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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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FORM 8-K/A

 

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CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report: October 12, 2007

(Date of earliest event reported: September 21, 2007)

 

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Constellation Energy Partners LLC

(Exact name of registrant as specified in its charter)

 

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Delaware		001-33147		11-3742489
(State or other jurisdiction of incorporation)		(Commission File Number)		(IRS Employer Identification No.)

 

111 Market Place Baltimore, MD		21202
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (410) 468-3500

Not applicable

(Former name or former address, if changed since last report.)

 

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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

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On September 26, 2007, the Company filed a Current Report on Form 8-K (the “Report”) in connection with its acquisition of certain oil and gas properties in Oklahoma pursuant to a definitive purchase agreement (the “Purchase Agreement”) with Newfield Exploration Mid-Continent Inc. (“Newfield”) for an aggregate purchase price of approximately $128 million, subject to purchase price adjustments (the “Newfield Acquisition”). The description of the Newfield Acquisition and terms of the Purchase Agreement contained in the Company’s 8-K filed on August 3, 2007 are incorporated herein by reference. A copy of the Purchase Agreement was filed as Exhibit 2.1 on Form 8-K on September 26, 2007 and is incorporated herein by reference. The Current Report on Form 8-K filed on September 26, 2007 is being amended by this Amendment No. 1 to include the required historical financial statements and other financial information with respect to the Newfield Acquisition as required by Item 9.01 (a) and the pro forma financial information required by Item 9.01 (b).

This Report replaces Item 9.01 of that filing:

 

Item 9.01

Financial Statements and Exhibits.

(a) Financial Statements of businesses acquired.

The following information is included as an exhibit to this report as noted in (d) below:

1. The audited statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Mid-Continent Inc. for the years ended December 31, 2006 and December 31, 2005, the six month periods ended June 30, 2007 and December 31, 2004, and the unaudited six month period ended June 30, 2006.

(b) Pro Forma Financial Information.

The following unaudited pro forma condensed combined financial statements reflect the combination of the historical consolidated balance sheets and income statements of Constellation Energy Partners LLC, the oil and gas properties acquired from Newfield, and certain other acquisitions, adjusted for certain effects of the acquisitions and their related funding:

1. Unaudited Pro Forma Condensed Combined Balance Sheet

2. Unaudited Pro Forma Condensed Combined Statement of Operations

3. Notes to Unaudited Pro Forma Condensed Combined Financial Statements

4. Unaudited Pro Forma Combined Supplemental Oil and Gas Disclosures

(c) Not Applicable.

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(d) Exhibits.

 

Exhibit Number		Description
99.1		The audited statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Mid-Continent Inc. for the years ended December 31, 2006 and December 31, 2005, the six month periods ended June 30, 2007 and December 31, 2004, and the unaudited six month period ended June 30, 2006.
99.2		The unaudited pro forma condensed balance sheet of Constellation Energy Partners LLC as of June 30, 2007, which gives effect to the Newfield Acquisition and certain other acquisitions as if they had occurred on June 30, 2007 and the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007, which give effect to the Newfield Acquisition and certain other acquisitions as if they occurred on January 1, 2006.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

				CONSTELLATION ENERGY PARTNERS LLC
Date: October 12, 2007				By:		/s/ Angela A. Minas
						Angela A. Minas
						Chief Financial Officer

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EXHIBIT INDEX

 

Exhibit Number		Description
99.1		The audited statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Mid-Continent Inc. for the years ended December 31, 2006 and December 31, 2005, the six month periods ended June 30, 2007 and December 31, 2004, and the unaudited six month period ended June 30, 2006.
99.2		The unaudited pro forma condensed balance sheet of Constellation Energy Partners LLC as of June 30, 2007, which gives effect to the Newfield Acquisition and certain other acquisitions as if they had occurred on June 30, 2007 and the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007, which give effect to the Newfield Acquisition and certain other acquisitions as if they occurred on January 1, 2006.

Exhibit 99.1

Newfield Exploration Mid-Continent Inc.

Audited Statements of Revenues and Direct Operating Expenses

for the Years Ended December 31, 2006 and 2005, the Six Month

Periods Ended June 30, 2007 and December 31, 2004, and

the Unaudited Six Month Period Ended June 30, 2006

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INDEX TO FINANCIAL STATEMENTS

 

		Page
Report of Independent Registered Public Accounting Firm		1
Statements of Revenues and Direct Operating Expenses of Certain Oil and Gas Properties Acquired from Newfield Exploration Mid-Continent Inc. for the years ended December 31, 2006 and 2005, for the six month periods ended June 30, 2007 and December 31, 2004, and for the unaudited six month period ended June 30, 2006		2
Notes to Statements of Revenues and Direct Operating Expenses of Certain Oil and Gas Properties Acquired from Newfield Exploration Mid-Continent Inc.		3
Supplementary Financial Information — Supplementary Oil and Gas Disclosures — Unaudited		5

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors of Newfield Exploration Company:

We have audited the accompanying statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Mid-Continent Inc. for the years ended December 31, 2006 and 2005 and for the six month periods ended June 30, 2007 and December 31, 2004. These financial statements are the responsibility of the management of Newfield Exploration Company. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying financial statements were prepared on the basis of accounting described in Note 1 for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete presentation in conformity with accounting principles generally accepted in the United States of America. In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Mid-Continent Inc. for the years ended December 31, 2006 and 2005 and for the six month periods ended June 30, 2007 and December 31, 2004, in conformity with the basis of accounting described in Note 1.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

October 11, 2007

 

1

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Statements of Revenues and Direct Operating Expenses of

Certain Oil and Gas Properties Acquired from Newfield Exploration Mid-Continent Inc.

(in thousands)

 

		Six Months Ended June 30, 2007			Six Months Ended June 30, 2006			Year Ended December 31,						Six Months Ended December 31, 2004
								2006			2005
					Unaudited
Revenues		$	12,548		$	13,713		$	26,067		$	35,035		$	4,632
Direct operating expenses			3,594			3,616			7,218			6,516			1,525
Revenues in excess of direct operating expenses		$	8,954		$	10,097		$	18,849		$	28,519		$	3,107

 

2

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Notes to Statements of Revenues and Direct Operating Expenses of

Certain Oil and Gas Properties Acquired from Newfield Exploration Mid-Continent Inc.

 

1.	Background and Basis of Presentation

On August 2, 2007, Newfield Exploration Mid-Continent Inc. (“Newfield”) entered into a Purchase and Sale Agreement with Constellation Energy Partners LLC (“CEP”) whereby CEP acquired substantially all of Newfield’s leasehold, personal property and producing properties in Craig, Nowata, Rogers, Tulsa and Washington Counties of Oklahoma (the “Newfield Properties”) for a total cash consideration of approximately $128 million and the assumption of liabilities associated with the abandonment of wells. The agreement was effective as of July 1, 2007.

On July 8, 2004, Newfield acquired these properties from a private company. The accompanying statements include the revenues and direct operating expenses of the Newfield Properties subsequent to this date.

The accompanying statements include revenues directly associated with oil, natural gas and natural gas liquids production and direct lease operating expenses associated with the Newfield Properties. For purposes of these statements, all properties identified in the purchase and sale agreement are included herein. Because the Newfield Properties were not separate legal entities, the accompanying statements vary from an income statement in that they do not show certain expenses that were incurred in connection with ownership and operation of the Newfield Properties including, but not limited to, general and administrative expenses, interest and corporate income taxes. These costs were not separately allocated to the properties in the accounting records of the Newfield Properties. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Newfield Properties had they been CEP’s properties due to the differing size, structure, operations and accounting of Newfield and CEP. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs which CEP would incur upon the allocation of purchase price paid for the Newfield Properties. Furthermore, a balance sheet has not been presented for the Newfield Properties due to the lack of segregated or easily obtainable data regarding their historical cost and related working capital balances. Accordingly, the historical statements of revenues and direct operating expenses of the Newfield Properties are presented in lieu of the full financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.

In the opinion of Newfield management, the accompanying unaudited interim period includes all adjustments considered necessary for a fair presentation. Interim period results are not necessarily indicative of the results of operations for a full year.

Revenue Recognition – Substantially all of the natural gas and oil production associated with the Newfield Properties was sold to a variety of purchasers under short-term (less than 12 months) contracts at market sensitive prices. Revenue is recorded when production is delivered to the customer and collectibility is reasonably assured. Revenues from the production of oil and gas in which Newfield has joint ownership are recorded under the sales method. Differences between these sales and Newfield’s entitled share of production were not significant.

Direct Operating Expenses – Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Newfield Properties. The direct operating expenses include lease operating, processing, and production and other tax expense. Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs and other field expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, facilities and insurance directly related to oil and natural gas production activities. Production and other taxes consist of severance and ad valorem taxes.

 

3

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2.	Commitments and Contingencies

Pursuant to the terms of the Purchase and Sale Agreement between Newfield and CEP (and subject to the indemnity thresholds and caps set forth in such agreement), Newfield will retain and indemnify CEP for claims made: (i) within six months after the closing date and related to certain excluded assets, breaches of Newfield’s representations and warranties, or the ownership or operation of the assets prior to the effective time (excluding, however, claims with respect to environmental matters, which, generally, are assumed by CEP), and (ii) within one year after the closing date and relating to Newfield’s breach of its obligations under the Purchase and Sale Agreement or relating to royalty obligations or payment of property, ad valorem or severance taxes, to the extent such claims with respect to royalties or taxes accrued prior to the effective time.

Notwithstanding this indemnification, management of Newfield is not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the statements of revenues and direct operating expenses.

Newfield has been unable to obtain third-party consents (the “Outstanding Consents”) with respect to certain oil and gas leases and related assets (the “Designated Properties”) included in the purchase and sale agreement. As a result of the Outstanding Consents, Newfield and CEP entered into a Nominee Agreement pursuant to which Newfield will hold legal title for the benefit of CEP for the Designated Properties. As required under the Nominee Agreement, during the 90 day period following September 21, 2007 (the “Cure Period”), Newfield shall use diligent, commercially reasonable efforts to obtain the Outstanding Consents with respect to the Designated Properties, and shall deliver to CEP assignments of all of its right, title and interest in all of the Designated Properties as to which Outstanding Consents are obtained during the Cure Period. If Newfield fails to obtain Outstanding Consents for any of the Designated Properties within the Cure Period, CEP may reassign to Newfield its beneficial interest in such property and shall be entitled to a refund from Newfield of the purchase price paid with respect to such property, subject to certain adjustments. The accompanying financial statements include the revenues and direct operating expenses for the Designated Properties.

 

4

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Supplementary Financial Information

Supplementary Oil and Gas Disclosures — Unaudited

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

Estimated Net Quantities of Proved Oil and Gas Reserves

The following table sets forth the total net proved reserves and the total net proved developed reserves and the changes in the total net proved developed and undeveloped reserves for each of the periods indicated below, as estimated by Newfield’s petroleum engineering staff for the Newfield Properties:

 

		Oil, Condensate and Natural Gas Liquids (MBbls)			Natural Gas (MMcf)			Total (MMcfe)
Proved developed and undeveloped reserves as of:
July 1, 2004		—			—			—
Revisions of previous estimates		—			—			—
Extensions, discoveries and other additions		—			1,610			1,610
Purchases of properties		8			32,351			32,397
Production		(5	)		(1,050	)		(1,080	)
December 31, 2004		3			32,911			32,927
Revisions of previous estimates		167			(557	)		445
Extensions, discoveries and other additions		320			8,119			10,039
Purchases of properties		—			—			—
Production		(41	)		(4,561	)		(4,807	)
December 31, 2005		449			35,912			38,604
Revisions of previous estimates		(243	)		(2,795	)		(4,255	)
Extensions, discoveries and other additions		28			4,446			4,614
Purchases of properties		—			—			—
Production		(32	)		(3,995	)		(4,187	)
December 31, 2006		202			33,568			34,776
Proved developed reserves as of:
July 1, 2004		—			—			—
December 31, 2004		3			11,394			11,412
December 31, 2005		229			21,608			22,982
December 31, 2006		146			21,510			22,386

 

5

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Supplementary Financial Information

Supplementary Oil and Gas Disclosures — Unaudited — (Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information was developed utilizing procedures prescribed by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.” The information is based on estimates prepared by Newfield’s petroleum engineering staff. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended.

Newfield believes that in reviewing the information that follows the following factors should be taken into account:

 

•

future costs and sales prices will probably differ from those required to be used in these calculations;

 

•

actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

 

•

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and

 

•

future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices applicable to these reserves to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

 

6

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Supplementary Financial Information

Supplementary Oil and Gas Disclosures — Unaudited — (Continued)

The standardized measure of discounted future net cash flows and a summary of the changes in the standardized measure of discounted future net cash flows related to the proved oil and gas reserves of the Newfield Properties is as follows:

 

		December 31,
		2006				2005				2004
		(In thousands)
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows		$	171,053			$	293,879			$	182,629
Less related future:
Production costs			(55,017	)			(59,522	)			(46,135	)
Development and abandonment costs			(18,762	)			(10,292	)			(12,433	)
Future net cash flows before income taxes			97,274				224,065				124,061
Future income tax expense			(34,046	)			(78,423	)			(43,421	)
Future net cash flows before 10% discount			63,228				145,642				80,640
10% annual discount for estimating timing of cash flows			(19,157	)			(38,712	)			(23,764	)
Standardized measure of discounted future net cash flows		$	44,071			$	106,930			$	56,876
		Year Ended December 31,
		2006				2005				2004
		(In thousands)
Changes in Standardized Measure of Discounted Future Net Cash Flows
Beginning of period		$	106,930			$	56,876			$	0
Revisions of previous estimates:
Changes in prices and costs			(65,589	)			39,752				0
Changes in quantities			(9,896	)			1,983				0
Changes in future development costs			(5,904	)			1,572				0
Development costs incurred during the period			3,878				8,114				0
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs			8,996				42,780				4,279
Purchases and sales of reserves in place, net			0				0				86,093
Accretion of discount			16,451				8,750				0
Sales of oil and gas, net of production costs			(25,418	)			(19,927	)			(2,870	)
Net change in income taxes			33,847				(26,952	)			(30,626	)
Production timing and other			(19,224	)			(6,018	)			0
Net increase (decrease)			(62,859	)			50,054				56,876
End of period		$	44,071			$	106,930			$	56,876

 

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EXHIBIT 99.2

Constellation Energy Partners LLC

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

INDEX

 

		Page
Unaudited Pro Forma Condensed Combined Balance Sheet as of June 30, 2007		F-1
Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2006		F-2
Unaudited Pro Forma Condensed Combined Statement of Operations for the six months ended June, 2007		F-3
Notes to Unaudited Pro Forma Condensed Combined Financial Statements		F-4

 

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Constellation Energy Partners LLC

Unaudited Pro Forma Condensed Combined Balance Sheet

At June 30, 2007

 

		CEP Historical				Amvest Historical				Pro Forma Adjustments						CEP Pro Forma
Assets
Current assets
Cash and cash equivalents		$	7,668			$	3			$	10,360			a,b,i		$	18,031
Accounts receivable			9,717				4,381				(775	)		a,i			13,323
Prepaid expenses			258				150				—						408
Risk management assets			5,922				—				—						5,922
Drilling fund			—				—				8,500			a			8,500
Other			2,033				6,039				(6,039	)		i			2,033
Total current assets			25,598				10,573				12,046						48,217
Natural gas properties (See Note 2)
Natural gas properties and related equipment
Natural gas properties, equipment and facilities			306,448				130,451				223,578			a,i			660,477
Material and supplies			546				1,775				665			a			2,986
Less accumulated depreciation, depletion and amortization			(17,126	)			(28,454	)			28,454			i			(17,126	)
Net natural gas properties			289,868				103,772				252,697						646,337
Other assets
Loan Costs			1,229				—				350			a,c,i			1,579
Intangible contracts			—				—				10,000			a,i			10,000
Other Non-Current Assets			4,050				12				(12	)		i			4,050
Risk management assets			1,839				—				—						1,839
Total assets		$	322,584			$	114,357			$	275,081					$	712,022
Liabilities and members’ equity (deficit)
Liabilities
Current liabilities
Accounts payable		$	2,364			$	1,591			$	788			a,c,i		$	4,743
Payable to affiliate			1,822				—				—						1,822
Accrued liabilities			3,847				1,137				(484	)		a,i			4,500
Royalty payable			2,999				1,669				(389	)		a,i			4,279
Deferred taxes			—				92				(92	)		i			—
Environmental liability			717				—				—						717
Mark to market derivative liabilities			—				—				—						—
Total current liabilities			11,749				4,489				(177	)					16,061
Other liabilities
Asset retirement obligation			5,933				871				2,730			a			9,534
Deferred taxes			—				29,330				(29,330	)		i			—
Mark to market derivative liabilities			1,873				—				—						1,873
Debt			82,500				—				70,500			b			153,000
Total other liabilities			90,306				30,201				43,900						164,407
Total liabilities			102,055				34,690				43,723						180,468
Class D Interests			7,667				—				—						7,667
Members’ equity (deficit)
Members’ equity			203,354				79,667				231,358			b,i			514,379
Accumulated other comprehensive income			9,508				—				—						9,508
Total members’ equity			212,862				79,667				231,358						523,887
Total liabilities and members’ equity		$	322,584			$	114,357			$	275,081					$	712,022

 

F-1

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Constellation Energy Partners LLC

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2006

 

		CEP Historical				EQR and KPC Historical			Amvest Historical				Newfield Historical			Pro Forma Adjustments						CEP Pro Forma
Revenues
Gas sales		$	36,917			$	18,772		$	36,632			$	26,067		$	(1,625	)		i		$	116,763
Total Revenues			36,917				18,772			36,632				26,067			(1,625	)					116,763
Expenses:
Operating expenses:
Lease operating expenses			7,234				8,806			6,871				5,712			(1,625	)		i			26,998
Cost of sales			—				—			1,481				—			—						1,481
Production taxes			1,783				812			2,126				1,506			—						6,227
General and administrative			4,573				—			4,809				—			—			h			9,382
Depreciation, depletion and amortization			7,444				544			8,604				—			25,960			d			42,552
Accretion expense			141				—			42				—			400			e			583
Total operating expenses			21,175				10,162			23,933				7,218			24,735						87,223
Other expense/(income)
Interest expense			221				—			1,178				—			8,452			f,g			9,851
Interest (income)			(468	)			—			—				—			—						(468	)
Other (income)			—				—			(12	)			—			—						(12	)
Total other expenses/(income)			(247	)			—			1,166				—			8,452						9,371
																							—
Total expenses			20,928				10,162			25,099				7,218			33,187						96,594
Income before taxes		$	15,989			$	8,610		$	11,533			$	18,849		$	(34,812	)				$	20,169
Income tax provision			—				—			4,333				—			(4,333	)		i			—
Net income (loss)		$	15,989			$	8,610		$	7,200			$	18,849		$	(30,479	)				$	20,169
Other comprehensive income			13,113				—			—				—			—						13,113
Comprehensive income (loss)		$	29,102			$	8,610		$	7,200			$	18,849		$	(30,479	)				$	33,282
Earnings per unit - Basic		$	1.41																			$	.90
Units outstanding - Basic			11,320,300														11,030,828			b			22,351,128
Earnings per unit - Diluted		$	1.41																			$	.90
Units outstanding - Diluted			11,320,300														11,030,828			b			22,351,128

 

F-2

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Constellation Energy Partners LLC

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Six Months Ended June 30, 2007

 

		CEP Historical				EQR and KPC Historical			Amvest Historical				Newfield Historical			Pro Forma Adjustments						CEP Pro Forma
Revenues
Gas sales		$	26,497			$	4,702		$	20,073			$	12,548		$	(407	)		i		$	63,413
Loss from mark-to-market activities			(5,401	)			—			—				—			—						(5,401	)
Total Revenues			21,096				4,702			20,073				12,548			(407	)					58,012
Expenses:
Operating expenses:
Lease operating expenses			4,745				1,966			3,992				2,827			(407	)		i			13,123
Cost of sales			—				—			698				—			—						698
Production taxes			1,144				171			1,143				767			—						3,225
General and administrative			3,390				—			2,166				—			—			h			5,556
Loss on sale of asset			94				—			—				—			—						94
Depreciation, depletion and amortization			5,543				163			5,544				—			10,991			d			22,241
Accretion expense			113				—			21				—			146			e			280
Total operating expenses			15,029				2,300			13,564				3,594			10,730						45,217
Other expense/(income)
Interest expense			1,825				—			683				—			2,981			f,g			5,489
Interest (income)			(135	)			—			—				—									(135	)
Other (income)			(70	)			—			(37	)			—			—						(107	)
Total other expenses/(income)			1,620				—			646				—			2,981						5,247
Total expenses			16,649				2,300			14,210				3,594			13,711						50,464
Income before taxes		$	4,447			$	2,402		$	5,863			$	8,954		$	(14,118	)				$	7,548
Income tax provision			—				—			1,857				—			(1,857	)		i			—
Net income (loss)		$	4,447			$	2,402		$	4,006			$	8,954		$	(12,261	)				$	7,548
Other comprehensive income			(3,605	)			—			—				—			—						(3,605	)
Comprehensive income (loss)		$	842			$	2,402		$	4,006			$	8,954		$	(12,261	)				$	3,943
Earnings per unit - Basic		$	0.36																			$	.34
Units outstanding - Basic			12,201,279														10,149,849			b			22,351,128
Earnings per unit - Diluted		$	0.36																			$	.34
Units outstanding - Diluted			12,201,279														10,149,849			b			22,351,128
Distributions declared and paid per unit		$	0.6736																			$	0.6736

 

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Constellation Energy Partners LLC

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The unaudited pro forma condensed combined balance sheet as of June 30, 2007, is derived from:

 

•

the historical consolidated financial statements of Constellation Energy Partners LLC (“CEP,” or the “Company”);

 

•

the preliminary purchase price allocation of certain oil and natural gas properties acquired from Newfield Mid-Continent Inc. (“Newfield”); and

 

•

the preliminary purchase price allocation of certain oil and natural gas properties and other related assets acquired in the purchase of Amvest Osage, Inc. (“Amvest”).

The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2006, and the six months ended June 30, 2007, are derived from:

 

•

the historical consolidated financial statements of CEP;

 

•

the historical statements of direct revenues and direct operating expenses of Newfield;

 

•

the historical consolidated financial statements of Amvest;

 

•

the historical statements of direct revenues and direct operating expenses of EnergyQuest Resources, L.P. (“EQR”); and

 

•

the historical financial statements of Kansas Processing EQR, LLC (“KPC”).

The unaudited pro forma condensed combined balance sheet gives effect to the Newfield and Amvest acquisitions and the related financing activities as if the transactions had occurred on June 30, 2007. The unaudited pro forma condensed combined statements of operation give effect to the Newfield, Amvest, EQR, and KPC acquisitions and the related financing activities as if the transactions had occurred on January 1, 2006.

The unaudited pro forma condensed combined financial statements reflect the following transactions:

 

•

the Newfield, Amvest, EQR, and KPC acquisitions;

 

•

the equity issuance of additional Class B units on September 21, 2007, used to finance the Newfield acquisition;

 

•

the equity issuance of additional Class B units and Class F units on July 25, 2007, used to finance the Amvest acquisition;

 

•

an increase in debt in August 2007 and in September 2007, used to finance the Newfield acquisition and to fund certain investment capital expenditures in the Cherokee Basin; and

 

•

an increase in debt in July 2007, used to finance the Amvest acquisition and to fund certain investment capital expenditures in the Black Warrior Basin and Cherokee Basin.

The unaudited pro forma condensed combined balance sheet and statements of operations are presented for illustrative purposes only, and do not purport to be indicative of the financial position or results of operations that would actually have occurred if the transactions described had occurred as presented in such statements or that may be obtained in the future. In addition, future results may vary significantly from the results reflected in such statements due to factors described in “Risk Factors” included in our Quarterly Report on Form 10-Q for the six months ended June 30, 2007, in our Annual Report on Form 10-K for the year ended December 31, 2006 or elsewhere in the Company’s reports and filings with the Securities and Exchange Commission (“SEC”). The unaudited pro forma condensed combined balance sheet and statements of operations should be read in conjunction with our historical

 

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consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2006 and our Quarterly Report on Form 10-Q for the six months ended June 30, 2007.

The pro forma statements should also be read in conjunction with the statements of revenues and direct operating expenses for Newfield and the notes thereto included elsewhere in this Form 8-K/A, the consolidated financial statements of Amvest included in a Form 8-K/A filing with the SEC dated September 14, 2007, and with the statements of direct revenues and direct operating expenses for EQR and the notes thereto and the consolidated financial statements of KPC included in a Form 8-K/A filing with the SEC dated July 5, 2007.

2. ACQUISITION AND PRELIMINARY PURCHASE PRICE ALLOCATION

Newfield Acquisition

The Newfield acquisition was completed on September 21, 2007 (“Closing Date”). The Company acquired certain oil and natural gas properties from Newfield for approximately $128.0 million, subject to purchase price adjustments.

The acquisition included approximately 600 net producing wells on approximately 80,000 net acres with current net production of approximately 9.3 MMcfe per day. Also included were support equipment and facilities, including a pipeline gathering system.

The total consideration was $132.7 million which consisted of cash of $129.0 million and estimated transaction costs of $1.0 million. The Company assumed liabilities of $2.7 million, primarily associated with abandonment obligations on the properties. The purchase price allocation of the total consideration of $132.7 million is as follows:

 

Natural Gas and Oil Properties		$	113.5 million
Unproved Properties			2.6 million
Pipelines			10.0 million
Other PP&E			1.0 million
Intangible Third Party Gas Contracts			5.0 million
Inventory			0.6 million
Asset Retirement Obligation			(2.7) million
Total		$	130.0 million

The preliminary purchase price allocation used for the purpose of this pro forma financial information is based on preliminary appraisals, evaluations of proved oil and natural gas reserves, discounted cash flows, quoted market prices, and other estimates by management. The purchase price allocation related to the Newfield acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.

A post-closing adjustment will occur within 90 days of the Closing Date to settle certain items including the revenue distributions and certain expenses associated with the oil and gas properties after the effective date of July 1, 2007. Additionally, as of the Closing Date, Newfield had been unable to obtain third-party consents (the “Outstanding Consents”) with respect to certain oil and gas leases and related assets (the “Designated Properties”) which represent less than 14% of the aggregate purchase price of the acquisition. As a result of the Outstanding Consents, Newfield and the Company entered into a Nominee Agreement pursuant to which Newfield will hold legal title for the benefit of the Company for the Designated Properties. As required under the Nominee Agreement, during the 90 day period following the Closing Date (the “Cure Period”), Newfield shall use diligent, commercially reasonable efforts to obtain the Outstanding Consents with respect to the Designated Properties, and shall deliver to the Company assignments of all of its right, title and interest in all of the Designated Properties as to which Outstanding Consents are obtained during

 

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the Cure Period. If Newfield fails to obtain Outstanding Consents for any of the Designated Properties within the Cure Period, the Company may reassign to Newfield its beneficial interest in such property and shall be entitled to a refund from Newfield of the purchase price paid with respect to such property, subject to certain adjustments.

Amvest Acquisition

The Amvest acquisition was completed on July 25, 2007. The Company acquired certain oil and natural gas properties in purchasing Amvest for approximately $240.0 million, subject to purchase price adjustments.

The acquisition included a 13 year exclusive concession from the Osage Nation for coalbed methane and shale rights on approximately 560,000 net acres in Osage County, Oklahoma, with potential for up to 100,000 additional acres, and approximately 370 producing wells with current net production of approximately 16 MMcfe per day. Also included were support equipment and facilities, including certain pipeline gathering systems.

The total consideration was $241.9 million which consisted of cash of $241.0 million and estimated transaction costs of $0.9 million. An amount of $8.5 million was included in a drilling escrow fund that was used by the Company for drilling programs on proved undeveloped locations after the close of the transaction. The purchase price allocation of the total consideration (after the return of the drilling fund) of $233.4 million is as follows:

 

Natural Gas and Oil Properties		$	181.3 million
Unproved Properties			38.4 million
Pipelines			5.0 million
Other PP&E			1.4 million
Intangible Third Party Gas Contracts			5.0 million
Net Working Capital			2.3 million
Total		$	233.4 million

The preliminary purchase price allocation used for the purpose of this pro forma financial information is based on preliminary appraisals, evaluations of proved oil and natural gas reserves, discounted cash flows, quoted market prices, other estimates by management, and a preliminary valuation report. The purchase price allocation related to the Amvest acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.

3. PRO FORMA ADJUSTMENTS

The unaudited pro forma condensed combined financial statements have been adjusted to reflect the following:

 

a.

the Newfield and Amvest acquisitions as detailed in Note 2.

 

b.

the issuance and sale of 2,470,592 Common Units for approximately $104.7 million ($105 million less $0.3 million in estimated expenses) and borrowings of $28.0 million under the reserve-based credit facility to fund the remaining balance of the Newfield purchase price and certain capital expenditures in the Cherokee Basin and the issuance and sale of 3,371,219 Class F Units and 2,664,998 Common Units for approximately $206.3 million ($210.0 million less $3.675 million in estimated expenses) and borrowings of $42.5 million under the reserve-based credit facility to fund the remaining balance of the Amvest purchase price and certain investment capital expenditures in the Black Warrior Basin and the Cherokee Basin.

 

c.

the debt issuance costs of approximately $0.35 million related to the borrowings under the reserve-based credit facility to fund the remaining purchase price of Amvest.

 

d.

recording incremental depreciation, depletion and amortization expense related to the assets acquired in the Newfield, Amvest, EQR, and KPC acquisitions based on the relative fair value allocation of the purchase price to the acquired assets. The proforma depletion expense attributable to the Amvest acquisition has been updated to reflect a proved reserve estimate from September 26, 2007.

 

F-6

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e.

recording incremental accretion expense related to the assumed asset retirement obligations of Newfield and EQR.

 

f.

recording incremental interest expense at 7.45% associated with the increase in long-term debt of approximately $28.0 million incurred to fund the balance of the purchase price of Newfield, as well as to fund planned capital expenditures on these properties; recording incremental interest expense at 7.11% associated with the increase in long-term debt of approximately $42.5 million incurred to fund the balance of the purchase price of Amvest, as well as to fund planned capital expenditures on these properties; and recording incremental interest expense at 7.235% associated with the increase in long-term debt of approximately $60.5 million incurred to fund the balance of the purchase price of EQR and KPC, the escrow deposit and certain investment capital expenditures in the Black Warrior Basin.

A 0.125% increase or decrease in this rate results in a $0.16 million change in interest expense associated with these increases in outstanding debt.

 

g.

recording incremental amortization of additional debt issuance costs associated with an increase in the reserve-based credit facility.

 

h.

no incremental pro forma adjustments for general and administrative expenses have been reflected for any costs associated with a Transition Services Agreement, pursuant to which Newfield will operate the Newfield assets and conduct a specified drilling program on CEP’s behalf until December 31, 2007. In addition, no incremental pro forma adjustments for general and administrative expenses have been reflected for any costs associated with a Transition Services Agreement, pursuant to which EQR will operate the EQR and KPC assets and conduct a specified drilling program on CEP’s behalf. The Transition Services Agreement provides for a reimbursement of EQR’s actual costs plus a 10% premium for any general and administrative services that CEP specifically requests. This amount may not be indicative of any actual future general and administrative costs incurred by CEP. Under this agreement, CEP estimates that the monthly requested general and administrative services related to EQR will be approximately $140,000 per month.

 

i.

to eliminate intercompany activities between EQR and KPC, to eliminate historical balances from Amvest not acquired in the transaction, to eliminate historical interest expense on historical affiliate balances, and to eliminate historical income tax-related balances as CEP is not a taxpayer.

4. DEBT

Newfield Acquisition

In August 2007, the Company borrowed $13.0 million under the reserve-based credit facility to fund an acquisition deposit escrow account for the purchase of the Newfield assets. In September 2007, the Company borrowed an additional $15.0 million to fund the purchase price of the Newfield acquisition, as well as to fund a portion of planned capital expenditures on these properties.

In August 2007, the amount guaranteed under the credit support fee agreement with Constellation Energy Group, Inc. (“CEG”), under which CEG will guarantee credit support for the Company’s financial derivatives, was increased to $10.0 million. The guarantee is for financial derivatives that the Company entered into in anticipation of the Newfield acquisition.

Amvest Acquisition

In July 2007, the Company borrowed $42.5 million under the reserve-based credit facility to fund the purchase price of the Amvest acquisition, as well as to fund a portion of planned capital expenditures on these properties. On July 6, 2007, the borrowing base of the reserve-based credit facility was increased to $135.0 million, and then to $180.0 million on July 26, 2007.

 

F-7

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In July 2007, the amount guaranteed under the credit support fee agreement with Constellation Energy Group, Inc. (“CEG”), under which CEG will guarantee credit support for the Company’s financial derivatives, was increased to $15.0 million. This guarantee and a previous guarantee for $25.0 million were released effective July 6, 2007, when the borrowing base under the Company’s reserve-based credit facility was increased to $135.0 million. On July 13, 2007, the Company entered into a credit support fee agreement with CEG under which CEG guaranteed credit support up to $15.0 million for financial derivatives that the Company entered into in relation to the Amvest acquisition. This guarantee was released on July 26, 2007, when the borrowing base under the Company’s reserve-based credit facility was increased to $180.0 million. Debt issuance costs related to these transactions were approximately $0.5 million which are being amortized over the life of the facility. The reserve-based credit facility will mature in October 2010.

5. EQUITY ISSUANCE

Newfield Acquisition

On August 2, 2007, the Company entered into a Common Unit Purchase Agreement (the “Purchase Agreement”) with certain unaffiliated third-party investors (the “Purchasers”) to sell 2,470,592 common units representing Class B limited liability company interests in the Company (the “New Common Units”) in a private placement for an aggregate purchase price of approximately $105 million. The Company used the proceeds from the private placement, together with funds available under the Company’s revolving credit facility, to fund the purchase price of the Newfield acquisition. At the issuance of the New Common Units, additional Class A units were issued such that the total outstanding amount remained at 2% of all outstanding units. Estimated offering expenses were $0.3 million.

In connection with the Unit Purchase Agreement, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with the Purchasers dated September 21, 2007, the closing date of the private placement. Pursuant to the Registration Rights Agreement, the Company is required to prepare and file a registration statement within 90 days of the closing date, and use its commercially reasonable efforts to cause the registration statement to become effective no later than 135 days following the closing date. In addition, the Registration Rights Agreement gives the Purchasers piggyback registration rights under certain circumstances. These registration rights, which represent the right to register and sell unregistered units in the event that the Company conducts an offering, are transferable to affiliates and, in certain circumstances, to third parties.

If the registration statement is not declared effective within 165 days after the closing date, then the Company must pay each Purchaser, as liquidated damages, 0.25% of the product of $42.50 times the number of New Common Units purchased by such Purchaser (the “Liquidated Damages Multiplier”) per 30-day period for the first 90 days following the 165th day after the closing date, increasing by an additional 0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 30 days, up to a maximum of 1.00% of the Liquidated Damages Multiplier per 30-day period. There is no limitation on the aggregate amount of the liquidated damages the Company must pay each Purchaser.

Amvest Acquisition

On July 16, 2007, the Company entered into a Class F Unit and Common Unit Purchase Agreement (the “Unit Purchase Agreement”) with certain unaffiliated third-party investors (the “July Purchasers”) to sell 3,371,219 Class F Units representing limited liability company interests (the “Class F Units”) and 2,664,998 common units representing Class B limited liability company interests in a private placement for an aggregate purchase price of approximately $210 million. The Company issued and sold 3,371,219 Class F Units and 2,664,998 Common Units to the July Purchasers pursuant to the Unit Purchase Agreement on July 25, 2007. The Company used the proceeds from the private placement, together with funds available under the Company’s revolving credit facility, to fund the purchase price of the Amvest acquisition. At the issuance of the Class F and Common Units, additional Class A units were issued such that the total outstanding amount remained at 2% of all outstanding units. Estimated offering expenses were $3.675 million.

 

F-8

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In connection with the Unit Purchase Agreement, the Company entered into a registration rights agreement (the “July Registration Rights Agreement”) with the July Purchasers dated July 25, 2007, the closing date of the private placement. Pursuant to the July Registration Rights Agreement, the Company is required to prepare and file a registration statement within 90 days of the closing of the private placement (the “Closing Date”), and use its commercially reasonable efforts to cause the registration statement to become effective no later than 135 days following the Closing Date. In addition, the July Registration Rights Agreement gives the July Purchasers piggyback registration rights under certain circumstances. These registration rights, which represent the right to register and sell unregistered units in the event that the Company conducts an offering, are transferable to affiliates and, in certain circumstances, to third parties.

If the registration statement is not declared effective within 165 days after the Closing Date, then the Company must pay each July Purchaser, as liquidated damages, 0.25% of the sum of the product of $34.43 times the number of Class F Units purchased by such July Purchaser plus the product of $35.25 times the number of Common Units purchased by such July Purchaser (the “July Liquidated Damages Multiplier”) per 30-day period for the first 90 days following the 165th day after the Closing Date, increasing by an additional 0.25% of the July Liquidated Damages Multiplier per 30-day period for each subsequent 30 days, up to a maximum of 1.00% of the July Liquidated Damages Multiplier per 30-day period. There is no limitation on the aggregate amount of the liquidated damages the Company must pay each July Purchaser.

6. SUBSEQUENT EVENT

Conversion of Class F Units

On October 12, 2007, at a special meeting of common unitholders, the Company’s common unitholders approved the conversion of all outstanding Class F units into common units.

As a result of the approval, all 3,371,219 of the Company’s outstanding Class F units will be canceled and the same number of common units will be issued to the former holders of Class F units.

To facilitate the conversion, the common unitholders approved both a change in the terms of the Company’s Class F units to provide that each Class F unit is convertible into the Company’s common units, and the issuance of additional common units upon the conversion of the Class F units.

7. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

The following table sets forth certain unaudited pro forma information concerning the Company’s proved oil and natural gas reserves for the year ended December 31, 2006, giving effect to the transactions relating to the Newfield, Amvest, and EQR acquisitions as if they had occurred on January 1, 2006. The information excludes reserves related to royalty and net profit interests. The Company’s estimate of proved reserves is based on the quantities of natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact.

 

F-9

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Natural Gas Reserves - MMCF

Year-Ended December 31, 2006

 

		CEP Historical			EQR Historical			Amvest Historical			Newfield Historical			CEP Pro Forma
Beginning Balance		112,025			39,822			76,733			35,912			264,492
Extensions and discoveries		—			5,334			25,678			4,446			35,458
Purchases of reserves in place		—			—			3,665			—			3,665
Sales of reserves in place		—			—			—			—			—
Revisions of previous estimates		12,952			(1,668	)		(30,651	)		(2,795	)		(22,162	)
Production		(4,641	)		(2,279	)		(5,367	)		(3,995	)		(16,282	)
End of year		120,336			41,209			70,058			33,568			265,171
Total developed reserves		97,387			23,479			44,170			21,510			186,546
Oil, Condensate, and Liquids - MBBLS
Year-Ended December 31, 2006
		CEP Historical			EQR Historical			Amvest Historical			Newfield Historical			CEP Pro Forma
Beginning Balance		—			8			209			449			666
Extensions and discoveries		—			—			—			28			28
Purchases of reserves in place		—			—			—			—			—
Sales of reserves in place		—			—			—			—			—
Revisions of previous estimates		—			8			31			(243	)		(204	)
Production		—			(2	)		(26	)		(32	)		(60	)
End of year		—			14			214			202			430
Total developed reserves		—			14			214			146			374
Natural Gas Equivalents - MMCFE
Year-Ended December 31, 2006
		CEP Historical			EQR Historical			Amvest Historical			Newfield Historical			CEP Pro Forma
Beginning Balance		112,025			39,873			77,990			38,604			268,492
Extensions and discoveries		—			5,334			25,678			4,614			35,626
Purchases of reserves in place		—			—			3,665			—			3,665
Sales of reserves in place		—			—			—			—			—
Revisions of previous estimates		12,952			(1,621	)		(30,467	)		(4,255	)		(23,391	)
Production		(4,641	)		(2,293	)		(5,526	)		(4,187	)		(16,647	)
End of year		120,336			41,293			71,340			34,776			267,745
Total developed reserves		97,387			23,563			45,452			22,386			188,788

 

F-10

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The following table sets forth certain unaudited pro forma information for the Company’s standardized measure of discounted cash flows relating to proved oil and natural gas reserves as of December 31, 2006, giving effect to the transactions relating to the Newfield, Amvest, and EQR acquisitions as if they had occurred on January 1, 2006. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.

Future cash inflows are calculated by applying year-end prices of natural gas, relating to the proved reserves, to the year-end quantities of those reserves. Future cash inflows exclude the impact of the Company’s hedging program and mark-to-market derivatives. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Company is a non-taxable entity.

The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present value. In addition, variations from expected production rates could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Standardized Measure

Year-Ended December 31, 2006

		CEP Historical			EQR Historical			Amvest Historical			Newfield Historical			CEP Pro Forma
Future cash inflows		677,866			216,410			412,325			171,053			1,477,654
Future production costs		(257,502	)		(79,642	)		(178,655	)		(55,017	)		(570,816	)
Future estimated development costs		(64,673	)		(24,629	)		(40,742	)		(18,762	)		(148,806	)
Future net cash inflows		355,691			112,139			192,928			97,274			758,032
10% annual discount for estimated timing of cash flows		(235,504	)		(52,037	)		(76,205	)		(29,474	)		(393,220	)
Standardized measure of discounted estimated future net cash flows(A)		120,187			60,102			116,723			67,800			364,812

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(A)	All historical cash flows are presented pre-tax as the Company is not a taxpayer.

The following table sets forth certain unaudited pro forma information for the principal sources of changes in discounted future net cash flows from the Company’s proved oil and natural gas reserves for the year ended December 31, 2006, giving effect to the transactions relating to the Newfield, Amvest, and EQR acquisitions as if they had occurred on January 1, 2006.

 

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Changes in Standardized Measure

Year-Ended December 31, 2006

 

		CEP Historical			EQR Historical			Amvest Historical			Newfield Historical			CEP Pro Forma
Beginning of the period		295,435			109,627			297,930			164,506			867,498
Sales and transfer of natural gas and oil, net of production costs		(40,064	)		(11,996	)		(46,925	)		(25,418	)		(124,403	)
Net changes in prices and production costs related to future production		(193,499	)		(52,950	)		(174,114	)		(81,389	)		(501,952	)
Development costs incurred during the period		12,292			1,457			14,469			3,878			32,096
Changes in extensions and discoveries		—			9,239			27,838			8,996			46,073
Revisions of previous quantity estimates		18,435			(3,013	)		(45,702	)		(9,896	)		(40,176	)
Purchases of reserves in place		—			—			13,435			—			13,435
Accretion discount		29,624			10,963			29,792			16,451			86,830
Other		(2,036	)		(3,225	)		—			(9,328	)		(14,589	)
Standardized measure of discounted estimated future net cash flows(A)		120,187			60,102			116,723			67,800			364,812

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(A)	All historical changes in cash flows are presented pre-tax as the Company is not a taxpayer.

 

F-12