2004/27087	July 28, 2004	Section 26, T21S, R12W

Burroughs, Archie L.	Everlast Energy LLC	2005/1869	July 28, 2004	Section 26, T21S, R11W

Burroughs, Billy Ray as Executor and Trustee Under the Will of Calvin Doyle Burroughs	Everlast Energy LLC	2003/22904	August 10, 2003	Sections 11 & 12, T21S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Burroughs, Darlene Booth and husband, Flavis L. Burroughs	Everlast Energy LLC	2004/5190	September 12, 2003	Sections 17 & 20, T21S, R11W

Burroughs, David L.	Everlast Energy LLC	2005/1866	July 29, 2004	Section 26, T21S, R12W

Burroughs, Falvis L.	Everlast Energy LLC	2004/27089	July 29, 2004	Section 26, T21S, R12W

Burroughs, Helen Partrich	EVERLAST ENERGY LLC	2004/3547	October 20, 2003	Section 14, T22S, R12W

Burrough, Irma Addilene	Everlast Energy LLC	2005/1820	July 27, 2004	Section 26, T21S, R12W

Burroughs, James Barry and wife, Amanda S. Burroughs	EVERLAST ENERGY LLC		November 11, 2004	Section 13, T22S, R12W

Burroughs, Jeremy Patrick	EVERLAST ENERGY LLC	2004/5317	December 2, 2003	Section 15, T22S, R12W

Burroughs, Jerry W.	Everlast Energy LLC	2004/27091	September 1, 2004	Section 14, T21S, R12W

Burroughs, Jimmy	Everlast Energy LLC	2004/27093	July 29, 2004	Section 26, T21S, R12W

Burroughs, Joe Thomas and wife, Janet P. Burroughs	EVERLAST ENERGY LLC	2004/3549	October 30, 2003	Section 12, T22S, R12W

Burroughs, Joseph William and wife, Cynthia Burroughs	Everlast Energy LLC	2004/5301	October 1, 2003	Section 1, T21S, R12W

Burroughs, Martha Olene	Everlast Energy LLC	2005/1906	July 29, 2004	Section 26, T21S, R12W

Burroughs Mary Ruth	EVERLAST ENERGY LLC	2004/3551	October 15, 2003	Sections 11, 12, 13 & 14, T22S, R12W

Burroughs, Montgomery and wife, Mavis Burroughs	EVERLAST ENERGY LLC	2005/6392	December 9, 2004	Section 13, T22S, R12W

Burroughs, Murray Joe	Everlast Energy LLC	2005/1863	July 27, 2004	Section 26, T21S, R12W

Burroughs, Richard O., et ux	Everlast Energy LLC	2003/21529	July 3, 2003	Section 25, T21S, R12W

Burroughs, Richard Verdo	EVERLAST ENERGY LLC	2004/5225	December 2, 2003	Section 15, T22S, R12W

Burroughs, Roger	Everlast Energy LLC	2005/1860	July 29, 2004	Section 26, T21S, R12W

Burroughs, Sally	Everlast Energy LLC	2004/5299	November 1, 2003	Section 2, T21S, R12W

Burroughs, Terry and wife, Cindy Burroughs	EVERLAST ENERGY LLC	2005/6374	November 11, 2004	Section 13, T22S, R12W

Burroughs, William Leslie and wife Jean Peeks Burroughs	EVERLAST ENERGY LLC	2004/3516	October 17, 2003	Section 11, T22S, R12W

Burroughs, William Leslie and wife Jean Peeks Burroughs	EVERLAST ENERGY LLC	2004/3519	October 17, 2003	Sections 14, 22 & 23, T22S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Burroughs, William Verdo and wife, Helen Partrich Burroughs	Everlast Energy LLC	2004/3554	October 17, 2003	Section 11, T22S, R12W

Byrd, Benford O. and Bessie Kay	Everlast Energy LLC	2004/5156	October 1, 2003	Section 1, T21S, R12W

Cade, Norman Christopher and wife, Vanessa Jefferson Cade	EVERLAST ENERGY LLC	2004/5152	November 21, 2003	Section 18, T22S, R11W; Section 13, T22S, R12W

Cain, Shirley M.	Everlast Energy LLC	2003/22908	September 2, 2003	Section 17, T21S, R11W

Calabrese, Joel Patrick and wife, Shirley Ann Calabrese	Everlast Energy LLC	2004/12240	December 11, 2003	Section 4, T21S, R11W

Calabrese, Joel P., Jr.	EVERLAST ENERGY LLC	2005/12374	December 2, 2004	Section 13, T22S, R12W

Cammon, Eula	EVERLAST ENERGY LLC	2004/23292	August 17, 2004	Section 20, T22S, R11W

Camp, Johnny C. and wife, Jo Ann Camp	Everlast Energy LLC	2004/5293	November 17, 2003	Section 19, T21S, R11W

Campbell, Stephen M. and wife Lara V. Campbell	Everlast Energy LLC	2004/5150	November 4, 2003	Section 12, T21S, R11W

Campbell, Terry W. and wife, Carolyn M. Campbell	Everlast Energy LLC	2004/440	November 1, 2003	Section 12, T21S, R11W

Capley, Denny	Everlast Energy LLC	2003/24572	September 17, 2003	Section 30, T21S, R11W

Carpenter, E. M. and wife, Mary M. Carpenter	Everlast Energy LLC	2003/24438	October 5, 2003	Section 20, T21S, R11W

Carter, Kenneth M. and wife, Pamela M. Carter	EVERLAST ENERGY LLC	2005/1799	October 28, 2003	Section 13, T22S, R12W

Chamblee, Jerry L. and wife, Myniley E. Chamblee	Everlast Energy LLC	2003/24440	October 5, 2003	Section 20, T21S, R11W

Channell, Charles Edward and wife, Wanda Gail Channell	Everlast Energy LLC	2004/23294	July 20, 2004	Section 34, T21S, R12W

Channell, James Ray and wife, Shirley Jean Channell	Everlast Energy LLC	2004/5147	November 8, 2003	Section 1, T21S, R12W

Channell, Jr., James Leon and wife, Cecelia D. Channell	Everlast Energy LLC	2003/24442	September 17, 2003	Section 30, T21S, R11W

Channell, L.J.	Everlast Energy LLC	2003/24575	September 17, 2003	Section 1, T21S, R12W

Channell, Mary Lee	Everlast Energy LLC	2004/23298	August 2, 2004	Section 26, T21S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Chism, Jr. John P. and wife, Josefa D. Chism	Everlast Energy LLC	2004/450	November 25, 2003	Section 33, T20S, R11W

Christian, Wynona B.	Everlast Energy LLC	2003/22917	August 28, 2003	Section 4, T21S, R11W

Clark, Mamie R. Cornelius	Everlast Energy LLC	2003/24577	September 17, 2003	Section 11, T21S, R11W

Clements, Glenn P. and wife, Crystle C. Clements	Everlast Energy LLC	2004/434	September 28, 2003	Section 20, T21S, R11W

Cleveland, Mary	EVERLAST ENERGY LLC	2004/23301	August 24, 2004	Sections 20 & 22, T22S, R11W

Coker Baptist Church	Everlast Energy LLC	2005/6379	December 12, 2004	Sections 3, 4 & 9, T21S, R11W

Coker Water Authority, Inc.	Everlast Energy LLC	2004/5623	November 3, 2003	Section 4, T21S, R11W

Colby, James I. N.	EVERLAST ENERGY LLC	2005/1751	October 10, 2004	Sections 22 & 23, T22S, R11W

Coleman, Willie E. also known as W. E. Coleman	Everlast Energy LLC	2003/22924	September 1, 2003	Section 22 & 23, T21S, R12W

Collins, Ronnie Scott and wife, Terrie W. Collins	Everlast Energy LLC	2004/5626	November 16, 2003	Section 12, T21S, R11W

Cook, Brian	EVERLAST ENERGY LLC	2005/1903	September 21, 2004	Section 20, T22S, R11W

Cook, Clevelle	EVERLAST ENERGY LLC	2004/27107	September 21, 2004	Section 20, T22S, R11W

Cook, Gene	Everlast Energy LLC	2005/1793	July 16, 2004	Section 1, T21S, R12W

Cook, Jr., James T. and wife, Betty Jean Pate Cook	Everlast Energy LLC	2004/5144	September 3, 2003	Section 10, T21S, R11W

Cook, Michael	EVERLAST ENERGY LLC	2005/1901	September 21, 2004	Section 20, T21S, R11W

Cooper, Alonzo	EVERLAST ENERGY LLC	2004/27105	August 17, 2004	Section 20, T22S, R11W

Cooper, Michael	EVERLAST ENERGY LLC	2004/27100	September 9, 2004	Section 20, T22S, R11W

Copeland, Betty A.	Everlast Energy LLC	2004/442	October 26, 2003	Section 12, T21S, R11W

Cork, Sr., Franklin W. and wife Wilma W. Cork	Everlast Energy LLC	2003/24579	August 16, 2003	Section 17, T21S, R11W

Cox, Dorothy	EVERLAST ENERGY LLC	2004/12243	December 31, 2003	Section 21, T21S, R11W

Cox, Jeannine and husband, John B. Cox	Everlast Energy LLC	2004/3557	August 11, 2003	Section 4 & 9, T21S, R11W

Cox, Jeannine and husband, John B. Cox	Everlast Energy LLC	2003/21524	October 8, 2003	Section 4, T21S, R11W

Crawford, Paul S. and wife, Christina L. Crawford	EVERLAST ENERGY LLC	2004/5142	October 30, 2003	Section 12, T22S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Crocker, James Russell	Everlast Energy LLC	2004/3559	October 28, 2003	Section 12, T21S, R11W

Crocker, Linda Mae and husband, Russell Crocker	Everlast Energy LLC	2004/5140	October 28, 2003	Section 12, T21S, R11W

Crotts, Jerry W. and wife, Carolyn Crotts	Everlast Energy LLC	2004/3522	October 22, 2003	Section 4, T21S, R11W

Dalton, John Ralph and wife, Kristina L. Dalton	Everlast Energy LLC	2005/1858	October 29, 2004	Section 11, T21S, R11W

Daniel, Jr., Thomas W., Trustee	Everlast Energy LLC	2003/24582	September 5, 2003	Section 12, T21S, R12W

Davant James E.	Everlast Energy LLC	2004/5132	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Davant William Louis	Everlast Energy LLC	2004/5136	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W, Section 3, T22S, R12W

Davant, Jr., Robert M.	Everlast Energy LLC	2003/24589	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Davis, Brenda Raye	Everlast Energy LLC	2003/24444	October 26, 2003	Section 12, T21S, R11W

Davis, Charles and wife, Cornelia L. Davis	EVERLAST ENERGY LLC	2005/6382	August 30, 2004	Section 13, T22S, R12W

Davis, Derek H.	Everlast Energy LLC	2004/5221	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Davis, Stephanie Foster	EVERLAST ENERGY LLC	2003/24597	October 9, 2003	Section 24, T22S, R12W

Dawson, Leighton Estate	Everlast Energy LLC	2003/21535	May 28, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Dawson, R. Matt	Everlast Energy LLC	2003/21542	May 28, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Dawson, R. Matt	Everlast Energy LLC	2004/5721	December 11, 2003	Section 25, T20S, R12W

Dean, Jimmy and wife, Brenda Dean	Everlast Energy LLC	2004/10388	December 1, 2003	Section 35, T20S, R12W

Dearman, William R. and wife, Marie M. Dearman	Everlast Energy LLC	2003/21549	August 23, 2003	Section 34, 520S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Defreese, Nimon Paul and wife, Leigh Defreese	Everlast Energy LLC	2004/10393	October 28, 2003	Section 12, T21S, R11W

Denby, Frank	EVERLAST ENERGY LLC	2005/1899	September 23, 2004	Section 20, T22S, R11W

Denby, Thomas	EVERLAST ENERGY LLC	2004/27098	September 23, 2004	Section 20, T22S, R11W

Dickerson, Gary and wife, Georgia	Everlast Energy LLC	2004/5130	October 9, 2003	Section 5, T21S, R11W

Dickson, Arkeisha	EVERLAST ENERGY LLC	2005/12379	January 10, 2005	Section 24, T22S, R12W

Dickson, Ida R., etal	EVERLAST ENERGY LLC	2005/1982	January 10, 2005	Section 24, T22S, R12W

Dockery, Billy R. and wife, Annie Dockery	Everlast Energy LLC	2004/5339	October 28, 2003	Section 12, T21S, R11W

Dodson Jack R.	Everlast Energy LLC	2004/10395	December 11, 2003	Section 25, T20S, R12W

Dodson, Jack R. Jr.	Everlast Energy LLC	2003/21552	June 6, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Dodson, Kathryn Davant	Everlast Energy LLC	2003/21557	June 20, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Dodson, Kathryn Davant	Everlast Energy LLC	2004/5729	December 11, 2003	Section 25, T20S, R12W

Donald, III, William James and wife, Aldis A. Donald	Everlast Energy LLC	2003/24446	September 30, 2003	Section 3, T20S, R11W

Duckworth, Jr., F. Edward	Everlast Energy LLC	2004/5628	November 24, 2003	Section 1, T21S, R12W

Duckworth, Jr., Ronald P.	Everlast Energy LLC	2004/5631	December 15, 2003	Section 1, T21S, R12W

Duckworth, Ronald P.	Everlast Energy LLC	2004/5633	December 15, 2003	Section 1, T21S, R12W

Duncan Vera c/o Martha D. Fincher	EVERLAST ENERGY LLC	2004/5103	November 25, 2003	Section 20, T22S, R11W

Duncan, J. C. and wife, Margie J. Duncan	EVERLAST ENERGY LLC	2004/5128	November 21, 2003	Section 20, T22S, R11W

Dunn, Cathy G.	Everlast Energy LLC	2004/5101	November 6, 2003	Section 4, T21S, R11W

Dunn, Steve J. and wife, Nichole L. Dunn	Everlast Energy LLC	2004/10400	December 4, 2003	Section 12, T21S, R11W

Dunnum, Thomas E. III	Everlast Energy LLC	2003/21562	June 20, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Dunnum, Thomas E. III	Everlast Energy LLC	2004/5726	December 11, 2003	Section 25, T20S, R12W

Dupree, Patricia Jones	EVERLAST ENERGY LLC	2005/1768	September 25, 2004	Section 21, T22S, R11W

Duren, Timothy, etux	Everlast Energy LLC	2003/21567	August 12, 2003	Section 4, T21S


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Connie T. Duren				R11W

Dyer, Douglas and Martha Dyer	Everlast Energy LLC	2005/12376	September 12, 2003	Section 4 & 11, T21S, R11W

Dyer, Jeffery S.	Everlast Energy LLC	2004/10423	November 10, 2003	Section 1, T21S, R12W

Edge, Helen	Everlast Energy LLC	2004/5337	November 6, 2003	Section 3, T21S, R11W

Elizabeth H. and Richard P. Holman Irrevocable Trust dated, December 8, 1992	Everlast Energy LLC	2004/3566	November 21, 2003	Section 19, T20S, R11W

Elizabeth H. and Richard P. Homan Irrevocable Trust No. 3	Everlast Energy LLC	2004/3563	November 21, 2003	Section 23, T22S, R11W

Elizabeth H. Homan #2 LLC	Everlast Energy LLC	2004/3569	November 21, 2003	Section 31, T20S, R11W; 24, 25, & 36, T20S, R12W

Elliott, Bertus Delano and wife, Marilyn Elliott	Everlast Energy LLC	2004/444	October 28, 2003	Section 12, T21S, R11W

Elmore, Peggy D.	Everlast Energy LLC	2004/5636	November 24, 2003	Section 1, T21S, R12W

Emerson, Ann Burroughs	Everlast Energy LLC	2005/1855	July 29, 2004	Section 26, T21S, R12W

Estes, Lannie S. and wife, Mable Channell Estes	Everlast Energy LLC	2005/1771	June 21, 2004	Section 34, T21S, R12W

Evers, Maria Medina	EVERLAST ENERGY LLC	2004/393	October 9, 2003	Section 24, T22S, R12W

Fair, James M.	Everlast Energy LLC	2003/24599	July 29, 2003	Section 32, T20S, R11W; Section 5, T21S, R11W

Fair, James M. and wife, Doris N. Fair	Everlast Energy LLC	2004/5071	November 18, 2003	Section 3, T21S, R11W

Fair, James M. and wife, Doris N. Fair	Everlast Energy LLC	2004/5073	November 18, 2003	Section 3, T21S, R11W

Fair, James M. and wife, Doris N. Fair	Everlast Energy LLC	2004/5075	November 18, 2003	Section 3, T21S, R11W

Fair, James M. and wife, Dornis N. Fair	Everlast Energy LLC	2004/5077	November 18, 2003	Section 3, T21S, R11W

Falls, Karon Dale	Everlast Energy LLC	2004/5291	November 18, 2003	Section 3, T21S, R11W

Farley, Melgium	EVERLAST ENERGY LLC	2004/23304	August 24, 2004	Sections 20 & 22, T22S, R11W

Farmer, Dorothy C., Trustee	Everlast Energy LLC	2004/19481	June 14, 2004	Section 21 & 22, T22S, R11W

Faulkner, Barry L. and wife, Cheryl C. Faulkner	Everlast Energy LLC	2004/436	October 28, 2003	Section 12, T21S, R11W

Findley, Margaret K.	Everlast Energy LLC	2003/22932	August 9, 2003	Sections 21 & 23, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Findley, Margaret K. Ind. and as Trustee of the Herbert Lyman Findley, Jr. Marital Trust	Everlast Energy LLC	2003/21570	September 19, 2003	Section 26, T21S, R11W

Fisher, Jr., Robert Owen	Everlast Energy LLC	2004/5170	December 11, 2003	Section 9, T21S, R11W

Fleming, Doris Howard	Everlast Energy LLC	2004/5289	November 18, 2003	Section 3, T21S, R11W

Foley, Kenneth C.	Everlast Energy LLC	2003/21573	July 21, 2003	Section 8, T21S, R11W

Foster, Brenda single woman	EVERLAST ENERGY LLC	2003/24601	October 4, 2003	Section 24, T22S, R12W

Foster, Cleveland a married man	EVERLAST ENERGY LLC	2003/24449	October 4, 2003	Section 24, T22S, R12W

Foster, Houston	EVERLAST ENERGY LLC	2004/27161	August 4, 2004	Section 20, T22S, R12W

Foster, Houston, etal	EVERLAST ENERGY LLC	2004/23810	August 19, 2004	Section 20, T22S, R12W

Foster, Houston	EVERLAST ENERGY LLC	2004/23307	August 27, 2004	Section 22, T22S, R12W

Foster, Jr., Joseph	EVERLAST ENERGY LLC	2003/22937	September 25, 2003	Section 13, T22S, R12W

Foster, Jr., Joseph	EVERLAST ENERGY LLC		September 25, 2003	Section 24, T22S, R12W

Foster, Lester	EVERLAST ENERGY LLC	2005/1749	August 8, 2004	Section 20, T22S, R11W

Foster, Lester	EVERLAST ENERGY LLC	2004/27075	August 27, 2004	Section 22, T22S, R11W

Foster, Sr. Pearlie	EVERLAST ENERGY LLC	2004/391	October 2, 2003	Section 24, T22S, R12W

Foster, Percy	EVERLAST ENERGY LLC	2004/23312	August 8, 2004	Section 20, T22S, R11W

Foster, Percy	EVERLAST ENERGY LLC	2004/23282	August 27, 2004	Section 22, T22S, R11W

Foster, Virginia and Jack J. Foster	EVERLAST ENERGY LLC	2004/10369	October 7, 2003	Section 24, T22S, R12W

Fountain, Janice	EVERLAST ENERGY LLC	2004/5098	September 24, 2003	Section 10, T21S, R11W

Frazier, Debbie Robinson	EVERLAST ENERGY LLC	2004/27096	September 21, 2004	Section 20, T22S, R11W

Fricke, Carolyn Davant	Everlast Energy LLC	2004/10402	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Galloway, Kenneth Dupree and wife, Soneia B. Galloway	Everlast Energy LLC	2004/5285	December 10, 2003	Section 1, T21S, R11W

Gann, Joseph Lee and wife, Monica J. Gann	Everlast Energy LLC	2004/5069	October 29, 2003	Section 12, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Gardiner, Don and wife, Jaunita W. Gardiner	Everlast Energy LLC	2004/5283	November 25, 2003	Section 33, T20S, R11W

Geer, W.O. and wife, Myrtle B. Geer	Everlast Energy LLC	2004/5094	November 1, 2003	Section 25, T21S, R12W

Gilliam, Ralph Wayne and wife, Sylvia Partrich Burroughs Gilliam	EVERLAST ENERGY LLC	2004/448	October 2, 2003	Section 11, T22S, R12W

Gilliam, Sylvia Partrich Burroughs	EVERLAST ENERGY LLC	2004/425	October 2, 2003	Sections 11 & 14, T22S, R12W

Glover, James O.	Everlast Energy LLC	2004/19483	June 14, 2004	Section 21, T22S, R11W

Glover, Norma	EVERLAST ENERGY LLC	2004/27110	August 16, 2004	Sections 20 & 22, T22S, R11W

Goins, Gary Bernard and wife, Cathy Marie Goins	Everlast Energy LLC	2004/5067	October 23, 2003	Section 1, T21S, R11W

Goins, Ollie Jewel	EVERLAST ENERGY LLC	2004/12245	December 30, 2003	Section 20, T22S, R11W

Goodman, Joe L. and wife, Minnie P. Goodman	Everlast Energy LLC	2004/5168	November 18, 2003	Section 3, T21S, R11W

Gordon, Nora Lee	Everlast Energy LLC	2004/5366	November 1, 2003	Section 30, T20S, R11W; Sections 1 & 23, T21S, R12W

Goree, William F. and wife, Mary Beth Goree	Everlast Energy LLC	2003/21579	July 22, 2003	Section 20, T20S, R11W

Goss, Kathryn Dodson	Everlast Energy LLC	2003/21582	June 20, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Gradick, John E. Jr.	Everlast Energy LLC	2003/24603	August 21, 2003	Sections 27 & 34, T20S, R11W

Gray, George Rolland and Debra K. Gray, husband and wife	Everlast Energy LLC	2003/21576	August 11, 2003	Section 34, T21S, R12W

Gregory, Vivian L.	EVERLAST ENERGY LLC	2005/1796	October 6, 2004	Sections 10 & 15, T22S, R12W

Groenedyke, Jr., Richard A.	Everlast Energy LLC	2004/5090	November 20, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Guin, Joe E.	Everlast Energy LLC	2003/24610	July 29, 2003	Section 20, T20S, R11W

Guin, Joe E. and wife, Ruby C. Guin	Everlast Energy LLC	2003/21587	July 24, 2003	Section 6, T21S, R11W

Gulf States Paper Corporation	Everlast Energy LLC	2004/5254	July 9, 2003	Sections 32 & 33, T20S, R11W; 2, 16, 17 & 21, T21S, R11W

Gulf States Paper Corporation	Everlast Energy LLC	2005/1839	July 7, 2004	Section 35, T20S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Gunn, Laura A.	Everlast Energy LLC	2003/21589	June 20, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Gunn, Laura A.	Everlast Energy LLC	2004/5639	December 11, 2003	Section 25, T20S, R12W

Haglar, Ruth Leona and husband, George Glen Hagler	Everlast Energy LLC	2003/24617	September 27, 2003	Section 20, T21S, R11W

Hale, Dayton F.	Everlast Energy LLC	2003/21595	August 1, 2003	Sections 35 & 36, T20S, R12W; Section 34, T21S, R12W

Hall, J.B. and Elizabeth Dean Hall	Everlast Energy LLC	2003/24619	August 21, 2003	Section 1, T21S, R12W

Hall, Josie B. and husband, Thomas B. Hall	EVERLAST ENERGY LLC	2005/1837	August 18, 2004	Section 10, T22S, R12W

Hall, Kerry Martin	Everlast Energy LLC	2004/5251	November 25, 2003	Section 34, T20S, R12W

Hall, Robert Ray and wife, Bobbie Sue Hall	Everlast Energy LLC	2004/5642	October 26, 2003	Section 12, T21S, R11W

Hallman, David P. and wife, Dorothy Hallman & Armel Hallman	Everlast Energy LLC	2004/3561	October 28, 2003	Section 1, T21S, R12W

Hallman, J.L.	Everlast Energy LLC	2003/21601	July 24, 2003	Section 35, T20S, R12W

Hamner, Amye B.	Everlast Energy LLC	2004/5280	November 12, 2003	Section 1, T21S, R12W

Hamner, Amye B.	Everlast Energy LLC	2004/12247	November 12, 2003	Section 1, T21S, R12W

Hamner, Wilburn C. and wife, Edith G. Hamner	Everlast Energy LLC	2004/5065	December 1, 2003	Section 1, T22S, R12W

Hanna, Eula D.	EVERLAST ENERGY LLC	2003/22875	November 21, 2003	Section 20, T22S, R11W

Hanson, James Dewitte and wife, Sharon Barger Hanson	Everlast Energy LLC	2004/23314	June 15, 2004	Section 34, T21S, R12W

Hanson, Sharon Barger	Everlast Energy LLC	2004/27114	July 21, 2004	Section 26, T21S, R12W

Hanson, Patricia Vandegraaf	Everlast Energy LLC	2003/21659	August 5, 2003	Sections 2 & 3, T21S, R12W

Hardy, Shirley Sealey	EVERLAST ENERGY LLC	2005/6384	December 11, 2004	Section 13, T22S, R12W

Harless, Michael T. and wife, Karen W. Harless	Everlast Energy LLC	2004/5063	October 26, 2003	Section 12, T21S, R11W

Hardy, Linda Joyce	EVERLAST ENERGY LLC	2004/23317	September 10, 2004	Section 20, T22S, R11W

Harper, Socrates and wife, Consuella J. Harper	Everlast Energy LLC	2004/5716	January 21, 2004	Section 13, T22S, R12W

Harper, Truella M. Foster	EVERLAST ENERGY LLC	2003/24621	October 8, 2003	Section 24, T22S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Harrell, Roberta	EVERLAST ENERGY LLC	2004/10406	January 2, 2004	Section 20, T22S, R11W

Harris, Larry	EVERLAST ENERGY LLC	2005/761	January 6, 2005	Section 13, T22S, R12W

Harris, Ruthleen McKinney	EVERLAST ENERGY LLC	2004/5610	October 22, 2003	Section 24, T22S, R12W

Hartley, Jr. Arthur and wife, Tina Hartley	Everlast Energy LLC	2004/28135	September 2, 2004	Section 36, T20S, R12W

Harvest LLC	EVERLAST ENERGY LLC	2005/1984	January 18, 2005	Section 13, T22S, R12W

Hawkins, Sr., Earnest, and wife Rebecca R. Hawkins	EVERLAST ENERGY LLC	2005/1830	September 1, 2004	Section 14, T22S, R12W

Henderson, Gene Koster	Everlast Energy LLC	2003/22939	August 9, 2003	Section 21 & 23, T21S, R11W

Herndon, Howard	Everlast Energy LLC	2004/5309	September 23, 2003	Section 10, T21S, R11W

Hester, James R. and wife, Debra T. Hester	Everlast Energy LLC	2004/5644	December 6, 2003	Section 33, T20S, R11W

Hicks, Dora Dean Washington	EVERLAST ENERGY LLC	2004/27163	September 29, 2004	Section 26, T22S, R12W

Hicks, Dora D.	EVERLAST ENERGY LLC	2005/12372	January 7, 2005	Section 30, T22S, R11W

Hicks, Gary and Angie	Everlast Energy LLC	2004/422	October 1, 2003	Section 1, T21S, R12W

Hicks, Glenn Tracey and wife, Donna Michelle Hicks	Everlast Energy LLC	2004/420	October 1, 2003	Section 1, T21S, R12W

Higgins, Kathryn Davant	Everlast Energy LLC	2004/5246	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Hill, Annie Ruth	EVERLAST ENERGY LLC	2004/12250	December 30, 2003	Section 20, T22S, R11W

Hill, Jr., Billy	EVERLAST ENERGY LLC	2004/23319	September 10, 2004	Section 20, T22S, R11W

Hill, David M. and wife, Beverly E. Hill	Everlast Energy LLC	2005/1828	August 18, 2004	Section 1, T21S, R12W

Hill, James A.	EVERLAST ENERGY LLC	2005/1826	October 29, 2004	Section 28, T22S, R11W

Hill, John E.	EVERLAST ENERGY LLC	2004/12252	December 20, 2003	Section 20, T22S, R11W

Hill, Richard M.	EVERLAST ENERGY LLC	2005/1791	November 3, 2004	Section 27 & 28, T22S, R11W

Hinson, Christopher W. and wife, Amy E. Hinson	Everlast Energy LLC	2004/12254	October 26, 2003	Section 12, T21S, R11W

Hinton, Charles Anthony and wife, Josie D. Hinton	Everlast Energy LLC	2004/19485	June 23, 2004	Section 5, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Hinton, Jane	Everlast Energy LLC	2004/23323	June 24, 2004	Section 5, T21S, R11W

Hinton, Linda Smalley	Everlast Energy LLC	2004/5646	November 2, 2003	Section 17, T21S, R12W

Hitt, Ottis Deal and wife, Martha Elois Hitt	Everlast Energy LLC	2004/12258	October 1, 2003	Section 1, T21S, R12W

Hitt, Terry Ray	Everlast Energy LLC	2004/12256	October 1, 2003	Section 1, T21S, R12W

Holland, Alice B. and Michelle Elaine Latner	Everlast Energy LLC	2004/3527	October 1, 2003	Section 1, T21S, R12W

Hollingsworth, Arden Norris	EVERLAST ENERGY LLC	2003/24451	October 24, 2003	Section 30, T22S, R1W; Section 25, T22S, R12W

Hollingsworth, Douglas H. and wife, Martha J. Hollingsworth	Everlast Energy LLC	2004/5087	November 1, 2003	Section 23, T20S, R11W; Sections 9 & 17, T21S, R11W

Hollingsworth, III, James H.	EVERLAST ENERGY LLC	2004/5648	October 28, 2003	Section 25, T22S, R12W

Holly Springs Baptist Church	EVERLAST ENERGY LLC	2004/5125	October 27, 2003	Section 24, T22S, R12W

Holman Investments, L.L.C.	Everlast Energy LLC	2004/3572	November 21, 2003	Section 6, T21S, R11W

Holman, James Albert	Everlast Energy LLC	2004/8600	March 11, 2004	Section 19, T20S, R11W; Sections 24 & 25, T20S, R12W; Section 6, T21S, R12W; Section 23, T22S, R11W

Holman, Zackary and wife, Jennifer Holman	EVERLAST ENERGY LLC	2004/5059	October 30, 2003	Section 3, T22S, R12W

Hopkins, Richard Dale and wife, Janie Lee M. Hopkins	Everlast Energy LLC	2004/5657	November 5, 2003	Section 2, T22S, R11W

Hopson, Bertha Lee Washington	EVERLAST ENERGY LLC	2004/28150	September 22, 2004	Section 26, T22S, R12W

Hopson, Bertha L.	EVERLAST ENERGY LLC	2005/765	January 5, 2005	Section 30, T22S, R11W

Horton, Vera W.	EVERLAST ENERGY LLC	2004/27066	September 29, 2004	Section 22, T22S, R11W

Houston, Tommie Lynn	Everlast Energy LLC	2003/21603	August 5, 2003	Section 19 & 20, T20S, R11W

Huggins, Salarano	EVERLAST ENERGY LLC	2004/23328	August 24, 2004	Section 20 & 22, T22S, R11W

Hughes, Ronald Joe and wife, Sherry Hughes	Everlast Energy LLC	2004/5085	November 1, 2003	Section 9, T21S, R11W

Hulsey, Marie K.	Everlast Energy LLC	2004/387	October 26, 2003	Section 12, T21S, R11W

Hundley, Valerie L.	Everlast Energy LLC	2004/5217	December 30, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Hutchinson, Jesse Randall and wife, Betty Jo Hutchinson	Everlast Energy LLC	2004/23325	June 28, 2004	Section 1, T21S, R12W

Hutton, Ross C. and wife, Jo Anne C. Hutton	Everlast Energy LLC	2003/21605	July 7, 2003	Section 7, T21S, R11W; Section 12, T21S, R12W

Hysaw, Stephen A., single	Everlast Energy LLC	2004/3524	September 23, 2003	Section 4, T21S, R11W

Hysaw, Stephen A., single	Everlast Energy LLC	2004/418	October 20, 2003	Section 4, T21S, R11W

Ike, Verlena Foster	Everlast Energy LLC	2004/5315	December 18, 2003	Section 24, T22S, R12W

Jackson, Johnny D. And wife, Gail L. Jackson	Everlast Energy LLC	2004/5121	November 1, 2003	Section 9, T21S, R11W

Jacobs, A.J. and wife, Juanita S. Jacobs	Everlast Energy LLC	2004/415	October 26, 2003	Section 12, T21S, R11W

James Graham Brown Foundation, Inc.	Everlast Energy LLC	2004/21515	September 23, 2003	Section 27, 29 & 30; T20S, R11W; Section 26, T20S, R12W

James, Thomas A.	Everlast Energy LLC	2003/24454	October 26, 2003	Section 12, T21S, R11W

Johnson, Annie Pearl McKinney	EVERLAST ENERGY LLC	2004/5615	October 22, 2003	Section 24, T22S, R12W

Johnson, Ella M.	EVERLAST ENERGY LLC	2005/1970	January 7, 2005	Section 20, T22S, R11W

Johnson, Ella Mae Washington	EVERLAST ENERGY LLC	2004/27165	September 22, 2004	Section 24, T22S, R12W

Johnson, Faye Henderson	Everlast Energy LLC	2004/5119	November 8, 2003	Section 4, T21S, R11W

Johnson, Sherman J. and wife, Janet H. Johnson	Everlast Energy LLC	2004/5172	November 19, 2003	Section 12, T21S, R11W

Johnston, Laban Keith and Patricia L. Johnston, husband and wife	Everlast Energy LLC	2004/5215	July 23, 2003	Section 2, T21S, R12W

Joiner, Thomas J. and wife, Virginia H. Joiner	Everlast Energy LLC	2003/21609	May 21, 2003	Section 23, T22S, R11W

Jones, Alfred and wife, Sue Jones	Everlast Energy LLC	2003- 21612	August 26, 2003	Section 30, T21S, R11W

Jones, Barry	Everlast Energy LLC	2003/24625	September 17, 2003	Section 14, T21S, R12W

Jones, Cecil Wynelle and wife, Virginia Hawthorne Jones	Everlast Energy LLC	2004/5116	November 4, 2003	Section 1, T21S, R12W

Jones, Jr., Curtis Oliver and wife, Marilyn Jones	Everlast Energy LLC	2004/5113	November 4, 2003	Section 1, T21S, R12W

Jones, Ethel Mae	EVERLAST ENERGY LLC	2004/23330	August 11, 2004	Sections 20 & 22, T22S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Jones, Fred, Jr.	EVERLAST ENERGY LLC	2005/1788	November 11, 2004	Sections 21 & 22, T22S, R11W

Jones, Freddie Lee	EVERLAST ENERGY LLC	2004/23332	August 11, 2004	Sections 20 & 22, T22S, R11W

Jones, Jerry Jerome	EVERLAST ENERGY LLC	2004/23335	August 11, 2004	Sections 20 & 22, T22S, R11W

Jones, Michael	EVERLAST ENERGY LLC	2004/23339	August 11, 2004	Sections 20 & 22, T22S, R11W

Jones, Otis	EVERLAST ENERGY LLC	2004/23337	August 11, 2004	Sections 20 & 22, T22S, R11W

Jones, Patricia Ann	EVERLAST ENERGY LLC	2004/23341	August 11, 2004	Sections 20 & 22, T22S, R11W

Jones, Percy Lee	EVERLAST ENERGY LLC	2004/27061	August 11, 2004	Sections 20 & 22, T22S, R11W

Jones, Ronald B. and wife, Martha C. Jones	Everlast Energy LLC	2004/10408	November 24, 2003	Section 3, T21S, R11W

Jones, Jr., Walter James	EVERLAST ENERGY LLC	2004/27063	August 18, 2004	Sections 20 & 22, T22S, R11W

Jones, Willary Cary	Everlast Energy LLC	2004/12261	November 3, 2003	Section 12, T21S, R11W

Jones, William K. and wife, Leigh Ann D. Jones	Everlast Energy LLC	2004/10411	November 1, 2003	Section 1, T21S, R12W

Jones, Willie Glenn	EVERLAST ENERGY LLC	2004/23343	August 11, 2004	Sections 20 & 22, T22S, R11W

Kansas City Southern Railway Company	Everlast Energy LLC	2004/17171	July 9, 2004	Sections 31 & 32, T20S, R11W; Section 36, T20S, R12W; Section 4, 5, 9, 10 & 11, T21S, R11W; Section 1, 2 & 3, T21S, R12W

Keasler, Thomas M. and wife, Jo Ann Keasler	Everlast Energy LLC	2003/24627	August 21, 2003	Section 4, T21S, R11W

Kelly, Vallery B. and husband, Christopher M. Kelly	Everlast Energy LLC	2004/5083	November 19, 2003	Section 12, T21S, R11W

Kent, Daryl and wife, Rebecca Kent	Everlast Energy LLC	2004/5732	February 17, 2004	Section 19 & 20, T22S, R11W

Kidd, Jack Thomas and wife, Marilyn Sue Kidd	Everlast Energy LLC	2003/24456	September 24, 2003	Section 33, T20S, R11W

Kidd, Robert E. and wife, Mary Kaye Kidd	Everlast Energy LLC	2004/5111	November 1, 2003	Section 4, T21S, R11W

Killingsworth, Johnie Hall and husband, Roy W. Killingsworth	Everlast Energy LLC	2003/12236	August 5, 2003	Section 2, T21S, R12W

King, Nelda	EVERLAST ENERGY LLC	2004/5671	January 2, 2004	Section 20, T22S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
King, Edna	EVERLAST ENERGY LLC	2004/10413	January 2, 2004	Section 20, T22S, R11W

King, Jr. Ernest	EVERLAST ENERGY LLC	2004/5659	January 2, 2004	Section 20, T22S, R11W

King, Harrison	EVERLAST ENERGY LLC	2004/5664	January 1, 2004	Section 20, T22S, R11W

King, Kenneth	Everlast Energy LLC	2004/5810	January 2, 2004	Section 20, T22S, R11W

King, Michael	EVERLAST ENERGY LLC	2004/5666	January 2, 2004	Section 20, T22S, R11W

King, Rosanna	EVERLAST ENERGY LLC	2004/27057	September 9, 2004	Section 20, T22S, R11W

King, Vera	EVERLAST ENERGY LLC	2004/10398	January 2, 2004	Section 20, T22S, R11W

Kirby, Otis B. and wife, Bety H. Kirby	Everlast Energy LLC	2004/5081	November 17, 2003	Section 33, T20S, R11W

Kircharr, Richard D. and wife, Ashley M. Kircharr	Everlast Energy LLC	2004/5277	December 12, 2003	Section 12, T21S, R11W

Kitchen, Jo Ann Burroughs and husband, Richard M. Kitchen	Everlast Energy LLC	2004/5108	November 8, 2003	Section 1, T21S, R12W

Knight, Nicholas R. and wife, Stephanie A. Knight	Everlast Energy LLC	2004/5079	November 16, 2003	Section 12, T21S, R11W

Kulp, Joseph R. and wife, Patricia A. Kulp	Everlast Energy LLC	2003/24456	October 26, 2003	Section 12, T21S, R11W

Kyzer, James and wife, Betty Kyzer	Everlast Energy LLC	2004/5105	November 21, 2003	Sections 1 & 2, T21S, R12W

Ladewig, Mary Kathryn Dunnam	Everlast Energy LLC	2003/21614	June 20, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Ladewig, Mary Kathryn Dunnam	Everlast Energy LLC	2004/5673	December 11, 2003	Section 25, T20S, R12W

Laird, Deidra R.	Everlast Energy LLC	2004/412	September 3, 2003	Section 34, T21S, R12W

Lancaster, Keith N. and wife, Myra S. Lancaster	Everlast Energy LLC	2004/4981	November 24, 2003	Section 9, T21S, R11W

Lasseter, Paul A.	Everlast Energy LLC	2003/21621	July 23, 2003	Section 22, T20S, R11W; Section 5, T21S, R11W

Latner, Jr., Clarence L. and wife, Karen S. Latner	Everlast Energy LLC	2004/5272	October 6, 2003	Section 11, T21S, R11W

Lee, Pamela Carol McKnight and husband, Todd Alana Lee	Everlast Energy LLC	2004/12266	November 18, 2003	Section 9, T21S, R11W

Lee, Roger Dale and wife, Sue L. Lee	Everlast Energy LLC	2004/5275	December 10, 2003	Section 1, T21S, R12W

Leonard, David Eugene and wife, Merle Pate Leonard	Everlast Energy LLC	2004/3576	October 21, 2003	Section 9, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Leps, Linda T.	Everlast Energy LLC	2003/24461	August 21, 2003	Sections 27 & 34, T20S, R11W

Lewis, Wendell R. and wife, Tonya L. Lewis	Everlast Energy LLC	2004/4979	September 24, 2003	Section 9, T22S, R12W

Light, Laura Maurice and husband, Alfred David Light	Everlast Energy LLC	2004/23345	July 14, 2004	Section 34, T21S, R12W

Lilley, E.H.	Everlast Energy LLC	2003/21628	August 21, 2003	Sections 27 & 34, T20S, R11W

Lindsey, BonnieT.	Everlast Energy LLC	2004/12268	November 4, 2003	Section 12, T21S, R11W

Lindsey, Phyllis	EVERLAST ENERGY LLC	2004/28152	October 25, 2004	Section 26, T22S, R12W

Lovell, Roy Dwyatt and wife, Tracey A. Lovell	Everlast Energy LLC	2004/4977	October 28, 2003	Section 12, T21S, R11W

Lucious, Canary	EVERLAST ENERGY LLC	2004/28155	September 9, 2004	Section 20, T22S, R11W

Lucious, Eddie	EVERLAST ENERGY LLC	2004/27116	September 9, 2004	Section 20, T22S, R11W

Lucious, Walter	EVERLAST ENERGY LLC	2004/27173	September 9, 2004	Section 20, T22S, R11W

Lucious, Willie	EVERLAST ENERGY LLC	2004/28157	September 9, 2004	Section 20, T22S, R11W

Lyons, Marvin E. and wife, Pam A. Lyons	Everlast Energy LLC	2004/12270	November 2, 2003	Section 12, T21S, R11W

Mattox, John Henry	EVERLAST ENERGY LLC	2004/23321	August 26, 2004	Section 20, T22S, R11W

Maddox, Willie James	EVERLAST ENERGY LLC	2004/27118	September 2, 2004	Section 20, T22S, R11W

Madison, Debra B., a married woman, formerly, Debra B. Ponds	Everlast Energy LLC	2003/21631	August 5, 2003	Section 34, T21S, R12W

Manley, Dwight and wife, Shelby Manley	Everlast Energy LLC	2004/4973	October 29, 2003	Section 12, T21S, R11W

Marlowe, III Lonnie Alton and wife, Jenny Marlowe	Everlast Energy LLC	2004/4971	September 17, 2003	Section 2, T21S, R12W

Marlowe, Jo Anne	Everlast Energy LLC	2004/3529	September 17, 2003	Section 2, T21S, R12W

Marlowe, Joe	Everlast Energy LLC	2004/12272	September 17, 2003	Section 2, T21S, R12W

Marlowe, Lonnie A.	Everlast Energy LLC	2004/3532	September 17, 2003	Section 2, T21S, R12W

Marshall, Essie Mae	EVERLAST ENERGY LLC	2004/27071	September 28, 2004	Section 22, T22S, R11W

Martin, Cheryl D.	Everlast Energy LLC	2003/21633	July 21, 2003	Section 8, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Marx, Sharon	Everlast Energy LLC	2004/5007	November 5, 2003	Section 1, T21S, R12W

Marx, Udo Franz	Everlast Energy LLC	2004/12274	November 5, 2003	Section 12, T21S, R12W

Mason, Walter Ronnie	Everlast Energy LLC	2004/27120	August 18, 2004	Section 12, T21S, R12W

Massey, Larry Olsen and wife, Janet Massey	Everlast Energy LLC	2004/4969	November 17, 2003	Section 12. T21S, R11W

Matthews, Stephanie T.	Everlast Energy LLC	2003/21636	August 21, 2003	Sections 27 & 34, T20S, R11W

Maughn, Johnny and wife, Sharon Maughn	Everlast Energy LLC	2004/3580	October 5, 2003	Section 10, T21S, R11W

McAteer, Daniel Jackson and wife, Mavis Faye McAteer	Everlast Energy LLC	2004/5012	November 3, 2003	Section 1, T21S, R12W

McAteer, Daniel Wade	Everlast Energy LLC	2004/12313	November 3, 2003	Section 1, T21S, R12W

McAteer, James Joseph & Willie Dean	Everlast Energy LLC	2003/24629	September 17, 2003	Section 2, T21S, R12W

McAteer, Rodney Deal and wife, Sonya Kay McAteer	Everlast Energy LLC	2004/4994	November 11, 2003	Section 1, T21S, R12W

McCall, Maxine Weatherspoon	EVERLAST ENERGY LLC	2003/24634	September 23, 2003	Section 24, T22S, R12W

McCool, Randy Lynne and wife, Mary Frances McCool	Everlast Energy LLC	2004/5676	December 19, 2003	Section 1, T21S, R11W

McCoy, Mary	EVERLAST ENERGY LLC	2004/27122	September 2, 2004	Section 20, T22S, R11W

McCracken, Andrew Hughes and wife, Patricia McCracken	Everlast Energy LLC	2004/5015	November 5, 2003	Section 1, T21S, R12W

McDaniel, Sarah Ellen, a widow a/k/a Sarah D. McDaniel	Everlast Energy LLC	2003/21478	September 3, 2003	Section 28, T20S, R11W

McDaniel, Verner Earl and wife, Martha S. McDaniel	Everlast Energy LLC	2003/21639	September 3, 2003	Section 28, T20S, R11W

McDonald, Forrest and wife, Ellen S. McDonald	Everlast Energy LLC	2003/24639	September 23, 2003	Section 33, T20S, R11W

McDuff, Donald H. and wife, Ruth McDuff	EVERLAST ENERGY LLC	2003/24642	October 1, 2003	Sections 10, 11 & 15, T22S, R12W

McKenzie, Merri Elizabeth Scales	Everlast Energy LLC	2003/21641	August 8, 2003	Sections 5 & 6, T21S, R11W

McKinney, Eddie, Annette McKinney and Yvonne McKinney	EVERLAST ENERGY LLC	2004/5617	October 22, 2003	Section 24, T22S, R12W

McKinney, Elaine	EVERLAST ENERGY LLC	2004/12285	October 22, 2003	Section 24, T22S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
McKnight, Benny Ross etux, Peggy Jean McKnight	Everlast Energy LLC	2003/21647	July 23, 2003	Section 4, T21S, R11W

McKnight, Billy Gene and wife, Linda McKnight	Everlast Energy LLC	2004/3584	November 16, 2003	Sections 4 & 9, T21S, R11W

McKnight, Billy Gene, a married man and Carolyn McKnight, an unmarried woman	Everlast Energy LLC	2004/12279	November 21, 2003	Section 9, T21S, R11W

McKnight, Jr., Billy Gene and wife, Peggy Dyer McKnight	Everlast Energy LLC	2004/3587	November 18, 2003	Section 9, T21S, R11W

McNight, Ross and wife, Peggy Jean McKnight	Everlast Energy LLC	2004/3534	November 14, 2003	Sections 4 & 9, T21S, R11W

McPherson, Robert E. and wife, Eva E. McPherson	Everlast Energy LLC	2004/12287	November 5, 2003	Section 1, T21S, R12W

McWilliams, Lewanna Foster	EVERLAST ENERGY LLC	2004/5213	December 17, 2003	Section 24, T22S, R12W

Medina, Richard	EVERLAST ENERGY LLC	2004/4996	October 13, 2003	Section 24, T22S, R12W

Mercier, David G. and wife, Rhonda L. Mercier	Everlast Energy LLC	2004/5335	November 16, 2003	Section 12, T21S, R11W

Mercier, Sr., David G.	Everlast Energy LLC	2004/12289	November 13, 2003	Section 33, T20S, R11W

Meriwether, III, Willis, J., etal	Everlast Energy LLC	2003/24494	October 27, 2003	Sections 2 & 11, T22S, R11W

Miller, Carolyn V.	Everlast Energy LLC	2003/21481	July 21, 2003	Section 8, T21S, R11W

Mills, James Carl and wife, Shella Dianne Mills	Everlast Energy LLC	2004/27124	August 24, 2004	Section 36, T20S, R12W

Mills, James Morris, Jr. and wife, Tracey B. Mills	Everlast Energy LLC	2004/23348	August 13, 2004	Section 24 & 25, T20S, R12W

Minor, Jon	Everlast Energy LLC	2005/1823	July 28, 2004	Section 1, T21S, R12W

Mitchum, Charlie V. and wife, Shirley J. Mitchum	Everlast Energy LLC	2003/24497	September 3, 2003	Section 10, T21S, R11W

Moe, Barbara S.	Everlast Energy LLC	2004/14754	April 4, 2004	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Montgomery, Cedora	EVERLAST ENERGY LLC	2004/23351	August 24, 2004	Sections 20 & 22, T22S, R11W

Montgomery, Deborah Ann Norris and husband, Roger D. Montgomery	Everlast Energy LLC	2004/27127	August 24, 2004	Section 13, T22S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Montgomery, M.C. and wife, Dean H. Montgomery	Everlast Energy LLC	2004/3589	October 30, 2003	Section 9, T21S, R11W

Moore, Adelaide by Fred Jones, Jr., Atty in Fact	EVERLAST ENERGY LLC	2005/1896	November 30, 2004	Section 22, T22S, R11W

Moore, Lucinda	EVERLAST ENERGY LLC	2005/1976	January 7, 2005	Section 30, T22S, R11W

Moore, Lucinda Washington	EVERLAST ENERGY LLC	2004/28159	September 16, 2004	Section 24, T22S, R12W

Morgan, Donald H.	Everlast Energy LLC	2003/24500	September 25, 2003	Section 17, T21S, R11W

Morgan, John M. and wife, Ruth E. Morgan	Everlast Energy LLC	2004/5242	October 29, 2003	Section 17, T21S, R11W

Morgan, Joseph C. and wife, Terry L. Morgan	Everlast Energy LLC	2004/4998	October 5, 2003	Section 20, T21S, R11W

Morgan, Zane Joyce, a widow	Everlast Energy LLC	2003/24507	September 24, 2003	Section 17, T21S, R11W

Morrison, A. Wayne	Everlast Energy LLC	2003/21650	July 8, 2003	Section 32, T20S, R11W

Morrison, Robert	EVERLAST ENERGY LLC	2004/27130	September 9, 2004	Section 20, T22S, R11W

Morrow, Mabel	EVERLAST ENERGY LLC	2004/10415	January 2, 2004	Section 20, T22S, R11W

Morton, Adrienne	EVERLAST ENERGY LLC	2005/1816	October 25, 2004	Section 26, T22S, R12W

Mountain Brook	EVERLAST ENERGY LLC	2005/1741	October 10, 2004	Section 29, T22S, R11W

Mullenix, Fredrick L.	Everlast Energy LLC	2004/27132	August 16, 2004	Section 5, T21S, R11W

Murray Eddie	EVERLAST ENERGY LLC	2005/1893	August 24, 2004	Section 20 & 22, T22S, R11W

Murray, Gary	EVERLAST ENERGY LLC	2004/23358	August 24, 2004	Sections 20 & 22, T22S, R11W

Murray, Greg	EVERLAST ENERGY LLC	2004/23358	August 24, 2004	Sections 20 & 22, T22S, R11W

Murray, Jr. James	EVERLAST ENERGY LLC	2004/28162	August 24, 2004	Section 20 & 22, T22S, R11W

Murray, Mickey	EVERLAST ENERGY LLC	2004/27134	August 24, 2004	Section 20 & 22, T22S, R11W

Murray, Ozella	EVERLAST ENERGY LLC	2004/5678	December 8, 2003	Section 20, T22S, R11W

New Hope Baptist Church	EVERLAST ENERGY LLC	2004/5612	December 4, 2003	Section 11, T22S, R12W

New, Eppie Webb C/O Linda New Mickle	Everlast Energy LLC	2004/3536	October 14, 2003	Sections 25 & 35, T20S, R12W

Newman, Gary C. and wife, Linda F. Newman	Everlast Energy LLC	2003/24468	October 26, 2003	Section 12, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Nicosia, Gurtha Lee Booth and husband, Eli F. Nicosia	Everlast Energy LLC	2004/23360	July 28, 2004	Section 26, T21S, R12W

Nordan, Cynthia Vermelle	Everlast Energy LLC	2004/5685	November 18, 2003	Section 3, T21S, R11W

Odom, Margaret	EVERLAST ENERGY LLC	2004/28165	October 27, 2004	Section 27, T22S, R11W

Odom, Tommy	EVERLAST ENERGY LLC	2004/27136	October 21, 2004	Section 28, T22S, R11W

Odom, Tommy	EVERLAST ENERGY LLC	2004/28167	October 22, 2004	Section 27, T22S, R11W

O’Hanlon, Doris G.	Everlast Energy LLC	2004/3592	November 1, 2003	Section 35, T20S, R12W; Section 2, T21S, 12W

O’Hanlon, Doris G., etal	Everlast Energy LLC	2004/3595	November 1, 2003	Section 35, T20S, R12W

O’Hanlon, Patrick	Everlast Energy LLC	2004/12291	November 1, 2003	Section 35, T20S, R12W

Oliver, E. Toy and wife, Yvonne Oliver	Everlast Energy LLC	2003/24470	September 28, 2003	Section 20, T21S, R11W

Oliver, Waymon A. and wife, Tawana D. Oliver	EVERLAST ENERGY LLC	2004/5040	November 11, 2003	Sections 11 & 14, T22S, R12W

Parham, Ruby Lee Pate	Everlast Energy LLC	2003/21485	August 4, 2003	Section 3, T21S, R11W

Parris, Jimmy R. and wife, Glenda E. Parris	EVERLAST ENERGY LLC	2003/24472	October 8, 2003	Section 24, T22S, R12W

Pate, Edward D	Everlast Energy LLC	2004/389	October 30, 2003	Section 32, T20S, R11W

Pate, J.H. and wife, Louise C. Pate	Everlast Energy LLC	2003/22946	September 1, 2003	Sections 3 & 23, T21S, R12W

Pate, Mattie Lou	EVERLAST ENERGY LLC	2004/5359	November 11, 2003	Section 14, T22S, R12W

Patton J. Stuart	EVERLAST ENERGY LLC	2004/27139	August 5, 2004	Section 22, T22S, R11W

Paulk, Geraldine	EVERLAST ENERGY LLC	2004/27112	August 16, 2004	Section 20 & 22, T22S, R11W

Paulk, Johnny	EVERLAST ENERGY LLC	2004/28169	August 16, 2004	Sections 20 & 22, T22S, R11W

Paulk, Pearlie	EVERLAST ENERGY LLC	2004/23362	August 13, 2004	Section 20 & 22, T22S, R11W

Paulk, Willie	EVERLAST ENERGY LLC	2004/23366	August 13, 2004	Section 20 & 22, T22S, R11W

Patrick, David Wayne	Everlast Energy LLC	2004/5044	November 8, 2003	Section 1, T21S, R12W

Payne, Robert and wife, Partricia	Everlast Energy LLC	2003/22950	September 1, 2003	Section 5, T21S, R11W

Perkins, Jerry S. and wife, Mary A. Perkins	Everlast Energy LLC	2004/4967	November 1, 2003	Section 9, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Perkins, Joseph D. and wife, Wilda Perkins	Everlast Energy LLC	2003/24474	October 26, 2003	Section 12, T21S, R11W

Perry, Cornelia Atwood	Everlast Energy LLC	2004/5320	November 12, 2003	Section 25, T20S, R12W, Section 5 & 7, T21S, R11W; Section 3, T228, R12W

Phillips, Brian K.	Everlast Energy LLC	2003/24479	October 26, 2003	Section 12, T21S, R11W

Piggott, Robert P. and wife, Thelma R. Piggott	Everlast Energy LLC	2003/22880	July 21, 2003	Section 32, T20S, R11W

Pinion, Jr., James H. and wife, Beverly H. Pinion	Everlast Energy LLC	2004/5047	November 12, 2003	Sections 29 and 30, T20S, R11W

Piper, Jamie Jackson and husband, Jim Michael Piper	Everlast Energy LLC	2003/24512	July 21, 2003	Section 8, T21S, R11W

Plowman, Roger Dale and wife, Mary Sue Plowman	Everlast Energy LLC	2004/5244	December 4, 2003	Section 9, T21S, R11W

Plowman, Thomas V. and Ruth Elizabeth Plowman, husband and wife	Everlast Energy LLC	2003/24515	July 23, 2003	Section 33, T21S, R12W

Porterfield, Evelyn	EVERLAST ENERGY LLC	2004/10425	January 2, 2004	Section 20, T22S, R11W

Posey, James and wife, Fairy Anne Posey	Everlast Energy LLC	2004/28171	September 9, 2004	Section 14, T21S, R12W

Prescott, Opal Harris	Everlast Energy LLC	2004/5333	October 26, 2003	Section 12, T21S, R11W

Pritchett, Elizabeth H.	Everlast Energy LLC	2004/4963	November 20, 2003	Section 12, T21S, R11W

Pruitt, Avery and wife, Betty J. Pruitt	EVERLAST ENERGY LLC		January 21, 2005	Section 13, T22S, R12W

Pruitt, Thomas and wife, Esther Pearl Pruitt	EVERLAST ENERGY LLC	2005/1786	October 19, 2004	Section 30, T22S, R11W

Pruitt, Ester Pearl	EVERLAST ENERGY LLC	2005/1814	October 19, 2004	Section 30, T22S, R11W

Quigley, John E.	Everlast Energy LLC	2004/4939	November 16, 2003	Section 12, T21S, R11W

Randolph, Cherokee Vandegraaf	Everlast Energy LLC	2003/21652	August 5, 2003	Sections 2 & 3, T21S, R12W

Rarrick, Jared and wife, Connie L. Rarrick	Everlast Energy LLC	2004/27141	June 29, 2004	Section 5, T21S, R11W

Ray, Virgie N. and wife, Maudine S. Ray	Everlast Energy LLC	2003/11252	May 6, 2003	Section 10, T22S, 11W

Raymon, Salye, Individually and as Trustee for Robert Preston Raymon	Everlast Energy LLC	2003/24650	August 18, 2003	Section 20, T20S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE

Redmond, Catherine	EVERLAST ENERGY LLC	2004/28174	September 2, 2004	Section 20, T22S, R11W

Reece, Gaines and wife, Frances Reece	Everlast Energy LLC	2003/24517	September 2, 2003	Section 3 & 4, T21S, R11W

Regions Bank as Trustee of the Cogie Trusts U/A dated 12-30-71	Everlast Energy LLC	2003/21493	June 17, 2003	Section 24, T21S, R12W

Resources for Independence	Everlast Energy LLC	2004/12293	October 26, 2003	Section 12, T21S, R11W

Reynolds, Marshall A.	Everlast Energy LLC	2004/5687	December 12, 2003	Section 12, T21S, R11W

Rice, Gary W. and Kay G. Rice, husband and wife	Everlast Energy LLC	2003/24520	September 2, 2003	Section 34, T21S, R12W

Rice, Harold W. and Myrtle Louise	Everlast Energy LLC	2004/3598	October 24, 2003	Section 1, T21S, R12W

Robertson, Kevin Scott and wife, Kimberly Susan Robertson	EVERLAST ENERGY LLC	2004/410	November 1, 2003	Section 13, T22S, R12W

Robinson, Kenneth	EVERLAST ENERGY LLC	2004/27143	September 21, 2004	Section 20, T22S, R11W

Rogers, Molly J.	Everlast Energy LLC	2004/4861	October 31, 2003	Section 12, T21S, R11W

Roscoe, Susie	EVERLAST ENERGY LLC	2004/27145	August 31, 2004	Section 20, T22S, R12W

Rosenberg, Mary D.	Everlast Energy LLC	2003/21654	June 20, 2003	Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Roulaine, Katherine A.	Everlast Energy LLC	2004/4955	November 16, 2003	Section 11, T21S, R11W

Roulaine, Katherine A.	Everlast Energy LLC	2004/4959	November 16, 2003	Section 11, T21S, R11W

Rowland, Harry Gene, et al and Kathy Keller	Everlast Energy LLC	2003/22954	August 26, 2003	Section 23, T21S, R11W

Rust, Robert J. and wife, Myre L. Rust	Everlast Energy LLC	2004/408	October 26, 2003	Section 12, T21S, R11W

Sanders, Daisy	EVERLAST ENERGY LLC	2004/23368	August 31, 2004	Section 20, T22S, R11W

Sanders, Janice G.	Everlast Energy LLC	2005/1811	July 29, 2004	Section 26, T21S, R12W

Sanders, Willie James	EVERLAST ENERGY LLC	2004/23370	August 31, 2004	Section 20, T22S, R11W

Sartain, Bobbie G.	Everlast Energy LLC	2004/5240	November 22, 2003	Section 4, T21S, R11W

Sartain, Woody Webster	Everlast Energy LLC	2003/21661	September 1, 2003	Sections 5, 6 & 17, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Sealey, Lela B.	EVERLAST ENERGY LLC	2005/1807	August 25, 2004	Section 20, T22S, R11W

Scogin, Ann P.	EVERLAST ENERGY LLC	2004/12296	December 31, 2003	Section 21, T22S, R11W

Scruggs, Hebert E. and wife, Helen Scruggs	Everlast Energy LLC	2003/21663	July 21, 2003	Section 8, T21S, R11W

Sealy, Charlie O. and William C. Wiggins	Everlast Energy LLC	2003/24548	September 8, 2003	Section 33, T20S, R11W

Sealey Andrew and wife, Bertha Seeley	EVERLAST ENERGY LLC	2005/1809	December 12, 2004	Section 13 & 24, T22S, 12W

Sessions, Charles Edward and wife Lannie N. Session	Everlast Energy LLC	2004/4953	November 16, 2003	Section 12, T21S, R11W

Shaw, David A. and wife, Marla S. Shaw	Everlast Energy LLC	2004/12298	November 18, 2003	Section 9, T21S, R11W

Shelton, Annie J. O’Hanlon; Roger Dale O’Hanlon; John Thomas O’Hanlon, et al.	Everlast Energy LLC	2003/21666	August 15, 2003	Section 35, T20S, R12W

Shelton, Annie J., etal.	Everlast Energy LLC	2004/5051	November 18, 2003	Section 2, T21S, R12W

Simpson, Yvonne T.	Everlast Energy LLC	2004/3600	October 1, 2003	Section 1, T21S, R12W

Skelton, Michael Wayne	Everlast Energy LLC	2004/10427	November 14, 2003	Section 12, T21S, R11W

Skelton, Noah S.	Everlast Energy LLC	2003/21488	July 22, 2003	Section 6, T21S, R11W

Skelton, Thomas E. and wife, Anna Laura Skelton	Everlast Energy LLC	2004/3604	November 3, 2003	Section 1, T21S, R12W

Skipper, Evelyn	EVERLAST ENERGY LLC	2004/23372	August 13, 2004	Section 20 & 22, T22S, R11W

Smelley, Jimmie E. and wife, Louise E. Smelley	Everlast Energy LLC	2004/5174	December 5, 2003	Section 12, T21S, R11W

Smelley, Martina	Everlast Energy LLC	2004/5357	December 2, 2003	Section 32, T20S, R11W

Smelley, Samuel	Everlast Energy LLC	2003/24526	August 18, 2003	Sections 20 & 21, T20S, R11W

Smith, Anita Foster	EVERLAST ENERGY LLC	2003/24483	October 4, 2003	Section 24, T22S, R12W

Smith, Barbara J.	EVERLAST ENERGY LLC	2005/1909	November 30, 2004	Sections 21 & 22, T22S, R11W

Smith, Leonard J. and wife, Mary F. Smith	Everlast Energy LLC	2003/24489	September 3, 2003	Section 10, T21S, R11W

Smith, Matthew Sheppard	Everlast Energy LLC	2004/4951	November 2, 2003	Section 19, T21S, R11W

Smith, Smitty, a married man and Billy Charles Smith, an unmarried man	Everlast Energy LLC	2003/24529	September 16, 2003	Section 9, T22S, R12W

Smith, Sylvia N.	Everlast Energy LLC	2004/5003	November 17, 2003	Section 12, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Smith, Vaughn Eugene and wife, Terri Lyn Smith	Everlast Energy LLC	2003/24531	August 18, 2003	Section 20, T20S, R11W

Smith, Vaughn, Brittany Smith & Kevin Lee Tunnell	Everlast Energy LLC	2003/24644	August 18, 2003	Section 20, T20S, R11W

Smith, William Windle and wife, Carolyn J. Smith	Everlast Energy LLC	2004/5691	October 26, 2003	Section 12, T21S, R11W

Snyder, Fred R. and Peggy B.	Everlast Energy LLC	2003/21668	August 4, 2003	Section 3, T21S, R11W

Snyder, Nannie E.	Everlast Energy LLC	2004/12300	November 10, 2003	Section 3, T21S, R11W

Southern, James T. and wife, Brenda Rice Southern	Everlast Energy LLC	2004/3602	October 28, 2003	Section 1, T21S, R12W

Spencer, Peter Warren	Everlast Energy LLC	2004/23374	July 30, 2004	Section 6, T21S, R11W

Spencer, Robert Jason and wife, Lorrie Oliver Spencer	Everlast Energy LLC	2004/4949	October 30, 2003	Section 5, T21S, R11W

Spivey, Robert W.	Everlast Energy LLC	2004/5693	October 6, 2003	Section 11, T21S, R11W

Spurgin, Carl E. and wife, Dianne L. Spurgin	EVERLAST ENERGY LLC	2005/6388	November 11, 2004	Section 13, T22S, R12W

Stallworth, Helen	EVERLAST ENERGY LLC	2004/5696	January 2, 2004	Section 20, T22S, R11W

State of Alabama	Everlast Energy LLC	2005/1777	December 6, 2004	Section 25, 26, 33, 34 & 35, T21S, R11W & Sections 3, 15 & 23, T22S, R11W

Stell, Laura Cubelle Booth	Everlast Energy LLC	2005/1755	June 30, 2004	Section 34, T 21S, R12W

Stipe, Sara Hall and husband, Roy F. Stipe	Everlast Energy LLC	2003/21670	August 5, 2003	Section 2, T21S, R12W

Stipe, Thomas Hall, Trustee	Everlast Energy LLC	2003/21673	August 5, 2003	Section 2, T21S, R12W

Stokes, Stacey A. and wife Ramona W. Stokes	Everlast Energy LLC	2003/24534	September 3, 2003	Sections 16 & 17, T21S, R11W

Strickland, Jo Frances Harper and Melody Gay Harper Motes	Everlast Energy LLC	2004/5053	October 1, 2003	Section 26, T21S, R11W

Strickland, Charles D. and wife, Elizabeth A. Strickland	Everlast Energy LLC	2004/406	October 28, 2003	Section 12, T21S, R11W

Strickland, Cletis T. and wife, Bettye H. Strickland	Everlast Energy LLC	2004/403	September 24, 2003	Section 10, T21S, R11W

Strickland, Jason W.	Everlast Energy LLC	2004/3607	October 28, 2003	Section 12, T21S, R11W

Strickland, Julie Nelson	Everlast Energy LLC	2003/21679	September 12, 2003	Section 28, T20S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Strickland, Oliver and wife, Bland Strickland	Everlast Energy LLC	2004/5030	November 1, 2003	Section 9, T21S, R11W

Stripling, J.B. and wife Maudine Stripling	Everlast Energy LLC	2004/12302	November 13, 2003	Section 33, T20S, R11W

Styres, Voncille Gregory	EVERLAST ENERGY LLC	2004/28176	September 21, 2004	Sections 23, 26 & 27, T22S, R12W

Sudduth, Robert W. and wife, Betty J. Sudduth	Everlast Energy LLC	2004/5235	December 2, 2003	Section 12, T21S, R11W; Section 7, T21S, R10W

Sullivan, Robert W. and wife, Brenda Diane Sullivan	Everlast Energy LLC	2004/5166	November 16, 2003	Section 4, T21S, R11W

Sullivan, W.G.	Everlast Energy LLC	2003/21681	August 25, 2003	Sections 10 & 11, T21S, R12W

Sundberg, Amelia	Everlast Energy LLC	2004/5698	December 30, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Sutton, Malinda F.	Everlast Energy LLC	2004/3540	October 23, 2003	Section 12, T21S, R11W

Taylor, David E. and wife, Veronica A. Taylor	Everlast Energy LLC	2003/21676	August 13, 2003	Section 20, T20S, R11W

Taylor, David E. and wife, Veronica Anne Taylor	Everlast Energy LLC	2003/22883	August 18, 2003	Section 20, T20S, R11W

Taylor, Lucille, Individually and as Administratrix of the Estate of Elbert Taylor	Everlast Energy LLC	2003/22962	August 26, 2003	Section 3, T21S, R11W

Texas Gulf Bank as Escrow Agent for David Dewitt Jones	Everlast Energy LLC	2004/147/58	June 10, 2004	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

The Rice Martial Trust	Everlast Energy LLC	2004/4984	October 27, 2003	Section 28, T20S, R11W

Thompson, Charles Willard	Everlast Energy LLC	2003/22886	August 21, 2003	Sections 27 & 34, T20S, R11W

Thompson, James E.	Everlast Energy LLC	2003/21683	August 21, 2003	Sections 27 & 34, T20S, R11W

Thompson, Joe Banks	Everlast Energy LLC	2003/21686	August 21, 2003	Sections 27 & 34, T20S, R11W

Thompson, John R., Jr.	Everlast Energy LLC	2003/22889	August 21, 2003	Sections 27 & 34, T20S, R11W

Thompson, M.E., Jr.	Everlast Energy LLC	2003/21692	August 21, 2003	Sections 27 & 34, T20S, R11W

Thompson, Robert C., Jr.	Everlast Energy LLC	2003/21689	August 21, 2003	Sections 27 & 34, T20S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Thompson, Scott Arthur	Everlast Energy LLC	2003/22894	August 21, 2003	Sections 27 & 34, T20S, R11W

Thrasher, Boyd W.	Everlast Energy LLC	2004/12304	November 4, 2003	Section 12, T21S, R11W

Thrasher, Marline E. Estate	Everlast Energy LLC	2004/12284	October 30, 2003	Section 12, T21S, R11W

Tidwell, Susan Smelley	Everlast Energy LLC	2004/400	August 18, 2003	Section 20, T20S, R11W

Tilley, Mabel W.	Everlast Energy LLC	2004/5000	November 7, 2003	Section 4, T21S, R11W

Tooson, Marie	EVERLAST ENERGY LLC	2005/1974	January 7, 2005	Section 30, T21S, R11W

Tooson, Marie Washington	EVERLAST ENERGY LLC	2005/1891	September 17, 2004	Section 26, T22S, R12W

Tormin, Inc	Everlast Energy LLC	2003/21494	August 5, 2003	Section 23, T21S, R11W

Townsend, Howard Ray	Everlast Energy LLC	2004/4947	October 6, 2003	Section 11, T21S, R11W

Tubbs, Herbert O. and wife Mattie M. Tubbs	Everlast Energy LLC	2003/24537	September 25, 2003	Section 17, T21S, R11W

Tucker, Wilburn E. and wife, Nellie P. Tucker	Everlast Energy LLC	2004/5176	November 19, 2003	Section 32, T20S, R11W

Turner, Ruth T.	Everlast Energy LLC	2003/21695	August 19, 2003	Sections 27 & 34, T20S, R11W

Tuscaloosa County Board of Education	Everlast Energy LLC	2004/5718	October 24, 2003	Section 4, T21S, R11W

Tuscaloosa County Board of Education	Everlast Energy LLC	2004/5705	November 19, 2003	Section 33, T22S, R11W

Tuscaloosa County Board of Education	EVERLAST ENERGY LLC	2004/5702	November 19, 2003	Section 2, T21S, R12W

Tuscaloosa County Board of Education	EVERLAST ENERGY LLC	2004/5619	November 1, 2003	Section 12, T22S, R11W

Tuscaloosa County Board of Education	Everlast Energy LLC	2004/28179	August 23, 2004	Section 13, T22S, R12W

Tuscaloosa County, Alabama	Everlast Energy LLC	2004/5347	December 3, 2003	Section 16, T21S, R11W; Section 1, T21S, R12W

Valentyn, Clarence J.	Everlast Energy LLC	2004/5035	September 24, 2003	Section 10, T21S, R11W

Vargo, Allen Wayne and wife, Lynette W. Vargo	Everlast Energy LLC	2004/5331	October 28, 2003	Section 12, T21S, R11W

Vaughn, Addie	Everlast Energy LLC	2004/3609	September 17, 2003	Section 1, T21S, R12W

Vines, Carole Ann	EVERLAST ENERGY LLC	2004/23284	August 13, 2004	Section 21, T22S, R11W

Vines, Carole Ann and Stephanie Ann Vines	EVERLAST ENERGY LLC	2005/1775	October 19, 2004	Section 27, T22S, R11W

Vining, William Gerald	Everlast Energy LLC	2004/4945	September 1, 2003	Section 4, T21S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE
Walker, Barbara D., Trustee	Everlast Energy LLC	2004/23379	July 2, 2004	Section 6, T21S, R11W

Walker, Lois Dean Booth	Everlast Energy LLC	2005/1766	July 5, 2004	Section 34, T21S, R12W

Wallace, Gordon W.	Everlast Energy LLC	2003/24540	September 28, 2003	Section 20, T21S, R11W

Wallace, Jerry and wife, Betty Joyce Wallace	Everlast Energy LLC	2004/4943	November 16, 2003	Section 6, T21S, R11W

Walters, Kenneth F. and wife, Judy G. Walters	Everlast Energy LLC	2004/5018	September 24, 2003	Section 10, T21S, R11W

Walton, Evelyn Foster, a married woman	EVERLAST ENERGY LLC	2003/24492	October 4, 2003	Section 24, T22S, R12W

Washington, Jim Henry	EVERLAST ENERGY LLC	2004/5708	December 8, 2003	Section 20, T22S, R11W

Washington, Mary	EVERLAST ENERGY LLC	2005/1889	September 29, 2004	Section 26, T22S, R12W

Washington, Pierce, Jr.	EVERLAST ENERGY LLC	2004/27150	August 17, 2004	Sections 24, 25 & 27, T22S, R12W

Washington, Pierce, Jr.	EVERLAST ENERGY LLC	2004/27147	August 17, 2004	Section 26, T22S, R12W

Washington, Pierce, Jr.	EVERLAST ENERGY LLC	2005/763	January 6, 2005	Section 30, T22S, R11W

Washington, Rhonda R.	EVERLAST ENERGY LLC	2004/28182	October 25, 2004	Section 26, T22S, R12W

Washington, Timothy	EVERLAST ENERGY LLC	2004/28185	October 25, 2004	Section 26, T22S, R12W

Washington, Valerie	EVERLAST ENERGY LLC	2004/28188	October 25, 2004	Section 26, T22S, R12W

Wasileski, Doris P.	Everlast Energy LLC	2004/5710	December 9, 2003	Sections 4 & 9, T21S, R11W

Weatherspoon, Jerome	EVERLAST ENERGY LLC	2004/5005	October 13, 2003	Section 24, T22S, R12W

Weatherspoon, Willie James	EVERLAST ENERGY LLC	2004/452	October 4, 2003	Section 24, T22S, R12W

Webb, Katie M.	Everlast Energy LLC	2003/21698	June 26, 2003	Sections 10 & 11, T21S, R11W

Webster, Timothy Matthew and wife, Tracey Lachelle Webster	Everlast Energy LLC	2004/398	October 18, 2003	Section 4, T21S, R11W

Webster, Vista M. & Carl D. Hall	Everlast Energy LLC	2004/5354	November 25, 2003	Section 34, T20S, R11W

Wedgeworth, Ruth G.	Everlast Energy LLC	2004/27167	August 26, 2004	Section 20, T20S, R11W

Wedgworth, Tonya Lynn and husband Zachary Wedgeworth	Everlast Energy LLC	2004/5021	November 12, 2003	Section 1, T21S, R12W

Wentling, Ann Houston	Everlast Energy LLC	2003/21491	August 5, 2003	Sections 19 & 20, T20S, R11W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE

Wesley West Minerals, Ltd.	Everlast Energy LLC	2004/395	November 18, 2003	Sections 19, 21 & 31, T20S, R11W; Section 35, T20S, R12W; Section 17, T 21S, R11W; Sections 21, 27, 33 & 35, T21S, R12W

West, Barbara Ann Mason and husband, Jimmie West	Everlast Energy LLC	2003/24542	September 3, 2003	Section 10, T21S, R11W

Westside Bible Chapel of Northport, Alabama	Everlast Energy LLC	2004/12276	November 6, 2003	Section 12, T21S, R11W

Weyerhaeuser Company	Everlast Energy LLC	2003/21701	June 20, 2003	Sections 19 & 30, T20S, R 11W; Sections 1, 2, 3 10 & 15, T21S, R12W; Section 32, T22S, R11W

Wheat, Glyndon	Everlast Energy LLC	2003/24545	August 16, 2003	Section 34, T21S, R12W

Wheatley, Katherine Booth	Everlast Energy LLC	2004/5364	October 26, 2003	Section 12, T21S, R11W

Wheatley, Terry Glenn and wife, Debra Lynn Wheatley	Everlast Energy LLC	2004/5328	October 27, 2003	Section 12, T21S, R11W

White, Annie L.	EVERLAST ENERGY LLC	2005/759	January 6, 2005	Section 13, T22S, R12W

White Oak Investments, Ltd.	Everlast Energy LLC	2003/21707	July 9, 2003	Sections 14, 23 & 24, T21S, R12W

Whitehead, Christy L.	Everlast Energy LLC	2004/10417	November 16, 2003	Section 12, T21S, R11W

Whitley, Donald Ray and wife, Mildred L. Whitley	Everlast Energy LLC	2004/4941	November 4, 2003	Section 4, T21S, R11W

Whitely, Kenneth R. and wife, Juanita A. Whitley	Everlast Energy LLC	2004/3611	October 28, 2003	Section 14, T21S, R11W

Wildmon, Cynthia L.	Everlast Energy LLC	2003/22971	August 21, 2003	Sections 27 & 34, T20S, R11W

Wilhite, R. Gene and wife, Judy V. Wilhite	Everlast Energy LLC	2004/5712	November 1, 2003	Section 9, T21S, R11W

Wilkerson, Kenneth Ray and wife, Jayleen T. Wikerson	EVERLAST ENERGY LLC	2004/5028	November 13, 2003	Section 14, T22S, R12W

Williams, A.T.	EVERLAST ENERGY LLC	2004/27157	September 28, 2004	Section 22, T22S, R11W

Williams Kemp	EVERLAST ENERGY LLC	2004/27153	September 28, 2004	Section 22, T22S, R11W

Williams, Louise	EVERLAST ENERGY LLC	2004/23382	September 10, 2004	Section 20, T22S, R11W

Willmon, Jr. Joe and wife, Rhonda Willmon	Everlast Energy LLC	2004/3613	November 4, 2003	Section 1, T21S, R12W


LESSOR’S NAME	LESSEE	RECORDED Deed Book/ Page	DATE OF LEASE	SECTION TOWNSHIP & RANGE

Wilson, Annette	Everlast Energy LLC	2004/23386	July 27, 2004	Section 26, T21S, R12W

Wilson, Carolyn Smith	Everlast Energy LLC	2004/12306	December 30, 2003	Section 12, T21S, R11W

Wilson, Eugenia Davant	Everlast Energy LLC	2004/5324	November 12, 2003	Section 25, T20S, R12W; Sections 5 & 7, T21S, R11W; Section 3, T22S, R12W

Wilson, James et ux, Mary Ruth	Everlast Energy LLC	2003/21711	August 21, 2003	Section 6, T21S, R11W

Wilson, Larry E.	Everlast Energy LLC	2003/21713	August 21, 2003	Section 6, T21S, R11W

Wilson, Raymond O. and wife, Sylvia H. Wilson	Everlast Energy LLC	2004/5714	December 13, 2003	Section 1, T21S, R12W

Wilson, Sr., James D. and wife Betty J. Wilson	Everlast Energy LLC	2004/5025	September 24, 2003	Section 10, T21S, R11W

Windham, Donna K.	EVERLAST ENERGY LLC	2004/10419	January 2, 2004	Section 20, T22S, R11W

Wood, Lois B.	Everlast Energy LLC	2004/23388	July 27, 2004	Section 26, T21S, R12W

Woods, Deborah T.	Everlast Energy LLC	2004/4990	November 16, 2003	Section 12, T21S, R11W

Woods, Jimmy M. and wife, Mary D. Woods	Everlast Energy LLC	2004/4988	September 2, 2003	Section 16, T21S, R11W

Yager, Steven R. and wife, Tammy T. Yager	Everlast Energy LLC	2004/5211	December 2, 2003	Section 32, T20S, R11W

Yager, Tammy T.	Everlast Energy LLC	2004/5352	December 2, 2003	Section 32, T20S, R11W

*EVERLAST ENERGY LLC (Thornton Creek Area)

*Everlast Energy LLC (Robinson’s Bend Area)

Master Agreement and Schedule

Exhibit 10.7

(Multicurrency—Cross Border)

ISDA^®

International Swaps and Derivatives Association, Inc.

MASTER AGREEMENT

dated as of June 16, 2006

THE ROYAL BANK OF SCOTLAND PLC (“PARTY A”) and CONSTELLATION ENERGY RESOURCES LLC (“PARTY B”) have entered and/or anticipate entering into one or more transactions (each a “Transaction”) that are or will be governed by this Master Agreement, which includes the schedule (the “Schedule”), and the documents and other confirming evidence (each a “Confirmation”) exchanged between the parties confirming those Transactions.

Accordingly, the parties agree as follows: –

1.	Interpretation

(a) Definitions. The terms defined in Section 14 and in the Schedule will have the meanings therein specified for the purpose of this Master Agreement.

(b) Inconsistency. In the event of any inconsistency between the provisions of the Schedule and the other provisions of this Master Agreement, the Schedule will prevail. In the event of any inconsistency between the provisions of any Confirmation and this Master Agreement (including the Schedule), such Confirmation will prevail for the purpose of the relevant Transaction.

(c) Single Agreement. All Transactions are entered into in reliance on the fact that this Master Agreement and all Confirmations form a single agreement between the parties (collectively referred to as this “Agreement”), and the parties would not otherwise enter into any Transactions.

2.	Obligations

(a) General Conditions.

(i) Each party will make each payment or delivery specified in each Confirmation to be made by it, subject to the other provisions of this Agreement.

(ii) Payments under this Agreement will be made on the due date for value on that date in the place of the account specified in the relevant Confirmation or otherwise pursuant to this Agreement, in freely transferable funds and in the manner customary for payments in the required currency. Where settlement is by delivery (that is, other than by payment), such delivery will be made for receipt on the due date in the manner customary for the relevant obligation unless otherwise specified in the relevant Confirmation or elsewhere in this Agreement.

(iii) Each obligation of each party under Section 2(a)(i) is subject to (1) the condition precedent that no Event of Default or Potential Event of Default with respect to the other party has occurred and is continuing, (2) the condition precedent that no Early Termination Date in respect of the relevant Transaction has occurred or been effectively designated and (3) each other applicable condition precedent specified in this Agreement.

(b) Change of Account. Either party may change its account for receiving a payment or delivery by giving notice to the other party at least five Local Business Days prior to the scheduled date for the payment or delivery to which such change applies unless such other party gives timely notice of a reasonable objection to such change.

(i)

in the same currency; and

(ii)

in respect of the same Transaction,

by each party to the other, then, on such date, each party’s obligation to make payment of any such amount will be automatically satisfied and discharged and, if the aggregate amount that would otherwise have been payable by one party exceeds the aggregate amount that would otherwise have been payable by the other party, replaced by an obligation upon the party by whom the larger aggregate amount would have been payable to pay to the other party the excess of the larger aggregate amount over the smaller aggregate amount.

The parties may elect in respect of two or more Transactions that a net amount will be determined in respect of all amounts payable on the same date in the same currency in respect of such Transactions, regardless of whether such amounts are payable in respect of the same Transaction. The election may be made in the Schedule or a Confirmation by specifying that subparagraph (ii) above will not apply to the Transactions identified as being subject to the election, together with the starting date (in which case subparagraph (ii) above will not, or will cease to, apply to such Transactions from such date). This election may be made separately for different groups of Transactions and will apply separately to each pairing of Offices through which the parties make and receive payments or deliveries.

(d) Deduction or Withholding for Tax.

(i) Gross-Up. All payments under this Agreement will be made without any deduction or withholding for or on account of any Tax unless such deduction or withholding is required by any applicable law, as modified by the practice of any relevant governmental revenue authority, then in effect. If a party is so required to deduct or withhold, then that party (“X”) will: –

(1) promptly notify the other party (“Y”) of such requirement;

(2) pay to the relevant authorities the full amount required to be deducted or withheld (including the full amount required to be deducted or withheld from any additional amount paid by X to Y under this Section 2(d)) promptly upon the earlier of determining that such deduction or withholding is required or receiving notice that such amount has been assessed against Y;

(3) promptly forward to Y an official receipt (or a certified copy), or other documentation reasonably acceptable to Y, evidencing such payment to such authorities; and

(4) if such Tax is an Indemnifiable Tax, pay to Y, in addition to the payment to which Y is otherwise entitled under this Agreement, such additional amount as is necessary to ensure that the net amount actually received by Y (free and clear of Indemnifiable Taxes, whether assessed against X or Y) will equal the full amount Y would have received had no such deduction or withholding been required. However, X will not be required to pay any additional amount to Y to the extent that it would not be required to be paid but for: –

(A) the failure by Y to comply with or perform any agreement contained in Section 4(a)(i), 4(a)(iii) or 4(d); or

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(B) the failure of a representation made by Y pursuant to Section 3(f) to be accurate and true unless such failure would not have occurred but for (I) any action taken by a taxing authority, or brought in a court of competent jurisdiction, on or after the date on which a Transaction is entered into (regardless of whether such action is taken or brought with respect to a party to this Agreement) or (II) a Change in Tax Law.

(ii) Liability. If: –

(1) X is required by any applicable law, as modified by the practice of any relevant governmental revenue authority, to make any deduction or withholding in respect of which X would not be required to pay an additional amount to Y under Section 2(d)(i)(4);

(2) X does not so deduct or withhold; and

(3) a liability resulting from such Tax is assessed directly against X,

then, except to the extent Y has satisfied or then satisfies the liability resulting from such Tax, Y will promptly pay to X the amount of such liability (including any related liability for interest, but including any related liability for penalties only if Y has failed to comply with or perform any agreement contained in Section 4(a)(i), 4(a)(iii) or 4(d)).

(e) Default Interest; Other Amounts. Prior to the occurrence or effective designation of an Early Termination Date in respect of the relevant Transaction, a party that defaults in the performance of any payment obligation will, to the extent permitted by Law and subject to Section 6(c), be required to pay interest (before as well as after judgment) on the overdue amount to the other party on demand in the same currency as such overdue amount, for the period from (and including) the original due date for payment to (but excluding) the date of actual payment, at the Default Rate. Such interest will be calculated on the basis of daily compounding and the actual number of days elapsed. If, prior to the occurrence or effective designation of an Early Termination Date in respect of the relevant Transaction, a party defaults in the performance of any obligation required to be settled by delivery, it will compensate the other party on demand if and to the extent provided for in the relevant Confirmation or elsewhere in this Agreement.

3.	Representations

Each party represents to the other party (which representations will be deemed to be repeated by each party on each date on which a Transaction is entered into and, in the case of the representations in Section 3(f), at all times until the termination of this Agreement) that: –

(a) Basic Representations.

(i) Status. It is duly organized and validly existing under the laws of the jurisdiction of its organization or incorporation and, if relevant under such laws, in good standing;

(ii) Powers. It has the power to execute this Agreement and any other documentation relating to this Agreement to which it is a party, to deliver this Agreement and any other documentation relating to this Agreement that it is required by this Agreement to deliver and to perform its obligations under this Agreement and any obligations it has under any Credit Support Document to which it is a party and has taken all necessary action to authorize such execution, delivery and performance;

(iii) No Violation or Conflict. Such execution, delivery and performance do not violate or conflict with any law applicable to it, any provision of its constitutional documents, any order

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or judgment of any court or other agency of government applicable to it or any of its assets or any contractual restriction binding on or affecting it or any of its assets;

(iv) Consents. All governmental and other consents that are required to have been obtained by it with respect to this Agreement or any Credit Support Document to which it is a party have been obtained and are in full force and effect and all conditions of any such consents have been complied with; and

(v) Obligations Binding. Its obligations under this Agreement and any Credit Support Document to which it is a party constitute its legal, valid and binding obligations, enforceable in accordance with their respective terms (subject to applicable bankruptcy, reorganization, insolvency, moratorium or similar laws affecting creditors’ rights generally and subject, as to enforceability, to equitable principles of general application (regardless of whether enforcement is sought in a proceeding in equity or at law)).

(b) Absence of Certain Events. No Event of Default or Potential Event of Default or, to its knowledge, Termination Event with respect to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Agreement or any Credit Support Document to which it is a party.

(c) Absence of Litigation. There is not pending or, to its knowledge, threatened against it or any of its Affiliates any action, suit or proceeding at law or in equity or before any court, tribunal, governmental body, agency or official or any arbitrator that is likely to affect the legality, validity or enforceability against it of this Agreement or any Credit Support Document to which it is a party or its ability to perform its obligations under this Agreement or such Credit Support Document.

(d) Accuracy of Specified Information. All applicable information that is furnished in writing by or on behalf of it to the other party and is identified for the purpose of this Section 3(d) in the Schedule is, as of the date of the information, true, accurate and complete in every material respect.

(e) Payer Tax Representation. Each representation specified in the Schedule as being made by it for the purpose of this Section 3(e) is accurate and true.

(f) Payee Tax Representations. Each representation specified in the Schedule as being made by it for the purpose of this Section 3(f) is accurate and true.

4.	Agreements

Each party agrees with the other that, so long as either party has or may have any obligation under this Agreement or under any Credit Support Document to which it is a party: –

(a) Furnish Specified Information. It will deliver to the other party or, in certain cases under subparagraph (iii) below, to such government or taxing authority as the other party reasonably directs: –

(i) any forms, documents or certificates relating to taxation specified in the Schedule or any Confirmation;

(ii) any other documents specified in the Schedule or any Confirmation; and

(iii) upon reasonable demand by such other party, any form or document that may be required or reasonably requested in writing in order to allow such other party or its Credit Support Provider to make a payment under this Agreement or any applicable Credit Support Document without any deduction or withholding for or on account of any Tax or with such deduction or withholding at a reduced rate (so long as the completion, execution or submission of such form or document would not materially prejudice the legal or commercial position of the party in receipt of such demand),

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with any such form or document to be accurate and completed in a manner reasonably satisfactory to such other party and to be executed and to be delivered with any reasonably required certification,

in each case by the date specified in the Schedule or such Confirmation or, if none is specified, as soon as reasonably practicable.

(b) Maintain Authorizations. It will use all reasonable efforts to maintain in full force and effect all consents of any governmental or other authority that are required to be obtained by it with respect to this Agreement or any Credit Support Document to which it is a party and will use all reasonable efforts to obtain any that may become necessary in the future.

(c) Comply with Laws. It will comply in all material respects with all applicable laws and orders to which it may be subject if failure so to comply would materially impair its ability to perform its obligations under this Agreement or any Credit Support Document to which it is a party.

(d) Tax Agreement. It will give notice of any failure of a representation made by it under Section 3(f) to be accurate and true promptly upon learning of such failure.

(e) Payment of Stamp Tax. Subject to Section 11, it will pay any Stamp Tax levied or imposed upon it or in respect of its execution or performance of this Agreement by a jurisdiction in which it is incorporated, organized, managed and controlled, or considered to have its seat, or in which a branch or office through which it is acting for the purpose of this Agreement is located (“Stamp Tax Jurisdiction”) and will indemnify the other party against any Stamp Tax levied or imposed upon the other party or in respect of the other party’s execution or performance of this Agreement by any such Stamp Tax Jurisdiction which is not also a Stamp Tax Jurisdiction with respect to the other party.

5.	Events of Default and Termination Events

(a) Events of Default. The occurrence at any time with respect to a party or, if applicable, any Credit Support Provider of such party or any Specified Entity of such party of any of the following events constitutes an event of default (an “Event of Default”) with respect to such party: –

(i) Failure to Pay or Deliver. Failure by the party to make, when due, any payment under this Agreement or delivery under Section 2(a)(i) or 2(e) required to be made by it if such failure is not remedied on or before the third Local Business Day after notice of such failure is given to the party;

(ii) Breach of Agreement. Failure by the party to comply with or perform any agreement or obligation (other than an obligation to make any payment under this Agreement or delivery under Section 2 (a)(i) or 2(e) or to give notice of a Termination Event or any agreement or obligation under Section 4(a)(i), 4(a)(iii) or 4(d)) to be complied with or performed by the party in accordance with this Agreement if such failure is not remedied on or before the thirtieth day after notice of such failure is given to the party;

(iii) Credit Support Default.

(1) Failure by the party or any Credit Support Provider of such party to comply with or perform any agreement or obligation to be complied with or performed by it in accordance with any Credit Support Document if such failure is continuing after any applicable grace period has elapsed;

(2) the expiration or termination of such Credit Support Document or the failing or ceasing of such Credit Support Document to be in full force and effect for the purpose of this Agreement (in either case other than in accordance with its terms) prior to the satisfaction of all obligations of such party under each Transaction to which such Credit Support Document relates without the written consent of the other party; or

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(3) the party or such Credit Support Provider disaffirms, disclaims, repudiates or rejects, in whole or in part, or challenges the validity of, such Credit Support Document;

(iv) Misrepresentation. A representation (other than a representation under Section 3(e) or (f)) made or repeated or deemed to have been made or repeated by the party or any Credit Support Provider of such party in this Agreement or any Credit Support Document proves to have been incorrect or misleading in any material respect when made or repeated or deemed to have been made or repeated;

(v) Default under Specified Transaction. The party, any Credit Support Provider of such party or any applicable Specified Entity of such party (1) defaults under a Specified Transaction and, after giving effect to any applicable notice requirement or grace period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of, that Specified Transaction, (2) defaults, after giving effect to any applicable notice requirement or grace period, in making any payment or delivery due on the last payment, delivery or exchange date of, or any payment on early termination of, a Specified Transaction (or such default continues for at least three Local Business Days if there is no applicable notice requirement or grace period) or (3) disaffirms, disclaims, repudiates or rejects, in whole or in part, a Specified Transaction (or such action is taken by any person or entity appointed or empowered to operate it or act on its behalf);

(vi) Cross Default. If “Cross Default” is specified in the Schedule as applying to the party, the occurrence or existence of (1) a default, event of default or other similar condition or event (however described) in respect of such party, any Credit Support Provider of such party or any applicable Specified Entity of such party under one or more agreements or instruments relating to Specified Indebtedness of any of them (individually or collectively) in an aggregate amount of not less than the applicable Threshold Amount (as specified in the Schedule) which has resulted in such Specified Indebtedness becoming, or becoming capable at such time of being declared, due and payable under such agreements or instruments before it would otherwise have been due and payable or (2) a default by such party, such Credit Support Provider or such Specified Entity (individually or collectively) in making one or more payments on the due date thereof in an aggregate amount of not less than the applicable Threshold Amount under such agreements or instruments (after giving effect to any applicable notice requirement or grace period);

(vii) Bankruptcy. The party, any Credit Support Provider of such party or any applicable Specified Entity of such party: –

(1) is dissolved (other than pursuant to a consolidation, amalgamation or merger); (2) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due; (3) makes a general assignment, arrangement or composition with or for the benefit of its creditors; (4) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditors’ rights, or a petition is presented for its winding-up or liquidation, and, in the case of any such proceeding or petition instituted or presented against it, such proceeding or petition (A) results in a judgment of insolvency or bankruptcy or the entry of an order for relief or the making of an order for its winding-up or liquidation or (B) is not dismissed, discharged, stayed or restrained in each case within 30 days of the institution or presentation thereof; (5) has a resolution passed for its winding-up, official management or liquidation (other than pursuant to a consolidation, amalgamation or merger); (6) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for it or for all or substantially all its assets; (7) has a secured party take possession of all or substantially all its assets or has a distress, execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or

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substantially all its assets and such secured party maintains possession, or any such process is not dismissed, discharged, stayed or restrained, in each case within 30 days thereafter; (8) causes or is subject to any event with respect to it which, under the applicable laws of any jurisdiction, has an analogous effect to any of the events specified in clauses (1) to (7) (inclusive); or (9) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts; or

(viii) Merger Without Assumption. The party or any Credit Support Provider of such party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer: –

(1) the resulting, surviving or transferee entity fails to assume all the obligations of such party or such Credit Support Provider under this Agreement or any Credit Support Document to which it or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other party to this Agreement; or

(2) the benefits of any Credit Support Document fail to extend (without the consent of the other party) to the performance by such resulting, surviving or transferee entity of its obligations under this Agreement.

(b) Termination Events. The occurrence at any time with respect to a party or, if applicable, any Credit Support Provider of such party or any Specified Entity of such party of any event specified below constitutes an Illegality if the event is specified in (i) below, a Tax Event if the event is specified in (ii) below or a Tax Event Upon Merger if the event is specified in (iii) below, and, if specified to be applicable, a Credit Event Upon Merger if the event is specified pursuant to (iv) below or an Additional Termination Event if the event is specified pursuant to (v) below: –

(i) Illegality. Due to the adoption of, or any change in, any applicable law after the date on which a Transaction is entered into, or due to the promulgation of, or any change in, the interpretation by any court, tribunal or regulatory authority with competent jurisdiction of any applicable law after such date, it becomes unlawful (other than as a result of a breach by the party of Section 4(b)) for such party (which will be the Affected Party): –

(1) to perform any absolute or contingent obligation to make a payment or delivery, or to receive a payment or delivery in respect of such Transaction or to comply with any other material provision of this Agreement relating to such Transaction; or

(2) to perform, or for any Credit Support Provider of such party to perform, any contingent or other obligation which the party (or such Credit Support Provider) has under any Credit Support Document relating to such Transaction.

(ii) Tax Event. Due to (x) any action taken by a taxing authority, or brought in a court of competent jurisdiction, on or after the date on which a Transaction is entered into (regardless of whether such action is taken or brought with respect to a party to this Agreement) or (y) a Change in Tax Law, the party (which will be the Affected Party) will, or there is a substantial likelihood that it will, on the next succeeding Scheduled Payment Date (1) be required to pay to the other party an additional amount in respect of an Indemnifiable Tax under Section 2(d)(i)(4) (except in respect of interest under Section 2(e), 6(d)(ii) or 6(e)) or (2) receive a payment from which an amount is required to be deducted or withheld for or on account of a Tax (except in respect of interest under Section 2(e), 6(d)(ii) or 6(e)) and no additional amount is required to be paid in respect of such Tax under Section 2(d)(i)(4) (other than by reason of Section 2(d)(i)(4)(A) or (B));

(iii) Tax Event Upon Merger. The party (the “Burdened Party”) on the next succeeding Scheduled Payment Date will either (1) be required to pay an additional amount in respect of an Indemnifiable Tax under Section 2(d)(i)(4) (except in respect of interest under Section 2(e), 6(d)(ii) or

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6(e)) or (2) receive a payment from which an amount has been deducted or withheld for or on account of any Indemnifiable Tax in respect of which the other party is not required to pay an additional amount (other than by reason of Section 2(d)(i)(4)(A) or (B)), in either case as a result of a party consolidating or amalgamating with, or merging with or into, or transferring all or substantially all its assets to, another entity (which will be the Affected Party) where such action does not constitute an event described in Section 5(a)(viii);

(iv) Credit Event Upon Merger. If “Credit Event Upon Merger” is specified in the Schedule as applying to the party, such party (“X”), any Credit Support Provider of X or any applicable Specified Entity of X consolidates or amalgamates with, or merges with or into, or transfers all or substantially all its assets to, another entity and such action does not constitute an event described in Section 5(a)(viii) but the creditworthiness of the resulting, surviving or transferee entity is materially weaker than that of X, such Credit Support Provider or such Specified Entity, as the case may be, immediately prior to such action (and, in such event, X or its successor or transferee, as appropriate, will be the Affected Party); or

(v) Additional Termination Event. If any “Additional Termination Event” is specified in the Schedule or any Confirmation as applying, the occurrence of such event (and, in such event, the Affected Party or Affected Parties shall be as specified for such Additional Termination Event in the Schedule or such Confirmation).

(c) Event of Default and Illegality. If an event or circumstance which would otherwise constitute or give rise to an Event of Default also constitutes an Illegality, it will be treated as an Illegality and will not constitute an Event of Default.

6.	Early Termination

(a) Right to Terminate Following Event of Default. If at any time an Event of Default with respect to a party (the “Defaulting Party”) has occurred and is then continuing, the other party (the “Non-defaulting Party”) may, by not more than 20 days notice to the Defaulting Party specifying the relevant Event of Default, designate a day not earlier than the day such notice is effective as an Early Termination Date in respect of all outstanding Transactions. If, however, “Automatic Early Termination” is specified in the Schedule as applying to a party, then an Early Termination Date in respect of all outstanding Transactions will occur immediately upon the occurrence with respect to such party of an Event of Default specified in Section 5(a)(vii)(l), (3), (5), (6) or, to the extent analogous thereto, (8) and as of the time immediately preceding the institution of the relevant proceeding or the presentation of the relevant petition upon the occurrence with respect to such party of an Event of Default specified in Section 5(a)(vii)(4) or, to the extent analogous thereto, (8).

(b) Right to Terminate Following Termination Event.

(i) Notice. If a Termination Event occurs, an Affected Party will, promptly upon becoming aware of it notify the other party, specifying the nature of that Termination Event and each Affected Transaction and will also give such other information about that Termination Event as the other party may reasonably require.

(ii) Transfer to Avoid Termination Event. If either an Illegality under Section 5(b)(i)(1) or a Tax Event occurs and there is only one Affected Party, or if a Tax Event Upon Merger occurs and the Burdened Party is the Affected Party, the Affected Party will, as a condition to its right to designate an Early Termination Date under Section 6(b)(iv), use all reasonable efforts (which will not require such party to incur a loss, excluding immaterial, incidental expenses) to transfer within 20 days after it gives notice under Section 6(b)(i) all its rights and obligations under this Agreement in respect of the Affected Transactions to another of its Offices or Affiliates so that such Termination Event ceases to exist.

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If the Affected Party is not able to make such a transfer it will give notice to the other party to that effect within such 20 day period, whereupon the other party may effect such a transfer within 30 days after the notice is given under Section 6(b)(i).

Any such transfer by a party under this Section 6(b)(ii) will be subject to and conditional upon the prior written consent of the other party, which consent will not be withheld if such other party’s policies in effect at such time would permit it to enter into transactions with the transferee on the terms proposed.

(iii) Two Affected Parties. If an Illegality under Section 5(b)(i)(l) or a Tax Event occurs and there are two Affected Parties, each party will use all reasonable efforts to reach agreement within 30 days after notice thereof is given under Section 6(b)(i) on action to avoid that Termination Event.

(iv) Right to Terminate. If: –

(1) a transfer under Section 6(b)(ii) or an agreement under Section 6(b)(iii), as the case may be, has not been effected with respect to all Affected Transactions within 30 days after an Affected Party gives notice under Section 6(b)(i); or

(2) an Illegality under Section 5(b)(i)(2) a Credit Event Upon Merger or an Additional Termination Event occurs, or a Tax Event Upon Merger occurs and the Burdened Party is not the Affected Party,

either party in the case of an Illegality, the Burdened Party in the case of a Tax Event Upon Merger, any Affected Party in the case of a Tax Event or an Additional Termination Event if there is more than one Affected Party, or the party which is not the Affected Party in the case of a Credit Event Upon Merger or an Additional Termination Event if there is only one Affected Party may, by not more than 20 days notice to the other party and provided that the relevant Termination Event is then continuing, designate a day not earlier than the day such notice is effective as an Early Termination Date in respect of all Affected Transactions.

(i) If notice designating an Early Termination Date is given under Section 6(a) or (b), the Early Termination Date will occur on the date so designated, whether or not the relevant Event of Default or Termination Event is then continuing.

(ii) Upon the occurrence or effective designation of an Early Termination Date, no further payments or deliveries under Section 2(a)(i) or 2(e) in respect of the Terminated Transactions will be required to be made, but without prejudice to the other provisions of this Agreement. The amount, if any, payable in respect of an Early Termination Date shall be determined pursuant to Section 6(e).

(d) Calculations.

(i) Statement. On or as soon as reasonably practicable following the occurrence of an Early Termination Date, each party will make the calculations on its part, if any, contemplated by Section 6(e) and will provide to the other party a statement (1) showing, in reasonable detail, such calculations (including all relevant quotations and specifying any amount payable under Section 6(e)) and (2) giving details of the relevant account to which any amount payable to it is to be paid. In the absence of written confirmation from the source of a quotation obtained in determining a Market Quotation, the records of the party obtaining such quotation will be conclusive evidence of the existence and accuracy of such quotation.

(ii) Payment Date. An amount calculated as being due in respect of any Early Termination Date under Section 6(e) will be payable on the day that notice of the amount payable is effective (in the case of an Early Termination Date which is designated or occurs as a result of an Event of

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Default) and on the day which is two Local Business Days after the day on which notice of the amount payable is effective (in the case of an Early Termination Date which is designated as a result of a Termination Event). Such amount will be paid together with (to the extent permitted under applicable law) interest thereon (before as well as after judgment) in the Termination Currency, from (and including) the relevant Early Termination Date to (but excluding) the date such amount is paid, at the Applicable Rate. Such interest will be calculated on the basis of daily compounding and the actual number of days elapsed.

(e) Payments on Early Termination. If an Early Termination Date occurs, the following provisions shall apply based on the parties’ election in the Schedule of a payment measure, either “Market Quotation” or “Loss,” and a payment method, either the “First Method” or the “Second Method”. If the parties fail to designate a payment measure or payment method in the Schedule, it will be deemed that “Market Quotation” or the “Second Method,” as the case may be, shall apply. The amount, if any, payable in respect of an Early Termination Date and determined pursuant to this Section will be subject to any Set-off.

(i) Events of Default. If the Early Termination Date results from an Event of Default: –

(1) First Method and Market Quotation. If the First Method and Market Quotation apply, the Defaulting Party will pay to the Non-defaulting Party the excess, if a positive number, of (A) the sum of the Settlement Amount (determined by the Non-defaulting Party) in respect of the Terminated Transactions and the Termination Currency Equivalent of the Unpaid Amounts owing to the Non-defaulting Party over (B) the Termination Currency Equivalent of the Unpaid Amounts owing to the Defaulting Party.

(2) First Method and Loss. If the First Method and Loss apply, the Defaulting Party will pay to the Non-defaulting Party, if a positive number, the Non-defaulting Party’s Loss in respect of this Agreement.

(3) Second Method and Market Quotation. If the Second Method and Market Quotation apply, an amount will be payable equal to (A) the sum of the Settlement Amount (determined by the Non-defaulting Party) in respect of the Terminated Transactions and the Termination Currency Equivalent of the Unpaid Amounts owing to the Non-defaulting Party less (B) the Termination Currency Equivalent of the Unpaid Amounts owing to the Defaulting Party. If that amount is a positive number, the Defaulting Party will pay it to the Non-defaulting Party; if it is a negative number, the Non-defaulting Party will pay the absolute value of that amount to the Defaulting Party.

(4) Second Method and Loss. If the Second Method and Loss apply, an amount will be payable equal to the Non-defaulting Party’s Loss in respect of this Agreement. If that amount is a positive number, the Defaulting Party will pay it to the Non-defaulting Party; if it is a negative number, the Non-defaulting Party will pay the absolute value of that amount to the Defaulting Party.

(ii) Termination Events. If the Early Termination Date results from a Termination Event: –

(1) One Affected Party. If there is one Affected Party, the amount payable will be determined in accordance with Section 6(e)(i)(3), if Market Quotation applies, or Section 6(e)(i)(4), if Loss applies, except that, in either case, references to the Defaulting Party and to the Non-defaulting Party will be deemed to be references to the Affected Party and the party which is not the Affected Party, respectively, and, if Loss applies and fewer than all the Transactions are being terminated, Loss shall be calculated in respect of all Terminated Transactions.

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(2) Two Affected Parties. If there are two Affected Parties: –

(A) if Market Quotation applies, each party will determine a Settlement Amount in respect of the Terminated Transactions, and an amount will be payable equal to (I) the sum of (a) one-half of the difference between the Settlement Amount of the party with the higher Settlement Amount (“X”) and the Settlement Amount of the party with the lower Settlement Amount (“Y”) and (b) the Termination Currency Equivalent of the Unpaid Amounts owing to X less (II) the Termination Currency Equivalent of the Unpaid Amounts owing to Y; and

(B) if Loss applies, each party will determine its Loss in respect of this Agreement (or, if fewer than all the Transactions are being terminated, in respect of all Terminated Transactions) and an amount will be payable equal to one-half of the difference between the Loss of the party with the higher Loss (“X”) and the Loss of the party with the lower Loss (“Y”).

If the amount payable is a positive number, Y will pay it to X; if it is a negative number, X will pay the absolute value of that amount to Y.

(iii) Adjustment for Bankruptcy. In circumstances where an Early Termination Date occurs because “Automatic Early Termination” applies in respect of a party, the amount determined under this Section 6(e) will be subject to such adjustments as are appropriate and permitted by law to reflect any payments or deliveries made by one party to the other under this Agreement (and retained by such other party) during the period from the relevant Early Termination Date to the date for payment determined under Section 6(d)(ii).

(iv) Pre-Estimate. The parties agree that if Market Quotation applies an amount recoverable under this Section 6(e) is a reasonable pre-estimate of loss and not a penalty. Such amount is payable for the loss of bargain and the loss of protection against future risks and except as otherwise provided in this Agreement neither party will be entitled to recover any additional damages as a consequence of such losses.

7.	Transfer

Subject to Section 6(b)(ii), neither this Agreement nor any interest or obligation in or under this Agreement may be transferred (whether by way of security or otherwise) by either party without the prior written consent of the other party, except that: –

(a) a party may make such a transfer of this Agreement pursuant to a consolidation or amalgamation with, or merger with or into, or transfer of all or substantially all its assets to, another entity (but without prejudice to any other right or remedy under this Agreement); and

(b) a party may make such a transfer of all or any part of its interest in any amount payable to it from a Defaulting Party under Section 6(e).

Any purported transfer that is not in compliance with this Section will be void.

8.	Contractual Currency

(a) Payment in the Contractual Currency. Each payment under this Agreement will be made in the relevant currency specified in this Agreement for that payment (the “Contractual Currency”). To the extent permitted by applicable law, any obligation to make payments under this Agreement in the Contractual Currency will not be discharged or satisfied by any tender in any currency other than the Contractual Currency, except to the extent such tender results in the actual receipt by the party to which payment is owed, acting in a reasonable manner and in good faith in converting the currency so tendered into the Contractual Currency, of the full amount in the Contractual Currency of all amounts payable in respect of this Agreement. If for any reason the amount in the Contractual Currency so received falls short of the

ISDA^® 1992

amount in the Contractual Currency payable in respect of this Agreement, the party required to make the payment will, to the extent permitted by applicable law, immediately pay such additional amount in the Contractual Currency as may be necessary to compensate for the shortfall. If for any reason the amount in the Contractual Currency so received exceeds the amount in the Contractual Currency payable in respect of this Agreement, the party receiving the payment will refund promptly the amount of such excess.

(b) Judgments. To the extent permitted by applicable law, if any judgment or order expressed in a currency other than the Contractual Currency is rendered (i) for the payment of any amount owing in respect of this Agreement, (ii) for the payment of any amount relating to any early termination in respect of this Agreement or (iii) in respect of a judgment or order of another court for the payment of any amount described in (i) or (ii) above, the party seeking recovery, after recovery in full of the aggregate amount to which such party is entitled pursuant to the judgment or order, will be entitled to receive immediately from the other party the amount of any shortfall of the Contractual Currency received by such party as a consequence of sums paid in such other currency and will refund promptly to the other party any excess of the Contractual Currency received by such party as a consequence of sums paid in such other currency if such shortfall or such excess arises or results from any variation between the rate of exchange at which the Contractual Currency is converted into the currency of the judgment or order for the purposes of such judgment or order and the rate of exchange at which such party is able, acting in a reasonable manner and in good faith in converting the currency received into the Contractual Currency, to purchase the Contractual Currency with the amount of the currency of the judgment or order actually received by such party. The term “rate of exchange” includes, without limitation, any premiums and costs of exchange payable in connection with the purchase of or conversion into the Contractual Currency.

(c) Separate Indemnities. To the extent permitted by applicable law, these indemnities constitute separate and independent obligations from the other obligations in this Agreement, will be enforceable as separate and independent causes of action, will apply notwithstanding any indulgence granted by the party to which any payment is owed and will not be affected by judgment being obtained or claim or proof being made for any other sums payable in respect of this Agreement.

(d) Evidence of Loss. For the purpose of this Section 8, it will be sufficient for a party to demonstrate that it would have suffered a loss had an actual exchange or purchase been made.

9.	Miscellaneous

(a) Entire Agreement. This Agreement constitutes the entire agreement and understanding of the parties with respect to its subject matter and supersedes all oral communication and prior writings with respect thereto.

(b) Amendments. No amendment, modification or waiver in respect of this Agreement will be effective unless in writing (including a writing evidenced by a facsimile transmission) and executed by each of the parties or confirmed by an exchange of telexes or electronic messages on an electronic messaging system.

(c) Survival of Obligations. Without prejudice to Sections 2(a)(iii) and 6(c)(ii), the obligations of the parties under this Agreement will survive the termination of any Transaction.

(d) Remedies Cumulative. Except as provided in this Agreement, the rights, powers, remedies and privileges provided in this Agreement are cumulative and not exclusive of any rights, powers, remedies and privileges provided by law.

(e) Counterparts and Confirmations.

(i) This Agreement (and each amendment, modification and waiver in respect of it) may be executed and delivered in counterparts (including by facsimile transmission), each of which will be deemed an original.

ISDA^® 1992

(ii) The parties intend that they are legally bound by the terms of each Transaction from the moment they agree to those terms (whether orally or otherwise). A Confirmation shall be entered into as soon as practicable and may be executed and delivered in counterparts (including by facsimile transmission) or be created by an exchange of telexes or by an exchange of electronic messages on an electronic messaging system, which in each case will be sufficient for all purposes to evidence a binding supplement to this Agreement. The parties will specify therein or through another effective means that any such counterpart, telex or electronic message constitutes a Confirmation.

(f) No Waiver of Rights. A failure or delay in exercising any right, power or privilege in respect of this Agreement will not be presumed to operate as a waiver, and a single or partial exercise of any right, power or privilege will not be presumed to preclude any subsequent or further exercise, of that right, power or privilege or the exercise of any other right, power or privilege.

(g) Headings. The headings used in this Agreement are for convenience of reference only and are not to affect the construction of or to be taken into consideration in interpreting this Agreement.

10.	Offices; Multibranch Parties

(a) If Section 10(a) is specified in the Schedule as applying, each party that enters into a Transaction through an Office other than its head or home office represents to the other party that, notwithstanding the place of booking office or jurisdiction of incorporation or organization of such party, the obligations of such party are the same as if it had entered into the Transaction through its head or home office. This representation will be deemed to be repeated by such party on each date on which a Transaction is entered into.

(b) Neither party may change the Office through which it makes and receives payments or deliveries for the purpose of a Transaction without the prior written consent of the other party.

(c) If a party is specified as a Multibranch Party in the Schedule, such Multibranch Party may make and receive payments or deliveries under any Transaction through any Office listed in the Schedule, and the Office through which it makes and receives payments or deliveries with respect to a Transaction will be specified in the relevant Confirmation.

11.	Expenses

A Defaulting Party will, on demand, indemnify and hold harmless the other party for and against all reasonable out-of-pocket expenses, including legal fees and Stamp Tax, incurred by such other party by reason of the enforcement and protection of its rights under this Agreement or any Credit Support Document to which the Defaulting Party is a party or by reason of the early termination of any Transaction, including, but not limited to, costs of collection.

12.	Notices

(a) Effectiveness. Any notice or other communication in respect of this Agreement may be given in any manner set forth below (except that a notice or other communication under Section 5 or 6 may not be given by facsimile transmission or electronic messaging system) to the address or number or in accordance with the electronic messaging system details provided (see the Schedule) and will be deemed effective as indicated: –

(i) if in writing and delivered in person or by courier, on the date it is delivered;

(ii) if sent by telex, on the date the recipient’s answerback is received;

(iii) if sent by facsimile transmission, on the date that transmission is received by a responsible

ISDA^® 1992

employee of the recipient in legible form (it being agreed that the burden of proving receipt will be on the sender and will not be met by a transmission report generated by the sender’s facsimile machine);

(iv) if sent by certified or registered mail (airmail, if overseas) or the equivalent (return receipt requested), on the date that mail is delivered or its delivery is attempted; or

(v) if sent by electronic messaging system, on the date that electronic message is received,

unless the date of that delivery (or attempted delivery) or that receipt, as applicable, is not a Local Business Day or that communication is delivered (or attempted) or received, as applicable, after the close of business on a Local Business Day, in which case that communication shall be deemed given and effective on the first following day that is a Local Business Day.

(b) Change of Addresses. Either party may by notice to the other change the address, telex or facsimile number or electronic messaging system details at which notices or other communications are to be given to it.

13.	Governing Law and Jurisdiction

(a) Governing Law. This Agreement will be governed by and construed in accordance with the law specified in the Schedule.

(b) Jurisdiction. With respect to any suit, action or proceedings relating to this Agreement (“Proceedings”), each party irrevocably: –

(i) submits to the jurisdiction of the English courts, if this Agreement is expressed to be governed by English law, or to the non-exclusive jurisdiction of the courts of the State of New York and the United States District Court located in the Borough of Manhattan in New York City, if this Agreement is expressed to be governed by the laws of the State of New York; and

(ii) waives any objection which it may have at any time to the laying of venue of any Proceedings brought in any such court, waives any claim that such Proceedings have been brought in an inconvenient forum and further waives the right to object, with respect to such Proceedings, that such court does not have any jurisdiction over such party.

Nothing in this Agreement precludes either party from bringing Proceedings in any other jurisdiction (outside, if this Agreement is expressed to be governed by English law, the Contracting States, as defined in Section 1(3) of the Civil Jurisdiction and Judgments Act 1982 or any modification, extension or re-enactment thereof for the time being in force) nor will the bringing of Proceedings in any one or more jurisdictions preclude the bringing of Proceedings in any other jurisdiction.

(c) Service of Process. Each party irrevocably appoints the Process Agent (if any) specified opposite its name in the Schedule to receive, for it and on its behalf, service of process in any Proceedings. If for any reason any party’s Process Agent is unable to act as such, such party will promptly notify the other party and within 30 days appoint a substitute process agent acceptable to the other party. The parties irrevocably consent to service of process given in the manner provided for notices in Section 12. Nothing in this Agreement will affect the right of either party to serve process in any other manner permitted by law.

(d) Waiver of Immunities. Each party irrevocably waives, to the fullest extent permitted by applicable law, with respect to itself and its revenues and assets (irrespective of their use or intended use), all immunity on the grounds of sovereignty or other similar grounds from (i) suit, (ii) jurisdiction of any court, (iii) relief by way of injunction, order for specific performance or for recovery of property, (iv) attachment of its assets (whether before or after judgment) and (v) execution or enforcement of any judgment to which it or its revenues or assets might otherwise be entitled in any Proceedings in the courts of any jurisdiction and irrevocably agrees, to the extent permitted by applicable law, that it will not claim any such immunity in any Proceedings.

ISDA^® 1992

14.	Definitions

As used in this Agreement: –

“Additional Termination Event” has the meaning specified in Section 5(b).

“Affected Party” has the meaning specified in Section 5(b).

“Affected Transactions” means (a) with respect to any Termination Event consisting of an Illegality, Tax Event or Tax Event Upon Merger, all Transactions affected by the occurrence of such Termination Event and (b) with respect to any other Termination Event, all Transactions.

“Affiliate” means, subject to the Schedule, in relation to any person, any entity controlled, directly or indirectly, by the person, any entity that controls, directly or indirectly, the person or any entity directly or indirectly under common control with the person. For this purpose, “control” of any entity or person means ownership of a majority of the voting power of the entity or person.

“Applicable Rate” means: –

(a) in respect of obligations payable or deliverable (or which would have been but for Section 2(a)(iii)) by a Defaulting Party, the Default Rate;

(b) in respect of an obligation to pay an amount under Section 6(e) of either party from and after the date (determined in accordance with Section 6(d)(ii)) on which that amount is payable, the Default Rate;

(c) in respect of all other obligations payable or deliverable (or which would have been but for Section 2(a)(iii)) by a Non-defaulting Party, the Non-default Rate; and

(d) in all other cases, the Termination Rate.

“Burdened Party” has the meaning specified in Section 5(b).

“Change in Tax Law” means the enactment, promulgation, execution or ratification of, or any change in or amendment to, any law (or in the application or official interpretation of any law) that occurs on or after the date on which the relevant Transaction is entered into.

“consent” includes a consent, approval, action, authorization, exemption, notice, filing, registration or exchange control consent.

“Credit Event Upon Merger” has the meaning specified in Section 5(b).

“Credit Support Document” means any agreement or instrument that is specified as such in this Agreement.

“Credit Support Provider” has the meaning specified in the Schedule.

“Default Rate” means a rate per annum equal to the cost (without proof or evidence of any actual cost) to the relevant payee (as certified by it) if it were to fund or of funding the relevant amount plus 1% per annum.

“Defaulting Party” has the meaning specified in Section 6(a).

“Early Termination Date” means the date determined in accordance with Section 6(a) or 6(b)(iv).

“Event of Default” has the meaning specified in Section 5(a) and, if applicable, in the Schedule.

ISDA^® 1992

“Illegality” has the meaning specified in Section 5(b).

“Indemnifiable Tax” means any Tax other than a Tax that would not be imposed in respect of a payment under this Agreement but for a present or former connection between the jurisdiction of the government or taxation authority imposing such Tax and the recipient of such payment or a person related to such recipient (including, without limitation, a connection arising from such recipient or related person being or having been a citizen or resident of such jurisdiction, or being or having been organized, present or engaged in a trade or business in such jurisdiction, or having or having had a permanent establishment or fixed place of business in such jurisdiction, but excluding a connection arising solely from such recipient or related person having executed, delivered, performed its obligations or received a payment under, or enforced, this Agreement or a Credit Support Document).

“law” includes any treaty, law, rule or regulation (as modified, in the case of tax matters, by the practice of any relevant governmental revenue authority) and “lawful” and “unlawful” will be construed accordingly.

“Local Business Day” means, subject to the Schedule, a day on which commercial banks are open for business (including dealings in foreign exchange and foreign currency deposits) (a) in relation to any obligation under Section 2(a)(i), in the place(s) specified in the relevant Confirmation or, if not so specified, as otherwise agreed by the parties in writing or determined pursuant to provisions contained, or incorporated by reference, in this Agreement, (b) in relation to any other payment, in the place where the relevant account is located and, if different, in the principal financial centre, if any, of the currency of such payment, (c) in relation to any notice or other communication, including notice contemplated under Section 5(a)(i), in the city specified in the address for notice provided by the recipient and, in the case of a notice contemplated by Section 2(b), in the place where the relevant new account is to be located and (d) in relation to Section 5(a)(v)(2), in the relevant locations for performance with respect to such Specified Transaction.

“Loss” means, with respect to this Agreement or one or more Terminated Transactions, as the case may be, and a party, the Termination Currency Equivalent of an amount that party reasonably determines in good faith to be its total losses and costs (or gain, in which case expressed as a negative number) in connection with this Agreement or that Terminated Transaction or group of Terminated Transactions, as the case may be, including any loss of bargain, cost of funding or, at the election of such party but without duplication, loss or cost incurred as a result of its terminating, liquidating, obtaining or reestablishing any hedge or related trading position (or any gain resulting from any of them). Loss includes losses and costs (or gains) in respect of any payment or delivery required to have been made (assuming satisfaction of each applicable condition precedent) on or before the relevant Early Termination Date and not made, except, so as to avoid duplication, if Section 6(e)(i)(1) or (3) or 6(e)(ii)(2)(A) applies. Loss does not include a party’s legal fees and out-of-pocket expenses referred to under Section 11. A party will determine its Loss as of the relevant Early Termination Date, or, if that is not reasonably practicable, as of the earliest date thereafter as is reasonably practicable. A party may (but need not) determine its Loss by reference to quotations of relevant rates or prices from one or more leading dealers in the relevant markets.

“Market Quotation” means, with respect to one or more Terminated Transactions and a party making the determination, an amount determined on the basis of quotations from Reference Market-makers. Each quotation will be for an amount, if any, that would be paid to such party (expressed as a negative number) or by such party (expressed as a positive number) in consideration of an agreement between such party (taking into account any existing Credit Support Document with respect to the obligations of such party) and the quoting Reference Market-maker to enter into a transaction (the “Replacement Transaction”) that would have the effect of preserving for such party the economic equivalent of any payment or delivery (whether the underlying obligation was absolute or contingent and assuming the satisfaction of each applicable condition precedent) by the parties under Section 2(a)(i) in respect of such Terminated Transaction or group of Terminated Transactions that would, but for the occurrence of the relevant Early Termination Date, have been required after that date. For this purpose, Unpaid Amounts in respect of the Terminated Transaction or group of Terminated Transactions are to be excluded but, without limitation, any payment or delivery that would, but for the relevant Early Termination Date, have been required (assuming satisfaction of each applicable condition precedent) after that Early Termination Date is to be included. The Replacement Transaction would be subject to such documentation as such party and the Reference Market-maker may, in good faith, agree. The party making the determination (or its agent) will request each

Reference Market-maker to provide its quotation to the extent reasonably practicable as of the same day and time (without regard to different time zones) on or as soon as reasonably practicable after the relevant Early Termination Date. The day and time as of which those quotations are to be obtained will be selected in good faith by the party obliged to make a determination under Section 6(e), and, if each party is so obliged, after consultation with the other. If more than three quotations are provided, the Market Quotation will be the arithmetic mean of the quotations, without regard to the quotations having the highest and lowest values. If exactly three such quotations are provided, the Market Quotation will be the quotation remaining after disregarding the highest and lowest quotations. For this purpose, if more than one quotation has the same highest value or lowest value, then one of such quotations shall be disregarded. If fewer than three quotations are provided, it will be deemed that the Market Quotation in respect of such Terminated Transaction or group of Terminated Transactions cannot be determined.

“Non-default Rate” means a rate per annum equal to the cost (without proof or evidence of any actual cost) to the Non-defaulting Party (as certified by it) if it were to fund the relevant amount.

“Non-defaulting Party” has the meaning specified in Section 6(a).

“Office” means a branch or office of a party, which may be such party’s head or home office.

“Potential Event of Default” means any event which, with the giving of notice or the lapse of time or both, would constitute an Event of Default.

“Reference Market-makers” means four leading dealers in the relevant market selected by the party determining a Market Quotation in good faith (a) from among dealers of the highest credit standing which satisfy all the criteria that such party applies generally at the time in deciding whether to offer or to make an extension of credit and (b) to the extent practicable, from among such dealers having an office in the same city.

“Relevant Jurisdiction” means, with respect to a party, the jurisdictions (a) in which the party is incorporated, organized, managed and controlled or considered to have its seat, (b) where an Office through which the party is acting for purposes of this Agreement is located, (c) in which the party executes this Agreement and (d) in relation to any payment, from or through which such payment is made.

“Scheduled Payment Date” means a date on which a payment or delivery is to be made under Section 2(a)(i) with respect to a Transaction.

“Set-off” means set-off, offset, combination of accounts, right of retention or withholding or similar right or requirement to which the payer of an amount under Section 6 is entitled or subject (whether arising under this Agreement, another contract, applicable law or otherwise) that is exercised by, or imposed on, such payer.

“Settlement Amount” means, with respect to a party and any Early Termination Date, the sum of: –

(a) the Termination Currency Equivalent of the Market Quotations (whether positive or negative) for each Terminated Transaction or group of Terminated Transactions for which a Market Quotation is determined; and

(b) such party’s Loss (whether positive or negative and without reference to any Unpaid Amounts) for each Terminated Transaction or group of Terminated Transactions for which a Market Quotation cannot be determined or would not (in the reasonable belief of the party making the determination) produce a commercially reasonable result.

ISDA^® 1992

“Specified Entity” has the meaning specified in the Schedule.

“Specified Indebtedness” means, subject to the Schedule, any obligation (whether present or future, contingent or otherwise, as principal or surety or otherwise) in respect of borrowed money.

“Specified Transaction” means, subject to the Schedule, (a) any transaction (including an agreement with respect thereto) now existing or hereafter entered into between one party to this Agreement (or any Credit Support Provider of such party or any applicable Specified Entity of such party) and the other party to this Agreement (or any Credit Support Provider of such other party or any applicable Specified Entity of such other party) which is a rate swap transaction, basis swap, forward rate transaction, commodity swap, commodity option, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, currency swap transaction, cross-currency rate swap transaction, currency option or any other similar transaction (including any option with respect to any of these transactions), (b) any combination of these transactions and (c) any other transaction identified as a Specified Transaction in this Agreement or the relevant confirmation.

“Stamp Tax” means any stamp, registration, documentation or similar tax.

“Tax” means any present or future tax, levy, impost, duty, charge, assessment or fee of any nature (including interest, penalties and additions thereto) that is imposed by any government or other taxing authority in respect of any payment under this Agreement other than a stamp, registration, documentation or similar tax.

“Tax Event” has the meaning specified in Section 5(b).

“Tax Event Upon Merger” has the meaning specified in Section 5(b).

“Terminated Transactions” means with respect to any Early Termination Date (a) if resulting from a Termination Event, all Affected Transactions and (b) if resulting from an Event of Default, all Transactions (in either case) in effect immediately before the effectiveness of the notice designating that Early Termination Date (or, if “Automatic Early Termination” applies, immediately before that Early Termination Date).

“Termination Currency” has the meaning specified in the Schedule.

“Termination Currency Equivalent” means, in respect of any amount denominated in the Termination Currency, such Termination Currency amount and, in respect of any amount denominated in a currency other than the Termination Currency (the “Other Currency”), the amount in the Termination Currency determined by the party making the relevant determination as being required to purchase such amount of such Other Currency as at the relevant Early Termination Date, or, if the relevant Market Quotation or Loss (as the case may be), is determined as of a later date, that later date, with the Termination Currency at the rate equal to the spot exchange rate of the foreign exchange agent (selected as provided below) for the purchase of such Other Currency with the Termination Currency at or about 11:00 a.m. (in the city in which such foreign exchange agent is located) on such date as would be customary for the determination of such a rate for the purchase of such Other Currency for value on the relevant Early Termination Date or that later date. The foreign exchange agent will, if only one party is obliged to make a determination under Section 6(e), be selected in good faith by that party and otherwise will be agreed by the parties.

“Termination Event” means an Illegality, a Tax Event or a Tax Event Upon Merger or, if specified to be applicable, a Credit Event Upon Merger or an Additional Termination Event.

“Termination Rate” means a rate per annum equal to the arithmetic mean of the cost (without proof or evidence of any actual cost) to each party (as certified by such party) if it were to fund or of funding such amounts.

“Unpaid Amounts” owing to any party means, with respect to an Early Termination Date, the aggregate of (a) in respect of all Terminated Transactions, the amounts that became payable (or that would have become

ISDA^® 1992

payable but for Section 2(a)(iii)) to such party under Section 2(a)(i) on or prior to such Early Termination Date and which remain unpaid as at such Early Termination Date and (b) in respect of each Terminated Transaction, for each obligation under Section 2(a)(i) which was (or would have been but for Section 2(a)(iii)) required to be settled by delivery to such party on or prior to such Early Termination Date and which has not been so settled as at such Early Termination Date, an amount equal to the fair market value of that which was (or would have been) required to be delivered as of the originally scheduled date for delivery, in each case together with (to the extent permitted under applicable law) interest, in the currency of such amounts, from (and including) the date such amounts or obligations were or would have been required to have been paid or performed to (but excluding) such Early Termination Date, at the Applicable Rate. Such amounts of interest will be calculated on the basis of daily compounding and the actual number of days elapsed. The fair market value of any obligation referred to in clause (b) above shall be reasonably determined by the party obliged to make the determination under Section 6(e) or, if each party is so obliged, it shall be the average of the Termination Currency Equivalents of the fair market values reasonably determined by both parties.

IN WITNESS WHEREOF the parties have executed this document on the respective dates specified below with effect from the date specified on the first page of this document.

THE ROYAL BANK OF SCOTLAND PLC

By: Greenwich Capital Markets, Inc., its agent

CONSTELLATION ENERGY RESOURCES LLC

By:

/s/ Christopher F. Swanson

By:

/s/ Felix J. Dawson

Name:

Christopher F. Swanson

Name:

Felix J. Dawson

Title:

Managing Director

Title:

President and CEO

Date:

June 20, 2006

Date:

June 20, 2006

ISDA^® 1992

Multicurrency - Cross Border

SCHEDULE

to the

Master Agreement

Dated as of June 16, 2006

between

THE ROYAL BANK OF SCOTLAND PLC

A bank organized under the laws of Scotland

(“Party A”)

and

CONSTELLATION ENERGY RESOURCES LLC

A corporation organized and existing under the laws of Delaware

(“Party B”)

Part 1.

Termination Provisions

(1)	“Specified Entity” means in relation to Party A and Party B for the purpose of:


Section 5(a)(v)		Not Applicable
Section 5(a)(vi)		Not Applicable
Section 5(a)(vii)		Not Applicable
Section 5(a)(iv)		Not Applicable

(2)

“Specified Transaction” means (a) any transaction (including an agreement with respect thereto) now existing or hereafter entered into between one party to this Agreement (or any Credit Support Provider of such party or any applicable Specified Entity of such party) and any other party (including, without limitation, the other party to this Agreement or any Credit Support Provider of such other party or any applicable Specified Entity of such other party) which is a rate swap transaction, basis swap, forward rate transaction, commodity swap, commodity option, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, currency swap transaction, cross-currency rate swap transaction, currency option, or any other similar transaction (including any option with respect to any of these transactions), (b) any transaction relating to the delivery of securities between the parties to this Agreement, (c) any combination of these transactions, and (d) any other transaction identified as a Specified Transaction in this Agreement or the relevant confirmation.

(3)	The “Cross Default” provisions of Section 5(a)(vi) will apply to Party A and will apply to Party B. For purposes of Section 5(a)(vi), the following provisions apply:

“Specified Indebtedness” will have the meaning specified in Section 14 of this Agreement.

“Threshold Amount” means, (i) with respect to Party A, the greater of (a) three percent (3%) of the shareholders’ equity of Party A as shown on its most recent annual audited financial statements, and (b) USD 50 Million; (ii) with respect to Party B or its Credit Support Providers, and its Specified Entities (if any), the greater of (a) three percent (3%) of the shareholders’ equity of Party A’s Credit Support Provider as shown in its most recent annual audited financial statements, and (b) USD 50 Million (including in each case, its equivalent in any other currency or composite currency).

(4)

The “Credit Event Upon Merger” provisions of Section 5(b)(iv) will apply to Party A and to Party B, provided; however, that “materially weaker” appearing in the fifth line of Section 5(b)(iv) shall mean the resulting, surviving, or transferee entity of the Affected Party, or its Credit Support Provider, if applicable, receives a rating, with respect to its long-term unsecured and unsubordinated indebtedness, lower than Baa3 by Moody’s Investor Services, Inc., or lower than BBB- by Standard and Poor’s Ratings Group.

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

Multicurrency - Cross Border

(5)	The “Automatic Early Termination” provision of Section 6(a) will not apply to Party A and to Party B.

(6)	Payments on Early Termination. For the purpose of Section 6(e) of this Agreement:

(i)

Market Quotation will apply; and

(ii)

The Second Method will apply.

(7)	“Termination Currency” means United States Dollars.

(8)	“Additional Termination Event” will not apply.

Part 2.

Tax Representations

(a)	Payer Tax Representations. For the purpose of Section 3(e) of this Agreement, each party will make with respect to itself the following representation: –

It is not required by any applicable law, as modified by the practice of any relevant governmental revenue authority, of any Relevant Jurisdiction to make any deduction or withholding for or on account of any Tax from any payment (other than interest under Section 2(e), 6(d)(ii), or 6(e) of this Agreement) to be made by it to the other party under this Agreement. In making this representation, it may rely on (i) the accuracy of any representation made by the other party pursuant to Section 3(f) of this Agreement; (ii) the satisfaction of the agreement of the other party contained in Section 4(a)(i) or 4(a)(iii) of this Agreement and the accuracy and effectiveness of any document provided by the other party pursuant to Section 4(a)(i) or 4(a)(iii) of this Agreement; and (iii) the satisfaction of the agreement of the other party contained in Section 4(d) of this Agreement, provided that it shall not be a breach of this representation where reliance is placed on sub-clause (ii) above and the other party does not deliver a form or document under Section 4(a)(iii) by reason of material prejudice to its legal or commercial position.

(b)	Tax Representation. For the purpose of Section 3(f) of this Agreement, (i) the following representations will apply to Party A:

(a)

It is a tax resident of the United Kingdom.

(b)

It is a “foreign person” within the meaning of the applicable U.S. Treasury Regulations concerning information reporting and backup withholding tax (as in effect on January 1, 2001), unless Party A provides written notice to Party B that it is no longer a foreign person.

(c)

In respect of each Transaction it enters into through an office or discretionary agent in the United States or which otherwise is allocated (in whole or part) for United States federal income tax purposes to such United States trade or business, each payment received or to be received by it under such Transaction (or portion thereof, if applicable) will be effectively connected with its conduct of a trade or business in the United States; and,

(d)

In respect of all other Transactions or portions thereof, no such payment received or to be received by it in connection with this Agreement is attributable to a trade or business carried on by it through a permanent establishment in the United States.

(c)	Tax Representation. For the purpose of Section 3(f) of this Agreement, the following representations will apply to Party B:

It is a corporation established under the laws of the State of Delaware and its U.S. taxpayer identification number is: 11-3742489.

Each payment received or to be received by Party B in connection with this Agreement will effectively connected with the conduct of a trade or business in the U.S.

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

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Part 3.

Agreement to Deliver Documents

For the purpose of Section 4(a) of this Agreement, each party agrees to deliver the following documents, as applicable:

(a)	Tax forms, documents, or certificates to be delivered are: –


Party required to deliver document	Forms/Documents/ Certificate	Date by which to be delivered	Covered by Section 3(d)
Party A	(i) In respect of each Transaction described in Part 2, subsection (b)(i)(d), United States Internal Revenue Service Form W-8BEN (with parts I, II & IV fully completed, including checking lines 9a, 9b and 9c), or any successor form; and (ii) In respect of each Transaction described in Part 2, subsection (b)(i)(c), United States Internal Revenue Service Form W-8ECI (with all parts fully completed), or any successor form.	(i) On a date which is before the first Scheduled Payment Date under this Agreement, and every three years thereafter, (ii) promptly upon reasonable demand by Party B, and (iii) promptly upon learning that any such form previously provided by Party A has become obsolete, incorrect, or ineffective.	Yes

Party B	United States Internal Revenue Service Form W-9, or any successor form.	(i) On a date which is before the first Scheduled Payment Date under this Agreement, (ii) promptly upon reasonable demand by Party A, and (iii) promptly upon learning that any such form previously provided by Party B has become obsolete, incorrect, or ineffective.	Yes

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

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(b)

Other documents to be delivered are: –


Party required to deliver document	Forms/Documents/ Certificate	Date by which to be delivered	Covered by Section 3(d)
Party A and Party B	An incumbency certificate with respect to the signatory of this Agreement.	Upon execution of this Agreement.	Yes

Party A and Party B’s Credit Support Provider	A copy of its annual report containing audited consolidated financial statements for such fiscal year certified by independent public accountants and prepared in accordance with generally accepted accounting practices consistently applied.	As soon as practicable after demand, but in no event later than 120 days after the end of each fiscal year of each party, or its Credit Support Provider if such financial statement is not available on “EDGAR” or a party, or its Credit Support Provider’s home page on the World Wide Web at www.constellation.com for Party B.	Yes

Party B’s Credit Support Provider	A copy of the unaudited financial statements for its most recent fiscal quarter and prepared in accordance with generally accepted accounting practices consistently applied.	As soon as practicable after demand, but in no event later than 60 days after the end of each fiscal quarter of each party, or its Credit Support Provider if such financial statement is not available on “EDGAR” or a party, or its Credit Support Provider’s home page on the World Wide Web at www.constellation.com for Party B.	Yes

Party B	A copy of the resolutions (the “Authorizing Resolutions”) of the board of directors, certified by a secretary or assistant secretary, pursuant to which it is authorized to enter into this Agreement and each Transaction entered into hereunder.	Upon execution of this Agreement.	Yes

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

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Part 4.

Miscellaneous

(1)	Addresses for Notices. For the purpose of Section 12(a) of this Agreement:

(i)

Address for notices or communications to Party A:


Address:		The Royal Bank of Scotland plc, Financial Markets 135 Bishopsgate London EC2M 3UR
Attention:		Swaps Administration
Telephone No.:		+44 20 7375 5000
Facsimile No.:		+44 20 7375 5050

With a copy to:

Address:		600 Steamboat Road Greenwich, CT 06830
Attention:		Legal Department - Derivatives Documentation
Telephone No.:		203-618-2531/6467
Facsimile No.:		203-422-4531/4247

(ii)

Address for notices or communications to Party B:


Address:		Constellation Energy Resources LLC 111 Market Place, Suite 500 Baltimore, Maryland 21202
Attention:		Contract Administration
Telephone No.:		410-468-3798
Facsimile No.:		410-468-3499

For Transaction Confirmations:

Attention:		Operations Department
Telephone No.:		410-468-3620
Facsimile No.:		410-468-3540

With an additional copy of any notices required under Sections 5 and 6 to be delivered to:

		Constellation Energy Commodities Group, Inc. 111 Market Place, Suite 500 Baltimore, MD 21202 Attn: General Counsel Facsimile No.: (410) 468-3499

(2)	Governing Law. This Agreement will be governed by and construed in accordance with the laws of the State of New York without reference to choice of law doctrine.

(3)	Process Agent. For the purpose of Section 13(c) of the Agreement: Not Applicable.

(4)	Offices. The provisions of Section 10(a) of the Agreement will apply.

(6)	Multibranch Party. For the purpose of Section 10 of the Agreement:

(b)

Party A is a Multibranch Party and may act through any of its Offices including, but not limited to, its London and New York Offices.

(b)

Party B is not a Multibranch Party and will act through its Maryland Office.

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

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(7)	Effectiveness of Notice. Section 12(a) is hereby amended by deleting the words “facsimile transmission or” in line 3 thereof. Sections 12(a)(ii) and (v) are void under this Agreement.

(8)	Calculation Agent. The Calculation Agent is Party A unless an Event of Default or Potential Event of Default has occurred and is continuing in which event Party B shall be the Calculation Agent.

(9)	“Affiliate” will have the meaning specified in Section 14 of the Agreement.

(10)	Netting of Payments. Subparagraph (ii) of Section 2(c) of the Agreement will apply.

(11)	Section 9(b) is hereby amended by deleting all the words after “parties” on the third line.

(12)	Credit Support Document(s):

With respect to Party B, the guarantee of Party B’s Credit Support Provider.

(12)	Credit Support Provider(s).

“Credit Support Provider” means with respect to Party A: Not applicable; and with respect to Party B, Constellation Energy Group, Inc.

Part 5.

Other Provisions

(1)	Confirmations. Notwithstanding anything to the contrary in the Agreement:

The parties hereby amend Section 9(e)(ii) by adding the following sentences at the end thereof; “On or promptly following the trade date of a Transaction, Party A will send to Party B a Confirmation. Party B will promptly thereafter confirm the accuracy of such Confirmation by executing and returning such Confirmation to Party A; or, by requesting Party A to correct such Confirmation. If any dispute shall arise as to whether an error exists in a Confirmation, the parties shall in good faith make reasonable efforts to resolve the dispute. If Party B fails to accept or dispute the Confirmation in the manner set forth above within two local Business Days after it was effectively sent to Party B, the Confirmation shall be deemed to correctly reflect the parties’ agreement on the terms of the Transaction referred to therein, absent manifest error. The requirement of this section and elsewhere in this Agreement that the parties exchange Confirmations shall for all purposes be deemed satisfied by a Confirmation sent and an acknowledgment deemed given as provided herein.”

(2)

Additional Agreements. Each party agrees, upon learning of the occurrence of any event or commencement of any condition that constitutes (or that with the giving of notice or passage of time or both would constitute) an Event of Default or Termination Event with respect to such party, promptly to give the other party notice of such event or condition (or, in lieu of giving notice of such event or condition in the case of an event or condition that with the giving of notice or passage of tine or both would constitute an Event of Default or Termination Event with respect to the party, to cause such event or condition to cease to exist before becoming an Event of Default or Termination Event).

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

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(3)	Additional Representations. Section 3 of the Agreement is hereby amended by adding at the end thereof the following subsections:

(g)

Trade Option Exemption. In the case of Party B, it is a producer, processor or commercial user of, or a merchant handling, each “commodity” (as such term is defined in Section la(3) of the Commodities Exchange Act, as amended) which may be the subject of any option entered into between the parties, and any such option entered into is entered into solely for purposes related to its business as such.

(h)

Eligible Contract Participant. It constitutes an “eligible contract participant” as such term is defined in Section 1a(12) of the Commodity Exchange Act, as amended and neither this Agreement nor any Transaction will be executed or traded on a “trading facility” within the meaning of section 1(a)(33) of the Commodity Exchange Act, as amended.

(i)

Standardization and Creditworthiness. (x) The economic terms of this Agreement, any Credit Support Document to which it is a party, and each Transaction have been individually tailored and negotiated by it; (y) it has received and reviewed financial information concerning the other party and has had a reasonable opportunity to ask questions of and receive answers and information from the other party concerning such other party, this Agreement, such Credit Support Document, and such Transaction, and the creditworthiness of the other party was a material consideration in its entering into or determining the terms of this Agreement, such Credit Support Document, and such Transaction.

(j)

Line of Business. It has entered into this Agreement (including each Transaction hereunder) in conjunction with its line of business (including financial intermediation services) or the financing of its business.

(k)

No Reliance. In connection with the negotiation of, the entering into, and the confirming of the execution of, this Agreement, any Credit Support Document to which it is a party, and each Transaction: (i) it is acting as principal (and not as agent for any other party or in any other capacity, fiduciary or otherwise); (ii) the other party is not acting as a fiduciary or financial or investment advisor for it; (iii) it is not relying upon any advice, statements, recommendations or representations (whether written or oral) of the other party other than the written representations expressly set forth in this Agreement, in such Credit Support Document or in the Confirmation of such Transaction; (iv) the other party has not given to it (directly or indirectly through any other person) any advice, counsel, assurance, guarantee, or representation whatsoever as to the expected or projected success, profitability, return, performance, result, effect, consequence, or benefit (either legal, regulatory, tax, financial, accounting, or otherwise) of this Agreement, such Credit Support Document, or such Transaction; (v) it has consulted with its own legal, regulatory, tax, business, investment, financial, and accounting advisors to the extent it has deemed necessary, and it has made its own investment, hedging, and trading decisions based upon its own judgment and upon any advice from such advisors as it has deemed necessary, and not upon any view expressed by the other party; (vi) all trading decisions have been the result of arm’s length negotiations between the parties and are not intended to preclude either Party (or any of such Party’s Affiliates) from undertaking proprietary trading activities, including hedging and other transactions relating, directly or indirectly, to generation capacity owned or controlled by such Party or its Affiliates; (vii) it is entering into this Agreement, such Credit Support Document, and such Transaction with a full understanding of all of the risks hereof and thereof (economic and otherwise), and it is capable of assuming and willing to assume (financially and otherwise) those risks and (viii) it has the capacity to evaluate (internally or through independent professional advice) this Agreement, any such Credit Support Document and each such Transaction (including decisions regarding the appropriateness or suitability thereof) and has made its own decision to enter into this Agreement, such Credit Support Document and each such Transaction.

(l)

No Agency. In connection with the negotiation of, the entering into, and the confirming of the executing of, this Agreement, any Credit Support Document to which it is a party, and each Transaction, it is acting as principal (and not as agent in any other capacity, fiduciary or otherwise).

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

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(m)

Bankruptcy Code Representation. The parties hereto intend that this Agreement shall be a “master agreement” for purposes of 11 U.S.C. 101(53B) and 12 U.S.C. 1821 (e)(8)(d)(vii) or any successor provisions.

(n)

Financial Institution Status. It is a “financial institution”, in that it engages, will engage and holds itself out as engaging in “financial contracts,” as a counterparty on both sides of one or more “financial markets” (as such quoted terms are defined in Regulation EE of the US Federal Reserve Board, 12 C.F.R. Part 231) and it fulfills at least one of the quantitative tests contained in such Regulation EE (12 C.F.R. §231 (a)(1) or (a)(2).

(4)

Netting Provisions. If an Early Termination Date is designated, amounts determined in respect of all Terminated Transactions shall, to the fullest extent permitted by law, be aggregated with and netted against one another in performing the calculations contemplated by Section 6(e) of this Agreement. Any Terminated Transaction(s) that cannot be so aggregated and netted pursuant to the application of the previous sentence shall be aggregated and netted amongst themselves to the fullest extent permitted by law. Any Terminated Transactions that cannot be so aggregated and netted against themselves shall instead be (and is hereby agreed always to have been) governed by, and subject to, (i) the terms and conditions set out in any relevant agreement otherwise superseded by this Agreement as referred to in Part 5(l)(a) of this Schedule or (ii) if no such agreement exists, the terms and conditions set out in the relevant Confirmation(s) with respect to such Transaction(s).

(5)

Severability. Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of the Agreement or affecting the validity or enforceability of such provision in any other jurisdiction unless such severance shall substantially impair the benefits of the remaining portions of this Agreement or changes the reciprocal obligations of the parties. The parties hereto shall endeavor in good faith negotiations to replace the prohibited or unenforceable provision with a valid provision, the economic effect of which comes as close as possible to that of the prohibited or unenforceable provision. This severability provision will not be applicable if any provision of Section 2, 5, 6 or 13 (or any definition or provision in Section 14 to the extent it relates to, or is used in or in connection with, any such section) is held to be invalid or unenforceable.

(6)	WAIVER OF JURY TRIAL. EACH PARTY HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY PROCEEDINGS.

(7)

Consent to Telephonic Recording. Each party hereto consents to the monitoring or recording, at any time and from time to time, by the other party of the telephone conversations of trading and marketing personnel of the parties and their authorized representatives in connection with this Agreement or any Transaction or potential Transaction; and the parties, waive any further notice of such monitoring or recording and agree to give proper notice and obtain any necessary consent of such personnel for any such monitoring or recording.

(8)	Set Off. Section 6 of the Agreement is amended by adding the following new subsection 6(f):

(f) In addition to any rights of set-off a party may have as a matter of law or otherwise, upon the occurrence of an Event of Default or Termination Event under Section 5(b)(iv) with respect to a party (“X”) the other party (“Y”) will have the right (but will not be obliged) without prior notice to X or any other person to set-off any obligation of X owing to Y (whether or not arising under this Agreement, whether or not matured, whether or not contingent and regardless of the currency, place of payment or booking office of the obligation) against any obligation of Y owing to X [(or any Affiliate of X)] (whether or not arising under this Agreement, whether or not matured, whether or not contingent and regardless of the currency, place of payment or booking office of the obligation). Y will give notice to the other party of any set-off effected hereunder.

For the purpose of cross-currency set-off, Y may convert any obligation to another currency into the Termination Currency at the rate of exchange at which such party would be able, acting in a reasonable manner and in good faith, to purchase the relevant amount of such currency.

If an obligation is unascertained, Y may in good faith estimate that obligation and set-off in respect of the estimate, subject to the relevant party accounting to the other when the obligation is ascertained.

Nothing in this provision will be deemed to create a charge or other security instrument.

Constellation Energy Commodities Group Inc.

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Notwithstanding any provision to the contrary contained in this Agreement, the Non-defaulting Party or party that is not the Affected Party (the “Non-affected Party”), as the case may be, shall not be required to pay to the Defaulting Party or Affected Party any amount under Section 6(e) until the Non-defaulting Party or Non-affected Party receives confirmation satisfactory to it in its reasonable discretion (which may include an opinion of its counsel) that all other obligations of any kind whatsoever (whether pursuant to Specified Indebtedness as defined herein or otherwise) of the Defaulting Party or Affected Party to make any payments to the Non-defaulting Party or Non-affected Party or any of its Affiliates under this Agreement, or any other contract or agreement, which are due and payable as of the Early Termination Date hereof have been fully and finally performed.

(9)

ISDA Definitions. Unless otherwise specified in a Confirmation, this Agreement, each Confirmation and each Transaction incorporates, and is subject to and governed by the 2000 ISDA Definitions (the “Swap Definitions”), as published by the International Swaps and Derivatives Association, Inc. (collectively the “Definitions”). In the event of any inconsistency between the provisions of this Agreement and the Swap Definitions, this Agreement will prevail. In the event of any inconsistency between the provisions of any Confirmation and this Agreement or the Swap Definitions, such Confirmation will prevail for the purpose of the relevant Transaction.

(10)

Reference Market-makers. The definition of “Reference Market-markers” in Section 14 of this Agreement is hereby amended by: (i) deleting “(a)” from the second line thereof, (ii) deleting in the fourth line thereof after the word “credit” the words “and (b) to the extent practicable, from among such dealers having an office in the same city” and (iii) replacing such words with the words “or to enter into transactions similar in nature to Transactions.”

(11)	Sharing of Information. In connection with its review and approval of Transactions hereunder (including, without limitation, review by credit sanctioning personnel), each party may share any information concerning the other party with any of its Affiliates.

(12)	Agency Role of Greenwich Capital Markets, Inc. In connection with this Agreement, Greenwich Capital Markets, Inc. has acted as agent on behalf of Party B. Greenwich Capital Markets, Inc. has not guaranteed and is not otherwise responsible for the obligations of Party B under this Agreement.

(13)

Relationship Between The Parties: In connection with the negotiation of, the entering into, of this Agreement, and any other documentation relating to this Agreement to which it is a party or that it is required by this Agreement to deliver, each party hereby represents and warrants, and, in connection with the negotiation of, the entering into, and the confirming of the execution of each Transaction, each party will be deemed to represent, to the other party as of the date hereof (or, in connection with any Transaction, as of the date which it enters into such Transaction) that (absent a written agreement between the parties that expressly imposes affirmative obligations to the contrary for that Transaction): –

(i)

Assessment and Understanding. It is capable of assessing the merits of and understanding (on its own behalf or through independent professional advice), and understands and accepts, the terms, conditions and risks of that Transaction. It is also capable of assuming, and assumes, the risks of that Transaction. It has determined to its satisfaction whether or not the rates, prices or other economic terms of each Transaction and the indicative quotations (if any) provided by the other party reflect those in the relevant market for similar transactions, and all trading decisions have been the result of arm’s length negotiations between the parties.

(ii)

Status of Parties. The other party is not acting as a fiduciary for or an adviser to it in respect of that Transaction.

(iii)

Related Transactions. It is aware that each other party to this Agreement and its Affiliates may from time to time (A) take positions in instruments that are identical or economically related to a Transaction or (B) have an investment banking or other commercial relationship with the issuer of an instrument underlying a Transaction.

(14)

Accuracy of Specified Information. Section 3(d) of this Agreement is hereby amended by the addition of the following in the third line thereof after the word “respect” and before the period: “or, in the case of audited or unaudited financial statements, is a fair presentation of the financial condition of the relevant party in accordance with generally accepted accounting principles as of the dates of such statements”.

Constellation Energy Commodities Group Inc.

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(15)	US Federal Securities Laws. In the event Party A and Party B enter into equity or equity-related Transactions, the following representations shall apply:

Party A and Party B understand that certain Transactions under the Agreement may constitute the purchase or sale of “securities” as defined in the Securities Act and understand that any such purchase or sale of securities will not be registered under the Securities Act and that any such Securities Transactions may not be re-offered, resold, pledged, sub-participated or otherwise transferred except (x) in accordance with the Agreement, (y) pursuant to an effective registration statement under the Securities Act or pursuant to an exemption from the registration requirements of the Securities Act and (z) in accordance with any applicable securities laws of any state of the United States.”

(16)

Condition to Transfer under Section 7. Upon any transfer pursuant to Section 7 of this Agreement, the transferring party agrees to provide the non-transferring party with the name and address of the transferee so that the non-transferring party may fulfill its requirements to record the transfer on its books and records, and, notwithstanding anything to the contrary herein, any failure by the transferring party to do so will render the purported transfer void.

SIGNATURE PAGE FOLLOWS

Constellation Energy Commodities Group Inc.

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IN WITNESS WHEREOF, the parties have executed this document on the respective dates specified below with effect from the date specified on the first page of this document.


THE ROYAL BANK OF SCOTLAND PLC By: Its Agent, Greenwich Capital Markets, Inc.

By:		/s/ Christopher F. Swanson
Name:		Christopher F. Swanson
Date:		June 20, 2006


CONSTELLATION ENERGY RESOURCES, LLC

By:		/s/ Felix J. Dawson
Name:		Felix J. Dawson
Title:		President and CEO
Date:		June 20, 2006

Constellation Energy Commodities Group Inc.

Final ISDA Schedule

Confirmation, dated June 28, 2006

Exhibit 10.8

TRANSMISSION VERIFICATION REPORT


TIME	:	07/11/2006 06:32
NAME	:	CONSTELLATION POWER
FAX	:	4104683839
TEL	:	4104683839
SER. #	:	BROH3J607675


DATE, TIME		07/11 06:31
FAX NO./NAME		0011442070854876
DURATION		00:01:31
PAGE(S)		05
RESULT		OK
MODE		STANDARD
		ECM

LOGO


Deal Reference Number COMM1090.1		28 June 2006

Constellation Energy Resources LLC

United States

Attention: Kimberly Fisher

Fax: 001 410 468 3540

Commodity Swap - Cash Settled

Dear Sirs

The purpose of this letter agreement (this “Confirmation”) is to confirm the terms and conditions of the Transaction entered into between Constellation Energy Resources LLC (the “Counterparty”) and The Royal Bank of Scotland plc (“RBS”) on the Trade Date specified below (the “Transaction”).

The definitions and provisions contained in the 2005 ISDA Commodity Definitions (as published by the International Swaps and Derivatives Association, Inc.), (the “Definitions”) are incorporated into this Confirmation. In the event of any inconsistency between the Definitions and this Confirmation, this Confirmation will govern.

This Confirmation constitutes a “Confirmation” as referred to in, and supplements, forms a part of, and is subject to, the applicable ISDA Master Agreement which for these purposes means either: (i) where we have entered into an ISDA Master Agreement, that ISDA Master Agreement, or (ii) where we have not entered into any ISDA Master Agreement, an agreement in the form of the ISDA Master Agreement as if we had executed an agreement in such form (but without any Schedule except for the election of English law as the governing law and Sterling as the Termination Currency) on the Trade Date of the first such

LOGO


Deal Reference Number COMM1090.1		28 June 2006

Constellation Energy Resources LLC

United States

Attention: Kimberly Fisher

Fax: 001 410 468 3540

Commodity Swap - Cash Settled

Dear Sirs

The terms of the particular Transaction to which this Confirmation relates, are as follows:

1. General Terms


Notional Quantity per Calculation Period:		As specified in the Annex

Commodity:		Natural gas

Trade Date:		20 June 2006

This communication is confidential and may also be privileged. If you are not the intended recipient, please notify us immediately and do not copy it or disclose its contents to any other person.

The Royal Bank of Scotland plc Registered in Scotland No 90312 Registered Office: 38 SI Andrew Square Edinburgh EH2 2YB

A member of the London Stock Exchange and authorised and regulated by the Financial Services Authority


Calculation Period(s):		As specified in the Annex. If the Calculation Period consists of only one Commodity Business Day, the Calculation Period will be subject to adjustment in accordance with the Following Business Day Convention.

Payment Date(s):		The fifth Business Day following each Calculation Period

Fixed Amount Details

Fixed Price Payer:		RBS

Fixed Price:		As specified in the Annex

Floating Amount Details

Floating Price Payer:		The Counterparty

Commodity Reference Price:		NATURAL GAS-HENRY HUB-NYMEX

Specified Price:		The official settlement price

Delivery Date:		First Nearby Month

Pricing Date(s):		The Commodity Business Day in the Calculation Period

Market Disruption Events and Disruption Fallbacks

Notwithstanding anything to the contrary in the Agreement, the Market Disruption Events set forth in Sections 7.4(c)(i) – 7.4(c)(v) of the Definitions, and the provisions relating to Disruption Fallbacks set forth in Section 7.5(d)(i) of the Definitions, shall apply to this Transaction.


Business Days:		New York

2. Calculation Agent:		RBS

3. Governing law:		The governing law of the Agreement


4. Offices:

The Office of RBS for the Transaction is:		London

The Office of the Counterparty for the Transaction is:		Baltimore

5. Account Details

Account(s) for payments to the Counterparty:		Please advise

Account(s) for payments to RBS:		As per our Standard Settlement Instructions

6. Representations

Each party represents to the other party on the trade date of this Transaction that (in the absence of a written agreement between the parties that expressly imposes affirmative obligations to the contrary for this Transaction):-

(a) Non-Reliance. It is acting for its own account, and it has made its own independent decisions to enter into this Transaction and as to whether this Transaction is appropriate or proper for it based upon its own judgement and upon advice from such advisers as it has deemed necessary. It is not relying on any communication (written or oral) of the other party as investment advice or as a recommendation to enter into this Transaction; it being understood that information and explanations related to the terms and conditions of this Transaction shall not be considered investment advice or a recommendation to enter into this Transaction, no communication (written or oral) received from the other party shall be deemed to be an assurance or guarantee as to the expected results of this Transaction.

(b) Assessment and Understanding. It is capable of assessing the merits of and understanding (on its own behalf or through independent professional advice), and understands and accepts, the terms, conditions and risks of this Transaction. It is also capable of assuming, and assumes, the risks of this Transaction.

(c) Status of Parties. The other party is not acting as a fiduciary for or an adviser to it in respect of this Transaction.

7. Other

This Transaction has been entered into between yourselves and The Royal Bank of Scotland plc, a member of the London Stock Exchange and authorised and regulated by the Financial Services Authority.

This Confirmation is in final form and replaces and supersedes all previous Confirmations and communications in respect of this Transaction. No hard copy will follow.

In the event that you disagree with any part of this Confirmation, please notify us promptly via the contact details below so that the discrepancy may be resolved. Please note that our telephone conversations with you may be recorded.

Please confirm that the foregoing correctly sets forth the terms of our agreement by executing a copy of this Confirmation and returning it to us by facsimile to:


Attention:		OTC Derivative Confirmations

Telephone:		+ 44(0)20 7085 6069 / + 44(0)20 7085 3775

Fax:		+ 44(0)20 7085 4876 / + 44(0)20 7085 5811


Yours sincerely, For and on behalf of The Royal Bank of Scotland plc

By:	/s/ Jonathan Pryor
	Name:	Jonathan Pryor
	Title:	Authorised Signatory


Confirmed as of the date first written Constellation Energy Resources LLC

By:	Constellation Energy Commodities Group, Inc.

	/s/ Stuart Rubenstein
	Name:	Stuart Rubenstein
	Title:

Annex


Calculation Period	Notional Quantity per Calculation Period (MMBTU)	Fixed Price (expressed as USD per MMBTU)
26 September 2006	310,000.00	8.830
26 October 2006	310,000.00	8.830
27 November 2006	310,000.00	8.830
26 December 2006	308,333.00	9.345
26 January 2007	308,333.00	9.345
23 February 2007	308,333.00	9.345
27 March 2007	308,333.00	9.345
25 April 2007	308,333.00	9.345
25 May 2007	308,333.00	9.345
26 June 2007	308,333.00	9.345
26 July 2007	308,333.00	9.345
28 August 2007	308,333.00	9.345
25 September 2007	308,333.00	9.345
26 October 2007	308,333.00	9.345
27 November 2007	308,333.00	9.345
26 December 2007	291,667.00	8.910
28 January 2008	291,667.00	8.910
26 February 2008	291,667.00	8.910
26 March 2008	291,667.00	8.910
25 April 2008	291,667.00	8.910
27 May 2008	291,667.00	8.910
25 June 2008	291,667.00	8.910
28 July 2008	291,667.00	8.910
26 August 2008	291,667.00	8.910
25 September 2008	291,667.00	8.910
28 October 2008	291,667.00	8.910
21 November 2008	291,667.00	8.910
24 December 2008	275,000.00	8.400
27 January 2009	275,000.00	8.400
24 February 2009	275,000.00	8.400
26 March 2009	275,000.00	8.400
27 April 2009	275,000.00	8.400
26 May 2009	275,000.00	8.400
25 June 2009	275,000.00	8.400
28 July 2009	275,000.00	8.400
26 August 2009	275,000.00	8.400
25 September 2009	275,000.00	8.400
27 October 2009	275,000.00	8.400
23 November 2009	275,000.00	8.400

Each date in the column headed Payment Dates shall be subject to adjustment in accordance with the Modified Following Business Day Convention.

Asset Purchase and Sale Agreement

Exhibit 10.9

ASSET PURCHASE AND SALE AGREEMENT

between

Everlast Energy LLC,

RB Marketing Company LLC

and

Robinson’s Bend Operating Company LLC

as “Seller”

and

CBM Equity IV, LLC

as “Buyer”

Dated as of May 12, 2005

Table of Contents


		Page
ARTICLE I PROPERTIES TO BE SOLD AND PURCHASED		1
Section 1.1.	Assets Included	1
Section 1.2.	Assets Excluded	3
Section 1.3.	Conveyance Subject to Royalty Trust Conveyance	4

ARTICLE II PURCHASE PRICE		4
Section 2.1.	Purchase Price	4
Section 2.2.	Accounting Adjustments	4
Section 2.3.	Closing and Post-Closing Accounting Settlements	5
Section 2.4.	Payment of Adjusted Purchase Price	5
Section 2.5.	Allocation of Purchase Price	6

ARTICLE III THE CLOSING		6

ARTICLE IV REPRESENTATIONS AND WARRANTIES OF SELLER		6
Section 4.1.	Organization and Existence	6
Section 4.2.	Power and Authority	6
Section 4.3.	Valid and Binding Agreement	7
Section 4.4.	Non-Contravention	7
Section 4.5.	Approvals	7
Section 4.6.	Pending Litigation	7
Section 4.7.	Contracts	8
Section 4.8.	Commitments, Abandonments or Proposals	8
Section 4.9.	Production Sales Contracts	9
Section 4.10.	Plugging and Abandonment	9
Section 4.11.	Permits	9
Section 4.12.	Payment of Expenses	9
Section 4.13.	Compliance with Laws	10
Section 4.14.	Imbalances; Prepayments	10
Section 4.15.	Intellectual Property	10
Section 4.16.	Taxes	10
Section 4.17.	Fees and Commissions	11
Section 4.18.	Equipment; Easements and Rights of Way	11
Section 4.19.	Title to Non-Oil and Gas Properties	11
Section 4.20.	Additional Seller's Representations and Warranties	12
Section 4.21.	Absence of Certain Changes	13
Section 4.22.	Disclaimer of Warranties	13

ARTICLE V REPRESENTATIONS AND WARRANTIES OF BUYER		15
Section 5.1.	Organization and Existence	15
Section 5.2.	Power and Authority	15
Section 5.3.	Valid and Binding Agreement	15
Section 5.4.	Non-Contravention	15
Section 5.5.	Approvals	15
Section 5.6.	Pending Litigation	16

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Section 5.7.	Knowledgeable Purchaser	16
Section 5.8.	Funds	16
Section 5.9.	Qualified Leaseholder	16
Section 5.10.	Fees and Commissions	16

ARTICLE VI CERTAIN COVENANTS OF SELLER PENDING CLOSING		16
Section 6.1.	Access to Files	16
Section 6.2.	Conduct of Operations	17
Section 6.3.	Restrictions on Certain Actions	17
Section 6.4.	Payment of Expenses	17
Section 6.5.	Preferential Rights and Third Party Consents	18
Section 6.6.	No-Shop Provision	18

ARTICLE VII ADDITIONAL PRE-CLOSING AND POST-CLOSING AGREEMENTS OF BOTH PARTIES		19
Section 7.1.	Reasonable Best Efforts	19
Section 7.2.	Notice of Litigation	19
Section 7.3.	Notification of Certain Matters	19
Section 7.4.	Fees and Expenses	20
Section 7.5.	Public Announcements	20
Section 7.6.	Acquisition of Royalty Interest or Royalty Trust Units	20
Section 7.7.	Casualty Loss Prior to Closing	20
Section 7.8.	Governmental Bonds	21
Section 7.9.	Assumed Obligations	21
Section 7.10.	Books and Records	21
Section 7.11.	Suspended Funds	21
Section 7.12.	Letters-in-Lieu	22
Section 7.13.	Logos and Names	22
Section 7.14.	Transition Services Agreement	22
Section 7.17.	Further Assurances	23

ARTICLE VIII DUE DILIGENCE EXAMINATION		23
Section 8.1.	Title Due Diligence Examination	23
Section 8.2.	Environmental Due Diligence Examination	27
Section 8.3.	Adjustments to Purchase Price for Defects	29
Section 8.4.	Buyer Indemnification	29

ARTICLE IX CONDITIONS PRECEDENT TO THE OBLIGATIONS OF THE PARTIES		30
Section 9.1.	Conditions Precedent to the Obligations of Buyer	30
Section 9.2.	Conditions Precedent to the Obligations of Seller	31

ARTICLE X TERMINATION, AMENDMENT AND WAIVER		32
Section 10.1.	Termination	32
Section 10.2.	Effect of Termination	33
Section 10.3.	Amendment	33
Section 10.4.	Waiver	33

ARTICLE XI SURVIVAL OF REPRESENTATIONS, WARRANTIES AND COVENANTS; INDEMNIFICATION		33
Section 11.1.	Survival	33

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Section 11.2.	Seller's Indemnification Obligations.	34
Section 11.3.	Buyer's Indemnification Obligations.	35
Section 11.4.	Net Amounts.	35
Section 11.5.	Indemnification Proceedings.	36
Section 11.6.	Indemnification Exclusive Remedy.	36
Section 11.7.	Limited to Actual Damages.	37
Section 11.8.	Indemnification Despite Negligence.	37
Section 11.9.	Indemnification Support Escrow Agreement.	37

ARTICLE XII MISCELLANEOUS MATTERS		38
Section 12.1.	Dispute Resolution for Title Defects, Environmental Defects and Breaches.	38
Section 12.2.	Notices.	40
Section 12.3.	Entire Agreement.	41
Section 12.4.	Injunctive Relief.	42
Section 12.5.	Binding Effect; Assignment; No Third Party Benefit.	42
Section 12.6.	Severability.	42
Section 12.7.	GOVERNING LAW.	42
Section 12.8.	Counterparts.	42
Section 12.9.	WAIVER OF CONSUMER RIGHTS.	43
Section 12.10.	WAIVER OF JURY TRIAL.	43

ARTICLE XIII DEFINITIONS AND REFERENCES		43
Section 13.1.	Certain Defined Terms.	43
Section 13.2.	Certain Additional Defined Terms.	47
Section 13.3.	References, Titles and Construction.	48

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ASSET PURCHASE AND SALE AGREEMENT

THIS ASSET PURCHASE AND SALE AGREEMENT dated May 12, 2005, is made by and among Everlast Energy, LLC, a Delaware limited liability company (“Everlast”), RB Marketing Company LLC, a Delaware limited liability company (“RB Marketing”), and Robinson’s Bend Operating Company LLC, a Delaware limited liability company (“RB Operating;” Everlast, together with RB Marketing and RB Operating, is herein collectively called “Seller”), and CBM Equity IV, LLC, a Delaware limited liability company (“Buyer”).

WITNESSETH:

WHEREAS, Seller desires to sell, assign and convey to Buyer, and Buyer desires to purchase and accept from Seller, certain oil and gas properties and related assets located in the counties of Tuscaloosa and Pickens, State of Alabama; and

WHEREAS, Seller and Buyer deem it in their mutual best interests to execute and deliver this Agreement;

NOW, THEREFORE, in consideration of the foregoing Recitals and the mutual covenants and agreements contained herein, Seller and Buyer do hereby agree as follows:

ARTICLE I

PROPERTIES TO BE SOLD AND PURCHASED

Section 1.1. Assets Included. Subject to Section 1.2, Seller agrees to sell and Buyer agrees to purchase, for the consideration hereinafter set forth, and subject to the terms and provisions herein contained, the following described properties, rights and interests:

(a) All of Seller’s right, title and interest in and to those properties described in Part 1 of Exhibit I attached hereto and made a part hereof for all purposes;

(b) Without limitation of the foregoing but subject to Section 1.2, all other right, title and interest (of whatever kind or character, whether legal or equitable, and whether vested or contingent) of Seller in and to the oil, gas and other minerals in and under or that may be produced from the lands described in Part 1 of Exhibit I hereto (including interests in oil, gas or mineral leases covering such lands, overriding royalties, production payments and net profits interests in such lands or such leases, and fee mineral interests, fee royalty interests and other interests in such oil, gas and other minerals), whether such lands be described in a description set forth in such Part 1 or be described in such Part 1 by reference to another instrument (and without limitation by any depth limitations that may be set forth in such Part 1 or in any such instrument so referred to for description), even though Seller’s interest in such oil, gas and other minerals may be incorrectly described in, or omitted from, such Part 1;

(c) All rights, titles and interests of Seller in and to, or otherwise derived from, all presently existing and valid oil, gas or mineral unitization, pooling, or communitization agreements, declarations and/or orders and in and to the properties covered and the units created thereby (including all units formed under orders, rules, regulations, or other official acts of any

federal, state, or other authority having jurisdiction, voluntary unitization agreements, designations and/or declarations) relating to the properties, rights, and interests described in paragraphs (a) and (b) above;

(d) All rights, titles and interests of Seller in and to all presently existing and valid production sales (and sales related) contracts, operating agreements (including claims under any joint interest audit attributable to the period after the Effective Date), and other agreements and contracts which relate to any of the properties, rights, and interests described in paragraphs (a), (b) and (c) above, or which relate to the exploration, development, operation, or maintenance thereof or the treatment, storage, transportation or marketing of production therefrom (or allocated thereto), including servitudes, easements, surface leases, right-of-way agreements, licenses and other agreements or arrangements relating to the use or ownership of such properties, specifically including any of the foregoing described in Section 4.7 of Seller’s Disclosure Schedule;

(e) All rights, titles and interests of Seller in and to all materials, supplies, inventory, machinery, equipment, vehicles, rolling stock, improvements and other personal property and fixtures (including all wells, casing, wellhead equipment, pumping units, flowlines, tanks, buildings, injection facilities, saltwater disposal facilities, compression facilities, gathering pipelines and gathering systems, and other equipment), and all easements, rights-of-way, surface leases and other surface rights, all permits and licenses, and all other appurtenances being used or held for use in connection with, or otherwise related to, the exploration, development, operation or maintenance of any of the properties, rights, and interests described in paragraphs (a), (b) and (c) above, or the treatment, storage, transportation or marketing of production therefrom (or allocated thereto), including the easements, rights-of-way, surface leases and other surface rights of the foregoing described on Part 2 to Exhibit I attached hereto;

(f) All rights of Seller under the Existing Hedges;

(g) All of Seller’s lease files, abstracts and title opinions, production records, well files, accounting records (but not including general financial and accounting records), seismic records and surveys, gravity maps, electric logs, geological, geophysical or seismic data and records, and other files, documents and records of every kind and description which relate to the properties, rights, and interests described above and in subsection (h) below; and

(h) All rights to make claims and receive proceeds under any insurance policy held by or on behalf of Seller in connection with the properties, rights, and interests described in this Section 1.1 for any claim that arises and is attributable to the period starting on the Effective Date and ending on the Closing Date in connection with the properties, rights and interest described in this Section 1.1.

(i) Seller’s obligations from and after the Effective Date pursuant to Section 15.3 of the Torch Purchase and Sale Agreement, subject to Buyer’s obligations under Section 7.9 of this Agreement.

As used herein: (i) ”Oil and Gas Properties” means the properties, rights and interests described in paragraphs (a), (b) and (c) above, save and except for any such properties or assets that are Excluded Assets; and (ii) ”Properties” means the Oil and Gas Properties plus the properties, rights and interests described in paragraphs (d), (e), (f), (g), (h), and (i) above, save and except for any such properties or assets that are Excluded Assets.

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Section 1.2. Assets Excluded. Notwithstanding anything herein contained to the contrary, the Properties do not include, and there is hereby excepted and reserved unto Seller, the following:

(a) All trade credits attributable to the Properties with respect to all periods prior to the Effective Date;

(b) All oil, gas or other hydrocarbon production from or attributable to the Properties with respect to all periods prior to the Effective Date, all proceeds attributable thereto, and all oil, gas or other hydrocarbons that, at the Effective Date, are owned by Seller and are in storage or within processing plants;

(c) Any refund of costs, taxes or expenses borne by Seller or Seller’s predecessors in title attributable to periods prior to the Effective Date;

(d) Any and all proceeds from the settlements of contract disputes with purchasers of oil, gas or other hydrocarbons from the Properties, including settlement of take-or-pay disputes, insofar as said proceeds are attributable to periods of time prior to the Effective Date;

(e) Any and all proceeds from settlements with regard to reclassification of gas produced from the Properties, insofar as said proceeds are attributable to periods of time prior to the Effective Date;

(f) All claims (including insurance claims) and causes of action of Seller against one or more third parties arising from acts, omission or events occurring prior to the Effective Date and all claims under any joint interest audit attributable to any period prior to the Effective Date;

(g) All limited liability company, financial, tax and legal (other than title) books and records of Seller;

(h) Seller’s office lease at 111 North Ennis, Houston, Texas, and all furniture, fixtures and equipment located thereat, including computers, telephone equipment and other similar items of tangible personal property;

(i) All of Seller’s patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property;

(j) All documents and instruments of Seller that may be protected by an attorney-client privilege (exclusive of title opinions in respect of the Oil and Gas Properties); and

(k) All (i) correspondence or other documents or instruments of Seller relating to the transactions contemplated hereby, (ii) lists of other prospective purchasers of Seller or the Properties compiled by Seller, (iii) bids submitted to Seller by other prospective purchasers of Seller or the Properties, (iv) analyses by Seller or any Affiliates thereof submitted by other prospective purchasers of Seller or the Properties, and (v) correspondence between or among Seller or its Affiliates or their respective representatives with respect to, or with, any other prospective purchasers of Seller or the Properties.

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The properties and interests specified in the foregoing paragraphs (a) through (k) of this Section 1.2 are herein collectively called the “Excluded Assets”.

Section 1.3. Conveyance Subject to Royalty Trust Conveyance. The Properties will be conveyed by Seller, and Buyer will accept the Properties, subject to all of the terms and conditions of that certain Net Profits Overriding Royalty Conveyance dated November 22, 1993, but effective as of October 1, 1993 (the “Royalty Trust Conveyance”), from, pursuant to Part I thereof, Velasco Gas Company, L.P. (“Velasco”) to Torch Energy Advisors Incorporated (“TEAI”), and, pursuant to Part II thereof, from TEAI to the Torch Energy Royalty Trust (the “Royalty Trust”). Pursuant to the Royalty Trust Conveyance, that portion of the Properties listed in Exhibit 1.3 attached hereto is subject to the “Net Royalty Interest,” as defined in the Royalty Trust Conveyance, and to the provisions of Sections 9.02 and 9.03 of the Torch Energy Royalty Trust Agreement dated October 1, 1993, by and among TEAI, Torch Royalty Company, Velasco, and Wilmington Trust Company (the “Royalty Trust Agreement”), concerning termination and disposition of the Royalty Trust assets.

ARTICLE II

PURCHASE PRICE

Section 2.1. Purchase Price. In consideration of the sale of the Properties by Seller to Buyer, Buyer shall pay to Seller cash in the amount of $140,500,000 (the “Purchase Price”). The Purchase Price, as adjusted pursuant to this Article II and the other applicable provisions hereof, is herein called the “Adjusted Purchase Price”.

Section 2.2. Accounting Adjustments.

(a) Appropriate adjustments shall be made between Buyer and Seller so that (i) all expenses (including all drilling costs, all capital expenditures, and all overhead charges under applicable operating agreements, and all other overhead charges actually charged by third parties) for work done in the operation of the Properties after the Effective Date will be borne by Buyer, and all proceeds (net of applicable production, severance, and similar taxes) from the sale of oil, gas or other minerals produced from the Oil and Gas Properties after the Effective Date, and all revenue attributable to periods after the Effective Date under operating agreements, production sales, purchasing or marketing agreements, or other agreements to which Seller is a party and which are part of the Properties, will be received by Buyer, and (ii) all expenses for work done in the operation of the Properties before the Effective Date will be borne by Seller and all proceeds (net of applicable production, severance, and similar taxes) from the sale of oil, gas or other minerals produced therefrom before the Effective Date, and all revenue attributable to periods before the Effective Date under operating agreements, production sales, purchasing or marketing agreements, or other agreements to which Seller is a party and which are part of the Properties, will be received by Seller. It is agreed that, in making such adjustments: (i) oil which was produced from the Oil and Gas Properties and which was, on the Effective Date, stored in tanks located on the Oil and Gas Properties (or located elsewhere but used to store oil produced from the Oil and Gas Properties prior to delivery to oil purchasers) and above pipeline

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connections shall be deemed to have been produced before the Effective Date (it is recognized that such tanks were not gauged on the Effective Date for the purposes of this Agreement and that determination of the volume of such oil in storage will be based on the best available data, which may include estimates), (ii) ad valorem taxes assessed with respect to a period which the Effective Date splits shall be prorated based on the number of days in such period which fall on each side of the Effective Date (iii) no consideration shall be given to the local, state or federal income tax liabilities of any party and (iv) the day on which the Effective Date falls shall be counted in the period after the Effective Date.

Section 2.3. Closing and Post-Closing Accounting Settlements.

(a) At or before Closing, the parties shall determine, based upon the best information reasonably available to them, the amount of the adjustments provided for in Section 2.2. If the amount of adjustments so determined which would result in a credit to Buyer exceed the amount of adjustments so determined which would result in a credit to Seller, Buyer shall receive a credit, for the amount of such excess, against the Purchase Price to be paid at Closing, and, if the converse is true, Buyer shall pay to Seller, at Closing (in addition to amounts otherwise then owed), the amount of such excess.

(b) As promptly as reasonably practicable but in no event later than one hundred eighty (180) days after Closing, Buyer shall prepare and deliver to Seller a statement setting forth the additional adjustments required, in Buyer’s opinion, to the Purchase Price. Within ten (10) days thereafter, Buyer and Seller shall review any additional information which may then be available pertaining to the adjustments provided for in Section 2.2, shall determine if any additional adjustments (whether the same be made to account for expenses or revenues not considered in making the adjustments made at Closing, or to correct errors made in such adjustments) should be made beyond those made at Closing, and shall make any such adjustments by appropriate payments from Seller to Buyer or from Buyer to Seller. Following such additional adjustments, no further adjustments to the Purchase Price shall be made under this Section 2.3.

Section 2.4. Payment of Adjusted Purchase Price. The Adjusted Purchase Price shall be paid to Seller as follows:

(a) Contemporaneously with the execution and delivery of this Agreement, Buyer shall tender $7,025,000 cash to the Performance Deposit Escrow Agent as a deposit (the ”Performance Deposit”). The Performance Deposit shall be deposited by the Performance Deposit Escrow Agent in an interest bearing account. The Performance Deposit and any interest or other earnings earned thereon shall be applied (i) to the Adjusted Purchase Price at the Closing pursuant to Section 2.4(b), (ii) retained by Everlast pursuant to Section 10.2 or (iii) returned to Buyer pursuant to Section 10.2, as applicable.

(b) At the Closing, Buyer shall pay to Everlast cash equal to the Adjusted Purchase Price less (i) the Performance Deposit and any interest or other earnings earned thereon (which amount shall be released to Seller at Closing) and (ii) the Indemnification Support Deposit (which amount shall be paid into escrow by Buyer pursuant to the Indemnification Support Escrow Agreement at Closing as provided in Section 11.9(a)).

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(c) All cash payments by Buyer to Everlast pursuant to this Section 2.4(c) shall be made in immediately available funds by confirmed wire transfer to a bank account designated in writing by Everlast to Buyer.

Section 2.5. Allocation of Purchase Price. Buyer and Seller agree that each shall separately prepare a good faith allocation of the Adjusted Purchase Price (plus any fixed liabilities assumed by the Seller or to which the Properties are subject) among the Properties using the methodology required by Section 1060 of the Code. Buyer and Seller shall report the transactions contemplated hereby on all Tax Returns, including Form 8594, in a manner consistent with its respective allocation made in this manner. If any taxing authority makes or proposes an allocation different from the allocation determined by such party under this Section 2.5, such party may contest such allocation (or proposed allocation) and shall provide written notice to the other parties of such fact and shall provide such additional written notices as are reasonable to the other parties to make them aware of the status and final disposition of such contest of the allocation made or proposed by such taxing authority. Further, after providing written notice to the party adversely affected by such allocation (or proposed allocation) by a taxing authority, the other party hereto may file such protective claims or Tax Returns as may be reasonably required to protect its interests.

ARTICLE III

THE CLOSING

The closing of the transactions contemplated hereby (the “Closing”) shall take place (i) at the offices of Thompson & Knight LLP, Houston, Texas, at 10:00 a.m. (local Houston, Texas time) on June 13, 2005, or (ii) at such other time or place or on such other date as the parties hereto shall agree. The date on which the Closing is required to take place is herein referred to as the “Closing Date”. All Closing transactions shall be deemed to have occurred simultaneously.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SELLER

Seller hereby represents and warrants to Buyer as follows:

Section 4.1. Organization and Existence. Each of Everlast, RB Marketing and RB Operating is a limited liability company duly formed, validly existing, and in good standing under the laws of the State of Delaware. Each of Everlast, RB Marketing and RB Operating is duly qualified to transact business and is in good standing in the State of Alabama.

Section 4.2. Power and Authority. Seller has all requisite limited liability company power and authority to carry on its business as presently conducted, to execute, deliver, and perform this Agreement and each other agreement, instrument, or document executed or to be executed by party in connection with the transactions contemplated hereby to which it is a party and to consummate the transactions contemplated hereby and thereby. The execution, delivery, and performance by Seller of this Agreement and each other agreement, instrument, or document executed or to be executed by Seller in connection with the transactions contemplated hereby to

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which it is a party, and the consummation by it of the transactions contemplated hereby and thereby, have been or shall be duly authorized by all necessary limited liability company or member action of Seller.

Section 4.3. Valid and Binding Agreement. This Agreement has been duly executed and delivered by Seller and constitutes, and each other agreement, instrument, or document executed or to be executed by Seller in connection with the transactions contemplated hereby to which it is a party has been, or when executed will be, duly executed and delivered by Seller and constitutes, or when executed and delivered will constitute, a valid and legally binding obligation of Seller, enforceable against it in accordance with their respective terms, except that such enforceability may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium, and similar laws affecting creditors’ rights generally and (ii) equitable principles which may limit the availability of certain equitable remedies (such as specific performance) in certain instances.

Section 4.4. Non-Contravention. If Seller obtains the consents to assignment (or waivers of preferential rights to purchase) from third parties listed on Section 6.5 of the Seller Disclosure Schedule, then neither the execution, delivery, and performance by Seller of this Agreement and each other agreement, instrument, or document executed or to be executed by Seller in connection with the transactions contemplated hereby to which it is a party nor the consummation by it of the transactions contemplated hereby and thereby do and will (i) conflict with or result in a violation of Seller’s Governing Documents, (ii) conflict with or result in a violation of any provision of, or constitute (with or without the giving of notice or the passage of time or both) a default under, or give rise (with or without the giving of notice or the passage of time or both) to any right of termination, cancellation, modification, or acceleration under, any bond, debenture, note, mortgage or indenture, or any material lease, contract, agreement, or other instrument or obligation to which Seller is a party or by which Seller or any of the Properties may be bound, (iii) result in the creation or imposition of any lien or other encumbrance upon the Properties, or (iv) violate any Applicable Law binding upon Seller.

Section 4.5. Approvals. Other than the consents to assignment (or waivers of preferential rights to purchase) from third parties listed on Section 6.5 of Seller’s’ Disclosure Schedule, no consent, approval, order, or authorization of, or declaration, filing, or registration with, any Governmental Entity or of any third party is required to be obtained or made by Seller in connection with the execution, delivery, or performance by Seller of this Agreement, each other agreement, instrument, or document executed or to be executed by Seller in connection with the transactions contemplated hereby to which it is a party or the consummation by it of the transactions contemplated hereby and thereby.

Section 4.6. Pending Litigation. Except as set forth in Section 4.6 of the Seller Disclosure Schedule, there are no Proceedings pending or, to Seller’s Knowledge, threatened against or affecting Seller or any of the Properties (including any actions challenging or pertaining to Seller’s title to any of the Properties), or affecting the execution and delivery of this Agreement by Seller or the consummation of the transactions contemplated hereby by Seller.

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Section 4.7. Contracts.

(a) The oil, gas or mineral leases, Seller’s interests in which comprise parts of the Oil and Gas Properties, and all other material contracts and agreements, licenses, permits and easements, rights-of-way and other rights-of-surface use comprising any part of or otherwise relating to the Properties, a list of which is set forth in Section 4.7 of the Seller Disclosure Schedule (such leases and such material contracts, agreements, licenses, permits, easements, rights-of-way and other rights-of-surface use being herein called the “Basic Documents”), are in full force and effect and constitute valid and binding obligations of the parties thereto. Seller is not in breach or default (and no situation exists which with the passing of time or giving of notice would create a breach or default) of its obligations under the Basic Documents, and (to Seller’s Knowledge) no breach or default by any third party (or situation which with the passage of time or giving of notice would create a breach or default) exists. All payments (including all delay rentals, royalties, shut-in royalties and valid calls for payment or prepayment under operating agreements) owing under Basic Documents have been and are being made (timely, before the same became delinquent, and otherwise in accordance with the terms and conditions of the instruments creating such obligations) (i) by Seller (and, where the payment of same is the responsibility of a third party, have been and are being properly and timely made, to Seller’s Knowledge, by such third parties) and (ii) to Seller where Seller is the beneficiary of such payment.

(b) Section 4.7 of the Seller Disclosure Schedule is a list of all material contracts and agreements to which any of the Properties are bound, including (i) joint operating agreements, (ii) agreements with any Affiliate of Seller, (iii) any Production Sales Contracts, (iv) any agreement of Seller to sell, lease, farmout or otherwise dispose of any of its interests in the Oil and Gas Properties other than conventional rights of reassignment, (v) gas balancing agreements, (vi) transportation agreements, gathering agreements, disposal agreements, and exploration agreements, (vii) pooling, unitization or communitization agreements, (viii) area of mutual interest agreements, (ix) Hedges, (x) agreements containing seismic licenses, permits and other rights to geological or geophysical data and information directly or indirectly relating to the Oil and Gas Properties, and (xi) any contract that contains an indemnity with respect to environmental or health and safety matters (an “Environmental Indemnity Contract”). Seller has not received any claim for indemnity under any Environmental Indemnity Contract nor had Knowledge of any such claim at the time of consummating the transactions contemplated by the Torch Purchase and Sale Agreement. The terms of the indemnity with respect to environmental or health and safety matters contained in each Environmental Indemnity Contract are reasonably customary for provisions of this type in accordance with generally accepted standards and practices in the oil and gas industry.

(c) With respect to each of the Existing Hedges, Section 4.7 of the Seller Disclosure Schedule sets forth the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), and the counterparty to each such agreement.

Section 4.8. Commitments, Abandonments or Proposals. Except as set forth in Section 4.8 of the Seller Disclosure Schedule: (i) Seller has incurred no expenses, and has made no commitments to make expenditures in connection with the ownership or operation of the Properties after the Effective Date, other than routine expenses incurred in the normal operation

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of existing wells on the Oil and Gas Properties in accordance with generally accepted practices in the oil and gas industry; (ii) Seller has not abandoned any wells (or removed any of the Equipment, except items promptly replaced by items of materially equal suitability and value) on the Oil and Gas Properties since the Effective Date; and (iii) no proposals are currently outstanding by Seller or other working interest owners to drill additional wells, or to deepen, plug back, or rework existing wells, or to conduct other operations for which consent is required under the applicable operating agreement, or to conduct any other operations other than normal operation of existing wells on the Oil and Gas Properties, or to abandon any wells, on the Oil and Gas Properties.

Section 4.9. Production Sales Contracts. There exist no agreements or arrangements for the sale of Hydrocarbons from the Oil and Gas Properties (including calls on, or other rights to purchase, production, whether or not the same are currently being exercised) other than (i) production sales contracts (in this Section, the “Scheduled Production Sales Contracts”) disclosed in Section 4.9 of the Seller Disclosure Schedule or (ii) agreements or arrangements which are cancelable on 60 days notice or less without penalty or detriment. Seller is presently receiving a price for all production from (or attributable to) each Oil and Gas Property covered by a Scheduled Production Sales Contract as computed in accordance with the terms of such contract, and, except as disclosed in Section 4.9 of the Seller Disclosure Schedule is not having deliveries of Hydrocarbons from any Oil and Gas Property subject to a Scheduled Production Sale Contract curtailed below such property’s delivery capacity. All of the proceeds from the sale of Hydrocarbons produced from or attributable to the Oil and Gas Properties are being properly and timely paid to Seller by the purchasers of such production without suspension or indemnity other than standard division order indemnities.

Section 4.10. Plugging and Abandonment. Except for wells listed in Section 4.10 of the Seller Disclosure Schedule, there are no dry holes, or shut in or otherwise inactive wells, located on the Oil and Gas Properties or on lands pooled or unitized therewith, except for wells that have been plugged and abandoned, and except for wells drilled to depths not included within the Oil and Gas Properties or within units in which the Oil and Gas Properties participate but which have never been completed in depths in which the Oil and Gas Properties participate. All wells on the Properties that were plugged and abandoned by Seller and, to Seller’s Knowledge, all wells on the Properties that were plugged and abandoned by any other Person, have been plugged and abandoned in accordance with all laws applicable to such plugging and abandonment at the time of such plugging and abandonment.

Section 4.11. Permits. Seller has all Permits necessary or appropriate to own and operate the Properties as presently being owned and operated, including Permits required under Environmental Laws, and such Permits are in full force and effect (and are transferable to Buyer or are subject to being routinely replaced by a license or permit issued to Buyer as a successor owner of the Properties). Except as set forth in Section 4.11 of the Seller Disclosure Schedule, Seller has not received written notice of any violations in respect of any Permits and, to Seller’s Knowledge, there are no violations in respect of any Permit and no one has communicated to Seller that there are any violations in respect of any Permit.

Section 4.12. Payment of Expenses. All expenses (including all bills for labor, materials and supplies used or furnished for use in connection with the Properties, and all severance, production, ad valorem and other similar taxes) relating to the ownership or operation

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by Seller of the Properties, have been, and are being, paid (timely, and before the same become delinquent) by Seller, except such expenses and taxes as are disputed in good faith by Seller and for which an adequate accounting reserve has been established by Seller. Seller is not delinquent with respect to its obligations to bear costs and expenses relating to the development and operation of the Oil and Gas Properties.

Section 4.13. Compliance with Laws.

(a) The ownership and operation of the Properties by Seller have been and currently are in compliance with all Applicable Laws.

(b) To Seller’s Knowledge, Seller is not currently subject to, or threatened with, any Proceedings alleging a violation by Seller of any Environmental Laws. To Seller’s actual knowledge, and except as disclosed in Section 4.11 of the Seller Disclosure Schedule, Seller is in compliance with all Environmental Laws.

Section 4.14. Imbalances; Prepayments. Section 4.14 of the Seller Disclosure Schedule sets forth all Imbalances as of the date set forth in such Section with respect to the Oil and Gas Properties. Seller is not obligated by virtue of a take or pay payment, advance payment or other similar payment (other than royalties, overriding royalties and similar arrangements reflected on Section 4.14 to Seller’s Disclosure Schedule), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to the Oil and Gas Properties at some future time without receiving payment therefor at or after the time of delivery.

Section 4.15. Intellectual Property. Seller owns or has valid licenses or other rights to use all patents, copyrights, trademarks, software, databases, geological data, geophysical data, engineering data, maps, interpretations and other technical information used by Seller in connection with its ownership and operation of the Properties as presently conducted, subject to the limitations contained in the agreements governing the use of the same, which limitations are customary for companies engaged in the business of the exploration and production of Hydrocarbons. Section 4.15 of Seller’s Disclosure Schedule lists any of the foregoing that (x) Seller is restricted or prohibited from transferring to Buyer under the terms of any third party license, confidentiality agreement, or other agreement and (y) require payment of a fee or other consideration to any third party prior to a transfer to Buyer.

Section 4.16. Taxes.

(a) All Taxes due and payable by Seller with respect to the Properties through the year 2004 have been paid.

(b) With respect to all Taxes related to the Properties, (i) all Tax Returns relating to the Properties required to be filed on or before the date hereof by Seller with respect to any Taxes for any period ending on or before the date hereof have been timely filed with the appropriate Governmental Entity, (ii) such Tax Returns are true and correct, and (iii) all Taxes reported on such Tax Returns have been paid, except those being contested in good faith. Section 4.16(b) of the Seller Disclosure Schedule lists and describes all Taxes being contested in good faith.

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(c) With respect to all Taxes related to the Properties (i) there is not currently in effect any extension or waiver by Seller of any statute of limitations of any jurisdiction regarding the assessment or collection of any Tax related to the Properties and (ii) there are no administrative proceedings or lawsuits pending against the Properties or Seller with respect to the Properties by any taxing authority.

(d) None of the Properties were bound as of the Effective Date or will be bound at Closing by any tax partnership agreement binding upon Seller.

Section 4.17. Fees and Commissions. Except as set forth on Section 4.17 of the Seller Disclosure Schedule, no broker, investment banker, financial advisor or other Person is entitled to any broker’s, finder’s, financial advisor’s or other similar fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of Seller.

Section 4.18. Equipment; Easements and Rights of Way.

(a) Section 4.18 of the Seller Disclosure Schedule lists all material equipment, machinery, inventory, fixtures and other real, personal and mixed property situated on the Oil and Gas Properties or used or held for use in connection with the ownership or operation of the Oil and Gas Properties, including well equipment, casing, rods, tanks, boilers, buildings, tubing, pumps, motors, separators, dehydrators, compressors, treaters, power lines, field processing facilities, flowlines, gathering lines, transmission lines and other pipelines, but not including the Excluded Assets (collectively, the “Equipment”).

(b) The Equipment is in an operable state of repair and working order and is adequate for the normal operation of the Oil and Gas Properties after Closing, in substantially the same manner as such operations were conducted on the Effective Date.

(c) Section 4.18 of the Seller Disclosure Schedule lists all wells, platforms, structures, flow lines, pipelines (including gathering lines), and other equipment, pits and holding ponds presently located on the Properties and used or held for use in connection with the operation of the Oil and Gas Properties. The easements, rights-of-way, surface use agreements, licenses, and similar instruments described on Part 2 of Exhibit I attached hereto: (i) when taken together form a single, continuous, and contiguous system of rights and privileges across and between the lands encumbered by such instruments; and (ii) the wells, platforms, structures, flow lines, pipelines (including gathering lines), and other equipment, pits and holding ponds identified in Section 4.18 of the Seller Disclosure Schedule are located within the lands encumbered by such instruments. None of the foregoing easements, rights-of-way, surface agreements, licenses and other instruments contain unduly burdensome or extraordinary payment obligations on the part of Seller.

Section 4.19. Title to Non-Oil and Gas Properties.

Seller has good, valid, and indefeasible title to all of the Properties (other than the Oil and Gas Properties, title to which is addressed in Section 8.1), free and clear of all Liens other than Permitted Encumbrances. Seller has not previously sold, conveyed, mortgaged (except pursuant to the Senior Credit Facility), or transferred or agreed to sell, convey, mortgage (except pursuant

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to the Senior Credit Facility), or transfer the Properties (inclusive of the Oil and Gas Properties), except for Hydrocarbons sold in the ordinary course and except for items of materials, supplies, machinery, equipment, improvements, or other personal property or fixtures, which have been sold or otherwise disposed of and replaced with an item of substantially equal suitability and which, for purposes of this Agreement, have become part of the Properties.

Section 4.20. Additional Seller’s Representations and Warranties.

(a) The Properties include all of the properties and assets acquired by Seller from Velasco pursuant to the Torch Purchase and Sale Agreement (exclusive of Hydrocarbons sold in the ordinary course and except for items of materials, supplies, machinery, equipment, improvements, or other personal property or fixtures, which have been sold or otherwise disposed of and replaced with an item of substantially equal suitability and which, for purposes of this Agreement, have become part of the Properties).

(b) All books, records and files of Seller pertaining to and included as a part of the Properties, including with respect to production, gathering, transportation and sale of Hydrocarbons, and corporate, accounting, and financial records: (i) have been prepared, assembled and maintained in accordance with usual and customary policies and procedures and (ii) fairly and accurately reflect the ownership, use, enjoyment and operation by Seller of their assets. The books and records of Seller are in the possession of Seller and are materially complete as are reasonably necessary for the operation of Seller’s business as it is currently conducted.

(i) Seller has complied with its duties and obligations under Section 15.3 of the Torch Purchase and Sale Agreement. In connection therewith, since January 1, 2003, Seller has made its calculation of the amounts owed to the Royalty Trust in respect of the Net Royalty Interest pursuant to Section 3.01 of the Royalty Trust Conveyance based on ninety-five percent (95%) of the Net NPI Proceeds (with “Net Royalty Interest and “Net NPI Proceeds” being as defined in the Royalty Trust Conveyance). Seller has not received any written or oral notice from the Royalty Trust, its representatives or any other Person that either Seller or TEAI has violated any duties or obligations it may owe to the Royalty Trust under the Royalty Trust Conveyance or contesting Seller’s calculations of the amounts owed to the Royalty Trust in respect of the Net Royalty Interest pursuant to Section 3.01 of the Royalty Trust Conveyance.

(ii) Except as provided Section 4.20(c)(ii) of the Seller Disclosure Schedule, as of March 31, 2005, there are no “Excess Infill Costs,” “Excess NPI Costs,” or “Excess Pre 1980 Costs” under the Royalty Trust Conveyance.

(d) Seller, as owner of the Properties, has operated the Properties in compliance with the provisions of the Royalty Trust Conveyance and has been and is currently in compliance with the terms and provisions of the Royalty Trust Conveyance; provided, that in connection therewith, Seller has calculated the “Gross Proceeds” (as defined in the Royalty Trust Conveyance) attributable to gas utilizing the Sonat index price (i.e., the price applicable to the Robinson’s Bend Field) and not the weighted average “Monthly Gas Price” (as defined in the

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Royalty Trust Conveyance) (it being acknowledged and agreed, however, that TEAI is nonetheless obligated to pay such amounts to the Royalty Trust utilizing the weighted average “Monthly Gas Price,” as stipulated in the Royalty Trust Conveyance).

(e) With respect to the 1993 Gas Purchase Contract:

(i) Neither Seller nor any predecessor to Seller nor any party to the 1993 Gas Purchase Contract has exercised the “Option” (as that term is defined in Section 4.03 of the 1993 Gas Purchase Contract).

(ii) Except as provided in Section 4.20(c)(ii) of the Seller Disclosure Schedule, there are no existing “Price Credits” (as that term is defined in the 1993 Gas Purchase Contract) under the 1993 Gas Purchase Contract in respect of the Robinson’s Bend Field.

(iii) Except as provided in Section 4.20(c)(iii) of the Seller Disclosure Schedule, there has been no “Production Deficiency” or “Production Excess” (as such terms are defined in the 1993 Gas Purchase Contract) in respect of the Robinson’s Bend Field.

(f) With respect to employee related matters:

(i) There are no liabilities, breaches, violations or defaults under any employee benefit plans maintained or contributed to by Seller or under which Seller has any liability or contingent liability which would subject the Properties, the Buyer or any of its employee benefit plans to any taxes, penalties or other liabilities. Neither the acquisition by the Buyer of the Properties nor the employment by the Buyer of any employees of Seller will, directly or indirectly, give rise to any withdrawal liability or potential withdrawal liability on the part of the Buyer with respect to any plan maintained by Seller or to which Seller has or has had any obligation to contribute for the benefit of any employees that is a “multiemployer plan” as that term is defined in Section 3(37)(A) of ERISA.

(ii) Seller has not violated and the Closing will not violate the WARN Act (as defined below) and any requisite periods under the WARN Act have expired. Seller shall give all notices required by the WARN Act, if any. As used herein, “WARN Act” means the Worker Adjustment and Retraining Notification Act, 29 U.S.C. §§ 2101-2109, any comparable state statutes and related regulations.

Section 4.21. Absence of Certain Changes.

Since the Effective Date, (a) none of the Properties has suffered any material destruction, damage, or loss, casualty or otherwise, in each case whether or not covered by insurance; and (b) Seller has operated and maintained the Oil and Gas Properties in accordance with the “prudent operator” standard and other good industry practices.

Section 4.22. Disclaimer of Warranties. Other than those expressly set out in this Article IV or in the Conveyance, Seller hereby expressly disclaims any and all representations or

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warranties with respect to the Properties or the transaction contemplated hereby, and Buyer agrees that the Properties are being sold by Seller “where is” and “as is”, with all faults. Specifically as a part of (but not in limitation of) the foregoing, Buyer acknowledges that Seller has not made, and Seller hereby expressly disclaims, any representation or warranty (express, implied, under common law, by statute or otherwise) as to the condition of the Properties other than those expressly set out in this Article IV or in the Conveyance (INCLUDING ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS). OTHER THAN THOSE EXPRESSLY SET OUT IN THIS ARTICLE IV OR IN THE CONVEYANCE, SELLER MAKES NO REPRESENTATION OR WARRANTY AS TO (I) THE AMOUNT, VALUE, QUALITY, QUANTITY, VOLUME, OR DELIVERABILITY OF ANY OIL, GAS, OR OTHER MINERALS OR RESERVES (IF ANY) IN, UNDER, OR ATTRIBUTABLE TO THE PROPERTIES, (II) THE PHYSICAL, OPERATING, REGULATORY COMPLIANCE, SAFETY, OR ENVIRONMENTAL CONDITION OF THE PROPERTIES, BOTH SURFACE AND SUBSURFACE, INCLUDING MATTERS RELATED TO THE PRESENCE, RELEASE OR DISPOSAL OF HAZARDOUS MATERIALS, SOLID WASTES, ASBESTOS OR NATURALLY OCCURRING RADIOACTIVE MATERIALS (“NORM”), (III) THE GEOLOGICAL OR ENGINEERING CONDITION OF THE PROPERTIES OR ANY VALUE THEREOF OR (IV) THE ROYALTY TRUST, THE ROYALTY TRUST CONVEYANCE (INCLUDING THE CALCULATION OR STATUS OF THE “NET OVERRIDING ROYALTY” THEREUNDER), THE ROYALTY TRUST AGREEMENT AND ALL OTHER DOCUMENTS OR INSTRUMENTS IN CONNECTION WITH OR RELATED TO THE ROYALTY TRUST, THE ROYALTY TRUST CONVEYANCE OR THE ROYALTY TRUST AGREEMENT. OTHER THAN THOSE EXPRESSLY SET OUT IN THIS ARTICLE IV OR IN THE CONVEYANCE, SELLER MAKES NO WARRANTY OR REPRESENTATION, EXPRESS, STATUTORY, OR IMPLIED, AS TO (A) THE ACCURACY, COMPLETENESS, OR MATERIALITY OF ANY DATA, INFORMATION, OR RECORDS FURNISHED TO BUYER IN CONNECTION WITH THE PROPERTIES OR OTHERWISE CONSTITUTING A PORTION OF THE PROPERTIES; (B) THE ABILITY OF THE PROPERTIES TO PRODUCE HYDROCARBONS, INCLUDING PRODUCTION RATES, DECLINE RATES, AND RECOMPLETION OPPORTUNITIES; (C) IMBALANCE OR PAYOUT ACCOUNT INFORMATION, ALLOWABLES, OR OTHER REGULATORY MATTERS, (D) THE PRESENT OR FUTURE VALUE OF THE ANTICIPATED INCOME, COSTS, OR PROFITS, IF ANY, TO BE DERIVED FROM THE PROPERTIES, (E) ANY PROJECTIONS AS TO EVENTS THAT COULD OR COULD NOT OCCUR, AND (F) ANY OTHER MATTERS CONTAINED IN OR OMITTED FROM ANY INFORMATION OR MATERIAL FURNISHED TO BUYER BY SELLER OR OTHERWISE CONSTITUTING A PORTION OF THE PROPERTIES.

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ARTICLE V

REPRESENTATIONS AND WARRANTIES OF BUYER

Section 5.1. Organization and Existence. Buyer is a limited liability company duly organized, legally existing and in good standing under the laws of the State of Delaware, and is qualified to do business and in good standing in the State of Alabama.

Section 5.2. Power and Authority. Buyer has full limited liability company power and authority to carry on its business as presently conducted, to execute, deliver, and perform this Agreement and each other agreement, instrument, or document executed or to be executed by Buyer in connection with the transactions contemplated hereby to which it is a party and to consummate the transactions contemplated hereby and thereby. The execution, delivery, and performance by Buyer of this Agreement and each other agreement, instrument, or document executed or to be executed by Buyer in connection with the transactions contemplated hereby to which it is a party, and the consummation by it of the transactions contemplated hereby and thereby, have been or shall be duly authorized by all necessary limited liability company or member action of Buyer.

Section 5.3. Valid and Binding Agreement. This Agreement has been duly executed and delivered by Buyer and constitutes, and each other agreement, instrument, or document executed or to be executed by Buyer in connection with the transactions contemplated hereby to which it is a party has been, or when executed will be, duly executed and delivered by Buyer and constitutes, or when executed and delivered will constitute, a valid and legally binding obligation of Buyer, enforceable against it in accordance with their respective terms, except that such enforceability may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium, and similar laws affecting creditors’ rights generally and (ii) equitable principles which may limit the availability of certain equitable remedies (such as specific performance) in certain instances.

Section 5.4. Non-Contravention. The execution, delivery, and performance by Buyer of this Agreement and each other agreement, instrument, or document executed or to be executed by Buyer in connection with the transactions contemplated hereby to which it is a party and the consummation by it of the transactions contemplated hereby and thereby do not and will not (i) conflict with or result in a violation of any provision of Buyer’s Governing Documents, (ii) conflict with or result in a violation of any provision of, or constitute (with or without the giving of notice or the passage of time or both) a default under, or give rise (with or without the giving of notice or the passage of time or both) to any right of termination, cancellation, or acceleration under, any bond, debenture, note, mortgage, indenture, lease, contract, agreement, or other instrument or obligation to which Buyer is a party or by which Buyer or any of its properties may be bound, (iii) result in the creation or imposition of any lien or other encumbrance upon the properties of Buyer, or (iv) violate any Applicable Law binding upon Buyer.

Section 5.5. Approvals. No consent, approval, order, or authorization of, or declaration, filing, or registration with, any court or governmental agency or of any third party is required to be obtained or made by Buyer in connection with the execution, delivery, or performance by Buyer of this Agreement and each other agreement, instrument, or document

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executed or to be executed by Buyer in connection with the transactions contemplated hereby to which it is a party or the consummation by it of the transactions contemplated hereby and thereby.

Section 5.6. Pending Litigation. There are no Proceedings pending or, to Buyer’s Knowledge, threatened against or affecting the execution and delivery of this Agreement by Buyer or the consummation of the transactions contemplated hereby by Buyer.

Section 5.7. Knowledgeable Purchaser. Buyer is a knowledgeable purchaser, owner and operator of oil and gas properties, has the ability to evaluate (and in fact has evaluated) the Properties for purchase. Buyer is an “accredited investor,” as defined in Regulation D promulgated pursuant to the Securities Act, and is acquiring the Properties for its own account and not with the intent to make a distribution within the meaning of the Securities Act (and the rules and regulations pertaining thereto) or a distribution thereof in violation of any other applicable securities laws. Buyer has had access to the Properties, the officers and consultants of Seller, and the books, records, and files of Seller relating to the Properties. In making the decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has relied upon the representations and warranties, covenants and other agreements of Seller in this Agreement as well as its own independent due diligence investigation of the Properties, its own expertise and legal, land, tax, reservoir engineering, and other professional counsel concerning this transaction, the Properties and the value thereof.

Section 5.8. Funds. Buyer has, and at the Closing will have, sufficient cash and other sources of immediately available funds, as are necessary in order to pay the Adjusted Purchase Price to Seller at the Closing and otherwise consummate the transactions contemplated hereby.

Section 5.9. Qualified Leaseholder. Unless required sooner by Applicable Law as a result of its ownership of the Properties, within one hundred eighty (180) days of Closing, Buyer will be in compliance with the bonding requirements of the State of Alabama and other Governmental Entities; after Closing, Buyer reasonably anticipates that it will continue to be able to meet such bonding requirements.

Section 5.10. Fees and Commissions. No broker, investment banker, financial advisor or other Person is entitled to any broker’s, finder’s, financial advisor’s or other similar fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of Buyer.

ARTICLE VI

CERTAIN COVENANTS OF SELLER PENDING CLOSING

Section 6.1. Access to Files. Subject to the terms of the Confidentiality Agreement and Article IX, from the date hereof until Closing, Seller will give Buyer, and its attorneys and other authorized representatives, access at all reasonable times to the Properties and to any contract files, lease or other title files, production files, well files and other files of Seller pertaining to the ownership or operation of the Properties, and Seller will use its Reasonable Best Efforts to arrange for Buyer, and its attorneys and other representatives, to have access to any such files in the office of Seller.

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Section 6.2. Conduct of Operations. Subject to the restrictions set forth in Section 6.3, from the Effective Date until the date hereof, Seller has, and from the date hereof until Closing, Seller will (i) continue the routine operation of the Properties in the ordinary course of business and as would a prudent operator; (ii) operate the Properties in material compliance with all Applicable Laws and Environmental Laws and in material compliance with all Basic Documents; (iii) fulfill all material obligations under the Basic Documents and, in all material respects, under such Applicable Laws and Environmental Laws (iv) use its Reasonable Best Efforts to preserve relationships and good will with all third parties having business dealings with respect to the Properties; and (v) maintain in effect insurance providing the same type coverage, in the same or higher amounts and with the same deductibles as the insurance maintained in effect by Seller or its Affiliates on the Effective Date.

Section 6.3. Restrictions on Certain Actions. From the date hereof until Closing, Seller will not, without Buyer’s prior consent:

(a) expend any funds, or make any commitments to expend funds (including entering into new agreements which would obligate Seller to expend funds), or otherwise incur any other obligations or liabilities, other than to pay expenses or to incur liabilities in connection with routine operation of the Properties after the Effective Date and except (i) for those commitments listed in Section 4.8 of the Seller Disclosure Schedule and (ii) in the event of an emergency requiring immediate action to protect life or preserve the Properties;

(b) except where necessary to prevent the termination of an oil and gas lease or other material agreement governing Seller’s interest in the Properties (and then not without delivering prior notice describing the action proposed to be taken to Buyer), propose the drilling of any additional wells, or propose the deepening, plugging back or reworking of any existing wells, or propose the conducting of any other operations which require consent under the applicable operating agreement, or propose the conducting of any other operations other than the normal operation of the existing wells on the Oil and Gas Properties, or enter into or modify any pooling or unitization agreement, or propose the abandonment of any wells on the Oil and Gas Properties (and Seller agrees that it will advise Buyer of any such proposals made by third parties and will respond to each such proposal made by a third party in the manner requested by Buyer);

(c) sell, transfer or abandon any portion of the Properties other than items of materials, supplies, machinery, equipment, improvements or other personal property or fixtures forming a part of the Properties (and then only if the same is replaced with an item of substantially equal suitability, free of liens and security interests, which replacement item will then, for the purposes of this Agreement, become part of the Properties); or

(d) release (or permit to terminate), or modify or reduce its rights under, any oil, gas or mineral lease forming a part of the Oil and Gas Properties, or any other Basic Document, or enter into any new agreements which would constitute a Basic Document, or modify any existing production sales contracts or enter into any new production sales contracts, except contracts terminable by Seller with notice of 60 days or less.

Section 6.4. Payment of Expenses. Seller will cause all expenses (including all bills for labor, materials and supplies used or furnished for use in connection with the Properties and all severance, production, and similar taxes) relating to the ownership or operation of the

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Properties prior to the date of Closing to be promptly paid and discharged, except for expenses disputed in good faith. At Closing, Seller shall deliver a list of all expenses being so disputed to Buyer.

Section 6.5. Preferential Rights and Third Party Consents. No later than two (2) Business Days after its execution of this Agreement, Seller will request, from the appropriate parties (and in accordance with the documents creating such rights and/or requirements), waivers of the preferential rights to purchase, or requirements that consent to assignment be obtained, which are identified in Section 6.5 of the Seller Disclosure Schedule. Subject to Section 7.1 and Section 9.1(k), Seller shall have no obligation hereunder other than to so request such waivers (i.e., Seller shall have no obligation to assure that such waivers are obtained), and if all such waivers (or any other waivers of preferential rights to purchase or requirements that consent be obtained to assignment, even if the same are not listed on such Section 6.5) are not obtained, Buyer may treat any waiver which is not obtained as a matter which causes Seller’s title to not be sufficient to meet the standards set forth in Article VIII notwithstanding any limitations or deadlines for Buyer’s giving notice or for the dollar value of such Title Defects; provided, however, that if the unobtained waiver is a waiver of a preferential right to purchase, and if both Buyer and Seller agree to this treatment of such matter, Seller will tender the required interest in the Property affected by such unwaived preferential right to purchase to the holder, or holders, of such right who have elected not to waive such preferential right to purchase, and if, and to the extent that, such preferential right to purchase is exercised by such party or parties, such interest in such Property will be excluded from the transaction contemplated hereby and the Purchase Price will be reduced by the Allocated Value of such Property. If Buyer elects to treat a Property subject to such a preferential right as a Title Defect, Buyer shall be entitled to a reduction in the Purchase Price equal to the Allocated Value of such Property without regard to the $50,000 hurdle in Section 8.1 or the deductible otherwise applicable to Title Defects.

Section 6.6. No-Shop Provision.

From and after the date hereof and prior to the earlier of Closing or termination of this Agreement as permitted under Article X, Seller shall not, and shall cause their respective Affiliates not to, conduct any discussions with any third party with respect to (a) the purchase, sale, transfer, disposition, acquisition, or any other transaction involving all or any portion of the Properties or (b) any merger, consolidation, issuance of securities, or other transaction involving the ownership interests of Seller that could affect the transactions contemplated in this Agreement or which would conflict with the intent of this Agreement. In addition, Seller shall not, and shall cause their respective Affiliates not to, nor will any of them authorize or permit any of their respective officers, directors or employees or any attorneys, accountants, investment bankers or other representatives retained by any of them to, directly or indirectly, solicit or encourage (including by way of furnishing information) any inquiries or the making of any proposal which it is reasonably expected may lead to any such transaction.

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ARTICLE VII

ADDITIONAL PRE-CLOSING AND POST-CLOSING AGREEMENTS OF BOTH PARTIES

Section 7.1. Reasonable Best Efforts. Each party hereto agrees that it will not voluntarily undertake any course of action inconsistent with the provisions or intent of this Agreement and will use its Reasonable Best Efforts to take, or cause to be taken, all action and to do, or cause to be done, all things reasonably necessary, proper, or advisable under Applicable Laws to consummate the transactions contemplated by this Agreement, including (i) cooperation in determining whether any consents, approvals, orders, authorizations, waivers, declarations, filings, or registrations of or with any Governmental Entity or third party are required in connection with the consummation of the transactions contemplated hereby; (ii) Reasonable Best Efforts to obtain any such consents, approvals, orders, authorizations, and waivers and to effect any such declarations, filings, and registrations; (iii) Reasonable Best Efforts to cause to be lifted or rescinded any injunction or restraining order or other order adversely affecting the ability of the parties to consummate the transactions contemplated hereby; (iv) Reasonable Best Efforts to defend, and cooperation in defending, all Proceedings challenging this Agreement or the consummation of the transactions contemplated hereby; and (v) the execution of any additional instruments necessary to consummate the transactions contemplated hereby. Buyer agrees to give prompt notice to Seller of any third party consents to the transfer of any of the Properties of which Buyer becomes aware prior to Closing and not listed in Section 6.5 of the Seller Disclosure Schedule.

Section 7.2. Notice of Litigation. Until the Closing, (i) Buyer, upon learning of the same, shall promptly notify Seller of any Proceeding which is commenced or threatened against Buyer and which affects this Agreement, the Properties, or the transactions contemplated hereby and (ii) Seller, upon learning of the same, shall promptly notify Buyer of any Proceeding which is commenced or threatened against Seller and which affects this Agreement, the Properties, or the transactions contemplated hereby.

Section 7.3. Notification of Certain Matters. Until the Closing, Seller shall give prompt notice to Buyer of: (i) the occurrence or nonoccurrence of any event the occurrence or nonoccurrence of which, to Seller’s Knowledge, would be likely to cause any representation or warranty made by Seller in Article IV to be untrue or inaccurate at or prior to the Closing and (ii) any failure of Seller to comply with or satisfy any covenant, condition, or agreement to be complied with or satisfied by Seller hereunder prior to Closing. Until the Closing, Buyer shall give prompt notice to Seller of: (i) the occurrence or nonoccurrence of any event the occurrence or nonoccurrence of which, to Buyer’s Knowledge, would be likely to cause any representation or warranty contained in Article V to be untrue or inaccurate at or prior to the Closing, and (ii) any failure of Buyer to comply with or satisfy any covenant, condition, or agreement to be complied with or satisfied by Buyer hereunder prior to Closing. The delivery of any notice pursuant to this Section shall not be deemed to (x) modify the representations or warranties hereunder of the party delivering such notice, (y) modify the conditions set forth in Article X or (z) limit or otherwise affect the remedies available hereunder to the party receiving such notice.

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Section 7.4. Fees and Expenses.

(a) Except as otherwise provided herein, (i) all fees and expenses incurred in connection with this Agreement by Seller will be borne by and paid by Seller and (ii) all fees and expenses incurred in connection with this Agreement by Buyer will be borne by and paid by Buyer.

(b) All required documentary, filing and recording fees and expenses in connection with the filing and recording of the Conveyance and other instruments required to convey title to the Properties to Buyer shall be borne by Buyer. Buyer shall assume responsibility for, and shall bear and pay, all state sales and use taxes (including any applicable interest or penalties) incurred or imposed with respect to the transactions contemplated by this Agreement.

Section 7.5. Public Announcements. (a) Except as may be required by Applicable Law, Seller shall not shall issue any press release or otherwise make any statement to the public generally with respect to this Agreement or the transactions contemplated hereby without the prior consent of Buyer (which consent, if given verbally, shall be confirmed in writing within one Business Day thereafter). Any such press release or statement required by Applicable Law shall only be made after reasonable advance notice to Buyer (which notice shall include the proposed press release or statement) and consultation.

(b) Except as may be required by Applicable Law, Buyer shall not shall issue any press release or otherwise make any statement to the public generally with respect to this Agreement or the transactions contemplated hereby without reasonable advance notice to Seller (which notice shall include the proposed press release or statement) and consultation.

Section 7.6. Acquisition of Royalty Interest or Royalty Trust Units. Buyer agrees that Buyer will not, directly or indirectly, (i) acquire, offer to acquire or agree to acquire the net royalty interest owned by the Royalty Trust, (ii) enter, offer or agree to enter into any investment, acquisition or other business combination relating to the Royalty Trust, (iii) solicit or join in the solicitation of proxies to vote any units of the Royalty Trust, or (iv) assist or join a third party in any way related to the foregoing. This covenant and agreement contained in this Section shall expire only upon the consummation of the transactions contemplated hereby; otherwise, such covenants and agreement shall survive for four (4) years from the date of this Agreement, notwithstanding the termination of this Agreement.

Section 7.7. Casualty Loss Prior to Closing. Seller shall promptly notify Buyer of any Casualty Loss to the Properties of which Seller is or becomes aware. In the event of a Casualty Loss to the Properties after the Effective Date and prior to the Closing, then this Agreement shall remain in full force and effect, and (unless Buyer and Seller shall otherwise agree) in such event:

(a) With respect to any Oil and Gas Property that suffers a Casualty Loss, at Buyer’s election (i) such Oil and Gas Property shall be treated as if it were the subject of a properly asserted and undisputed Title Defect and the Purchase Price shall be reduced by the amount calculated pursuant to Article VIII with respect thereto or (ii) the Purchase Price shall not be reduced as a result of such Casualty Loss, and if Seller shall be entitled to make any claims under any insurance policy with respect to such Casualty Loss, at Buyer’s election, Seller shall either collect (and, when collected, pay to Buyer) insurance proceeds therefor, or assign to Buyer all Seller’s right, title, and interest in such insurance claims; and

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(b) With respect to any Property other than an Oil and Gas Property that suffers a Casualty Loss, Buyer may elect to (a) reduce the Purchase Price by an amount determined before the Closing by PriceWaterhouseCoopers (or, if such firm is unable or unwilling to serve, another independent public accounting firm mutually acceptable to Seller and Buyer), in which case Seller shall retain, all insurance proceeds relating to such Casualty Loss, or (b) require Seller to (i) transfer to Buyer at Closing all unpaid insurance proceeds, claims, awards and other payments arising out of such Casualty Loss, and (ii) pay to Buyer all sums paid to Seller as insurance proceeds, awards or other payments arising out of such Casualty Loss, whether such sums are paid to Seller prior to or after Closing. There shall not be an adjustment to the Purchase Price if Buyer elects to proceed pursuant to subsection (b) of this Section 7.7.

(c) Seller shall not voluntarily compromise, settle, or adjust any amounts payable by reason of any Casualty Loss without first obtaining the written consent of Buyer.

Section 7.8. Governmental Bonds. Unless required sooner by Applicable Law as a result of its ownership of the Properties, within one hundred eighty (180) days of Closing, Buyer shall deliver to Seller evidence that Buyer has completed all action necessary to permit Buyer to post bonds or other security immediately following the Closing with all applicable Governmental Entities meeting the requirements of such Governmental Entities to own, and where appropriate, operate, the Properties.

Section 7.9. Assumed Obligations. Except as otherwise specifically provided in Seller’s indemnification obligations set forth in Section 11.2 and subject to the immediately following sentence, at Closing Buyer shall assume and agree to pay, perform and discharge the Assumed Obligations. Seller agrees to deliver or cause to be delivered to Buyer at Closing written assurances reasonably acceptable to Buyer from the parties to the Torch Purchase and Sale Agreement (exclusive of Seller) to the effect that if, after the Closing, Buyer calculates the “Gross Proceeds” (as defined in the Royalty Trust Conveyance) attributable to gas utilizing the Sonat index price, it will not be deemed to be in violation of its covenants and obligations under Section 15.3 of the Torch Purchase and Sale Agreement.

Section 7.10. Books and Records. At or promptly after Closing, but in no event later than 15 days after Closing, Seller will deliver to Buyer all relating books and records that are a part of the Properties to a location designated by Buyer. Buyer will promptly reimburse Seller for all reasonable costs of shipping or transporting such books and records. Seller (or its Affiliates) shall have the right to have reasonable access during Buyer’s reasonable and customary business hours to inspect and copy (at Seller’s or such Affiliate’s expense) the books and records so delivered under this Section 7.10 for the six-year period commencing on the Closing Date.

Section 7.11. Suspended Funds. As soon as practicable after the Closing, but no later than 30 days thereafter, Seller shall provide to Buyer a listing showing all proceeds from production attributable to the Oil and Gas Properties which are currently held in suspense by Seller and shall transfer to Buyer all those suspended proceeds (the “Suspended Proceeds”). Thereafter, Buyer shall be responsible for proper distribution of the Suspended Proceeds to the parties lawfully entitled to them to the extent and only to the extent of Suspended Proceeds.

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Section 7.12. Letters-in-Lieu. Either at or after Closing (provided Buyer has given five Business Days advance request for same) Seller shall execute and deliver letters in lieu of transfer orders (or similar documentation) in form reasonably acceptable to Buyer and Seller.

Section 7.13. Logos and Names.

As soon as practicable after the Closing, Buyer will remove or cause to be removed the names and marks used by Seller and all variations and derivatives thereof and logos relating thereto from the Properties. Seller’s names and marks shall be deemed to be removed to the extent Buyer covers any stickers bearing Seller’s names and/or marks with stickers bearing Buyer’s name, marks, or logo.

Section 7.14. Transition Services Agreement.

At Closing, Buyer and Seller shall enter into a “Transition Services Agreement” (as herein called) on substantially the following terms and conditions: (i) Seller shall provide certain services to Buyer with respect to its ownership and operation of the Properties post-Closing; (ii) the services to be provided by Seller to Buyer will include services in respect of field operations (including development of the Properties or other implementation of capital expenditures at the direction of Buyer), lease and land administration, production marketing, accounting (including payment of accounts receivable, payment of royalties, computation and payment of severance and similar taxes, general ledger and financial reporting) and, without limiting the foregoing, services currently provided by Seller under Section 15.3 of the Torch Purchase and Sale Agreement (including calculation of the amounts due and owing the Royalty Trust under the Royalty Trust Conveyance); (iii) Seller will be compensated for providing such services in an amount equal to its actual cost but, in any event, not to exceed any limits on such compensation contained in the Royalty Trust Conveyance; (iv) the term of the agreement shall commence on the Closing Date and shall continue for a period of up to 180 days; (v) Seller shall perform its oil field services in a good and workmanlike manner as a prudent operator with due diligence and dispatch, in accordance with good oilfield practices, but shall have no liability to Buyer for any act or omission by Seller under the Transition Services Agreement except for such act or omission that constitutes fraud, willful misconduct or gross negligence; (vi) with respect to (x) accounting matters, Seller shall act in accordance with reasonable and customary practices and standards and (y) safekeeping and delivery of funds handled by Seller in the course of its services, Seller shall act as a fiduciary; (vii) Buyer shall indemnify and save Seller harmless from any costs, expenses or other damages incurred by Seller in connection with performing its services under the Transition Services Agreement, unless such costs, expenses or damages are as a result of Seller’s fraud, willful misconduct or gross negligence; and (viii) such other terms and conditions as are reasonable and customary in the oil and gas exploration and production business for agreements of this type in transactions of the type contemplated hereby. Subject to the foregoing, Buyer and Seller shall execute and deliver a Transition Services Agreement reasonably acceptable to both parties on or before the Closing Date.

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Section 7.15. Existing Hedges.

Between the date of this Agreement and the Closing, Buyer shall, in good faith, use its Reasonable Best Efforts to arrange for a financial institution to accept an assignment (or transfer of the economic risk and benefit) of the Existing Hedges from Wells Fargo Bank, N.A. at Closing subject to the terms of a mutually satisfactory master agreement governing the terms of the Existing Hedges; and provided further, that Buyer shall have no obligation to purchase any of the Existing Hedges, pay other than a nominal fee, or settle any outstanding amount due and owing the counter-party in respect of the Existing Hedges.

Section 7.16. 1993 Gas Purchase Contract.

Between the date of this Agreement and the Closing, Buyer shall, in good faith, use its Reasonable Best Effort to cause Torch Energy Marketing, Inc. (“TEMI”) to enter into arrangements reasonably satisfactory to Buyer to transfer the portion of the 1993 Gas Purchase Contract applicable to the Properties to Buyer or Buyer’s designee. In connection therewith, Buyer affirms for the benefit of Seller that, as of the date hereof, Buyer has discussed with TEMI an arrangement whereby, for the two-year period commencing the Closing Date, TEMI will provide gas marketing services to Buyer with respect to gas production from the Properties substantially similar to the services currently provided by TEMI to Seller in consideration of the payment by Buyer to TEMI of $30,000 per month plus 50% of any revenue created in excess of the revenue that would have been generated if the gas had been sold at the Sonat index price for the relevant period. While it is acknowledged and agreed that (i) such discussions are preliminary in nature, non-binding and subject to the negotiation, execution and delivery of definitive documentation acceptable to Buyer or (ii) that a different arrangement may hereafter be proposed by either Buyer or TEMI, Buyer nonetheless affirms that, in the context of the arrangement described above, the basic principal economic terms referenced above are generally acceptable to Buyer.

Section 7.17. Further Assurances. From time to time following the Closing, at the request of any party hereto and without further consideration, the other party or parties hereto shall execute and deliver to such requesting party such instruments and documents and take such other action (but without incurring any material financial obligation) as such requesting party may reasonably request in order to consummate more fully and effectively the transactions contemplated hereby.

ARTICLE VIII

DUE DILIGENCE EXAMINATION

Section 8.1. Title Due Diligence Examination.

(a) From the date of this Agreement until 5:00 p.m. (local time in Houston, Texas) on the third Business Day preceding the Closing Date (the “Examination Period”), Seller shall afford to Buyer and its authorized representatives reasonable access during normal business hours to the office, personnel and books and records of Seller in order for Buyer to conduct a title examination as it may in its sole discretion choose to conduct (i) with respect to Properties other than Oil and Gas Properties, to determine whether defects in Seller’s title exist, and

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(ii) with respect to the Oil and Gas Properties in order to determine whether Title Defects (as defined below) exist (“Buyer’s Title Review”). Such books and records shall include all abstracts of title, title opinions, title files, ownership maps, lease files, assignments, division orders, operating records and agreements, well files, financial and accounting records, geological, geophysical and engineering records, in each case insofar as same may now be in existence and in the possession of Seller, excluding, however, any information that Seller is prohibited from disclosing by bona fide, third party confidentiality restrictions; provided, that if requested by Buyer, Seller shall use its Reasonable Best Efforts to obtain a waiver of any such restrictions in favor of Buyer. The cost and expense of Buyer’s Title Review, if any, shall be borne solely by Buyer.

(b) If Buyer discovers any Title Defect affecting any of the Oil and Gas Properties, Buyer shall notify Seller prior to the expiration of the Examination Period of such alleged Title Defect. To be effective, such notice (“Title Defect Notice”) must (i) be in writing, (ii) be received by Seller prior to the expiration of the Examination Period, (iii) describe the Title Defect in reasonable detail (including any alleged variance in the Net Revenue Interest), (iv) identify the specific Oil and Gas Property affected by such Title Defect, and (v) include the value of such Title Defect as determined by Buyer in good faith. Any matters that may otherwise constitute Title Defects, but of which Seller has not been specifically notified by Buyer in accordance with the foregoing, shall be deemed to have been waived by Buyer for all purposes. Upon the receipt of such effective Title Defect Notice from Buyer, Seller shall have the option, in addition to the remedies set forth in Section 8.1(c) (the “Remedies for Title Defects”), but not the obligation, to attempt to cure such Title Defect at any time prior to the Closing. Each Oil and Gas Property affected by an uncured Title Defect shall be a “Title Defect Property”.

(c) With respect to each Title Defect that is not cured on or before the Closing, the Purchase Price shall be reduced, subject to this Article VIII, by the Title Defect Amount with respect to such Title Defect Property. The “Title Defect Amount” shall mean, with respect to a Title Defect Property, the amount by which such Title Defect Property is impaired as a result of the existence of one or more Title Defects, which amount shall be determined as follows:

(i) The Title Defect Amount with respect to a Title Defect Property shall be determined by taking into consideration the “Allocated Value” (as set forth in Exhibit 8.1(c) attached hereto) of the Oil and Gas Property subject to such Title Defect, the portion of the Oil and Gas Property subject to such Title Defect, and the legal effect of such Title Defect on the Oil and Gas Property affected thereby; provided, however, that: (A) if such Title Defect is in the nature of Seller’s Net Revenue Interest in an Oil and Gas Property being less than the Net Revenue Interest set forth in Exhibit 8.1(c) hereto and the Working Interest remains the same, then the Title Defect Amount shall equal the Allocated Value for the relevant Oil and Gas Property multiplied by the percentage reduction in such Net Revenue Interest as a result of such Title Defect or (B) if such Title Defect is in the nature of a Lien, then the Title Defect Amount shall equal the amount required to fully discharge such Lien; and

(ii) If the Title Defect results from any matter not described in Section 8.1(c)(i), the Title Defect Amount shall be an amount equal to the difference between the value of the Title Defect Property affected by such Title Defect with such Title Defect and the value of such Title Defect Property without such Title Defect (taking into account the portion of the Allocated Value of the Title Defect Property).

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(d) As used in this Section 8.1:

(i) “Defensible Title” means, as of the date of this Agreement and the Closing Date, with respect to the Oil and Gas Properties, such record title and ownership by Seller that:

(A) entitles Seller to receive and retain, without reduction, suspension or termination, not less than the percentage set forth in Exhibit 8.1(c) as Seller’s Net Revenue Interest of all Hydrocarbons produced, saved and marketed from each Lease comprising such Oil and Gas Property, through plugging, abandonment and salvage of all wells comprising or included in such Oil and Gas Property, and except for changes or adjustments that result from the establishment of units, changes in existing units (or the participating areas therein), or the entry into of pooling or unitization agreements, after the date hereof unless made in breach of the provisions of Section 6.3;

(B) obligates Seller to bear not greater than the percentage set forth in Exhibit 8.1(c) as Seller’s Working Interest of the costs and expenses relating to the maintenance, development and operation of each Lease comprising such Oil and Gas Property, through plugging, abandonment and salvage of all wells comprising or included in such Oil and Gas Property, and except for changes or adjustments that result from the establishment of units, changes in existing units (or the participating areas therein), or the entry into of pooling or unitization agreements, after the date hereof unless made in breach of the provisions of Section 6.3;

(D) reflects that such Oil and Gas Property is not burdened by a “Net Profits Interest” greater than that indicated for such Oil and Gas Property as set forth in Exhibit 8.1(c);

(E) reflects that all consents to assignment, notices of assignment or preferential purchase rights which are applicable to or must be complied with in connection with the transaction contemplated by this Agreement, or any prior sale, assignment or the transfer of such Oil and Gas Property, have been obtained and complied with to the extent the failure to obtain or comply with the same could render this transaction or any such sale, assignment or transfer (or any right or interest affected thereby) void or voidable or could result in Buyer or Seller incurring any liability; and

(F) is free of imperfections in title which a reasonable and experienced purchaser of oil and gas properties would, in accordance with customary and generally accepted industry practices and norms, consider a defect in title and not normally waive.

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(ii) “Permitted Encumbrances” shall mean (A) Liens for taxes which are not yet delinquent or which are being contested in good faith and for which adequate reserves have been established; (B) normal and customary Liens of co-owners under operating agreements, unitization agreements, and pooling orders relating to the Oil and Gas Properties, which obligations are not yet due and pursuant to which Seller is not in default; (C) mechanic’s and materialman’s Liens relating to the Oil and Gas Properties, which obligations are not yet due and pursuant to which Seller is not in default; (D) Liens in the ordinary course of business consisting of minor defects and irregularities in title or other restrictions (whether created by or arising out of joint operating agreements, farm-out agreements, leases and assignments, contracts for purchases of Hydrocarbons or similar agreements, or otherwise in the ordinary course of business) that are of the nature customarily accepted by prudent purchasers of oil and gas properties and do not decrease the Net Revenue Interest, increase the Working Interest (without a proportionate increase in the Net Revenue Interest) or that could not reasonably be expected to materially affect the value of any property encumbered thereby; (E) all approvals required to be obtained from Governmental Entities that are lessors under Leases forming a part of the Oil and Gas Properties (or who administer such Leases on behalf of such lessors) which are customarily obtained post-closing; (F) preferential rights to purchase and consent to transfer requirements of any Person (to the extent same have been complied with in connection with the prior sale, assignment or the transfer of such Oil and Gas Property and are not triggered by the consummation of the transactions contemplated herein); (G) Liens under the Senior Credit Facility (provided such Liens are released at Closing); and (H) conventional rights of reassignment normally actuated by an intent to abandon or release a lease and requiring notice to the holders of such rights.

(iii) “Title Defect” shall mean any particular defect in or failure of Seller’s ownership of any Oil and Gas Property: (A) that causes Seller to not have Defensible Title to such Oil and Gas Property and (B) that has attributable thereto a Title Defect Amount in excess of $50,000. “Title Defect” shall also mean any particular defects in or failures of Seller’s ownership of any Oil and Gas Properties: (A) that cause Seller to not have Defensible Title to such Oil and Gas Properties and (B) that has attributable thereto a Title Defect Amount that is, individually, less than $50,000 but that, when aggregated with all such Title Defect Amounts attributable to such defects or failures exceeds $500,000. Notwithstanding any other provision in this Agreement to the contrary, the following matters shall not constitute, and shall not be asserted as, a Title Defect: (A) defects or irregularities arising out of lack of corporate authorization which defects or irregularities have been outstanding for five years or more without being asserted as a defense to the action purported to be taken by the applicable entity; (B) defects or irregularities that have been cured or remedied by the applicable statutes of limitation or statutes for prescription; (C) defects or irregularities in the chain of title consisting of the failure to recite marital status in documents or omissions of heirship proceedings; (D) minor defects or irregularities in title which for a period of five years or more have not delayed or prevented Seller (or Seller’s predecessor) from receiving its Net Revenue Interest share of the proceeds of production and have not caused Seller to bear a share of expenses and costs greater than its Working Interest share from each Lease, unit or Well; and (E) defects or irregularities resulting from or related to probate proceedings or the lack thereof which defects or irregularities have been outstanding for five years or more

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without any person related to or affected by any instrument or property affected by such defects or irregularities asserting rights or privileges inconsistent with any such instrument or record title to such property.

(e) If Seller and Buyer are unable to reach an agreement as to whether a Title Defect exists or, if it does exist, the Title Defect Amount attributable such Title Defect, the provisions of Section 12.1 shall be applicable.

Section 8.2. Environmental Due Diligence Examination.

(a) Buyer shall have the right, or the right to cause an environmental consultant reasonably acceptable to Seller (“Buyer’s Environmental Consultant”), to conduct an environmental review of the Properties prior to the expiration of the Examination Period (“Buyer’s Environmental Review”). If not provided prior to the date hereof, Buyer shall furnish Seller with an outline of the proposed scope of its environmental review of the Properties promptly after the date hereof. The cost and expense of Buyer’s Environmental Review, if any, shall be borne solely by Buyer. No Person, other than Buyer’s Environmental Consultant and Buyer’s employees may conduct Buyer’s Environmental Review. Seller shall have the right to have representatives thereof present to observe Buyer’s Environmental Review conducted in Seller’s offices or on Seller’s properties. With respect to any samples taken in connection with Buyer’s Environmental Review, Seller shall be permitted to take split samples. Buyer agrees to conduct Buyer’s Environmental Review in a manner so as not to unduly interfere with the business operations of Seller and in compliance with all Applicable Laws, and Buyer shall exercise due care with respect to Seller’s properties and their condition.

(b) Prior to the Closing, unless otherwise required by Applicable Law or Environmental Law, Buyer shall (and shall cause Buyer’s Environmental Consultant, if applicable, to) treat confidentially any matters revealed by Buyer’s Environmental Review and any reports or data generated from such review (the “Environmental Information”), and Buyer shall not (and shall cause Buyer’s Environmental Consultant, if applicable, to not) disclose any Environmental Information to any Governmental Entity or other third party without the prior written consent of Seller. Prior to the Closing, unless otherwise required by Applicable Law or Environmental Law, Buyer may use the Environmental Information only in connection with the transactions contemplated by this Agreement. If Buyer, Buyer’s Environmental Consultant, if applicable, or any third party to whom Buyer has provided any Environmental Information become legally compelled to disclose any of the Environmental Information, Buyer shall provide Seller with prompt notice and Seller, at Seller’s expense, may file any protective order, or seek any other remedy, as it deems appropriate under the circumstances. If this Agreement is terminated prior to the Closing, Buyer shall deliver the Environmental Information to Seller, which Environmental Information shall become the sole property of Seller. Upon Seller’s written request to Buyer, Buyer shall provide copies of the Environmental Information to Seller without charge.

(c) If Buyer or Buyer’s Environmental Consultant, if applicable, discovers any Environmental Defect (as herein defined) prior to the expiration of the Examination Period, Buyer shall notify Seller prior to the expiration of the Examination Period of such alleged Environmental Defect. To be effective, such notice (an “Environmental Defect Notice”) must (i) be in writing; (ii) be received by Seller prior to the expiration of the Examination Period;

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(iii) describe the Environmental Defect in reasonable detail, including (A) the specific Properties affected by or associated with such Environmental Defect, (B) if applicable, a site plan showing the location of any sampling events, boring logs and other field notes describing the sampling methods utilized and the field conditions observed, if any, (C) the written conclusion of Buyer’s Environmental Consultant, if applicable, that an Environmental Defect is believed to exist, which conclusion shall be reasonably substantiated by the factual data gathered in Buyer’s Environmental Review, and (D) if feasible and applicable, a separate, reasonably specific citation of the provisions of the Environmental Laws alleged to be violated and the related facts that substantiate such violation; (iii) describe the procedures recommended to correct, eliminate or pay the Environmental Defect, together with any related recommendations from Buyer’s Environmental Consultant, if applicable; and (iv) set forth Buyer’s good faith estimate of the Environmental Defect Value, including the basis for such estimate. Any matters that may otherwise constitute Environmental Defects, but of which Seller has not been specifically notified by Buyer in accordance with the foregoing, together with any environmental matter that does not constitute an Environmental Defect, shall be deemed to have been waived by Buyer for purposes of this Section 8.3; provided, however, nothing in this Section 8.3 shall be construed or deemed to limit Buyer’s rights to indemnification from Seller with respect to any Environmental Defects comprising any part of the Non-Assumed Obligations. Upon the receipt of such effective notice from Buyer, Seller shall have the option, in addition to the remedy set forth in Section 8.3(d), but not the obligation, to attempt to cure such Environmental Defect at any time prior to the Closing, at the sole cost and expense of Sellers. If Seller and Buyer are unable to reach an agreement as to whether an Environmental Defect exists or, if it does exist, the amount of the Environmental Defect Value attributable thereto, the provisions of Section 12.1 shall be applicable.

(d) If any Environmental Defect described in a notice delivered in accordance with Section 8.2 is not cured on or before the Closing, then the Purchase Price shall be reduced, subject to Section 8.4, by the Environmental Defect Value of such Environmental Defect.

(e) As used in this Section 8.2:

(i) “Environmental Defect” shall mean, with respect to any given Property, a violation of Environmental Law in effect as of the date hereof or at any time prior to the Closing Date, in the jurisdiction in which such Property is located, an obligation under Environmental Laws to complete immediately or promptly after the Closing any corrective action at the Property, or any Environmental Liability arising from or attributable to any condition, event, circumstance, activity, practice, incident, action, or omission existing or occurring prior to the Closing Date, or the use, release, storage, treatment, transportation, or disposal of Hazardous Materials prior to the Closing Date, that has an Environmental Defect Value attributable thereto in excess of $50,000. “Environmental Defect” shall also mean any of the foregoing conditions or situations that, individually, have Environmental Defect Values of less than $50,000 if, in the aggregate, the Environmental Defect Values attributable to such conditions or situations exceeds $500,000.

(ii) “Environmental Defect Value” shall mean, (A) the net present value of the reasonably estimated costs and expenses to correct such Environmental Defect in the most cost effective manner reasonably available, consistent with Environmental Laws, or

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(B) the net present value of the amount of Environmental Liabilities reasonably believed will be incurred or required to be paid by Seller with respect thereto. The parties recognize that the calculation of an Environmental Defect Value may require the use of assumptions and extrapolations; however, it is acknowledged and agreed that any such assumptions and extrapolations will be consistent with the known factual information and reasonable in nature.

Section 8.3. Adjustments to Purchase Price for Defects.

(a) Notwithstanding anything to the contrary contained in this Agreement, no adjustment of the Purchase Price shall be made for Title Defects unless the aggregate of the Title Defect Amounts, as determined in accordance with this Agreement, equals or exceeds $1,400,000, in which event the Purchase Price shall be adjusted downward by the amount such Title Defect Amounts exceed $1,400,000 in the aggregate.

(b) Notwithstanding anything to the contrary contained in this Agreement, no adjustment of the Purchase Price shall be made for Environmental Defects unless the aggregate of the Environmental Defect Amounts, as determined in accordance with this Agreement, equals or exceeds $1,400,000, in which event the Purchase Price shall be adjusted downward by the amount such Environmental Defect Amounts exceed $1,400,000 in the aggregate.

(c) Notwithstanding anything herein to the contrary, if Seller is unable to cure a Title Defect or an Environmental Defect (a “Post-Closing Defect”) on or prior to Closing, Seller shall have the option, by notice in writing to Buyer on or before Closing, to attempt to cure such Post-Closing Defect within the 90-day period commencing the Closing Date (the “Cure Period”). In such event, the transactions contemplated hereby will close as provided herein and the Purchase Price shall be reduced by the applicable Title Defect Amount or Environmental Defect (as applicable) in respect of such Post-Closing Defect, as provided in Section 8.1 or Section 8.2. If, during or upon the expiration of the Cure Period, Seller and Buyer mutually agree that a Post-Closing Defect has been cured, then within two Business Days after such determination, Buyer shall tender to Seller an amount equal to the Title Defect Amount or Environmental Defect Amount (as applicable) in respect thereof. If, during or upon the expiration of the Cure Period, Seller and Buyer are unable to agree whether there has been a satisfactory cure of a Post-Closing Defect, then such disagreement shall be resolved as provided in Section 12.1.

Section 8.4. Buyer Indemnification. BUYER HEREBY INDEMNIFIES AND SHALL DEFEND AND HOLD SELLER, AFFILIATES THEREOF, AND ITS AND THEIR RESPECTIVE OWNERS, OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, REPRESENTATIVES, CONTRACTORS, SUCCESSORS, AND ASSIGNS HARMLESS FROM AND AGAINST ANY AND ALL OF THE FOLLOWING CLAIMS ARISING FROM BUYER’S INSPECTING AND OBSERVING THE PROPERTIES PURSUANT TO THIS ARTICLE VIII: (I) CLAIMS FOR PERSONAL INJURIES TO OR DEATH OF EMPLOYEES OF BUYER, ITS CONTRACTORS, AGENTS, CONSULTANTS, AND REPRESENTATIVES, AND DAMAGE TO THE PROPERTY OF BUYER OR OTHERS ACTING ON BEHALF OF BUYER, EXCEPT FOR INJURIES OR DEATH CAUSED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SELLER, AFFILIATES THEREOF OR ITS OR THEIR RESPECTIVE EMPLOYEES, CONTRACTORS, AGENTS, CONSULTANTS, OR REPRESENTATIVES; AND

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(II) CLAIMS FOR PERSONAL INJURIES TO OR DEATH OF EMPLOYEES OF SELLER OR THIRD PARTIES, AND DAMAGE TO THE PROPERTY OF SELLER OR THIRD PARTIES, TO THE EXTENT CAUSED BY THE NEGLIGENCE, GROSS NEGLIGENCE, OR WILLFUL MISCONDUCT OF BUYER. TO THE EXTENT PROVIDED ABOVE, THE FOREGOING INDEMNITY INCLUDES, AND THE PARTIES INTEND IT TO INCLUDE, AN INDEMNIFICATION OF THE INDEMNIFIED PARTIES FROM AND AGAINST CLAIMS ARISING OUT OF OR RESULTING, IN WHOLE OR PART, FROM THE CONDITION OF THE PROPERTY OR THE SOLE, JOINT, COMPARATIVE, OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF ANY OF THE INDEMNIFIED PARTIES. THE PARTIES HERETO AGREE THAT THE FOREGOING COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

ARTICLE IX

CONDITIONS PRECEDENT TO THE OBLIGATIONS OF THE PARTIES

Section 9.1. Conditions Precedent to the Obligations of Buyer. The obligations of Buyer under this Agreement are subject to each of the following conditions being met:

(a) Each of the representations and warranties of Seller contained in Article IV shall be true and correct on and as of the Closing Date as if made on and as of such date (and without regard to any materiality qualification in such representations and warranties), except (i) as affected by transactions contemplated or permitted by this Agreement, (ii) to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct as of such specified date; and (iii) any such inaccuracies or breaches the dollar value of which, when added to all (x) Title Defect Amounts, (y) amounts attributable to Casualty Losses and (z) Environmental Defect Values, do not exceed five percent (5%) of the Purchase Price. If Seller and Buyer are unable to reach agreement as to the dollar value attributable to an inaccuracy or breach of the representations and warranties of Seller, such dispute shall be resolved in accordance with Section 12.1.

(b) Seller shall have performed and complied in all material respects with (or compliance therewith shall have been waived by Buyer) each and every covenant, agreement and condition required by this Agreement to be performed or complied with by Seller prior to or at the Closing.

(c) Seller shall have delivered a certificate executed by the president of Seller dated the Closing Date, representing and certifying in such detail as Buyer may reasonably request that the conditions set forth in subsections (a) and (b) above have been fulfilled.

(d) No Proceeding (excluding any Proceeding initiated by Buyer or any of its Affiliates) shall, on the Closing Date, be pending or threatened before any Governmental Entity seeking to restrain, prohibit, or obtain damages or other relief in connection with the consummation of the transactions contemplated by this Agreement.

(e) Buyer shall have received a release of all Liens encumbering the Properties and related to and/or filed in connection with the Senior Credit Facility (including releases of associated financing statements, if any), executed in recordable form by the Senior Lender, and in form and substance agreeable to Buyer.

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(f) Buyer, or its designee, shall have received separate conveyances of the Properties owned by each of the respective entities comprising the Seller, which conveyances shall be substantially in the form of the instrument attached hereto as Exhibit 9.1(f) in all material respects (the “Conveyance”).

(g) Buyer shall have received a certificate of non-foreign status in form, date and content reasonably acceptable to Buyer, executed and delivered by Seller pursuant to Section 1445 of the Code and the regulations promulgated thereunder.

(h) Buyer shall have received all other agreements, instruments and documents which are required by other terms of this Agreement to be executed or delivered by Seller or any other party to Buyer prior to or in connection with the Closing.

(i) Wells Fargo Bank, N.A., shall have agreed to assign (or transfer the economic benefit of), and shall have delivered, at Closing, instruments effecting such assignment or transfer, the Existing Hedges to Buyer’s designated financial institution.

(j) All of the Existing Hedges shall be in full force and effect, and neither Seller nor the counterparty thereto shall be in breach or default thereunder.

(k) TEMI shall have entered into arrangements acceptable to Buyer in its sole discretion to transfer the portion of the 1993 Gas Purchase Contract applicable to the Properties to Buyer or Buyer’s designee.

(l) Seller shall have obtained all necessary consents to assignment or waivers of preferential rights to purchase with regard to the sale of the Properties.

(m) Seller shall have obtained and delivered to Buyer a full and complete copy of all exhibits and schedules to the 1993 Gas Purchase Contract or, alternatively, otherwise provided written assurances reasonably acceptable to Buyer from the parties to such agreement that the contents of any exhibit or schedule not so obtained and delivered will not adversely affect Buyer’s ownership and operation (or liabilities) of the Properties after the Closing in any material respect.

Section 9.2. Conditions Precedent to the Obligations of Seller. The obligations of Seller under this Agreement are subject to each of the following conditions being met:

(a) Each of the representations and warranties of Buyer contained in this Agreement shall be true and correct in all material respects as of the date made and (having been deemed to have been made again on and as of the Closing Date in the same language) shall be true and correct in all material respects on and as of the Closing Date, except as affected by transactions permitted by this Agreement and except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects as of such specified date.

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(b) Buyer shall have performed and complied in all material respects with (or compliance therewith shall have been waived by Seller) each and every covenant, agreement and condition required by this Agreement to be performed or complied with by Buyer prior to or at the Closing.

(c) No Proceeding (excluding any Proceeding initiated by Seller or any of its Affiliates) shall, on the Closing Date, be pending or threatened before any Governmental Entity seeking to restrain, prohibit, or obtain damages or other relief in connection with the consummation of the transactions contemplated by this Agreement.

(d) Seller shall have received all other agreements, instruments and documents which are required by other terms of this Agreement to be executed or delivered by Buyer or any other party to Seller prior to or in connection with the Closing.

ARTICLE X

TERMINATION, AMENDMENT AND WAIVER

Section 10.1. Termination. This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing in the following manner:

(a) by mutual written consent of Seller and Buyer; or

(b) by either Seller or Buyer, if:

(i) the Closing shall not have occurred on or before 5:00 p.m., local Houston, Texas time, June 27, 2005, unless such failure to close shall be due to a breach of this Agreement by the party seeking to terminate this Agreement pursuant to this clause (i); or

(ii) there shall be any statute, rule, or regulation that makes consummation of the transactions contemplated hereby illegal or otherwise prohibited or a Governmental Entity shall have issued an order, decree, or ruling or taken any other action permanently restraining, enjoining, or otherwise prohibiting the consummation of the transactions contemplated hereby, and such order, decree, ruling, or other action shall have become final and nonappealable; or

(c) by Buyer or Seller if the sum of the (i) Title Defect Amounts (including amounts attributable to Casualty Losses), (ii) Environmental Defect Values, and (iii) amounts attributable to inaccuracies or breaches of the representations and warranties of Seller contained in Article IV (and without regard to any materiality qualification in such representations and warranties) exceeds five percent (5%) of the Purchase Price; or

(d) by Seller, if (i) there shall be a material breach of any representation and warranty of Buyer contained in Article V, or (ii) there shall be a material breach by Buyer of any of its covenants and agreements contained in this Agreement, which breach, in the case of clause (i) or clause (ii), is not capable of being cured or, if it is capable of being cured, has not been cured by the 10^th Business Day following written notice to Buyer from Seller of such breach; or

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(e) by Buyer, if there shall be a breach by Seller of any of its covenants and agreements contained in this Agreement, which breach is not capable of being cured or, if it is capable of being cured, has not been cured by the 10^th Business Day following written notice to Seller from Buyer of such breach.

Section 10.2. Effect of Termination. In the event of the termination of this Agreement pursuant to Section 10.1 by Seller, on the one hand, or Buyer, on the other, written notice thereof shall forthwith be given to the other party or parties specifying the provision hereof pursuant to which such termination is made, and this Agreement shall become void and have no effect, except that the agreements contained in this Article X, in Sections 7.4, 7.5, 7.6 and 8.4 and in Articles XII and XIII shall survive the termination hereof. Except as provided in the sentence immediately following this sentence, nothing contained in this Section shall relieve any party from liability for damages actually incurred as a result of any breach of this Agreement. If this Agreement is terminated by Seller pursuant to (i) Section 10.1(b)(i) (and Buyer is in material breach of this Agreement) or (ii) Section 10.1(d) and if Seller has, as of the time of such termination, performed in all material respects its then current obligations hereunder, Seller shall retain the Deposit (plus interest earned thereon) as liquidated damages and as Seller’s sole and exclusive remedy. Buyer and Seller acknowledge and agree that the extent of damages to be suffered by Seller by any breach or misrepresentation by Buyer hereunder would be impossible or extremely difficult to ascertain and that the amount of the Performance Deposit is a fair and reasonable estimate of such damages under the circumstances. If this Agreement is terminated under Section 10.1 for any other reason, or if this Agreement is terminated by Seller under Section 10.1(b)(i) or Section 10.1(d) at a time when Seller has not performed in all material respects its then current obligations hereunder, the Deposit (plus interest earned thereon) shall be promptly returned to Buyer.

Section 10.3. Amendment. This Agreement may not be amended except by an instrument in writing signed by or on behalf of all the parties hereto.

Section 10.4. Waiver. Seller, on the one hand, or Buyer, on the other, may: (i) waive any inaccuracies in the representations and warranties of the other contained herein or in any document, certificate, or writing delivered pursuant hereto, or (ii) waive compliance by the other with any of the other’s agreements or fulfillment of any conditions to its own obligations contained herein. Any agreement on the part of a party hereto to any such waiver shall be valid only if set forth in an instrument in writing signed by or on behalf of such party. No failure or delay by a party hereto in exercising any right, power, or privilege hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right, power, or privilege.

ARTICLE XI

SURVIVAL OF REPRESENTATIONS, WARRANTIES AND COVENANTS; INDEMNIFICATION

Section 11.1. Survival.

(a) Each representation, warranty and covenant of the parties hereto contained in this Agreement and the liability of such parties under each such representation, warranty and

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covenant shall survive the Closing and the execution and delivery of the assignments and other instruments contemplated hereby and shall remain in effect thereafter for the period that an indemnified party is entitled to indemnification based on a breach of such representation, warranty or covenant contained in this Article XI.

(b) No party hereto shall have any indemnification obligation pursuant to this Article XI or otherwise in respect of any representation, warranty or covenant unless it shall have received from the party seeking indemnification written notice of the existence of the claim for or in respect of which indemnification is being sought on or before the one year anniversary of the Closing Date. Such notice shall set forth with reasonable specificity (A) the basis under this Agreement, and the facts that otherwise form the basis of such claim, (B) the estimate of the amount of such claim (which estimate shall not be conclusive of the final amount of such claim) and an explanation of the calculation of such estimate, including a statement of any significant assumptions employed therein, and (C) the date on and manner in which the party delivering such notice became aware of the existence of such claim.

Section 11.2. Seller’s Indemnification Obligations.

Seller shall, on the date of Closing, agree (and, upon delivery to Buyer of the Conveyance, shall be deemed to have agreed), subject to the limitations and procedures contained in this Article XI, following the Closing, to be responsible for, pay on a current basis, indemnify, defend and hold Buyer, its Affiliates and its and their respective successors and permitted assigns and all of their respective stockholders, partners, members, managers, directors, officers, employees, agents and representatives harmless from and against any and all claims, obligations, actions, liabilities, damages or expenses (collectively, “Buyer’s Losses”):

(i) relating to Seller’s ownership or operation of the Properties prior to the Effective Date, exclusive of any matters relating to (1) Seller’s title to the Oil and Gas Properties, (2) Seller’s compliance with Environmental Laws or any Environmental Liabilities with respect to the Properties (other than those matters referenced in clauses (i), (ii), (iii) and (iv) of the definition of Non-Assumed Obligations), and (3) the items referenced in clauses (i) and (ii) of the definition of Assumed Obligations;

(ii) arising from Seller’s performance of its obligations with respect to the Royalty Trust during the period of Seller’s ownership and operation of the Properties;

(iii) resulting from any misrepresentation or breach of any warranty, covenant or agreement of Seller contained in this Agreement or any certificate delivered by Seller at the Closing (inclusive of any matters relating to the Assumed Obligations);

(iv) relating to the Excluded Assets; and

(v) relating to or arising from any fees, expenses, or other payments incurred or owed by Seller or its Affiliates to any broker, investment banker, financial advisor, or other Person in connection with the transactions contemplated by this Agreement;

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provided, however, that:

(A) Seller shall have no obligation to indemnify Buyer for any claim under this Section 11.2 unless Buyer’s Losses attributable to such claim exceeds $50,000 (a ”Buyer’s Eligible Claim”);

(B) Seller shall have no obligation to indemnify Buyer under this Section 11.2 until the aggregate amount of all Buyer’s Eligible Claims equals or exceeds $1,000,000, and then only to the extent of the amount of such Buyer’s Eligible Claims in excess of $1,000,000;

(C) Seller’s indemnification obligations for Buyer’s Eligible Claims under this Section 11.2, including any such obligations related to or arising with respect to the Non-Assumed Obligations, shall expire on the first anniversary of the Closing Date (the ”Survival Date”), except for Buyer’s Eligible Claims received as provided in this Agreement on or prior to such Survival Date; and

(D) Seller’s liability under this Article XI shall, in no event, exceed ten percent (10%) of the Purchase Price with respect to Buyer’s Eligible Claims; provided, that if, during the six-month period commencing the Closing Date, the dollar amount of Buyer’s Eligible Claims for which Buyer has delivered notice to Seller in accordance with Section 11.1 aggregates five percent (5%) or less of the Purchase Price, Seller’s liability under this Article XI shall, in no event, exceed five percent (5%) of the Purchase Price.

Notwithstanding anything herein to the contrary, none of the foregoing limitations nor the limitations in Section 11.1 shall apply in any respect to Seller’s obligation to indemnify Buyer pursuant to clauses (iv) and (v) of this Section 11.2, which obligation shall not be limited as to duration or amount.

Section 11.3. Buyer’s Indemnification Obligations.

Buyer shall, on the date of Closing, agree (and, upon delivery to Buyer of the Conveyance, shall be deemed to have agreed), subject to the limitations and procedures contained in this Article XI, following the Closing, to be responsible for, pay on a current basis, indemnify, defend, and hold Seller, its Affiliates and its and their respective successors and permitted assigns and all of their respective stockholders, partners, members, managers, directors, officer, employees, agents and representatives harmless from and against any and all claims, obligations, actions, liabilities, damages, costs or expenses, (collectively, “Seller’s Losses”) (i) resulting from any misrepresentation or breach of any warranty, covenant or agreement of Buyer contained in this Agreement or any certificate delivered by Buyer at the Closing (unless such misrepresentation or breach of warranty, covenant or agreement of Buyer arises from or is attributable to any act or omission of any Related Party) or (ii) the Assumed Obligations, provided, that Buyer shall have no obligation to indemnify Seller under this Section 11.3 for an Assumed Obligation if, and to the extent that, Seller has an obligation to indemnify Buyer for such Assumed Obligation under Section 11.2.

Section 11.4. Net Amounts. Any amounts recoverable by any party pursuant to this Article XI with respect to any Buyer’s Loss or Seller’s Loss, as the case may be, shall be increased by any net tax costs to the indemnified party (taxes incurred with respect to any indemnity payment less tax benefits resulting from the circumstances serving as the basis for

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such Buyer’s Loss or Seller’s Loss, as the case may be) and shall be decreased by (i) any net tax benefit to the indemnified party (tax benefits less taxes incurred, as calculated above), and (ii) insurance proceeds or other amounts relating to such Buyer’s Loss or Seller’s Loss, as the case may be, paid to such indemnified party by any person (other than any Affiliate of such indemnified party) not a party to this Agreement.

Section 11.5. Indemnification Proceedings. In the event that any claim or demand for which a party (an “Indemnifying Party”), would be liable to another party under Section 11.2 or Section 11.3 (an “Indemnified Party”) is asserted against or sought to be collected from an Indemnified Party by a third party, the Indemnified Party shall with reasonable promptness notify the Indemnifying Party of such claim or demand, but the failure so to notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article XI, except to the extent the Indemnifying Party demonstrates that the defense of such claim or demand is materially prejudiced thereby. The Indemnifying Party shall have 30 days from receipt of the above notice from the Indemnified Party (in this Section 11.5, the “Notice Period”) to notify the Indemnified Party whether or not the Indemnifying Party desires, at the Indemnifying Party’s sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and not prejudicial to the Indemnifying Party. If the Indemnifying Party elects to assume the defense of any such claim or demand, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof. If the Indemnifying Party elects not to assume the defense of such claim or demand (or fails to give notice to the Indemnified Party during the Notice Period), the Indemnified Party shall be entitled to assume the defense of such claim or demand with counsel of its own choice, at the expense of the Indemnifying Party. If the claim or demand is asserted against both the Indemnifying Party and the Indemnified Party and based on the advice of counsel reasonably satisfactory to the Indemnifying Party it is determined that there is a conflict of interest which renders it inappropriate for the same counsel to represent both the Indemnifying Party and the Indemnified Party, the Indemnifying Party shall be responsible for paying separate counsel for the Indemnified Party; provided, however, that the Indemnifying Party shall not be responsible for paying for more than one separate firm of attorneys to represent all of the Indemnified Parties, regardless of the number of Indemnified Parties. If the Indemnifying Party elects to assume the defense of such claim or demand, (i) no compromise or settlement thereof may be effected by the Indemnifying Party without the Indemnified Party’s written consent (which shall not be unreasonably withheld) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Party and (ii) the Indemnifying Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld).

Section 11.6. Indemnification Exclusive Remedy. Indemnification pursuant to the provisions of this Article XI shall be the exclusive remedy of the parties hereto for any misrepresentation or breach of any warranty, covenant or agreement contained in this Agreement or in any closing document executed and delivered pursuant to the provisions hereof or thereof, or any other claim arising out of the transactions contemplated by this Agreement.

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Section 11.7. Limited to Actual Damages. The indemnification obligations of the parties pursuant to this Article XI shall be limited to actual Damages and shall not include incidental, consequential, indirect, punitive, or exemplary Damages, provided that any incidental, consequential, indirect, punitive, or exemplary Damages recovered by a third party (including a Governmental Entity, but excluding any Affiliate of any party) against a party entitled to indemnity pursuant to this Article XI shall be included in the Damages recoverable under such indemnity.

Section 11.8. Indemnification Despite Negligence. It is the express intention of the parties hereto that each party to be indemnified pursuant to this Article XI shall be indemnified and held harmless from and against all Damages as to which indemnity is provided for under this Article XI, notwithstanding that any such Damages arise out of or result from the ordinary, strict, sole, or contributory negligence of such party and regardless of whether any other party (including the other parties to this Agreement) is or is not also negligent. The parties hereto acknowledge that the foregoing complies with the express negligence rule and is conspicuous.

Section 11.9. Indemnification Support Escrow Agreement. Subject to the terms and conditions set forth in this Section 11.9, Buyer shall cause $7,025,000 (the “Indemnification Support Deposit”) to be deposited on the Closing Date with an escrow agent selected by Buyer and reasonably acceptable to Seller (the ”Indemnification Escrow Agent”) and pursuant to the terms of an escrow agreement reasonably satisfactory to the Indemnification Escrow Agent, Seller and Buyer and which incorporates or otherwise properly reflects the terms and provisions of this Section 11.9 (the ”Indemnification Support Escrow Agreement”). The Indemnification Support Deposit will be utilized solely to satisfy any indemnification obligations of Seller as described in Section 11.2.

(c) If Buyer, on behalf of itself and/or an Indemnified Party, asserts a claim against the Indemnification Support Deposit under Article XI and Seller does not dispute such claim, Buyer and/or such Indemnified Party, as the case may be, shall be entitled to indemnification by Seller in accordance with this Article XI, including the right to receive from the Indemnification Support Deposit funds in an amount equal to the amount of Damages for which Buyer or such Indemnified Party is entitled under this Article XI. If, however, Seller disputes such claim, Buyer shall not be entitled to receive any amount from the Indemnification Support Deposit with respect to such claim prior to resolution of such dispute in accordance with this Agreement and, if such dispute extends beyond the expiration of the Survival Date, the term of the Indemnification Support Deposit will be automatically extended as provided in Section 11.9(d).

(d) Provided the indemnification obligations of Seller to Buyer and each other Indemnified Party under this Article XI have been satisfied (including the obligation to pay Damages), prior to the expiration of the Survival Date, and no dispute then exists as to any claim for indemnification notified by Buyer to Seller hereunder prior to the expiration of the Survival Date, the remaining Indemnification Support Deposit will be released to Seller on the first Business Day immediately following the expiration of the Survival Date. To the extent there exists a claim for indemnification pursuant to this Article XI that has been notified by Buyer to Seller hereunder, but not satisfied in full by Seller prior to the expiration of the Survival Date, an amount equal to the maximum possible amount of such claim or claims reasonably believed by the parties hereto to be due or likely to be due hereunder (or, in the event of a dispute between

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the parties with respect thereto, the higher of the two estimates) will be withheld from the remaining Indemnification Support Deposit and will continue to be held by the Indemnification Escrow Agent pursuant to the terms of the Indemnification Support Escrow Agreement until such claim or claims have been fully resolved and the Indemnification Support Escrow Agreement shall be deemed to be extended accordingly.

(e) The fees and expenses of the Indemnification Escrow Agent shall be borne 50% by Seller and 50% by Buyer.

ARTICLE XII

MISCELLANEOUS MATTERS

Section 12.1. Dispute Resolution for Title Defects, Environmental Defects and Breaches.

(a) Each party shall have the right to submit claims, disputes, controversies, or other matters in question arising out of the matters covered by Article VIII (including the existence of Title Defects or the Title Defect Amounts attributable thereto, as applicable), or Section 9.1(a) (all of which are referred to herein as “Disputes”), to an independent expert not affiliated with either party appointed in accordance with this Section 12.1(a) (each, an “Independent Expert”), who shall serve as sole arbitrator. The Independent Expert shall be appointed by mutual agreement of Seller and Buyer from among candidates with experience and expertise in the area that is the subject of such Dispute, and failing such agreement, such Independent Expert for such Dispute shall be selected in accordance with the Rules (as hereinafter defined). Disputes to be resolved by an Independent Expert shall be resolved in accordance with mutually agreed procedures and rules and failing such agreement, in accordance with the rules and procedures for arbitration provided in Section 12.1(b). The Independent Expert shall be instructed by the parties to resolve such Dispute as soon as reasonably practicable in light of the circumstances, but in any event within thirty (30) days of the presentations by Buyer, on the one hand, and Seller, on the other hand. The decision and award of the Independent Expert shall be binding upon the parties as an award under the Federal Arbitration Act and shall be final and nonappealable to the maximum extent permitted by law, and judgment thereon may be entered in a court of competent jurisdiction and enforced by any party as a final judgment of such court.

(b) Any Dispute that is not resolved pursuant to Section 12.1(a) shall be settled exclusively and finally by arbitration in accordance with this Section 12.1(b).

(i) Such arbitration shall be conducted pursuant to the Federal Arbitration Act, except as expressly provided otherwise in this Agreement. The validity, construction, and interpretation of this Section 12.1(b), and all procedural aspects of the arbitration conducted pursuant hereto, including the determination of the issues that are subject to arbitration (i.e., arbitrability), the scope of the arbitrable issues, allegations of “fraud in the inducement” to enter into this Agreement or this arbitration provision, allegations of waiver, laches, delay or other defenses to arbitrability, and the rules governing the conduct of the arbitration (including the time for filing an answer, the time for the filing of counterclaims, the times for amending the pleadings, the specificity of the pleadings, the extent and scope of discovery, the issuance of subpoenas, the times for the

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designation of experts, whether the arbitration is to be stayed pending resolution of related litigation involving third parties not bound by this Agreement, the receipt of evidence, and the like), shall be decided by the arbitrators. The arbitration shall be administered by the American Arbitration Association (the “AAA”), and shall be conducted pursuant to the Commercial Arbitration Rules of the AAA (the “Rules”), except as expressly provided otherwise in this Agreement. The arbitration proceedings shall be subject to any optional rules contained in the Rules for emergency measures and, in the case of Disputes with respect to amounts in excess of $1 million, optional rules for large and complex cases.

(ii) The arbitrators shall permit and facilitate such discovery as they determine is appropriate in the circumstances, taking into account the needs of the parties and the desirability of making discovery expeditious and cost-effective. Such discovery may include pre-hearing depositions, particularly depositions of witnesses who will not appear personally to testify, if there is a demonstrated need therefore. The arbitrators may issue orders to protect the confidentiality of proprietary information, trade secrets and other sensitive information disclosed in discovery.

(iii) All arbitration proceedings hereunder shall be conducted in Houston, Texas or such other mutually agreeable location.

(iv) All arbitration proceedings hereunder shall be before a panel of three (3) arbitrators appointed in accordance with the Rules consisting of Persons (which can include lawyers) having at least ten (10) years of experience in or relating to the oil and gas industry.

(v) In deciding the substance of the Dispute, the arbitrators shall refer to the substantive laws of the State of Texas for guidance (excluding choice-of-law principles that might call for the application of the laws of another jurisdiction). Matters relating to arbitration shall be governed by the Federal Arbitration Act.

(vi) The parties shall request the arbitrators to conduct a hearing as soon as reasonably practicable after appointment of the third arbitrator, and to render a final decision completely disposing of the Dispute that is the subject of such proceedings as soon as reasonably practicable after the final hearing. The parties shall instruct the arbitrators to impose time limitations they consider reasonable for each phase of such proceeding, including, without limitation, limits on the time allotted to each party for the presentation of its case and rebuttal. The arbitrators shall actively manage the proceedings as they deem best so as to make the proceedings fair, expeditious, economical and less burdensome than litigation. To provide for speed and efficiency, the arbitrators may: (i) limit the time allotted to each party for presentation of its case; and (ii) exclude testimony and other evidence they deem irrelevant or cumulative.

(vii) Notwithstanding any other provision in this Agreement to the contrary, the parties expressly agree that the arbitrators shall have absolutely no authority to award consequential, incidental, special, treble, exemplary or punitive damages of any type under any circumstances regardless of whether such damages may be available under Texas law, or any other laws, or under the Federal Arbitration Act or the Rules.

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(viii) The parties agree that there shall be no transcript of any hearing before the arbitrators. The parties shall request that final decision of the arbitrators be in writing, be as brief as possible, set forth the reasons for such final decision, and if the arbitrators award monetary damages to either party, contain a certification by the arbitrators that they have not included any incidental, special, treble, exemplary or punitive damages. To the fullest extent permitted by law, the arbitration proceeding and the arbitrators’ decision and award shall be maintained in confidence by the parties and the parties shall instruct the arbitrators to likewise maintain such matters in confidence.

(ix) The fees and expenses of the arbitrators shall be borne equally by Seller and Buyer, but the decision of the arbitrators may include such award of the arbitrators’ fees and expenses and of other costs and attorneys’ fees as the arbitrators determine appropriate (provided that such award of costs and fees may not exceed the amount of such costs and fees incurred by the losing party in the arbitration).

(x) The decision and award of the arbitrators shall be binding upon the parties and final and nonappealable to the maximum extent permitted by law, and judgment thereon may be entered in a court of competent jurisdiction and enforced by any party as a final judgment of such court.

(c) Except for the Disputes described in Section 12.1(a), no claims, disputes, controversies, or other matters in question arising out of or relating to this Agreement is to be settled by arbitration. The awards granted pursuant to this Section 12.1 shall be limited to actual Damages and shall not include incidental, consequential, indirect, punitive, or exemplary Damages.

Section 12.2. Notices.

All notices, requests, demands, and other communications required or permitted to be given or made hereunder by any party hereto shall be in writing and shall be deemed to have been duly given or made if (i) delivered personally, (ii) transmitted by first class registered or certified mail, postage prepaid, return receipt requested, (iii) sent by a recognized prepaid overnight courier service (which provides a receipt), or (iv) sent by facsimile transmission, with receipt acknowledged, to the parties at the following addresses (or at such other addresses as shall be specified by the parties by like notice):

If to Seller:

Everlast Energy LLC

111 North Ennis

Houston, Texas 77003

Attention: Tim Goff and Mike Gibson

Fax No.: 713-222-0364

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With , prior to Closing, a copy to (which shall not constitute notice to Seller):

Thompson & Knight LLP

333 Clay Street, Suite 3300

Houston, Texas 77002

Attention: Michael K. Pierce and Louis J. Davis

Fax No.: Pierce — 832-397-8049 and Davis — 832-397-8148

If to Buyer:

c/o Constellation Energy Commodities Group, Inc.

111 Market Place, Suite 500

Baltimore, Maryland 21202

Attention: Mark Orman

Facsimile: 410-468-3541

and with a copy to:

Constellation Energy Group, Inc.

750 East Pratt Street, 18th Floor

Baltimore, Maryland 21202

Attention: General Counsel

Facsimile: 410.783.3609

and with a copy to:

Constellation Energy Commodities Group, Inc.

111 Market Place, Suite 500

Baltimore, Maryland 21202

Attention: General Counsel

Facsimile: 410.468.3499

Such notices, requests, demands, and other communications shall be effective upon receipt, and shall be deemed to have been received as follows: (A) if delivered personally, upon receipt; (B) if by first class registered or certified mail, upon the earlier of (1) receipt as indicated by the date on the signed receipt or (2) five days after it was deposited in the mail; (C) if sent by a recognized prepaid overnight courier service, upon receipt as indicated by the date on the signed receipt; (D) if sent by facsimile, upon receipt by the party giving or making such communication of an acknowledgment or transmission report generated by the machine from which the facsimile was sent indicating that the facsimile was sent in its entirety to the intended recipient’s facsimile number; (E) If the intended recipient rejects or otherwise refuses to accept a communication, or if the communication cannot be delivered because of a change in address for which no communication was received by the party attempting to give or make such communication, then upon the rejection, refusal, or inability to deliver.

Section 12.3. Entire Agreement. This Agreement, the Seller Disclosure Schedule, together with the Exhibits, and other writings referred to herein or delivered pursuant hereto, constitute the entire agreement between the parties hereto with respect to the subject matter hereof and supersede all prior agreements and understandings, both written and oral, between the parties with respect to the subject matter hereof.

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Section 12.4. Injunctive Relief. Seller acknowledges and agrees that irreparable damage to Buyer would occur in the event any of the provisions of this Agreement were not performed in accordance with their specific terms or were otherwise breached by Seller and that Buyer shall be entitled to an injunction or injunctions to prevent breaches of the provisions of this Agreement, and shall be entitled to enforce specifically the provisions of this Agreement, in any court of the United States or any state thereof having jurisdiction, in addition to any other remedy to which Buyer may be entitled under this Agreement or at law or in equity.

Section 12.5. Binding Effect; Assignment; No Third Party Benefit. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, legal representatives, successors, and permitted assigns. Except as otherwise expressly provided in this Agreement, neither this Agreement nor any of the rights, interests, or obligations hereunder shall be assigned by any of the parties hereto without the prior written consent of the other parties. Notwithstanding the foregoing, Seller acknowledges that at closing title to the Properties may be taken by one or more Affiliates of the Buyer or, post-closing, assigned in full or in part to one or more Affiliates of Buyer and Seller consents to such assignment or acquisition and agrees that any such Buyer Affiliate will have the same rights as Buyer to enforce any of the rights of Buyer under this Agreement including claims for indemnification under Article XI; provided, that (i) in no event shall any such assignment relieve Buyer of any of its duties and obligations under this Agreement (including its obligations under Article XI), (ii) any such assignment shall be conditioned upon receipt by Seller of written assurances from Buyer’s assignee reasonably satisfactory to Seller to the effect that such assignee agrees to jointly perform Buyer’s duties and obligations under this Agreement (including Buyer’s obligations under Article XI) and (iii) Seller shall be entitled to enforce Buyer’s duties and obligations under this Agreement against either Buyer or such assignee or both. Except as provided in this Section 12.5, Section 8.4 and Article XI, nothing in this Agreement, express or implied, is intended to or shall confer upon any Person other than the parties hereto, and their respective heirs, legal representatives, successors, and permitted assigns, any rights, benefits, or remedies of any nature whatsoever under or by reason of this Agreement.

Section 12.6. Severability. If any provision of this Agreement is held to be unenforceable, this Agreement shall be considered divisible and such provision shall be deemed inoperative to the extent it is deemed unenforceable, and in all other respects this Agreement shall remain in full force and effect; provided, however, that if any such provision may be made enforceable by limitation thereof, then such provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by Applicable Law.

Section 12.7. GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED AND ENFORCED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF TEXAS, WITHOUT REGARD TO THE PRINCIPLES OF CONFLICTS OF LAWS THEREOF.

Section 12.8. Counterparts. This instrument may be executed in any number of identical counterparts, each of which for all purposes shall be deemed an original, and all of which shall constitute collectively, one instrument. It is not necessary that each party hereto

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execute the same counterpart so long as identical counterparts are executed by each such party hereto. This instrument may be validly executed and delivered by facsimile or other electronic transmission.

Section 12.9. WAIVER OF CONSUMER RIGHTS. BUYER HEREBY WAIVES ITS RIGHTS UNDER THE TEXAS DECEPTIVE TRADE PRACTICES-CONSUMER PROTECTION ACT, SECTION 17.41 ET SEQ., BUSINESS AND COMMERCE CODE, A LAW THAT GIVES CONSUMERS SPECIAL RIGHTS AND PROTECTIONS, AND ANY SIMILAR LAW IN ANY OTHER STATE TO THE EXTENT SUCH ACT OR SIMILAR LAW WOULD OTHERWISE APPLY. AFTER CONSULTATION WITH AN ATTORNEY OF BUYER’S OWN SELECTION, BUYER VOLUNTARILY CONSENTS TO THIS WAIVER.

Section 12.10. WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVES ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY PROCEEDING BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN), OF THE PARTIES. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE PARTIES TO ENTER INTO THIS AGREEMENT.

ARTICLE XIII

DEFINITIONS AND REFERENCES

Section 13.1. Certain Defined Terms. When used in this Agreement, the following terms shall have the respective meanings assigned to them in this Section 13.1:

“1993 Gas Purchase Contract” means that certain Oil and Gas Purchase Contract dated October 1, 1993 by and between Torch Energy Marketing, Inc., Torch Royalty Company, and Velasco Gas Company, L.P.

“Affiliate” means any Person directly or indirectly controlling, controlled by or under common control with a Person.

“Agreement” means this Asset Purchase and Sale Agreement, as hereafter amended or modified in accordance with the terms hereof.

“Applicable Law” means any statute, law, principle of common law, rule, regulation, judgment, order, ordinance, requirement, code, writ, injunction, or decree of any Governmental Entity, exclusive of Environmental Laws.

“Assumed Obligations” means (i) the obligation to (1) plug and abandon or remove and dispose of all wells, platforms, structures, flow lines, pipelines and other equipment, pits and holding ponds now or hereafter located on the Oil and Gas Properties, (2) cap and bury all flow lines and other pipelines now or hereafter located on the Oil and Gas Properties; (ii) all Environmental Liabilities with respect to the Properties, including any actual or potential NORM contamination or chloride or other contamination of groundwater; and (iii) all costs, obligations

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and liabilities that arise under or otherwise relate to the Properties or the contracts or other agreements conveyed and assigned to Buyer hereunder and arise from or relate to events occurring on or after the Effective Date; provided, that Assumed Obligations does not mean or include: (x) Seller’s obligations and liabilities under the Senior Credit Facility or any amounts that may be due and owing Seller’s officers, employees or owners; (y) Seller’s obligations and liabilities with respect to any Excluded Assets; or (z) the Non-Assumed Obligations.

“Business Day” means a day other than a Saturday, Sunday or day on which commercial banks in the State of Texas are authorized or required to be closed for business.

“Casualty Loss” means (a) destruction by fire, blowout, storm, or other casualty, or (b) any taking, or pending or threatened taking, in condemnation or expropriation or under the right of eminent domain, in each case prior to the Closing.

“Code” means the Internal Revenue Code of 1986, or any successor statute thereto, as amended.

“Confidentiality Agreement” means that certain Confidentiality Agreement by and between Everlast and Constellation Energy Commodities Group dated April 5, 2005.

“Dollars” or “$” means U.S. Dollars.

“Effective Date” means 7:00 a.m., local time at the location of the Properties, on May 1, 2005.

“Environmental Laws” means all national, state, municipal or local laws, rules, regulations, statutes, ordinances or orders of any Governmental Entity pertaining to the protection of human health and safety or of the environment, including the Comprehensive Environmental Response, Compensation and Liability Act, as amended by the Superfund Amendments and Reauthorization Act, 42 U.S.C. § 9601 et seq. (“CERCLA”), the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. (“RCRA”), the Federal Water Pollution Control Act, as amended by the Clean Water Act, 33 U.S.C. § 1251 et seq., the Clean Air Act, 42 U.S.C. §7401 et seq., the Toxic Substances Control Act, 15 U.S.C. § 2601 et seq., the Occupational Safety and Health Act of 1970, 29 U.S.C. 661 et seq, and any similar state or local statutes.

“Environmental Liabilities” means any and all claims, obligations, actions, liabilities, damages or expenses (including any remedial, removal, response, abatement, clean-up, investigation and/or monitoring costs and associated legal costs) incurred or imposed (a) pursuant to any agreement order, notice of responsibility, directive (including directives embodied in Environmental Laws), injunctions, judgment or similar documents (including settlements) arising out of, in connection with, or under Environmental Laws, or (b) pursuant to any claim by a Governmental Entity or any other Person for personal injury, property damage, damage to natural resources, remediation, or payment or reimbursement of response costs incurred or expended by such Governmental Entity or other Person pursuant to common law or statute and related to the use or release of Hazardous Materials.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

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“Existing Hedges” mean the Hedges listed in subsection (i) of Section 4.7 of the Seller Disclosure Schedule.

“Governing Documents” means, when used with respect to an entity, the documents governing the formation and operation of such entity, including (i) in the instance of a corporation, the articles or incorporation and bylaws of such corporation, (ii) in the instance of a partnership, the partnership agreement, and (iii) in the instance of a limited liability company, the certificate of formation and limited liability company agreement.

“Governmental Entity” means any court or tribunal in any jurisdiction (domestic or foreign) or any federal, state, county, municipal or other governmental or quasi-governmental body, agency, authority, department, board, commission, bureau or instrumentality.

“Hazardous Materials” means (i) any substance or material that is listed, defined or otherwise designated as a “hazardous substance” under Section 101(14) of CERCLA, (ii) any petroleum or petroleum products, (iii) radioactive materials, urea formaldehyde, asbestos and PCBs and (iv) any other chemical substance or waste that is regulated by any Governmental Entity under any Environmental Law.

“Hedge” means any future derivative, swap, collar, put, call, cap, option or other contract that is intended to benefit from, relate to, or reduce or eliminate the risk of fluctuations in interest rates, basis risk or the price of commodities, including Hydrocarbons.

“Hydrocarbons” means oil, gas, other liquid or gaseous hydrocarbons, or any of them or any combination thereof, and all products and substances extracted, separated, processed and produced therefrom.

“Imbalances” means gas production, pipeline, storage, processing or other imbalance attributable to substances produced from the Oil and Gas Properties.

“IRS” means the Internal Revenue Service.

“Knowledge” of Seller (or similar references to Seller’s knowledge) means all information of which either Tim J. Goff, Dennis Hammond, Michael Gibson, Lee Seekely, Raymond Love, and Robert Porter, have knowledge or, following a reasonable investigation, should have had knowledge.

“Lien” means any claim, lien, mortgage, security interest, pledge, charge, option, right-of-way, easement, encroachment, or encumbrance of any kind.

“Material Adverse Effect” means any change, development, or effect (individually or in the aggregate) which is, or is reasonably likely to be, materially adverse (i) to the business, assets, results of operations or condition (financial or otherwise) of a party, or (ii) to the ability of a party to perform on a timely basis any material obligation under this Agreement or any agreement, instrument, or document entered into or delivered in connection herewith; provided, however, that changes, developments or effects relating to (x) the economy in general (including any effects on the economy arising as a result of acts of terrorism), (y) changes in Hydrocarbon commodity prices or other changes affecting the U.S. oil and gas industry generally, or (z) the

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announcement of the transactions contemplated hereby, shall not be deemed to constitute a Material Adverse Effect with respect to Seller and shall not be considered in determining whether a Material Adverse Effect has occurred with respect to Seller.

“Non-Assumed Obligations” means all liabilities, obligations, and duties attributable to the period prior to the Effective Date and that relate to or arise as a result of the following: (i) fines or civil, criminal or regulatory penalties that may be levied by any Governmental Entity for a violation of Environmental Laws; (ii)(1) the migration or leaching of Hazardous Materials from lands comprising the Properties into or onto lands or other property outside the lands comprising the Properties or (2) the removal or transportation to or storage at a location other than the Properties of any Hazardous Materials generated by, used in connection with, or associated with the Properties; (iii) any personal injury or toxic tort arising out of or related to exposure to Hazardous Materials on, or associated with, the Properties; (iv) any litigation or legal actions related to the Properties and not filed of record with the applicable Governmental Entity prior to Closing; (v) accounting for and disbursement of proceeds of production from the Oil and Gas Properties (except for the disbursement of funds in any suspense accounts delivered to Buyer pursuant to Section 7.11); or (vi) payment of all royalties, overriding royalties, production payments, net profits interest obligations, rentals, shut-in payments, and other burdens or encumbrances applicable to the Oil and Gas Properties, including any of the foregoing incurred or owed in connection to or with the Royalty Trust or pursuant to the Royalty Trust Conveyance or the Royalty Trust Agreement.

“Performance Deposit Escrow Agent” means Manufacturer’s and Traders Trust Company in Baltimore, Maryland.

“Permits” means licenses, permits, franchises, consents, approvals, variances, exemptions, and other authorizations of or from Governmental Entities.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, enterprise, unincorporated organization, or Governmental Entity.

“Proceedings” means all proceedings, actions, claims, suits, investigations, and inquiries by or before any arbitrator or Governmental Entity.

“Reasonable Best Efforts” means a party’s reasonable best efforts in accordance with reasonable commercial practice.

“Securities Act” shall mean the Securities Act of 1933, as amended, and all rules and regulations under such Act.

“Seller Disclosure Schedule” shall mean a schedule delivered by Seller to Buyer on the date hereof which sets forth additional information regarding the representations and warranties of Seller contained herein and information called for hereby.

“Senior Credit Facility” means Seller’s Credit Agreements as listed in subsection (k) of Section 4.7 of the Seller Disclosure Schedule.

“Senior Lender” means the lenders party to the Senior Credit Facility.

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“Tax Returns” mean any return, report, statement, form or similar statement required to be filed with respect to any Taxes (including any attached schedules), including, without limitation, any information return, claim for refund, amended return or declaration of estimated Taxes.

“Taxes” means any income taxes or similar assessments or any sales, excise, occupation, use, ad valorem, property, production, severance, transportation, employment, payroll, franchise, or other tax imposed by any United States federal, state, or local (or any foreign or provincial) taxing authority, including any interest, penalties, or additions attributable thereto, as well as any transferred liability with respect to and of the foregoing.

“Torch Purchase and Sale Agreement” means that certain Agreement for Purchase and Sale made and entered into on December 17, 2002, by and between Torch E & P Company, Torch Energy Services, Inc., TEAI Oil & Gas Company, Torch Energy Marketing, Inc., and Velasco Gas Company, L.P., collectively as Seller, and Everlast Energy LLC, as Buyer.

Section 13.2. Certain Additional Defined Terms. In addition to such terms as are defined in the preamble of and the recitals to this Agreement and in Section 13.1, the following terms are used in this Agreement as defined in the Articles or Sections set forth opposite such terms:


Defined Term		Reference
AAA		Section 12.1(d)(i)
Adjusted Purchase Price		Section 2.1
Allocated Value		Section 8.1(c)(i)
Basic Documents		Section 4.7
Buyer’s Eligible Claim		Section 11.2
Buyer’s Losses		Section 11.2
Buyer’s Title Review		Section 8.1(a)
Closing		Article III
Closing Date		Article III
Conveyance		Section 9.1(f)
Cure Period		Section 8.2(b)
Defensible Title		Section 8.1(d)(i)
Disputes		Section 12.1(a)
Environmental Defect		Section 8.2(e)(i)
Environmental Defect Notice		Section 8.2(c)
Environmental Defect Value		Section 8.2(e)(ii)
Environmental Indemnity Contract		Section 4.7
Environmental Information		Section 8.2(b)
Examination Period		Section 8.1(a)
Excluded Assets		Section 1.2
Indemnification Escrow Agent		Section 11.9(a)
Indemnification Support Deposit		Section 11.9(a)
Indemnification Support Escrow Agreement		Section 11.9(a)
Indemnified Party		Section 11.5
Indemnifying Party		Section 11.5
Independent Expert		Section 12.1(c)

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Defined Term		Reference
Notice Period		Section 11.5
Oil and Gas Properties		Section 1.1
Performance Deposit		Section 2.4(a)
Permitted Encumbrances		Section 8.1(d)(ii)
Post-Closing Defect		Section 8.3(b)
Properties		Section 1.1
Purchase Price		Section 2.1
Remedies for Title Defects		Section 8.1(b)
Royalty Trust		Section 1.3
Royalty Trust Agreement		Section 1.3
Royalty Trust Conveyance		Section 1.3
Rules		Section 12.1(b)(i)
Scheduled Production Sales Contracts		Section 4.9
Seller’s Losses		Section 11.3
Suspended Proceeds		Section 7.11
Survival Date		Section 11.2
TEAI		Section 1.3
TEMI		Section 7.16
Title Defect		Section 8.1(d)(iii)
Title Defect Amount		Section 8.1(c)
Title Defect Notice		Section 8.1(b)
Title Defect Property		Section 8.1(b)
Transition Services Agreement		Section 7.14
Velasco		Section 1.3
WARN Act		Section 4.2(d)(ii)

Section 13.3. References, Titles and Construction.

(a) All references in this Agreement to articles, sections, subsections and other subdivisions refer to corresponding articles, sections, subsections and other subdivisions of this Agreement unless expressly provided otherwise.

(b) Titles appearing at the beginning of any of such subdivisions are for convenience only and shall not constitute part of such subdivisions and shall be disregarded in construing the language contained in such subdivisions.

(c) The words “this Agreement”, “this instrument”, “herein”, “hereof”, “hereby”, “hereunder” and words of similar import refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited.

(d) Words in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Pronouns in masculine, feminine and neuter genders shall be construed to include any other gender.

(e) Unless the context otherwise requires or unless otherwise provided herein, the terms defined in this Agreement which refer to a particular agreement, instrument or document also refer to and include all renewals, extensions, modifications, amendments or restatements of such agreement, instrument or document, provided that nothing contained in this subsection shall be construed to authorize such renewal, extension, modification, amendment or restatement.

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(f) Examples shall not be construed to limit, expressly or by implication, the matter they illustrate.

(g) The word “or” is not intended to be exclusive and the word “includes” and its derivatives means “includes, but is not limited to” and corresponding derivative expressions.

(h) No consideration shall be given to the fact or presumption that one party had a greater or lesser hand in drafting this Agreement.

(i) All references herein to “$” or “dollars” shall refer to U.S. Dollars.

(j) Exhibits I, 1.3, 8.1(c) and 9.1(f) are attached hereto. Each such Exhibit is incorporated herein by reference for all purposes and references to this Agreement shall also include such Exhibit unless the context in which used shall otherwise require.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, this Agreement is executed by the parties hereto on the date set forth above.


SELLER:

EVERLAST ENERGY LLC

By:
Name:		Tim J. Goff
Title:		President

RB MARKETING COMPANY LLC

By:
Name:		Tim J. Goff
Title:		President

ROBINSON’S BEND OPERATING COMPANY LLC

By:
Name:		Tim J. Goff
Title:		President
BUYER:

CBM EQUITY IV, LLC

By:
Name:
Title:

SIGNATURE PAGE TO ASSET PURCHASE AND SALE AGREEMENT

EXHIBIT I

Letter Agreement

Exhibit 10.10

One Allen Center

500 Dallas Street

Suite 3300

Houston, Texas 77002

LOGO

June 7, 2006

The Investment Company LLC

1630 Welton Street, Suite 300

Denver, CO 80202

Attn: Mr. Mackie Cannon

Re:	Fee Agreement, Robinson’s Bend Field, Tuscaloosa County, Alabama

Gentlemen:

The Investment Company LLC (“TIC”) provided services to Constellation Energy Commodities Group, Inc. (“CCG”) in connection with the acquisition of certain interests in the Robinson’s Bend Field, located in Tuscaloosa County, Alabama then owned by Everlast Energy LLC (“Everlast”). CCG completed its acquisition of Everlast’s interests in the Robinson’s Bend Field in June 2005 (the “Transaction”). This letter (the “Agreement”) sets forth our agreement with regard to payment of a fee to TIC in connection with the Transaction.

If the pricing date for an initial public offering (the “Offering”) of common units of Constellation Energy Resources LLC, a wholly owned subsidiary of CCG (“CER”), occurs an or before October 31, 2006, then contemporaneously with such pricing date, CCG shall pay to TIC the sum of Three Million One Hundred Twenty-Five Thousand Dollars ($3,125,000.00). In addition, prior to closing of the Offering, Robinson’s Bend Production II, LLC, an indirect wholly owned subsidiary of CCG (“RBP”), will assign to CEP Equity II, LLC, another wholly owned indirect subsidiary of CCG (“CEP II”), an undivided interest in RBP’s oil and gas leases in the Robinson’s Bend Field, insofar and only insofar as such leases cover depths below 100 feet below the stratigraphic equivalent of the base of the “J” Coal Group of the Pottsville Formation, as seen in the Density Log for the Holman 8-11 #1 well located in Section 8 of Township 22 South, Range 11 West, Tuscaloosa County, Alabama (the “Deep Rights”). Promptly after the closing of the Offering, CCG will cause CEP II to assign to TIC an undivided three percent (3%) of the interest so assigned by RBP to CEP II. Prior to commencement of operations with respect to the Deep Rights, CEP II and TIC shall enter into a mutually acceptable joint operating agreement.

If the proposed Offering is not priced on or before October 31, 2006, then, in lieu of the consideration described in Paragraph 1 above, TIC shall have the option, exercisable upon written notice delivered to RBP on or before November 30, 2006, to purchase from RBP an undivided three percent (3%) of RBP’s right, title and interest in the oil and gas leases and wells in the Robinson’s Bend Field which were acquired by RBP from Everlast, as such interests are more fully described in that certain Assignment and Bill of Sale, dated June 13, 2005, but effective for all purposes as of May 1, 2005, from Everlast Energy LLC, as Assignor, to Robinson’s Bend Production II, LLC, as Assignee, which is recorded in Deed Book 2005, Page 12601 in the office of the Probate Judge of Tuscaloosa County, Alabama (the “Offered Interest”). The purchase price (“Purchase Price”) for the Offered Interest shall be the book value as of November 1, 2006 (the “Effective Date”), and the purchase and sale of the Offered Interest shall be effective as of the Effective Date. RBP will loan the Purchase Price to TIC, subject to TIC’s execution of a mutually acceptable promissory note and mortgage or deed of trust covering the Offered Interest as security for repayment of the loan. The loan shall bear interest at the lesser of the prime rate per annum established by Citibank, NA as in effect on the closing date or the maximum lawful rate. The loan shall be repaid from a production payment to be reserved by RBP from the assignment to TIC, which production payment shall entitle RBP to receive the net proceeds attributable to production of hydrocarbons from the Offered Interest from and after the Effective Date until such time as all principal and interest

have been repaid. For purposes of this agreement, “net proceeds” shall mean the gross proceeds received from the sale or other disposition of hydrocarbons produced from or attributable to the Offered Interest less (i) all severance, production and other similar taxes or assessments based on or measured by the production of hydrocarbons, (ii) all royalties, overriding royalties, net profits interests, and other similar burdens on production, but only to the extent such burdens arose prior to the Effective Date, (iii) all transportation, compression, processing and other costs incurred in connection with transportation and marketing of hydrocarbons produced from the Offered Interest, and (iv) all direct costs attributable to the operation of the Offered Interest after the Effective Date (expressly excluding capital expenditures). RBP shall look solely to the production payment for repayment of the loan, it being agreed that if the production payment proceeds are insufficient to pay the principal and interest on the loan, TIC shall have no liability for payment of the unpaid amounts. If TIC exercises its option to purchase the Offered Interest, closing of such sale shall occur at a mutually agreed location, date and time not later than fifteen (15) business days after RBP’s receipt of notice of TIC’s exercise of its option. At closing, (x) RBP shall assign the Offered Interest to TIC, subject to RBP’s reservation of the production payment described above, and (y) RBP and TIC shall enter into a mutually acceptable joint operating agreement with respect to the subject leases and the lands covered thereby. The assignment will be made without warranty, express or implied, except that, subject to the Hedging Agreements (as defined below), RBI shall warrant title to the Offered Interest to be free of claims arising by, through or under RBP, but not otherwise. The assignment shall be made subject to all burdens thereon existing as of RBP’s acquisition of the subject leases, including, without limitation, the net overriding royalty conveyance granted by Velasco Gas Company, Ltd. to Torch Energy Advisors Incorporated and its successors and assigns and all options, swaps, floors, caps, collars, forward sales or forward purchases or other derivative agreements existing as of the closing and assumed from Everlast by CCG and/or its affiliates (the “Hedging Agreements”).

Except for the alternative fees expressly provided in Paragraphs 1 and 2 above, TIC, on behalf of itself, its members, affiliates, successors, and assigns does hereby finally, completely and fully RELEASE, ACQUIT and FOREVER DISCHARGE CCG, CER, RBP and their affiliates and cacti of their respective members, officers, managers, agents, servants, employees, subsidiaries, affiliates, representatives, successors and assigns of and from any and all other claims, demands, controversies, obligations, actions, debts or causes of action, attorneys’ fees and costs, and damages of every kind, including statutory, compensatory, punitive and exemplary, and from all other causes of action, whether arising under contract, statute, regulation or judicial decision, whether known or unknown, relating to or arising from the Transaction.

This Agreement constitutes the sole and entire agreement of CCG, and its affiliates and TIC, with respect to the matters covered hereby (including, without limitation, any finder’s fees relating to the Transaction) and supersedes all prior negotiations and written, oral or implied representations, commitments, offers and understandings between or among the parties or any of their affiliates with respect to such matters.

THE PROVISIONS OF THIS AGREEMENT AND THE RELATIONSHIP OF THE PARTIES SHALL BE GOVERNED AND INTERPRETED ACCORDING TO THE LAWS OF THE STATE OF NEW YORK WITHOUT GIVING EFFECT TO PRINCIPLES Of CONFLICTS OF LAWS THAT WOULD DIRECT APPLICATION OF THE LAWS OF ANOTHER JURISDICTION. EACH PARTY HERETO AGREES THAT ANY PROCEEDINGS ARISING FROM OR RELATING TO DISPUTES UNDER THIS AGREEMENT MAY BE BROUGHT AND MAINTAINED IN FEDERAL OR STATE COURT LOCATED IN HARRIS COUNTY, TEXAS, AND EACH PARTY WAIVES ANY OBJECTION IT MAY HAVE TO VENUE THEREIN.

In case of a conflict between the provisions of this Agreement and the provisions of any applicable laws or regulations, the provisions of the laws or regulations shall govern over the provisions of this Agreement. If, for any reason and for so long as, any clause or provision of this Agreement is held by a court of competent jurisdiction to be illegal, invalid, unenforceable or unconscionable under any present or future law (or interpretation thereof), the remainder of this Agreement shall not be affected by such illegality or invalidity.

7.	Time is essential to this Agreement and, accordingly, all time limits herein shall be strictly construed and enforced.

8.	This Agreement may be executed in multiple counterparts, each of which shall be deemed an original and all of which together shall constitute one and the same instrument.

Please indicate TIC’s agreement with the foregoing by executing the enclosed counterpart of this Agreement in the space provided below and returning a fully executed original agreement to the undersigned.


Very truly yours, Constellation Energy Commodities Group, Inc.
By:		/s/ Stu Rubenstein
Name:		Stu Rubenstein
Title:		Chief Operating Officer

Robinson’s Bend Production II, LLC

By:		/s/ Felix Dawson
Name:
Title:


Agreed to and accepted this 7th day of June, 2006. The Investment Company LLC

By:		/s/ L M Cannon
Name:		L M Cannon
Title:		Principal

Form of Trademark License Agreement

Exhibit 10.11

TRADEMARK LICENSE AGREEMENT

THIS TRADEMARK LICENSE AGREEMENT (the “Agreement”), made as of the day of , 2006, is by and among Constellation Energy Partners LLC, a Delaware limited liability company (the “Company”), and Constellation Energy Group, Inc., a Maryland corporation (“Constellation”).

WHEREAS, subject to the terms hereof, Constellation desires to grant the Company, and the Company desires to take from Constellation, a limited license to use certain marks in connection with the Company’s business.

ARTICLE 1

DEFINITIONS

Section 1.1 Defined Terms. Capitalized terms used, but not defined herein, shall have the meanings given them in the LLC Agreement. As used in this Agreement, the following terms shall have the respective meanings set forth below:

“Affiliate” means, with respect to a Person, any other Person controlling, controlled by or under common control with such Person.

“Agreement” means this Agreement, as it may be amended from time to time.

“Business Day” means any day that is not a Saturday, Sunday or day on which banks are authorized by law to close in the States of Maryland or Texas.

“Closing Date” means the date of the closing of the initial public offering, pursuant to the Prospectus, of Common Units.

“Company” has the meaning set forth in the above preamble.

“Conflicts Committee” has the meaning given such term in the LLC Agreement.

“Constellation” has the meaning set forth in the above preamble.

“LLC Agreement” means the Second Amended and Restated Operating Agreement of the Company, dated as of the Closing Date, as such agreement is in effect on the Closing Date, to which reference is hereby made for all purposes of this Agreement. An amendment or modification to the LLC Agreement subsequent to the Closing Date shall be given effect for the purposes of this Agreement only if it has received the approval that would be required pursuant to Section 4.10 hereof if such amendment or modification were an amendment or modification of this Agreement.

“Marks” means all trademarks, tradenames, logos and service marks identified on Exhibit A.

“Proceedings” means all proceedings, actions, claims, suits and notices of investigations by or before any arbitrator or Governmental Authority.

“Prospectus” means the final prospectus, dated October , 2006, relating to the initial public offering of common units representing Class B limited liability company interests in the Company, as filed with Securities and Exchange Commission pursuant to Rule 424(b) under the Securities Act of 1933.

“Term” means the period from the Closing Date through the date upon which the right of the holder or holders of the Class A Units to elect Class A Managers pursuant to Section 11.8(e) of the LLC Agreement is terminated.

“Third Party” means any Person other than the Company or Constellation or any of their respective Affiliates.

Section 1.2 Other Definitions. Words not otherwise defined herein that have well-known and generally accepted technical or trade meanings in the oil and gas industry are used herein in accordance with such recognized meanings.

Section 1.3 Construction. As used in this Agreement, unless expressly stated otherwise, references to “includes” and its derivatives mean “includes, but is not limited to,” and corresponding derivative expressions. Unless otherwise specified, all references in this Agreement to “Sections” and “Exhibits” are references to the corresponding sections in and exhibits attached to this Agreement; all such exhibits are incorporated herein by reference.

ARTICLE 2

Intellectual Property License

Section 2.1 Limited License. Subject to the terms and conditions herein, Constellation hereby grants to the Company the limited right and license to use the Marks solely in connection with the Company’s businesses and the services performed therewith within the United States during the Term and for a period of six (6) months thereafter.

Section 2.2 Restrictions on Marks. In order to ensure the quality of uses under the Marks, and to protect the goodwill of the Marks, the Company agrees as follows:

(a) The Company will only use the Marks in formats approved by Constellation and only in strict association with the Company’s businesses and the services performed therewith;

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(b) Prior to publishing any new format or appearance of the Marks or the advertising or promotional materials, the Company shall first provide such format, appearance or materials to Constellation for its approval. If Constellation does not inform the Company in writing within fourteen (14) days from the date of the receipt of such new format, appearance or materials that such new format, appearance or materials is acceptable, then such new format, appearance or materials shall be deemed to be unacceptable and disapproved by Constellation. Constellation may withhold approval of any proposed changes to the format, appearance or materials that the Company propose to use in Constellation’s sole discretion; and

(c) The Company shall not, without the prior approval of Constellation, use any other trademarks, service marks, trade names or logos in connection with the Marks or use the Marks or any trademark or service mark confusingly similar to the Marks after the termination of this Agreement. The Company will not use the Marks in such a manner so as to impair the validity or enforceability of, or in any way disparage or dilute, the Marks.

Section 2.3 Ownership. Constellation shall own all right, title and interest, including all goodwill relating thereto, in and to the Marks, and all trademark rights embodied therein shall at all times be solely vested in Constellation. The Company shall have no right, title, interest or claim of ownership in the Marks, except for the limited license granted in this Agreement. All use of the Marks shall inure to the benefit of Constellation. The Company agrees that it will not attack the title of Constellation in and to the Marks.

Section 2.4 Estoppel. Nothing in this Agreement shall be construed as conferring by implication, estoppel or otherwise upon the Company (a) any license or other right under the intellectual property rights of Constellation other than the limited license granted herein to the Marks as set forth expressly herein or (b) any license rights other than those expressly granted herein.

Section 2.5 Warranties; Disclaimers.

(a) Constellation represents and warrants that (i) it owns and has the right to license the Marks licensed under this Agreement, and (ii) the Marks do not infringe upon the rights of any Third Parties.

(b) EXCEPT FOR THE WARRANTIES AND REPRESENTATIONS DESCRIBED IN SECTION 2.5(a), CONSTELLATION DISCLAIMS ANY AND ALL WARRANTIES, CONDITIONS OR REPRESENTATIONS (EXPRESS OR IMPLIED, ORAL OR WRITTEN) WITH RESPECT TO THE SUBJECT MATTER HEREOF, OR ANY PART THEREOF, INCLUDING ANY AND ALL IMPLIED WARRANTIES OF NON-INFRINGEMENT, MERCHANTABILITY OR FITNESS OR SUITABILITY FOR ANY PURPOSE (WHETHER CONSTELLATION KNOWS, HAS REASON TO KNOW, HAS BEEN ADVISED, OR IS OTHERWISE IN FACT AWARE OF ANY SUCH PURPOSE) WHETHER ALLEGED TO ARISE BY LAW, BY REASON OF CUSTOM OR USAGE IN THE TRADE OR BY COURSE OF DEALING.

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Section 2.6 Remedies and Enforcement. The Company acknowledges and agrees that a breach by it of its obligations under this Article 2 would cause irreparable harm to Constellation and that monetary damages would not be adequate to compensate Constellation. Accordingly, the Company agrees that Constellation shall be entitled to immediate equitable relief, including a temporary or permanent injunction, to prevent any threatened, likely or ongoing violation by the Company, without the necessity of posting bond or other security. Constellation’s right to equitable relief shall be in addition to other rights and remedies available to Constellation, for monetary damages or otherwise.

ARTICLE 3

INDEMNIFICATION; LIMITATIONS

Section 3.1 Indemnification by CEPM. Constellation hereby agrees to DEFEND, INDEMNIFY AND HOLD HARMLESS the Company and its officers, managers, members, partners, directors, employees, agents and Affiliates (collectively, the “Company Indemnitees”) from any and all threatened or actual claims, demands, causes of action, suits, proceedings, losses, damages, fines, penalties, liabilities, costs and expenses of any nature, including attorneys’ fees and court costs (collectively, “Liabilities”), sustained by, incurred by, arising in favor of or asserted by any Third Parties, employees, agents and representatives of Constellation, or any contractors or subcontractors of Constellation, in any way relating to any claim of infringement or ownership asserted by a Third Party as to the Marks.

Section 3.2 Negligence; Strict Liability. EXCEPT AS EXPRESSLY PROVIDED IN Section 3.1, THE DEFENSE AND INDEMNITY OBLIGATIONS IN Section 3.1 SHALL APPLY REGARDLESS OF CAUSE OR OF ANY NEGLIGENT ACTS OR OMISSIONS (INCLUDING SOLE NEGLIGENCE, CONCURRENT NEGLIGENCE OR STRICT LIABILITY), BREACH OF DUTY (STATUTORY OR OTHERWISE), VIOLATION OF LAW OR OTHER FAULT OF ANY INDEMNIFIED PARTY, OR ANY PRE-EXISTING DEFECT; PROVIDED, HOWEVER, THAT THIS PROVISION SHALL IN NO WAY LIMIT OR ALTER ANY QUALIFICATIONS SET FORTH IN SUCH DEFENSE AND INDEMNITY OBLIGATIONS EXPRESSLY RELATING TO GROSS NEGLIGENCE, INTENTIONAL MISCONDUCT OR BREACH OF THIS AGREEMENT. BOTH PARTIES AGREE THAT THIS STATEMENT COMPLIES WITH THE REQUIREMENT KNOWN AS THE ‘EXPRESS NEGLIGENCE RULE’ TO EXPRESSLY STATE IN A CONSPICUOUS MANNER AND TO AFFORD FAIR AND ADEQUATE NOTICE THAT THIS ARTICLE HAS PROVISIONS REQUIRING ONE PARTY TO BE RESPONSIBLE FOR THE NEGLIGENCE, STRICT LIABILITY, OR OTHER FAULT OF ANOTHER PARTY.

Section 3.3 Exclusion of Damages. NO PARTY SHALL BE LIABLE TO ANY OTHER PARTY HERETO FOR EXEMPLARY, PUNITIVE, CONSEQUENTIAL, SPECIAL, INDIRECT OR INCIDENTAL DAMAGES, EVEN IF ADVISED OF THE POSSIBILITY OF SUCH DAMAGES AND REGARDLESS OF THE FORM IN WHICH ANY ACTION IS BROUGHT.

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ARTICLE 4

MISCELLANEOUS PROVISIONS

Section 4.1 Notices. All notices or advices required or permitted to be given by or pursuant to this Agreement, shall be given in writing. All such notices and advices shall be (i) delivered personally, (ii) delivered by facsimile or delivered by U.S. registered or certified mail, return receipt requested mail, or (iii) delivered for overnight delivery by a nationally recognized overnight courier service. Such notices and advices shall be deemed to have been given (i) on the date of delivery if delivered personally or by facsimile, (ii) on the third Business Day following the date of mailing if mailed by U.S. registered or certified mail, return receipt requested, or (iii) on the date of receipt if delivered for overnight delivery by a nationally recognized overnight courier service. All such notices and advices and all other communications related to this Agreement shall be given as follows:

If to Constellation:

Constellation Energy Group, Inc.

Attn:

750 East Pratt Street

Baltimore, Maryland 21202

Telephone: (410)

Fax: (410)

With a copy to:

Constellation Energy Group, Inc.

Attn: General Counsel

750 East Pratt Street

Baltimore, Maryland 21202

Telephone: (410)

Fax: (410)

If to the Company:

Constellation Energy Partners LLC

Attn: Chief Financial Officer

111 Market Place

Baltimore, Maryland 21202

Telephone: (410) 468-3500

Fax: (410) 468-3499

With a copy to:

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Constellation Energy Partners LLC

Attn: Legal Department

One Allen Center

500 Dallas

Suite 3300

Houston, Texas 77002

Telephone: (713)

Fax: (713)

or to such other address as the party may have furnished to the other parties in accordance herewith, except that notice of change of addresses shall be effective only upon receipt.

Section 4.2 Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the State of New York, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each Party hereby submits to the non-exclusive jurisdiction of the federal courts in the State of New York and to venue in New York, New York.

Section 4.3 Entire Agreement. This Agreement is the entire Agreement of the Parties respecting the subject matter hereof. There are no other agreements, representations or warranties, whether oral or written, respecting the subject matter hereof, and this Agreement supersedes and replaces any such prior agreements, representations or warranties.

Section 4.4 Jointly Drafted. This Agreement, and all the provisions of this Agreement, shall be deemed drafted by both of the Parties, and shall not be construed against either Party on the basis of that Party’s role in drafting this Agreement.

Section 4.5 Further Assurances. In connection with this Agreement, each Party shall execute and deliver any additional documents and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement.

Section 4.6 Assignment. This Agreement may not be assigned by any Party without the prior written consent of all of the other Parties. This Agreement shall be binding upon and shall inure to the benefit of the Parties and their respective successors and permitted assigns.

Section 4.7 No Third-Party Beneficiaries. Nothing in this Agreement shall provide any benefit to any Third Party or entitle any Third Party to any claim, cause of action, remedy or right of any kind, it being the intent of the Parties that this Agreement shall not be construed as a third-party beneficiary contract.

Section 4.8 Relationship of the Parties. Nothing in this Agreement shall be construed to create a partnership or joint venture or give rise to any fiduciary or similar relationship of any kind.

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Section 4.9 Effect of Waiver or Consent. No waiver or consent, express or implied, by any Party to or of any breach or default by any Person in the performance by such Person of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a Party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such Party of its rights hereunder until the applicable statute of limitations period has run.

Section 4.10 Amendment or Modification. This Agreement may be amended, restated or modified from time to time only by the written agreement of both of the Parties; provided, however, that the Company may not, without the prior approval of the Conflicts Committee, agree to any amendment or modification of this Agreement that will adversely affect the holders of Common Units. Each such instrument shall be reduced to writing and shall be designated on its face an “Amendment,” “Addendum” or a “Restatement” to this Agreement.

Section 4.11 Severability. If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

Section 4.12 Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory Parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument.

Section 4.13 Withholding or Granting of Consent. Except as expressly provided to the contrary in this Agreement, each Party may, with respect to any consent or approval that it is entitled to grant pursuant to this Agreement, grant or withhold such consent or approval in its sole and uncontrolled discretion, with or without cause, and subject to such conditions as it shall deem appropriate.

Section 4.14 Laws and Regulations. Notwithstanding any provision of this Agreement to the contrary, no Party shall be required to take any act, or fail to take any act, under this Agreement if the effect thereof would be to cause such Party to be in violation of any applicable law, statute, rule or regulation.

[SIGNATURE PAGES FOLLOWS]

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IN WITNESS WHEREOF, the Parties have executed this Agreement on, and to be effective as of, the Closing Date.


“COMPANY”

CONSTELLATION ENERGY PARTNERS LLC

By:
Name:
Title:
Date:

“CONSTELLATION”

CONSTELLATION ENERGY GROUP, INC.

By:
Name:
Title:
Date:

EXHIBIT A

Marks

[to come]

EXH-A-1

Consent of PricewaterhouseCoopers LLP

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the use in this Amendment No. 2 to the Registration Statement on Form S-1 of our report dated June 12, 2006 relating to the financial statements of Constellation Energy Partners LLC and our report dated June 12, 2006 relating to the financial statements of Everlast Energy LLC, which appear in such Registration Statement. We also consent to the reference to us under the heading “Experts” in such Registration Statement.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Baltimore, Maryland

September 28, 2006

Consent of Netherland Sewell & Associates, Inc.

EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the reference to our Firm’s name in the Registration Statement on Form S-1/A-2 and related Prospectus of Constellation Energy Partners LLC for the registration of units representing limited liability company interests.


NETHERLAND, SEWELL & ASSOCIATES, INC.

By:		/s/ Danny D. Simmons
		Danny D. Simmons, P.E. Executive Vice President

Houston, Texas

September 28, 2006

SEC Response Letter

600 Travis, Suite 4200

Houston, Texas 77002

713.220.4200 Phone

713.220.4285 Fax

andrewskurth.com

September 28, 2006

BY FEDERAL EXPRESS

Securities and Exchange Commission

100 F Street, NE

Mail Stop 7010

Washington, DC 20549-7010

Attn: H. Roger Schwall

Re:

Constellation Energy Partners LLC

Amendment No. 2 to Registration Statement on Form S-1

File No. 333-134995

Dear Mr. Schwall:

Set forth below are the responses of Constellation Energy Partners LLC, a Delaware limited liability company (“CEP”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission by letter dated August 29, 2006, with respect to Amendment No. 1 to CEP’s Registration Statement on Form S-1 (File No. 333-134995). Where applicable, our responses indicate the additions, deletions or revisions we included in Amendment No. 2 to the Registration Statement (“Amendment No. 2”). For your convenience, our responses are prefaced by the exact text of the Staff’s corresponding comment in bold text. The references to page numbers in the responses to the Staff’s comments correspond to the pages in Amendment No. 2 that we are filing today via EDGAR.

Cash Distribution Policy and Restrictions on Distributions, page 60

Our Estimated Adjusted EBITDA, page 67

1.	We note your revised disclosure in response to prior comment 17 that you may borrow funds under your reserve based credit facility “only if certain financial tests are met.” Please disclose those financial tests.

Response:

We have revised our disclosure as requested. Please see page 71 of Amendment No. 2.

Austin Beijing Dallas Houston London Los Angeles New York The Woodlands Washington, DC

Unaudited Pro Forma Available Cash to Pay Distributions, page 73

We note your response to prior comment 18 and revised disclosure that you would not have obtained additional cash to pay the shortfall. Please revise your disclosure to clarify the amount, if any, you would have paid for your cash distribution in light of the shortfall. Further, disclose the amount you will pay if you have a shortfall of your estimated cash available to pay distributions.

Response:

We have revised our disclosure as requested. Please see pages 4 and 74 of Amendment No. 2.

Financial Statements

Note 2 - Restatement of Everlast Financial Statements, page F-14

We note your disclosure on page 109 explaining that the adjusted reserve quantities were not used in preparing your 2004 and 2003 financial statements because they reflect assumptions that are based on the interpretation of well performance data that was not available in those earlier periods, and a different pace for the drilling program.

However, your disclosure under this heading states that depletion expense is being corrected due to “…reserve estimates which incorrectly included certain proved undeveloped reserves.” We also note that you have not adjusted the reserve information presented on page F-29 to align your reserve reporting with the guidelines set forth in Rule 4-10 of Regulation S-X, based on the facts existing in those earlier periods.

Please expand your disclosure to include a reconciliation of the reserve information previously reported to the adjusted quantities, taking into account only the information that was available at the time that information was compiled, and necessary to comply with the SEC reporting guidelines; these quantities should be used when recalculating depletion and ceiling tests in the course of correcting your financial statements.

Likewise, please correct the SFAS 69 disclosures presented in Note 17, beginning on page F-27, to comply with Rule 4-10 of Regulation S-X. As Everlast Energy LLC is regarded as a predecessor, that information should also cover the period from January 1, 2005 through June 12, 2005; similar to the requirement for financial results. The ending balances for the predecessor should equal the beginning balances for the successor. Any columns including corrected reserve information should be labeled as restated.

As for the reserve information depicted on page 108, and any duplication of that data elsewhere in the filing, please understand that recasting prior amounts using new information or assumptions, as opposed to correcting amounts for information known at the time of initial compilation, is typically viewed as a pro forma presentation and would not be appropriate under the circumstances.

Please modify those disclosures to eliminate any recasting of prior reserve information for items that would not be appropriately regarded as errors in the earlier compilations; and to differentiate, in your narrative, between new information and assumptions factored into your 2005 reserve revisions and adjustments necessary to correct earlier disclosures.

Response:

We have revised our disclosure as discussed with the Staff via teleconferences. Please see pages 21, 22, 109, 110, F-15 and F-29 through F-32 of Amendment No. 2.

Engineering Comments

Business, page 101

Development Costs, page 113

We have read your response to previous comment 39, and continue to believe the measure you describe as development costs per Mcf, as you calculate it on a per equivalent reserve basis, is a non-GAAP measure. Further, we do not believe the label you have utilized is sufficiently descriptive, as you have included both development and acquisition costs in the numerator, while including both developed and undeveloped reserve quantities in the denominator.

Using the development costs of $7,851, depicted in your table on page F-28, and the change in developed reserves referenced in your narrative of 6.15 Bcf, the measure would be $1.28 per Mcf. We would not object to a view of this measure as being outside the scope of Item 10(e)(2) of Regulation S-K. If you wish to retain the measure you have calculated, you will need to utilize an alternate label and comply with other disclosure requirements for non-GAAP measures. This would need to include a reconciliation of your numerators and denominators to the related line items depicted in your SFAS 69 disclosures in Note 17, beginning on page F-27.

In any case, we believe you should also expand your disclosure to address the limitations of your measure, clarifying the status of all properties associated with the reserve increases, and the extent to which costs incurred during the period were fully reflective of the total costs necessary to develop the properties from the point of initial reserve determination, to the re-characterization of undeveloped reserves to developed reserves. Please also indicate the extent to which development costs incurred during the current period may facilitate a similar re-characterization of other reserves in future periods.

Response:

We have revised our disclosure to remove the calculation of the implied development costs. Please see page 114 of Amendment No. 2.

* * * * *

Please do not hesitate to call the undersigned at (713) 220-4360 or Tim Langenkamp at (713) 220-4357 with any comments or questions regarding this letter or the above-referenced Registration Statement.

Very truly yours,

/s/ G. Michael O’Leary

cc:	D. Delaney, Securities and Exchange Commission

K. Hiller, Securities and Exchange Commission

J. Wynn, Securities and Exchange Commission

J. Murphy, Securities and Exchange Commission

F. Dawson, Constellation Energy Partners LLC

A. Baden, Vinson & Elkins L.L.P.