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As filed with the Securities and Exchange Commission on November 2, 2006
Registration No. 333-134995
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 4 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, 26th 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.
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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 NOVEMBER 2, 2006
P R O S P E C T U S
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4,500,000 Common Units
Representing Class B Limited Liability Company Interests
We are offering 4,500,000 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 675,000 additional common units to cover over-allotments. We currently estimate that the initial public offering price will be between $19.00 and $21.00 per common unit. Our common units have been approved, subject to official notice of issuance, for listing 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 59% 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 $6.32 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
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We are a limited liability company focused on the acquisition, development and exploitation of oil and natural gas properties as well as related midstream assets. Our 112.0 Bcf of estimated proved reserves are 100% natural gas and are located in the Robinson’s Bend Field in Alabama’s Black Warrior Basin.
| Geographic Location of Current Constellation Energy Partners Assets |
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| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
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| Distributions and Payments to CCG, CEPH, CEP Equity II LLC, CHI and CEPM |
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| Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney |
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| 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.
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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 $20.00 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 226,406 Class A units, 6,593,894 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
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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 79% 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; |
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| • | 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 $20.2 billion as of September 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.”
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 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 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
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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.”
Cash Distribution Policy
Our board of managers has adopted a cash distribution policy to pay a regular quarterly distribution of $0.4625 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 $8.8 million. If we had completed the transactions contemplated in this prospectus on October 1, 2005, pro forma available cash generated during the twelve months ended September 30, 2006 would have been approximately $8.1 million. These amounts of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 42% and 39%, 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 September 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, we will 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.”
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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 September 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 226,406 Class A units, 6,593,894
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common units and the management incentive interests. Immediately after such conversion, CEPH will contribute the 226,406 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.”
Sale of Floyd Shale Rights. In connection with this offering, we sold 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 were 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 did not fit our investment strategy, given the uncertainty of encountering commercial quantities of oil or natural gas. On October 30, 2006, we received $475,000 in return for this sale of the Floyd Shale Rights.
Reserve-Based Credit Facility. On October 31, 2006 we entered into a new reserve-based credit facility under which our initial borrowing base is $75.0 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 $106.8 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 66 2/3% 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
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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.
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Index to Financial Statements
| Units offered by us |
4,500,000 common units; or 5,175,000 common units if the underwriters exercise their option to purchase additional common units in full. |
| Units outstanding after this offering |
11,093,894 common units, which does not include any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. |
| 226,406 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 the structuring fee and offering expenses, received from this offering(a) | $ | 80.7 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) | $ | 106.8 million | |
| Reduction of borrowings under our new reserve-based credit facility | $ | 8.0 million | |
| Working capital | $ | 3.9 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 and the structuring fee of $6.3 million and estimated offering expenses of $3.0 million (after reimbursement to us by the underwriters of approximately $0.2 million of offering expenses). (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 $0.4625 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 |
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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 $0.5319 (that is, the $0.4625 IQD plus $0.0694), 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. |
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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 interests equal to 17.65% of the sum of the cumulative amounts, if |
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Index to Financial Statements
| 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, or if we do make such distributions, how much they will be. For a further discussion of the management incentive interests, please read |
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Index to Financial Statements
| the information set forth under the caption “How We Make Cash Distributions–Management Incentive Interests.” |
| Special Class D interests distribution |
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 $333,333.33, 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 $333,333.41 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 December 31, 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 January 1, 2007, our revenues would be reduced by approximately $4.4 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 1.8 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. |
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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 $0.4625 on all Class A and common units for each quarter in the twelve-month period ending December 31, 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 September 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 |
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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 66 2/3% 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 |
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| ending December 31, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 30% 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 |
Our common units have been approved, subject to official notice of issuance, for listing on NYSE Arca under the trading symbol “CEP.” |
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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 nine months ended September 30, 2006 and for the period from February 7, 2005 (inception) to September 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 nine months ended September 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.
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| Predecessor |
Successor | ||||||||||||||||||||||||||||
| Everlast Energy LLC |
Constellation Energy Partners LLC | ||||||||||||||||||||||||||||
| For the year ended |
For the year ended |
For the June 12, |
For the (inception) to December 31, |
For the (inception) to September 30, |
For the nine months ended September 30, 2006 |
Pro Forma | |||||||||||||||||||||||
| For the year ended December 31, 2005 |
For the nine months ended September 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 | $ | 10,925 | $ | 26,154 | $ | 38,839 | $ | 26,154 | |||||||||||||
| Loss from mark-to-market activities |
(3,664 | ) | (9,107 | ) | (15,313 | ) | — | — | — | (15,313 | ) | — | |||||||||||||||||
| Total revenues |
18,656 | 18,387 | (2,431 | ) | 25,957 | 10,925 | 26,154 | 23,526 | 26,154 | ||||||||||||||||||||
| Operating expenses: |
|||||||||||||||||||||||||||||
| Lease operating expenses |
4,428 | 5,270 | 2,769 | 4,175 | 1,783 | 5,321 | 6,944 | 5,321 | |||||||||||||||||||||
| Production taxes |
1,279 | 1,479 | 676 | 1,400 | 500 | 1,340 | 2,076 | 1,340 | |||||||||||||||||||||
| General and administrative |
1,945 | 2,706 | 594 | 4,184 | 3,331 | 3,445 | 4,778 | 3,445 | |||||||||||||||||||||
| Depreciation, depletion and amortization |
3,684 | 3,719 | 1,683 | 4,176 | 2,229 | 5,987 | 7,281 | 5,987 | |||||||||||||||||||||
| Accretion expense |
73 | 86 | 46 | 78 | 43 | 106 | 141 | 106 | |||||||||||||||||||||
| Total operating expenses |
11,409 | 13,260 | 5,768 | 14,013 | 7,886 | 16,199 | 21,220 | 16,199 | |||||||||||||||||||||
| Other expenses/(income): |
|||||||||||||||||||||||||||||
| Interest expense/(income), net |
1,961 | 3,028 | 2,437 | 3 | 2 | (361 | ) | 1,546 | 966 | ||||||||||||||||||||
| Organization costs |
299 | — | — | — | — | — | — | — | |||||||||||||||||||||
| Total other expenses/(income) |
2,260 | 3,028 | 2,437 | 3 | 2 | (361 | ) | 1,546 | 966 | ||||||||||||||||||||
| Total expenses/(income) |
13,669 | 16,288 | 8,205 | 14,016 | 7,888 | 15,838 | 22,766 | 17,165 | |||||||||||||||||||||
| Net income (loss) |
$ | 4,987 | $ | 2,099 | $ | (10,636 | ) | $ | 11,941 | $ | 3,037 | $ | 10,316 | $ | 760 | $ | 8,989 | ||||||||||||
| Other Financial Information (unaudited): |
|||||||||||||||||||||||||||||
| Adjusted EBITDA |
$ | 10,193 | $ | 14,738 | $ | 8,795 | $ | 16,198 | $ | 5,311 | $ | 16,048 | $ | 24,993 | $ | 16,048 | |||||||||||||
| (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. |
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| Predecessor |
Successor | ||||||||||||||||||||||||||
| Everlast Energy LLC |
Constellation Energy Partners LLC | ||||||||||||||||||||||||||
| For the year ended |
For the year ended |
For the June 12, |
For the (inception) to December 31, |
For the (inception) to 2005(b) |
For the nine 2006 |
Pro Forma | |||||||||||||||||||||
| For the nine 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 | $ | 6,387 | $ | 3,911 | |||||||||||||||||
| Other current assets |
1,812 | 4,562 | 6,097 | 27,242 | 12,602 | ||||||||||||||||||||||
| Natural gas properties, net of accumulated depreciation, depletion and amortization |
49,252 | 52,531 | 165,211 | 169,918 | 169,918 | ||||||||||||||||||||||
| Other assets |
590 | 1,579 | — | 6,400 | 7,318 | ||||||||||||||||||||||
| Total assets |
$ | 54,217 | $ | 60,684 | $ | 186,139 | $ | 209,947 | $ | 193,749 | |||||||||||||||||
| Current liabilities |
$ | 4,403 | $ | 4,482 | $ | 13,895 | $ | 12,884 | $ | 5,763 | |||||||||||||||||
| Debt |
26,000 | 67,500 | 63 | — | 22,000 | ||||||||||||||||||||||
| Preferred units subject to mandatory redemption |
16,752 | — | — | — | — | ||||||||||||||||||||||
| Other long-term liabilities |
2,671 | 3,314 | 3,014 | 3,160 | 3,160 | ||||||||||||||||||||||
| Class D interests |
— | — | — | — | 8,000 | ||||||||||||||||||||||
| Members equity: |
|||||||||||||||||||||||||||
| Common members equity (deficit) |
4,391 | (14,612 | ) | 169,167 | 179,853 | 140,776 | |||||||||||||||||||||
| Accumulated other comprehensive income |
— | — | — | 14,050 | 14,050 | ||||||||||||||||||||||
| Total members’ equity (deficit) |
4,391 | (14,612 | ) | 169,167 | 193,903 | 154,826 | |||||||||||||||||||||
| Total liabilities and members’ equity (deficit) |
$ | 54,217 | $ | 60,684 | $ | 186,139 | $ | 209,947 | $ | 193,749 | |||||||||||||||||
| Cash Flow Data: |
|||||||||||||||||||||||||||
| Net cash provided by operating activities |
$ | 9,773 | $ | 4,906 | $ | 6,639 | $ | 23,313 | $ | 9,608 | $ | 14,313 | |||||||||||||||
| Net cash used in investing activities |
(47,832 | ) | (6,997 | ) | (4,203 | ) | (147,237 | ) | (142,632 | ) | (22,694 | ) | |||||||||||||||
| Net cash provided by (used in) financing activities |
40,622 | 1,540 | (2,500 | ) | 138,755 | 138,762 | (63 | ) | |||||||||||||||||||
| Development of natural gas properties |
(2,040 | ) | (5,680 | ) | (4,000 | ) | (8,286 | ) | (3,681 | ) | (10,071 | ) | |||||||||||||||
| (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. |
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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.
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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 2003 |
For the year ended |
For the June 12, 2005 |
For the December 31, |
For the September 30, |
For the nine months ended September 30, 2006 |
Pro Forma | ||||||||||||||||||||||||
| For the year ended |
For the nine months ended September 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 | $ | 3,037 | $ | 10,316 | $ | 760 | $ | 8,989 | |||||||||||||
| Add: |
||||||||||||||||||||||||||||||
| Interest expense/(income), net |
1,961 | 3,028 | 2,437 | 3 | 2 | (361 | ) | 1,546 | 966 | |||||||||||||||||||||
| Depreciation, depletion and amortization |
3,684 | 3,719 | 1,683 | 4,176 | 2,229 | 5,987 | 7,281 | 5,987 | ||||||||||||||||||||||
| Accretion of asset retirement obligation |
73 | 86 | 46 | 78 | 43 | 106 | 141 | 106 | ||||||||||||||||||||||
| 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 | $ | 5,311 | $ | 16,048 | $ | 24,993 | $ | 16,048 | ||||||||||||||
| 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 | $ | 9,608 | $ | 14,313 | ||||||||||||||||||
| Add: |
||||||||||||||||||||||||||||||
| Interest expense/(income), net(a) |
1,305 | 2,596 | 2,437 | 3 | 2 | (361 | ) | |||||||||||||||||||||||
| Expenses paid by CCG on behalf of CEP |
— | — | — | (64 | ) | (6 | ) | (370 | ) | |||||||||||||||||||||
| Realized loss on cancelled natural gas derivatives |
— | 7,962 | — | — | — | — | ||||||||||||||||||||||||
| Hedge ineffectiveness |
— | — | — | — | — | 129 | ||||||||||||||||||||||||
| Changes in working capital: |
||||||||||||||||||||||||||||||
| Accounts receivable |
1,547 | 2,278 | 707 | 1,289 | 863 | (1,146 | ) | |||||||||||||||||||||||
| Prepaid expenses |
265 | (246 | ) | 131 | 62 | 171 | 13 | |||||||||||||||||||||||
| Other assets |
— | — | 10 | 211 | 2 | 2,137 | ||||||||||||||||||||||||
| Loan amortization cost |
(288 | ) | (685 | ) | (237 | ) | — | — | — | |||||||||||||||||||||
| Accounts payable |
(908 | ) | (993 | ) | (807 | ) | (1,703 | ) | 615 | 3,811 | ||||||||||||||||||||
| Intercompany payable |
— | — | — | — | — | (3,616 | ) | |||||||||||||||||||||||
| Royalty payable |
(1,321 | ) | (708 | ) | (110 | ) | (1,859 | ) | (1,197 | ) | 1,148 | |||||||||||||||||||
| Accrued liabilities |
(180 | ) | (372 | ) | 25 | (5,054 | ) | (4,747 | ) | (10 | ) | |||||||||||||||||||
| Adjusted EBITDA |
$ | 10,193 | $ | 14,738 | $ | 8,795 | $ | 16,198 | $ | 5,311 | $ | 16,048 | ||||||||||||||||||
| (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. |
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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
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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.
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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.
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 $0.4625 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 December 31, 2007 set forth in “Cash Distribution Policy and Restrictions on Distributions” has been prepared by our management and we
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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 nine months ended September 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 $20.9 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 $8.8 million. If we had completed the transactions contemplated in this prospectus on October 1, 2005, pro forma available cash generated during the twelve months ended September 30, 2006 would have been approximately $8.1 million. These amounts of pro forma cash available for distribution would have been sufficient to allow us to pay approximately 42% and 39%, respectively, of the $0.4625 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 September 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.
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.
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 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.
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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; |
| • | the amount and timing of our capital expenditures; |
| • | the amount and timing of actual production; and |
| • | changes in governmental regulations or taxation. |
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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.
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
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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 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
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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.
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
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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 has 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 restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We are 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 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 in the credit facility or other loan documents, subject, in certain instances, to certain grace periods, which include covenants that: |
| • | Constellation and its affiliates maintain the right to elect our Class A Managers; and |
| • | we obtain the approval of the administrative agent (such approval not to be unreasonably withheld or delayed) of any management services plan upon the termination of the management services agreement with CEPM; |
| • | 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; |
| • | 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 ownership of our outstanding membership interests to less than 25%, and (ii) the ownership by any person (other than a wholly owned subsidiary of Constellation) of more than 35% of our outstanding membership interests. |
The reserve-based credit facility limits 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
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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. We do 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 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. 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 29% of our estimated initial borrowing base of $75.0 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 $53.0 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:
| • | 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; |
| • | 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; |
| • | 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 |
| • | 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. |
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
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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 66 2/3% 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 October 25, 2006 was $10.08 per MMBtu and $7.135 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 December 31, 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 January 1, 2007, our revenues would be reduced by approximately $4.4 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 1.8 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 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,
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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 ten months ended October 31, 2006, the monthly index price varied between a low of $4.18 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 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 per MMBtu and $2.82 per 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
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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 nine months ended September 30, 2006, five customers accounted for 100% of our total sales volumes. Specifically, Interconn Resources Inc., BP Energy Company, Enterprise Alabama, Coral Energy Resources, L.P. and ConocoPhillips accounted for approximately 30%, 22%, 18%, 17% and 13%, 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 September 30, 2005 for the twelve months ended September 30, 2006, we estimate that we would have realized approximately $13.1 million more revenue for that period. On June 20, 2006, we entered into derivative transactions that hedge the future prices of approximately 79% 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 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:
| • | a counterparty may not perform its obligation under the applicable derivative instrument; |
| • | there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and |
| • | the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures. |
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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.
As of December 31, 2005, we held 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 7,737 net acres are scheduled to expire before December 31, 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. 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
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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:
| • | the federal Clean Air Act, related federal regulations, and comparable state laws and regulations that impose obligations related to air emissions; |
| • | 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; |
| • | 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 |
| • | 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.”
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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:
| • | there is the potential for an accidental release from one of our wells or gathering pipelines; |
| • | 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 |
| • | 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 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.
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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:
| • | we cannot obtain future permits from applicable regulatory agencies; |
| • | water of lesser quality or requiring additional treatment is produced; |
| • | our wells produce excess water; or |
| • | 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 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
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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.
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
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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 59% of the outstanding common units, or approximately 53% if the underwriters’ option to purchase additional common units is exercised in full, and 100% of the outstanding Class A units. The percentages do not reflect any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. 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.
Our limited liability company agreement limits and modifies our managers’ and officers’ fiduciary duties.
Our limited liability company agreement contains provisions that modify and limit our managers’ and officers’ fiduciary duties to us and our unitholders. For example, our limited liability company agreement provides that:
| • | our managers and officers will not have any liability to us or our unitholders for decisions made in good faith, which is defined so as to require that they believed the decision was in our best interests; and |
| • | our managers and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the managers or officers acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was unlawful. |
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
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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; |
| • | 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, 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
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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 66 2/3% 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 $6.32 per common unit.
The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $13.68 per common unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $6.32 per common unit. Please read “Dilution.”
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.
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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 4,500,000 publicly traded common units, which number does not include any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. 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; |
| • | 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. |
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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 6,593,894 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 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.
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.
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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 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.
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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.
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 unitholders and in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, 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 unitholders receiving two Schedule K-1s) for one calendar year and the cost of the preparation of these returns will be borne by all unitholders.
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 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.
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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.
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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.
| Sources of Funds |
Uses of Funds | |||||
| Sale of 4,500,000 common units(a) |
$ 80.7 million |
Distribution to CEPH(c)(d) |
$106.8 million | |||
| Contribution by CHI for the Class D interests(b) |
$ 8.0 million |
Retained for working capital(d)(e) |
$ 3.9 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 |
$118.7 million |
Total |
$118.7 million | |||
| (a) | We estimate that we will receive net proceeds of approximately $80.7 million from the sale of the 4,500,000 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 and the structuring fee of $6.3 million and estimated offering expenses of $3.0 million (after reimbursement to us by the underwriters of approximately $0.2 million of offering expenses). |
| (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 $1.1 million will exceed the amounts we expect to be necessary for our working capital purposes. As a result, at least $1.1 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 6,593,894 common units to 5,918,894 common units, reducing CEPH’s and CEPM’s combined limited liability company interest in us from approximately 60% to approximately 54%, which percentages do not reflect any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering.
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The following table sets forth our cash and cash equivalents and our capitalization as of September 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 September 30, 2006 | ||||||
| Historical |
Pro Forma | |||||
| (In ’000’s) | ||||||
| Cash and cash equivalents |
$ | 6,387 | $ | 3,911 | ||
| Debt |
||||||
| Reserve-based credit facility(a) |
— | 22,000 | ||||
| Class D Interests(a)(b) |
— | 8,000 | ||||
| Equity |
||||||
| Members’ equity(c) |
179,853 | — | ||||
| Common units held by public(c): |
— | 55,960 | ||||
| Common units held by CEPH(c) |
— | 82,000 | ||||
| Class A units held by CEPM |
— | 2,816 | ||||
| Accumulated other comprehensive income |
14,050 | 14,050 | ||||
| Total equity(d) |
193,903 | 154,826 | ||||
| Total capitalization |
$ | 193,903 | $ | 184,826 | ||
| (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 contingently redeemable feature, the Class D interests will be treated as preferred units subject to contingent redemption in accordance with SEC Accounting Series Release No. 268, Presentation in Financial Statements of Redeemable Preferred Stocks. |
| (c) | Does not reflect any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. |
| (d) | Includes $14.1 million of unrealized gains on our cash flow hedges. |
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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 September 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 $154.8 million, or $13.68 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) |
$ | 28.43 | |||||
| Decrease in net tangible book value per common unit attributable to purchasers in the offering |
(14.75 | ) | |||||
| Less: Pro forma net tangible book value per common unit after the offering(b) |
13.68 | ||||||
| Immediate dilution in net tangible book value per common unit to new investors |
$ | 6.32 | |||||
| (a) | Determined by dividing the total number of common units and Class A units to be issued to CEPM and its affiliates (6,593,894 common units and 226,406 Class A units) into our net tangible book value of the contributed assets and liabilities of $193.9 million as of September 30, 2006. |
| (b) | Determined by dividing the total number of common units and Class A units to be outstanding after this offering (11,093,894 common units and 226,406 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 $154.8 million as of September 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 | 226,406 | 2% | (3) | $ | 2,445 | 1.49% | |||||
| CEPM and its affiliates(1)(2) |
Common units | 6,593,894 | 58% | (3) | 71,206 | 43.51% | ||||||
| New investors |
Common units | 4,500,000 | 40% | (3) | 90,000 | 55.00% | ||||||
| Total |
11,320,300 | 100% | $ | 163,651 | 100% | |||||||
| (1) | Upon the consummation of the transactions contemplated by this prospectus, CEPM and its affiliates will own 6,593,894 common units and 226,406 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 September 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 |
$ | 193.9 | ||
| Less: Distribution to CEPH |
(106.8 | ) | ||
| Distribution of excess cash and cash pool |
(13.5 | ) | ||
| $ | 73.6 | |||
| (3) | These percentages do not reflect any common units that may be issued pursuant to the long-term incentive plan we expect to adopt prior to the closing of this offering. |
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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 $0.4625 per unit, or $1.85 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.
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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; |
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| • | payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings; |
| • | expansion capital expenditures; |
| • | 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 |
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| • | 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. |
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
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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 |
| • | 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 $0.4625 IQD plus $0.0694) (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 |
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| 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; |
| • | 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 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. |
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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.
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 | |||||||
| Class A Unitholders |
Common Unitholders |
Management Incentive Interests | ||||||
| IQD |
$0.4625 | 2% | 98% | 0% | ||||
| Target Distribution |
above $0.4625 up to $0.5319 | 2% | 98% | 0% | ||||
| Thereafter* |
above $0.5319 | 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 $0.5319 Target Distribution will be made 2% to the holder of the Class A units and 98% to the holders of common units, pro rata. |
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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 |
| • | 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 capital” per initial common unit. 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 capital per common unit. 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 capital per common unit 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 unrecovered capital per common unit, 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 capital per common unit. |
For example, if a two-for-one split of the common units should occur, the Target Distribution and the unrecovered capital per common unit 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
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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 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 $333,333.33, 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 $333,333.41 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; |
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| • | 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 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.
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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 nine months ended September 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.”
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 $0.4625 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:
| • | 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. |
| • | 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 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. |
| • | 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.” |
| • | 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. |
| • | 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. |
| • | 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. |
| • | 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. |
| • | 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 59% of the outstanding common units (approximately 53% if the underwriters exercise their option to purchase additional common units in full) and CEPM will own 100% of the outstanding Class A units. These common unit percentages do not reflect any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. |
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.
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.
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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 $0.4625 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.”
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 $0.4625 per unit per quarter) and for four full quarters (at the initial rate of $1.85 per unit for four quarters):
| Initial Quarterly Distribution | |||||||||
| Number of Units |
One Quarter |
Four Quarters | |||||||
| (In ‘000’s) | |||||||||
| Common units |
11,093,894 | (a) | $ | 5,131 | $ | 20,524 | |||
| Class A units |
226,406 | (a) | 105 | 419 | |||||
| Total |
11,320,300 | $ | 5,236 | $ | 20,943 | ||||
| (a) | Does not include any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. |
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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 December 31, 2007. In those sections, we present the following two tables:
| • | “Our Estimated Cash Available to Pay Distributions,” in which we present our Estimated Adjusted EBITDA for the twelve months ending December 31, 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 December 31, 2007; and |
| • | “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 ended September 30, 2006, based on our pro forma financial statements that are included elsewhere in this prospectus. |
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 December 31, 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 December 31, 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
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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:
| • | with a view toward compliance with the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information; or |
| • | 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 $0.4625 per unit on all outstanding common units and Class A units for each full calendar quarter in the twelve-month period ending December 31, 2007. The number of outstanding common units on which we have based such belief does not include any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering.
Our Estimated Cash Available to Pay Distributions
In order to pay the IQD to our unitholders of $0.4625 per unit per quarter over the four full calendar quarters ending December 31, 2007, our cumulative available cash to pay distributions must be at least approximately $20.9 million over that period. We have calculated that the minimum amount of our Estimated Adjusted EBITDA for the twelve-month period ending December 31, 2007 that we estimate will be necessary to generate cash available to pay aggregate distributions of approximately $20.9 million over that period is approximately $32.6 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
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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:
| • | 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. |
In the table below entitled “Our Estimated Adjusted EBITDA,” we calculate that our Estimated Adjusted EBITDA will be approximately $32.6 million for the four full calendar quarters ending December 31, 2007, which is sufficient for us to be able to generate cash available to pay aggregate distributions of approximately $20.9 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 December 31, 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 December 31, 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 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 December 31, 2007, we have not estimated any expansion capital expenditures since we do not have any
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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 $32.6 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 December 31, 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 December 31, 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 December 31, 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 December 31, 2007, assuming that the offering was consummated on January 1, 2007. We explain each of the adjustments presented below in the footnotes to the table. All of the amounts for the twelve-month period ending December 31, 2007 in the table and footnotes below are estimates.
| Twelve-Month Period Ending December 31, 2007 |
||||
| (In ‘000’s, except per unit data and ratios) |
||||
| Estimated Adjusted EBITDA(a) |
$ | 32,580 | ||
| Less: |
||||
| Estimated maintenance capital expenditures(b) |
(4,950 | ) | ||
| Estimated interest expense(c) |
(1,540 | ) | ||
| Estimated investment capital expenditures(d) |
(3,949 | ) | ||
| Cash required to pay Class D special cash distributions(e) |
(1,384 | ) | ||
| Add: |
||||
| Borrowings to finance investment capital expenditures and Class D distributions(c)(d)(e) |
5,333 | |||
| Excess proceeds from initial public offering available for distribution(f) |
1,111 | |||
| Estimated cash available to pay distributions |
$ | 27,201 | ||
| Less: |
||||
| Estimated total cash distributions to common unitholders and Class A unitholder |
$ | (20,943 | ) | |
| Excess cash available |
$ | 6,258 | ||
| Estimated cash distributions |
||||
| Annualized initial quarterly distribution per unit |
$ | 1.85 | ||
| Estimated total cash distributions to common unitholders and Class A unitholder(g) |
$ | 20,943 | ||
| Borrowing base ratio(h) |
0.3x | |||
| Interest coverage ratio(h) |
18.1x | |||
| Total debt/Adjusted EBITDA ratio(h) |
0.7x | |||
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| (a) | As reflected in the table below, to generate our Estimated Adjusted EBITDA for the twelve months ending December 31, 2007, we have assumed the following regarding our operations, revenues and expenses: |
| Net sales volumes(1) |
5.1 Bcf | |
| Average Henry Hub Price (NYMEX) (hedged volumes)(2) |
$9.35 per MMBtu | |
| Average SONAT Inside FERC Price (unhedged volumes)(2) |
$8.35 per MMBtu | |
| Percentage of net production hedged |
80% | |
| Weighted average net realized natural gas sales price(2) |
$9.08 per MMBtu |
| Estimated adjusted EBITDA (in thousands): |
||||
| Total revenues(3) |
$ | 42,272 | ||
| Field operating expenses(4) |
(8,703 | ) | ||
| Torch NPI Payment(5) |
— | |||
| General and administrative expenses(6) |
(4,634 | ) | ||
| Hedge gains(3) |
3,645 | |||
| Estimated Adjusted EBITDA |
$ | 32,580 | ||
| (1) | Our forecasted net sales volumes for the twelve months ending December 31, 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 $9.08 per MMBtu used to compile our net forecasted revenues, which reflects pricing as of October 25, 2006. For the twelve months ended September 30, 2006, our sales volumes were approximately 4.5 Bcf. Our sales volumes for September 2006 were approximately 0.41 Bcf, or about 4.9 Bcf on an annualized basis. We are forecasting our sales volumes to be approximately 5.1 Bcf for the period from January 1, 2007 through December 31, 2007, which is consistent with the forecasted production in our internal reserve estimates. We expect to be able to add the additional 0.2 Bcf to our current production rate from our drilling and refracture program in 2007. |
Our estimates of approximately 5.1 Bcf net to our interest include production attributable to the 20 gross (18 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 December 31, 2007. We have assumed that each of the 20 gross (18 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.
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 10 gross (10 net) additional wells during the twelve months ending December 31, 2007.
| (2) | Our weighted average net natural gas sales price of $9.08 per MMBtu is calculated taking into account our executed hedges of 3.7 Bcf (or approximately 80% of our forecasted proved developed production volume from currently producing wells) at a weighted average NYMEX natural gas sales price of approximately $9.35 per MMBtu, and unhedged production volumes at an assumed price based on the SONAT Inside FERC Price, of $8.35 per MMBtu (based on forward curves as of October 25, 2006). |
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Our weighted average NYMEX hedge price of $9.35 per MMBtu was derived from our contractual fixed price contracts that were executed on June 20, 2006. Under these contracts, we have hedged approximately 3.7 Bcf of 2007 production at $9.345 per MMBtu.
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 October 25, 2006. The basis differential to NYMEX was approximately zero on October 25, 2006. On October 25, 2006, the NYMEX weighted average forward price was approximately $8.35 per MMBtu and SONAT was approximately $8.35 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 September 30, 2006, our average net realized sales price was approximately $9.07 per MMBtu as compared to approximately $9.08 per MMBtu forecast for the twelve-month period ending December 31, 2007.
| (3) | In calculating our Estimated Adjusted EBITDA, we have netted from our total revenues estimated gains that we expect to incur of approximately $3.6 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 December 31, 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 nine months ended September 30, 2006, respectively.
Our forecasted lease operating expenses of approximately $6.5 million are $0.4 million lower than 2005 lease operating expenses, which were approximately $6.9 million. The $0.4 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 or discretionary in nature that were incurred to enhance the field maintenance and production improvement programs.
| (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 zero 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 January 1, 2007, we estimate that our revenues would decline by $4.4 million during the twelve-month period ending December 31, 2007 based on forecast production from the Trust Wells for such twelve-month period and assuming the weighted average net realized sales price of $9.08 per MMBtu. |
We made no payments to the Trust in respect of the NPI in 2005. For the nine months ended September 30, 2006, we paid the Trust approximately $0.2 million, which is comprised of actual calculations through July 31, 2006 and estimates for August and September 2006. We have not made a
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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 for the forecast period. 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: |
| • | approximately $1.0 million in estimated expenses attributable to operations on the Robinson’s Bend Field properties, accounting and other similar administrative costs; |
| • | approximately $1.8 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 |
| • | 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 December 31, 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 $4.6 million for the twelve months ending December 31, 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 $2.9 million per year. These costs are $1.8 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. |
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 December 31, 2007, will be approximately $5.0 million. Our drilling program assumes that we will drill a total of 20 gross (18 net) development wells during the twelve months ending December 31, 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 nine months ended September 30, 2006. Of the 25 wells that were drilled and completed, our average costs
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were approximately $410,000 per well. We are forecasting approximately $400,000 per well to drill and complete during January 1, 2007 through December 31, 2007. Of the two wells that we refractured during the nine months ended September 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 January 1, 2007 through December 31, 2007.
| (c) | We have assumed that our interest expense (excluding fees) for the twelve-month period ending December 31, 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 December 31, 2007, we have assumed that our estimated investment capital expenditures consist of approximately $3.7 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 $3.7 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 December 31, 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 December 31, 2007, including our unproven properties, and to offset over the long-term the expected production decline 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 December 31, 2007 of approximately $3.9 million, including interest expense related to expansion capital borrowings, is expected to be incurred to drill, develop and place on production 8 gross (6 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 December 31, 2007 to offset the expected production decline rate |
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| from our existing producing wells. The estimated $3.9 million also includes capital required for the refracturing of the formations of approximately 10 gross (10 net) of our existing proved developed non-producing wells that we plan to complete during the twelve months ending December 31, 2007. Approximately $0.2 million of the $3.9 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 December 31, 2007 unless the gas purchase contract or, without the prior consent of our board of managers, the sharing arrangement provided thereunder is terminated before December 31, 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 $333,333.33). 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) | $3.9 million of the proceeds from this offering will be retained in working capital. Of the $3.9 million, $1.1 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 $1.1 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 $3.9 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 December 31, 2007. |
| Number of Units |
Distributions Per Unit |
Aggregate Distributions | |||||||
| (in ‘000’s) | |||||||||
| Estimated distributions on common units |
11,093,894 | (1) | $ | 1.85 | $ | 20,524 | |||
| Estimated distributions on Class A units |
226,406 | 1.85 | 419 | ||||||
| Total |
11,320,300 | (1) | $ | 1.85 | $ | 20,943 | |||
| (1) | Does not include any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. We have assumed that no common units are issued under that plan for the twelve-month period ending December 31, 2007. |
| (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 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 December 31, 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. |
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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 December 31, 2007 or thereafter, in which event the market price of the common units may decline materially.
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 December 31, 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 5.1 Bcf during the twelve months ending December 31, 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 5.3 Bcf or 4.8 Bcf), we estimate that our estimated cash available to pay distributions would increase (decrease) by approximately $2.0 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 $9.08 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 80% of our expected production from currently producing wells from January 1, 2007 through December 31, 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 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.
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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 $8.8 million. This amount would have been sufficient to pay approximately 42% of our $0.4625 per quarter IQD ($1.85 on an annualized basis) on our outstanding common units and Class A units. These common unit percentages do not reflect any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. If we had completed the transactions contemplated in this prospectus on October 1, 2005, our pro forma available cash to pay distributions generated during the twelve months ended September 30, 2006 would have been approximately $8.1 million. This amount would have been sufficient to pay approximately 39% of our $0.4625 per quarter IQD ($1.85 on an annualized basis) on our outstanding common units and Class A units. These common unit percentages do not reflect any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. 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 $8.8 million for 2005 and $8.1 million for the twelve months ended September 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 our reserve-based credit facility, 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 $75 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 September 30, 2006, cash available to pay distributions, assuming, in each case, that the following transactions had occurred on January 1, 2005 and October 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.” |
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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 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 September 30, 2006 |
|||||||
| (In ‘000’s, except ratios) (unaudited) |
||||||||
| Net income(a) |
$ | 760 | $ | 17,606 | ||||
| Plus: |
||||||||
| Interest expense(b) |
1,546 | 964 | ||||||
| Depreciation, depletion and amortization |
7,281 | 8,216 | ||||||
| Accretion of asset retirement obligation |
141 | 149 | ||||||
| Unrealized loss on natural gas derivatives |
15,265 | — | ||||||
| Adjusted EBITDA |
$ | 24,993 | $ | 26,935 | ||||
| Less: |
||||||||
| Estimated incremental general and administrative expenses(c) |
2,900 | 2,900 | ||||||
| Pro forma cash flow from operations |
22,093 | 24,035 | ||||||
| Less: |
||||||||
| Cash necessary to pay initial quarterly distributions on Class A units and common units(d) |
20,943 | 20,943 | ||||||
| Pro forma cash flow from operations after distributions |
1,150 | 3,092 | ||||||
| Less: |
||||||||
| Pro forma capital expenditures(e) |
(12,286 | ) | (14,937 | ) | ||||
| Cash required to pay Class D special cash distributions(f) |
(1,000 | ) | (1,000 | ) | ||||
| Shortfall |
$ | (12,136 | ) | $ | (12,845 | ) | ||
| Borrowing base ratio(g) |
0.3x | 0.3x | ||||||
| Interest coverage ratio(g) |
16.2x | 18.1x | ||||||
| Total debt/Adjusted EBITDA ratio(g) |
0.9x | 0.7x | ||||||
| (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 $2.9 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 $2.9 million in incremental general and administrative expenses we estimate that we would incur as a result of being a public company. |
| (d) | Does not include any common units that may be issued under the long-term incentive plan that we expect to adopt prior to the closing of this offering. |
| (e) | 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 |
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| 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 nine months ended September 30, 2006, we drilled and completed 25 gross (25 net) wells and commenced drilling on an additional 2 gross (2 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 September 30, 2006 were all funded from cash generated by our and Everlast’s operations, respectively. |
| (f) | 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 March 31, 2005 (for the year ended December 31, 2005) and December 31, 2005 (for the twelve months ended September 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. |
| (g) | 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 September 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. |
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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 nine months ended September 30, 2006 and for the period from February 7, 2005 (inception) to September 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 nine months ended September 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 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.
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Table of Contents
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 January 1, June 12, |
For the period from February 7, December 31, |
For the period from February 7, September 30, 2005(b) |
For the nine months ended September 30, 2006 |
Pro Forma | |||||||||||||||||||||||||||||
| For the year December 31, |
For the nine months ended | ||||||||||||||||||||||||||||||||||||
| 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 | $ | 10,925 | $ | 26,154 | $ | 38,839 | $ | 26,154 | |||||||||||||||||
| 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 | 10,925 | 26,154 | 23,526 | 26,154 | ||||||||||||||||||||||||||
| Operating Expenses: |
|||||||||||||||||||||||||||||||||||||
| Lease operating expenses |
9,254 | 7,763 | 4,428 | 5,270 | 2,769 | 4,175 | 1,783 | 5,321 | 6,944 | 5,321 | |||||||||||||||||||||||||||
| Production taxes |
592 | 368 | 1,279 | 1,479 | 676 | 1,400 | 500 | 1,340 | 2,076 | 1,340 | |||||||||||||||||||||||||||
| General and administrative |
162 | 92 | 1,945 | 2,706 | 594 | 4,184 | 3,331 | 3,445 | 4,778 | 3,445 | |||||||||||||||||||||||||||
| Depreciation, depletion and amortization |
199 | 77 | 3,684 | 3,719 | 1,683 | 4,176 | 2,229 | 5,987 | 7,281 | 5,987 | |||||||||||||||||||||||||||
| Accretion expense |
— | — | 73 | 86 | 46 | 78 | 43 | 106 | 141 | 106 | |||||||||||||||||||||||||||
| (Gain) loss on asset sale |
(193 | ) | (4 | ) | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||
| Total operating expenses |
10,014 | 8,296 | 11,409 | 13,260 | 5,768 | 14,013 | 7,886 | 16,199 | 21,220 | 16,199 | |||||||||||||||||||||||||||
| Other expenses/(income): |
|||||||||||||||||||||||||||||||||||||
| Interest expense/(income), net |
— | — | 1,961 | 3,028 | 2,437 | 3 | 2 | (361 | ) | 1,546 | 966 | ||||||||||||||||||||||||||
| Organization costs |
— | — | 299 | — | — | — | — | — | — | ||||||||||||||||||||||||||||
| Total other expenses (income) |
— | — | 2,260 | 3,028 | 2,437 | 3 | 2 | (361 | ) | 1,546 | 966 | ||||||||||||||||||||||||||
| Total expenses |
— | — | 13,669 | 16,288 | 8,205 | 14,016 | 7,888 | 15,838 | 22,766 | 17,165 | |||||||||||||||||||||||||||
| Net income (loss) |
$ | (798 | ) | $ | 414 | $ | 4,987 | $ | 2,099 | $ | (10,636 | ) | $ | 11,941 | $ | 3,037 | $ | 10,316 | $ | 760 | $ | 8,989 | |||||||||||||||
| Other Financial Information (unaudited) |
|||||||||||||||||||||||||||||||||||||
| Adjusted EBITDA |
$ | 10,193 | $ | 14,738 | $ | 8,795 | $ | 16,198 | $ | 5,311 | $ | 16,048 | $ | 24,993 | $ | 16,048 | |||||||||||||||||||||
| (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. |
77
Table of Contents
Index to Financial Statements
| Predecessor |
Successor | ||||||||||||||||||||||||||||||||||
| Torch Energy |
Everlast Energy LLC |
Constellation Energy Partners LLC | |||||||||||||||||||||||||||||||||
| For the | |||||||||||||||||||||||||||||||||||