Exhibit 99.1

Financial Statements of Constellation Energy Partners LLC

PART I — FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

PART II — FINANCIAL STATEMENTS FOR THE QUARTERS AND PERIODS ENDED JUNE 30, 2011 AND 2010

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

INDEX TO PART I		Page
Constellation Energy Partners LLC and Subsidiaries:
Reports of Independent Registered Public Accounting Firm			2
Consolidated Statements of Operations and Comprehensive Income (Loss)			3
Consolidated Balance Sheets			4
Consolidated Statements of Cash Flows			5
Consolidated Statements of Changes in Members’ Equity			7
Notes to Consolidated Financial Statements			8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unitholders and Board of Managers of Constellation Energy Partners LLC:

     In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and comprehensive income (loss), of cash flows, and of changes in members’ equity present fairly, in all material respects, the financial position of Constellation Energy Partners LLC and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it estimates the quantities of proved oil and natural gas reserves in 2009. As discussed in Notes 7 and 17 to the consolidated financial statements, the Company has entered into significant transactions with Constellation Energy Group, Inc. and its affiliates, a related party.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 25, 2011

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)

		For the year				For the year
		ended				ended
		December 31,				December 31,
		2010				2009
		(In 000’s except unit data)
Revenues
Oil and gas sales		$	108,692			$	123,126
Gain / (Loss) from mark-to-market activities (see Note 3)			42,081				19,410
Total revenues			150,773				142,536
Expenses:
Operating expenses:
Lease operating expenses			30,798				33,535
Cost of sales			2,473				2,638
Production taxes			3,179				3,153
General and administrative expenses			20,351				18,506
Exploration costs			760				855
(Gain) / Loss on sale of assets			(18	)			—
Depreciation, depletion and amortization			85,263				71,173
Asset impairments (see Note 5)			272,487				5,113
Accretion expense			822				406
Total operating expenses			416,115				135,379
Other expense / (income)
Interest expense			12,721				11,967
Interest expense (Gain)/Loss from mark-to-market activities (see Note 3)			(765	)			4,338
Interest (income)			(3	)			(2	)
Other expense (income)			(385	)			(123	)
Total other expenses / (income)			11,568				16,180
Total expenses			427,683				151,559
Net income (Loss)		$	(276,910	)		$	(9,023	)
Other comprehensive (Loss)			(17,447	)			(21,760	)
Comprehensive (Loss)		$	(294,357	)		$	(30,783	)
Earnings per unit (see Note 1)
Earnings (loss) per unit—Basic		$	(11.36	)		$	(0.40	)
Units outstanding—Basic			24,370,545				22,664,895
Earnings (loss) per unit—Diluted		$	(11.36	)		$	(0.40	)
Units outstanding—Diluted			24,370,545				22,664,895
Distributions declared and paid per unit		$	—			$	0.26

See accompanying notes to consolidated financial statements.

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Balance Sheets

		December 31, 2010				December 31, 2009
		(In 000’s)
ASSETS
Current assets
Cash and cash equivalents		$	7,892			$	11,337
Accounts receivable			7,371				8,379
Prepaid expenses			1,315				1,298
Risk management assets (see Note 3)			36,513				24,251
Total current assets			53,091				45,265
Oil and natural gas properties (See Note 5)
Oil and natural gas properties, equipment and facilities			774,060				794,520
Material and supplies			2,073				4,312
Less accumulated depreciation, depletion, amortization, and impairments			(499,214	)			(186,207	)
Net oil and natural gas properties			276,919				612,625
Other assets
Debt issue costs (net of accumulated amortization of $4,888 at December 31, 2010 and $2,924 at December 31, 2009)			3,727				5,590
Risk management assets (see Note 3)			46,986				33,916
Other non-current assets			3,654				10,921
Total assets		$	384,377			$	708,317
LIABILITIES AND MEMBERS’ EQUITY
Liabilities
Current liabilities
Accounts payable		$	1,418			$	1,102
Payable to affiliate			—				201
Accrued liabilities			10,369				10,033
Environmental liabilities			—				193
Royalty payable			2,605				4,747
Risk management liabilities (see Note 3)			141				208
Total current liabilities			14,533				16,484
Other liabilities
Asset retirement obligation			13,024				12,129
Debt			165,000				195,000
Total other liabilities			178,024				207,129
Total liabilities			192,557				223,613
Commitments and contingencies (See Note 8)
Class D Interests			6,667				6,667
Members’ equity
Class A units, 487,750 and 476,950 shares authorized, issued and outstanding, respectively			3,485				8,993
Class B units, 24,298,763 and 24,298,763 shares authorized, respectively, and 23,899,758 and 23,376,136 issued and outstanding, respectively			170,748				440,677
Accumulated other comprehensive income			10,920				28,367
Total members’ equity			185,153				478,037
Total liabilities and members’ equity		$	384,377			$	708,317

See accompanying notes to consolidated financial statements.

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Cash Flows

		For the year				For the year
		ended				ended
		December 31,				December 31,
		2010				2009
		(In 000’s)
Cash flows from operating activities:
Net income (loss)		$	(276,910	)		$	(9,023	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization			85,263				71,173
Asset impairments (see Note 5)			272,487				5,113
Amortization of debt issuance costs			1,964				1,429
Accretion expense			822				406
Equity (earnings) losses in affiliate			(385	)			(125	)
(Gain) Loss from disposition of property and equipment			(18	)			—
Bad debt expense			69				—
Dryhole costs			61				173
Hedge ineffectiveness			—				267
(Gain) Loss from mark-to-market activities			(42,846	)			(15,072	)
Unit-based compensation programs			1,849				1,308
Changes in Assets and Liabilities:
Change in net risk management assets and liabilities			(1	)			420
(Increase) decrease in accounts receivable			939				984
(Increase) decrease in prepaid expenses			(15	)			(275	)
(Increase) decrease in other assets			1				33
Increase (decrease) in accounts payable			316				(1,707	)
Increase (decrease) in payable to affiliate			(201	)			(842	)
Increase (decrease) in accrued liabilities			(424	)			2,203
Increase (decrease) in royalty payable			(2,142	)			(378	)
Net cash provided by operating activities			40,829				56,087
Cash flows from investing activities:
Cash paid for acquisitions, net of cash acquired			(6,369	)			(291	)
Development of natural gas properties			(7,973	)			(22,913	)
Proceeds from sale of equipment			91				130
Distributions from equity affiliate			485				503
Net cash used in investing activities			(13,766	)			(22,571	)
Cash flows from financing activities:
Members’ distributions			—				(5,820	)
Proceeds from issuance of debt			—				37,500
Repayment of debt			(30,000	)			(55,000	)
Costs for shelf registration statement			—				—
Units tendered by employees for tax withholdings			(376	)			(6	)
Equity issue costs			(2	)			(82	)
Debt issue costs			(130	)			(5,026	)
Net cash (used in) provided by financing activities			(30,508	)			(28,434	)
Net (decrease) increase in cash			(3,445	)			5,082
Cash and cash equivalents, beginning of period			11,337				6,255
Cash and cash equivalents, end of period		$	7,892			$	11,337

		For the year				For the year
		ended				ended
		December 31,				December 31,
		2010				2009
		(In 000’s)
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures		$	523			$	(2,760	)
Cash received during the period for interest		$	3			$	2
Cash paid during the period for interest		$	(7,106	)		$	(6,225	)
Cash paid during the period for income taxes		$	(2	)		$	(2	)

See accompanying notes to consolidated financial statements.

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

																		Accumulated
																		Other				Total
		Class A								Class B								Comprehensive				Members’
		Units				Amount				Units				Amount				Income				Equity
		( In 000’s, except unit data)
Balance, December 31, 2008			447,721			$	9,265				21,938,342			$	454,030			$	50,127			$	513,422
Distributions			—				(116	)			—				(5,704	)			—				(5,820	)
Equity Issuance Cost			—				(2	)			—				(82	)			—				(84	)
Units tendered by employees for tax withholding			(37	)			(0	)			(1,792	)			(6	)			—				(6	)
Change in fair value of commodity hedges			—				—				—				—				17,694				17,694
Cash settlement of commodity hedges			—				—				—				—				(46,730	)			(46,730	)
Change in fair value of interest rate hedges			—				—				—				—				7,276				7,276
Unit-based compensation programs			29,266				26				1,439,586				1,282				—				1,308
Net income (loss)			—				(180	)			—				(8,843	)			—				(9,023	)
Balance, December 31, 2009			476,950			$	8,993				23,376,136			$	440,677			$	28,367			$	478,037
Distributions			—				—				—				—				—				—
Units tendered by employees for tax withholding			(1,885	)			(8	)			(92,353	)			(368	)			—				(376	)
Change in fair value of commodity hedges			—				—				—				—				(495	)			(495	)
Cash settlement of commodity hedges			—				—				—				—				(17,341	)			(17,341	)
Cash settlement of interest rate hedges			—				—				—				—				389				389
Unit-based compensation programs			12,685				37				615,975				1,812				—				1,849
Net income (loss)			—				(5,538	)			—				(271,372	)			—				(276,910	)
Balance, December 31, 2010			487,750			$	3,484				23,899,758			$	170,749			$	10,920			$	185,153

See accompanying notes to consolidated financial statements.

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 and 2009

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Basis of Presentation

     Constellation Energy Partners LLC (“CEP”, “we”, “us”, “our” or the “Company”) was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and trade on the NYSE Arca under the symbol “CEP”. We are partially-owned by Constellation Energy Commodities Group, Inc. (“CCG”), which is owned by Constellation Energy Group, Inc. (NYSE: CEG) (“Constellation” or “CEG”). As of December 31, 2010, affiliates of Constellation own all of our Class A units, all of the management incentive interests, approximately 25% of our common units and all of our Class D interests.

     We are currently focused on the development and acquisition of natural gas properties in the Black Warrior Basin in Alabama, the Cherokee Basin in Kansas and Oklahoma, the Woodford Shale in Oklahoma, and the Central Kansas Uplift in Kansas and Nebraska.

     Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.

Cash and Cash Equivalents

     All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit were $1.6 million in 2010 and $0.9 million in 2009 and are included in accounts payable in our consolidated balance sheets.

Concentration of Credit Risk and Accounts Receivable

     Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our reserve-based credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. During 2010, there was bad debt expense of less than $0.1 million and there was no bad debt expense in 2009. We have no off-balance-sheet credit exposure related to our operations or customers.

     For the year ended December 31, 2010, five customers accounted for approximately 30%, 17%, 9%, 6% and 5% of our sales revenues. For the year ended December 31, 2009, five customers accounted for approximately 31%, 10%, 10%, 9% and 6% of our sales revenues.

Oil and Natural Gas Properties

     Oil and Natural Gas Properties

We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.

Effective for fiscal years ending on or after December 31, 2009, new accounting rules require that we price our future oil and natural gas production at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Prior to the new rules, we were required to price our future oil and natural gas production at an SEC-required price which is based on the oil and natural gas prices in effect at the end of each fiscal quarter. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.

Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. It has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter. Prior to the fourth quarter 2009, depreciation, depletion, and amortization expense was calculated using year-end reserve reports based on year-end pricing, however for the fourth quarter 2009 the SEC-required price was used to calculate depreciation, depletion, and amortization expense. As more fully described in Note 15, proved reserves estimates are subject to future revisions when additional information becomes available.

As described in Note 9, estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.

Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Cash flow estimates for the impairment testing exclude derivative instruments. Refer to Note 5 for additional information.

Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Impairment is deemed to have occurred if a lease is going to expire prior to any planned drilling on the leased property.

Property acquisition costs are capitalized when incurred.

Support Equipment and Facilities

Support equipment and facilities consist of certain of our water treatment facilities, gathering lines, roads, pipelines, and other various support equipment. Items are capitalized when acquired and depreciated using the straight-line method over the useful life of the assets.

Materials and Supplies

Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.

Depreciation, depletion and amortization of oil and natural gas properties was computed using the units-of-production method based on estimated proved gas reserves.

Oil and Natural Gas Reserve Quantities

     Our estimate of proved reserves was 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. Proved reserves were calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2010 and 2009 is described in detail in Note 15.

     Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.

     Proved reserve estimates were a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.

Derivatives and Hedging Activities

     We use derivative financial instruments to achieve a more predictable cash flow from our natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our reserve-based credit facility.

     We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheet under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statement of income under the caption “Gain (loss) from mark-to-market activities.” We record settled natural gas swaps as “Gas sales” and settled interest rate swaps as “Interest expense.”

Net Profits Interest

     Certain of our properties in the Robinson’s Bend Field are subject to a net profits interest (“NPI”). The NPI represents an interest in production created from the working interest and is based on a contracted revenue calculation (see Note 10). The NPI is accounted for as an overriding royalty interest. This is consistent with how we account for the NPI for reserves purposes. Any payments made to the NPI holder are reflected as a reduction in revenue.

Revenue Recognition

     Sales of oil and natural gas are recognized when oil or natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale are reasonably assured and the sales price is fixed or determinable. Oil and natural gas is sold on a monthly basis. Most of our sales contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil or natural gas, and prevailing supply and demand conditions, so that the price of the oil or natural gas fluctuates to remain competitive with other available energy supplies. As a result, revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil and natural gas contracts are customary in the industry.

     Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no gas imbalance positions at December 31, 2010 or 2009.

Income Taxes

     CEP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of its members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. CEP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama, Oklahoma, and Nebraska. CEP also has informational filing requirements in Georgia, Indiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states.

     Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For 2010, the current federal and state tax liability for the entity was approximately $0.02 million. This amount was paid to the IRS or the applicable states in quarterly installments. The entity had no deferred tax assets or liabilities.

Use of Estimates

     Estimates and assumptions are made when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:

	•		reported amounts of revenue and expenses in the Consolidated Statement of Operations and Other Comprehensive Income (Loss) during the reported periods,
	•		reported amounts of assets and liabilities in the Consolidated Balance Sheets at the dates of the financial statements,
	•		disclosure of quantities of reserves and use of those reserve quantities for depreciation, depletion and amortization, and
	•		disclosure of contingent assets and liabilities at the date of the financial statements.

     These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control. As a result, actual amounts could materially differ from these estimates.

Earnings per Unit

     The following table presents earnings per common unit amounts:

		Income								Per Unit
Year ended December 31, 2010		(loss)				Unit				Amount
		(In 000’s except unit data)
Basic EPS:
Income allocable to unitholders		$	(276,910	)			24,370,545			$	(11.36	)
Effect of dilutive securities:
Restricted common units that earn distributions			—				—				—
Diluted EPS:
Income allocable to common unitholders		$	(276,910	)			24,370,545			$	(11.36	)

		Income								Per Unit
Year ended December 31, 2009		(loss)				Unit				Amount
		(In 000’s except unit data)
Basic EPS:
Income allocable to unitholders		$	(9,023	)			22,664,895			$	(0.40	)
Effect of dilutive securities:
Restricted common units that earn distributions			—				—				—
Diluted EPS:
Income allocable to common unitholders		$	(9,023	)			22,664,895			$	(0.40	)

Comprehensive Income (Loss)

     Comprehensive income (loss) includes net earnings (loss) as well as unrealized gains and losses on derivative instruments.

Class D Interests

     Due to their contingently redeemable feature, the Class D interests are treated as preferred units subject to contingent redemption.

Environmental Cost

     We record environmental liabilities at their undiscounted amounts on our balance sheet in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Federal Environmental Protection Agency (“EPA”) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

Unit-Based Compensation

     We record compensation expense for all equity grants issued under the Long-Term Incentive Program, the 2009 Omnibus Incentive Compensation Plan, and the Executive Inducement Bonus Program based on the fair value at the grant date, recognized over the vesting period.

Other Contingencies

     We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.

Accounting Standards Adopted Through February 25, 2011

     In January 2010, the FASB issued its final guidance on additional supplemental fair value disclosures. Two new disclosures are required: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 roll forward reconciliation, which will replace the “net” presentation format, and (2) detailed disclosures about the transfers between Level 1 and 2 measurements. The guidance also provides several clarifications regarding the level of disaggregation and disclosures about inputs and valuation techniques. The new disclosures became effective for the first quarter 2010 for calendar year-end companies, except for the Level 3 “gross” activity disclosures, which will be deferred until the first quarter of 2011. The adoption of this guidance did not have a material impact on our financial statements or our disclosures.

     In February 2010, the FASB amended its guidance on subsequent events. SEC filers are now not required to disclose the date through which an entity has evaluated subsequent events. The amended guidance was effective upon issuance. The adoption of this guidance did not have an impact on our financial statements or our disclosures.

     In September 2009, the FASB issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Accounting Standards Update (ASU) 2010-03, Extractive Industries—Oil and Gas (Topic 932) with the requirements in the SEC’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and is effective for the year ended December 31, 2009. The final rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also

designed to modernize the oil and natural gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the final rule include, but are not limited to:

	•		Oil and natural gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day year-end price;
	•		Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and
	•		Easing the standard for the inclusion of proved undeveloped reserves (“PUDs”) and requiring disclosure of information indicating any progress toward the development of PUDs.

     We began complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009. Under the SEC rules, our year-end 2009 reserve report uses the new rules as a change in accounting principle that is inseparable form a change in estimates. Under the SEC’s final rule, prior period reserves were not restated. The impact of the adoption of the SEC final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

     In June 2009, the Financial Accounting Standards Board (“FASB”) released the final version of its new Accounting Standards Codification (the “Codification”) as the single authoritative source for U.S. GAAP. The Codification replaces all previous U.S. GAAP accounting standards as described in ASC 105 (SFAS 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles). While not intended to change U.S. GAAP, the Codification significantly changes the way in which the accounting literature is organized. It is structured by accounting topic to help accountants and auditors more quickly identify the guidance that applies to a specific accounting issue. However, because the Codification completely replaces existing standards, it will affect the way U.S. GAAP is referenced by companies in their financial statements and accounting policies. The Codification is effective for financial statements that cover interim and annual periods ending after September 15, 2009. The adoption of the Codification did not have a material impact on our financial statements.

     In May 2009, the FASB established general standards of accounting for and the disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that currently exist in the auditing standards. The standard, which includes a new required disclosure of the date through which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. We perform an evaluation of subsequent events until the issuance date of our document with the SEC so the adoption of the new requirements had no impact on our financial statements. See Note 17 for additional information.

New Accounting Pronouncements Issued But Not Yet Adopted

     As of December 31, 2010, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. We are currently reviewing the recently issued standards and interpretations but none are expected to have a material impact on our financial statements.

2. ACQUISITIONS

Central Kansas Uplift Non-Operated Acquisition

     On December 21, 2010, we acquired from a private seller, effective November 1, 2010, non-operated oil properties in the Central Kansas Uplift in northern Kansas and southern Nebraska for an all cash purchase price of approximately $5.9 million. At the acquisition, the properties produced approximately 126 barrels of oil equivalent per day from 36 wells. The operator of the properties is Murfin Drilling Company, Inc. Proved oil reserves were estimated to be 0.8 Bcfe, of which approximately 81% were classified as proved developed producing. The acquisition was funded with cash on hand. Our results of operations include the results of the non-operated wells after the date of acquisition.

     The total consideration paid was $5.9 million, which consisted of $5.9 million in cash and assumed liabilities of less than $0.1 million, primarily associated with asset retirement obligations on the properties. The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition.

Acquired December 21, 2010		(in millions)
Oil and Natural Gas Properties		$	5.9
Total assets acquired			5.9
Asset retirement obligations			(0.0	)
Net assets acquired		$	5.9

     The purchase price allocation is based on fair value evaluations of proved oil and natural gas reserves, discounted cash flows, quoted market prices, and other estimates by management. This purchase price allocation is preliminary and remains subject to post-closing adjustments during 2011.

Cola Acquisition

     On March 31, 2008, we acquired 83 non-operated producing natural gas wells in the Woodford Shale in the Arkoma Basin in Oklahoma from CoLa Resources LLC (“CoLa”) for $50.1 million, including purchase price adjustments (“CoLa Acquisition”). CoLa is an affiliate of CEG, our former sponsor. The transaction was reviewed and approved by our conflicts committee. In its review, our conflicts committee considered various economic factors (including historical and estimated future production, estimated proved reserves, future pricing estimates and operating cost estimates) regarding the transaction, and determined that the acquisition was fair and in the best interests of the Company. The 83 wells, located in Coal and Hughes Counties, Oklahoma, have an average gross working interest per well of 11.4% and an average net revenue interest per well of 9.2%. The acquired natural gas reserves associated with the wells are 100% proved developed producing. Our results of operations include the results of the non-operated wells after the date of acquisition.

     To fund the purchase of CoLa, we borrowed $53.0 million under our previous reserve-based credit facilities.

     Upon the announcement of the acquisition, we entered into derivative transactions to hedge a portion of the future expected production associated with these wells.

     The total consideration paid was $50.1 million, which consisted of $50.2 million in cash and transaction costs and assumed liabilities of approximately $0.1 million, primarily associated with asset retirement obligations on the properties. The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition.

Acquired March 31, 2008		(in millions)
Oil and Natural Gas Properties		$	50.2
Total assets acquired			50.2
Asset retirement obligations			(0.1	)
Net assets acquired		$	50.1

     The purchase price allocation is based on fair value evaluations of proved oil and natural gas reserves, discounted cash flows, quoted market prices, and other estimates by management.

     In July 2009, we received approximately $0.2 million from Cola for post-closing and title adjustments related to the CoLa acquisition. Under the purchase agreement, we had the right to assert, and CoLa had the right to attempt to cure, any title defects to the acquired wells until July 31, 2009. CoLa’s post-closing payment obligations with respect to title defects and indemnities under the purchase agreement was secured, in part, by a guaranty from CCG delivered at closing. The maximum amount of the CCG guaranty was limited to (i) 20% of the purchase price, with respect to indemnity obligations, and (ii) with respect to title defect obligations, the amount of such title defects, such amount to be calculated as provided in the purchase agreement. The amount of CCG’s guaranty with respect to title defect obligations has decreased as title curative were received and as CoLa received proceeds of production from the wells as to which payments of production proceeds had not commenced as of the closing date and which were attributable to periods prior to the effective time of the purchase agreement. No further title adjustments are expected and a guarantee no longer exists with respect to title defect obligations.

3. DERIVATIVE AND FINANCIAL INSTRUMENTS

Mark-to-Market Activities

     We have hedged a portion of our expected natural gas sales from currently producing wells through December 2014. All of our swaps and basis swaps were accounted for as mark-to-market activities as of December 31, 2010.

     At December 31, 2010, and December 31 2009, we had debt outstanding of $165.0 million and $195.0 million, respectively, under our reserve-based credit facility. We have entered into hedging arrangements in the form of interest rate swaps to reduce the impact of volatility stemming from changes in the London interbank offered rate (“LIBOR”) on $93.0 million of outstanding debt for various maturities extending through October 2014. All of our interest rate swaps are accounted for as mark-to-market activities as of December 31, 2010. Prior to February 2009, they were accounted for as cash flow hedges.

     For 2010 and 2009, we recognized mark-to-market gains of approximately $42.1 million and $19.4 million, respectively, in connection with our commodity derivatives. At December 31, 2010 and December 31, 2009, the fair value of the derivatives accounted for as mark-to-market activities amounted to a net asset of approximately $83.4 million and a net asset of approximately $58.0 million, respectively.

Accumulated Other Comprehensive Income

     Prior to the first quarter of 2009, we accounted for certain our commodity and interest rate derivatives as hedging activities. The value of the cash flow hedges included in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets was an unrecognized gain of approximately $10.9 million and an unrecognized gain of $28.4 million at December 31, 2010 and December 31, 2009, respectively. We expect that the unrecognized gain will be reclassified from accumulated other comprehensive income (loss) (“AOCI”) to the income statement in the following periods:

						Non-
		Commodity				performance
For the Quarter Ended		Derivatives				Risk				Total AOCI
March 31, 2011		$	724			$	(24	)		$	700
June 30, 2011			1,960				(75	)			1,885
September 30, 2011			1,749				(74	)			1,675
December 31, 2011			1,283				(60	)			1,223
March 31, 2012			718				(22	)			696
June 30, 2012			1,928				(66	)			1,862
September 30, 2012			1,721				(63	)			1,658
December 31, 2012			1,271				(50	)			1,221
Total		$	11,354			$	(434	)		$	10,920

Fair Value Measurements

     We measure fair value of our financial and non-financial assets and liabilities on a recurring basis. Accounting standards define fair value, establish a framework for measuring fair value and require certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. All of our derivative instruments are recorded at fair value in our financial statements. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

     The following hierarchy prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:

	•		Level 1 — Quoted prices available in active markets for identical assets or liabilities as of the reporting date.
	•		Level 2 — Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable as of the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.
	•		Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources.

     We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement of each individual asset and liability taken as a whole. Certain of our derivatives are classified as Level 3 because observable market data is not available for all of the time periods for which we have derivative instruments. As observable market data becomes available for all of the time periods, these derivative positions will be reclassified as Level 2. The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 or Level 3. We prioritize the use of the highest level inputs available in determining fair value.

     Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy. While we are required to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher level in the hierarchy.

     The following tables set forth by level within the fair value hierarchy our assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2010, and December 31, 2009.

														Netting and
														Cash				Total Fair
At December 31, 2010		Level 1				Level 2				Level 3				Collateral*				Value
		(In 000’s)
Risk management assets		$	—			$	87,072			$	(3,573	)		$	—			$	83,499
Risk management liabilities			—				(141	)			—				—				(141	)
Total		$	—			$	86,931			$	(3,573	)		$	—			$	83,358

														Netting and
														Cash				Total Fair
At December 31, 2009		Level 1				Level 2				Level 3				Collateral*				Value
		(In 000’s)
Risk management assets		$	—			$	62,894			$	(4,727	)		$	—				$58,167
Risk management liabilities			—				(208	)			—				—				(208	)
Total		$	—			$	62,686			$	(4,727	)		$	—				$57,959

     Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions. We classify all of our derivative instruments as “Risk management assets” or “Risk management liabilities” in our Consolidated Balance Sheets.

     We use observable market data or information derived from observable market data in order to determine the fair value amounts presented above. Prior to September 30, 2009, the valuation of our derivatives was performed by Constellation under a management services agreement (see Note 7). In order to determine the fair value amounts presented above, Constellation utilized various factors, including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. These factors included not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and parental guarantees), but also the impact of our nonperformance risk on our liabilities. We currently use our reserve-based credit facility to provide credit support for our derivative transactions. Historically, in connection with certain of our acquisitions, we have used guarantees from Constellation to provide credit support for our derivative transactions associated with the acquisition volumes. As a result, we do not post cash collateral with our counterparties, and have minimal non-performance credit risk on our liabilities with counterparties. We utilize observable market data for credit default

swaps to assess the impact of non-performance credit risk when evaluating our assets from counterparties. At December 31, 2010, the impact of non-performance credit risk on the valuation of our assets from counterparties was $1.9 million, of which $1.4 million was reflected as a decrease to our non-cash market-to-market gain and $0.5 million was reflected as a reduction to our accumulated other comprehensive income. At December 31, 2009, the impact of non-performance credit risk on the valuation of our assets from counterparties was $0.6 million, of which $0.1 million was reflected as an increase to our non-cash market-to-market gain and $0.7 million was reflected as a reduction to our accumulated other comprehensive income.

     We use observable market data or information derived from observable market data to measure the fair value of our derivative instruments. Prior to September 30, 2009, in certain instances, Constellation may have utilized internal models to measure the fair value of our derivative instruments. Generally, Constellation used similar models to value similar instruments. Valuation models utilized various inputs which included quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that were not active, other observable inputs for the assets or liabilities, and market-corroborated inputs, which were inputs derived principally from or corroborated by observable market data by correlation or other means.

     The following table sets forth a reconciliation of changes in the fair value of risk management assets and liabilities classified as Level 3 in the fair value hierarchy:

		Three Months Ended				Twelve Months Ended
		December 31, 2010				December 31, 2010
		(In 000’s)				(In 000’s)
Balance at beginning of period		$	(5,512	)		$	(4,727	)
Realized and unrealized gain (loss):
Included in earnings			1,308				(3,078	)
Included in other comprehensive income			—				389
Purchases, sales, issuances, and settlements			631				3,843
Transfers into and (out of) Level 3			—				—
Balance as of December 31, 2010		$	(3,573	)		$	(3,573	)
Change in unrealized gains relating to derivatives still held as of December 31, 2010		$	1,308			$	(2,689	)

		Three Months Ended				Twelve Months Ended
		December 31, 2009				December 31, 2009
		(In 000’s)				(In 000’s)
Balance at beginning of period		$	(6,168	)		$	6,752
Realized and unrealized gain (loss):
Included in earnings			(3,084	)			(12,923	)
Included in other comprehensive income			2,941				1,630
Purchases, sales, issuances, and settlements			1,584				5,349
Transfers into and (out of) Level 3(a)			—				(5,535	)
Balance as of December 31, 2009		$	(4,727	)		$	(4,727	)
Change in unrealized gains (losses) relating to derivatives still held as of December 31, 2009		$	(143	)		$	(1,872	)

Fair Value of Financial Instruments

     At December 31, 2010, the carrying values of cash and cash equivalents, accounts receivable, other current assets and current liabilities on the Consolidated Balance Sheets approximate fair value because of their short term nature. We believe the carrying value of long-term debt approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms, which represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.

     The following fair value disclosures are applicable to our financial statements as of December 31, 2010, and 2009:

				Fair Value of Asset/
				(Liability) on Balance Sheet
				(in 000’s)
		Location of Asset/		Year Ended				Year Ended
Derivative Type		(Liability) on Balance Sheet		December 31, 2010				December 31, 2009
Commodity-MTM		Risk management assets-current		$	38,945			$	30,292
Commodity-MTM		Risk management assets-non-current			60,324				47,285
Commodity-MTM		Risk management assets-current			(2,432	)			(6,041	)
Commodity-MTM		Risk management assets-non-current		$	(9,765	)		$	(8,642	)
Commodity-MTM		Risk management liabilities-current			(141	)			(208	)
Interest Rate-MTM		Risk management assets-non-current			(3,573	)			(4,727	)
		Total		$	83,358			$	57,959

				Amount of Gain/(Loss)
				in Income
				(in 000’s)
		Location of Gain/(Loss)		Quarter Ended				Quarter Ended
Derivative Type		in Income		December 31, 2010				December 31, 2009
Commodity-MTM		Gain/(Loss) from mark-to-market activities		$	(10,464	)		$	15,743
Commodity-MTM		Oil and gas sales			7,978				1,217
Interest Rate-MTM		Interest expense-Gain/(Loss) from mark-to-market activities			1,939				218
Interest Rate-MTM		Interest expense			(631	)			(361	)
		Total		$	(1,178	)		$	16,817

				Amount of Gain/(Loss)
				in Income
				(in 000’s)
		Location of Gain/(Loss)		Year Ended				Year Ended
Derivative Type		in Income		December 31, 2010				December 31, 2009
Commodity-MTM		Gain/(Loss) from mark-to-market activities		$	41,368			$	16,572
Commodity-MTM		Oil and gas sales			23,011			$	13,141
Interest Rate-MTM		Interest expense-Gain/(Loss) from mark-to-market activities			765				(1,397	)
Interest Rate-MTM		Interest expense			(3,454	)			(476	)
		Total		$	61,690			$	27,840

				Amount of Gain/
				(Loss) Reclassified
				from AOCI into								Amount of Gain/(Loss)
				Income-Effective								in Income-Ineffective
		Location of Gain/(Loss)		(in 000’s)								(in 000’s)
		for Effective and		Quarter				Quarter				Quarter				Quarter
		Ineffective		Ended				Ended				Ended				Ended
		Portion of Derivative		December 31,				December 31,				December 31,				December 31,
Derivative Type		in Income		2010				2009				2010				2009
Commodity-Cash Flow		Gain/(Loss) from mark-to-market activities		$	713			$	2,838			$	—			$	—
Commodity-Cash Flow		Oil and gas sales			3,568				9,920				—				—
Interest Rate-Cash flow		Gain/(Loss) from mark-to-market activities			—				(2,941	)			—				—
Interest Rate-Cash Flow		Interest expense			—				(1,222	)			—				—
		Total		$	4,281			$	8,595			$	—			$	—

				Amount of Gain/
				(Loss) Reclassified
				from AOCI into								Amount of Gain/(Loss)
		Location of Gain/(Loss)		Income-Effective								in Income-Ineffective
		for Effective and		(in 000’s)								(in 000’s)
		Ineffective		Year Ended				Year Ended				Year Ended				Year Ended
		Portion of Derivative		December 31,				December 31,				December 31,				December 31,
Derivative Type		in Income		2010				2009				2010				2009
Commodity-Cash Flow		Gain/(Loss) from mark-to-market activities		$	713			$	2,838			$	—			$	—
Commodity-Cash Flow		Oil and gas sales			17,341				46,730				—				267
Interest Rate-Cash flow		Gain/(Loss) from mark-to-market activities			—				(2,941	)			—				—
Interest Rate-Cash Flow		Interest expense			(389	)			(4,335	)			—				—
		Total Cash Flow		$	17,665			$	42,292			$	—			$	267

     As of December 31, 2010, we have interest rate swaps on $93.0 million of outstanding debt for various maturities extending through October 2014, various commodity swaps for 33,540,000 MMbtu of natural gas production through December 2014, and various basis swaps for 21,109,512 MMbtu of natural gas production in the Cherokee Basin through December 2014.

4. DEBT

Reserve-Based Credit Facility

     On November 13, 2009, we entered into an amended and restated $350.0 million reserve-based credit facility with The Royal Bank of Scotland plc as administrative agent and a syndicate of lenders. The reserve-based credit facility amends, extends, and consolidates our previous reserve-based credit facilities and matures on November 13, 2012. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The current lenders and their percentage commitments in the reserve-based credit facility are: The Royal Bank of Scotland plc (26.84%), BNP Paribas (21.95%), The Bank of Nova Scotia (21.95%), Wells Fargo Bank, N.A. (14.63%), and Societe Generale (14.63%).

     The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of December 31, 2010, our borrowing base was $195.0 million. The borrowing base is redetermined semi-annually, and may be redetermined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, together with, among other things, the oil and natural gas prices prevailing at such time. Our next semi-annual borrowing base redetermination is scheduled during the second quarter of 2011. Outstanding borrowings in excess of our borrowing

base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders.

     Borrowings under the reserve-based credit facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes. The reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit. As of December 31, 2010, no letters of credit are outstanding.

     At our election, interest for borrowings are determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.50% per annum based on utilization plus (iii) a commitment fee of 0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

     The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of our subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions.

     In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents, and cash reserves of the Company)) to Adjusted EBITDA (defined as, for any period, the sum of consolidated net income for such period plus (minus) the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives, and other similar charges) of not more than 3.50 to 1.0; (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt (to the extent such payments are not past due), of not less than 1.0 to 1.0, all calculated pursuant to the requirements under SFAS 133 and SFAS 143 (including the current liabilities in respect of the termination of natural gas and interest rate swaps). All financial covenants are calculated using our consolidated financial information.

     The reserve-based credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, guaranties not being valid under the reserve-based credit facility and a change of control. If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise other rights and remedies. The reserve-based credit facility contains a condition to borrowing and a representation that no material adverse effect (“MAE”) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.

     We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. As of February 25, 2011, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.

     The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then-current strip pricing (provided that such projection shall not be more than 115% of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit facility also permits us to hedge the interest rate on up to 90% of the then-outstanding principal amounts of our indebtedness for borrowed money.

     The reserve-based credit facility contains no covenants related to our relationship with Constellation or Constellation’s right to appoint all of the Class A managers of our board of managers.

     Debt Issue Costs

     As of December 31, 2010, our unamortized debt issue costs were approximately $3.7 million. These costs are being amortized over the life of the reserve-based credit facility through November 2012.

     Funds Available for Borrowing

     As of December 31, 2010, we had $165.0 million in outstanding debt under our reserve-based credit facility and $30.0 million in remaining borrowing capacity. As of December 31, 2009, we had $195.0 million in outstanding debt under our reserve-based credit facilities.

     Compliance with Financial Covenants

     At December 31, 2010, we believe that we were in compliance with the financial covenant ratios contained in our reserve-based credit facility. We monitor compliance on an ongoing basis. As of December 31, 2010, our actual Total Net Debt to annual Adjusted EBITDA ratio was 2.9 to 1.0 as compared with a required ratio of not greater than 3.5 to 1.0, our actual ratio of consolidated current assets to consolidated current liabilities was 3.2 to 1.0 as compared with a required ratio of not less than 1.0 to 1.0, and our actual quarterly Adjusted EBITDA to cash interest expense ratio was 9.2 to 1.0 as compared with a required ratio of not less than 2.5 to 1.0.

     If we are unable to remain in compliance with the debt covenants associated with our reserve-based credit facility or maintain the required ratios discussed above, we could request waivers from the lenders in our bank group. Although the lenders may not provide a waiver, we could take additional steps in the event of not meeting the required ratios or in the event of a reduction in the borrowing base below its current level of $195.0 million at one of the future redeterminations by the lenders. During 2011, we intend to use our surplus operating cash flows to reduce our outstanding debt. If it becomes necessary to reduce debt by amounts that exceed our operating cash flows, we could further reduce capital expenditures, continue to suspend our quarterly distributions to unitholders, sell oil and natural gas properties, liquidate in-the-money derivative positions, further reduce operating and administrative costs, or take additional steps to increase liquidity. If we become unable to obtain a waiver and were unsuccessful at reducing our debt to the necessary level, our debt could become due and payable upon acceleration by the lenders. To the extent that we do not enter into an agreement to refinance or extend the due date on the reserve-based credit facility, the outstanding debt balance at November 13, 2011, will become a current liability.

5. OIL AND NATURAL GAS PROPERTIES

     Natural gas properties consist of the following:

		December 31,				December 31,
		2010				2009
		(In 000’s)
Oil and natural gas properties and related equipment (successful efforts method)
Property (acreage) costs
Proved property		$	772,450			$	756,461
Unproved property			698				37,147

		December 31,				December 31,
		2010				2009
		(In 000’s)
Total property costs			773,148				793,608
Materials and supplies			2,073				4,312
Land			912				912
Total			776,133				798,832
Less: Accumulated depreciation, depletion, amortization and impairments			(499,214	)			(186,207	)
Natural gas properties and equipment, net		$	276,919			$	612,625

     Depletion, depreciation, amortization and impairments consisted of the following:

		Twelve				Twelve
		Months				Months
		Ended				Ended
		December 31,				December 31,
		2010				2009
		(In 000’s)
DD&A of oil and natural gas-related assets		$	85,263			$	71,173
Asset impairments			272,487				5,113
Total		$	357,750			$	76,286

     Impairment of Oil and Natural Gas Properties and Other Non-Current Assets

     In 2010, due to a significant decline in future natural gas price curves across all future production periods, we performed an impairment analysis of our oil and natural gas properties and other non-current assets. For the twelve months ended December 31, 2010, we recorded a total non-cash impairment charge of approximately $272.5 million, composed of $263.4 million to impair the value of our proved and unproved oil and natural gas properties in the Cherokee Basin, $6.3 million to impair our other non-current assets related to our activities in the Cherokee Basin, $0.4 million to impair the value of inventory in the Cherokee basin, $1.9 million to impair certain of our wells in the Woodford Shale, and $0.5 million to impair the value of our casing inventory. These non-cash charges are included in asset impairments in the Consolidated Statement of Operations. This impairment of our proved Cherokee Basin oil and natural gas properties and the impairment of certain of our wells located in the Woodford Shale was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 2 inputs. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates for the coalbed methane and non-operated shale properties of 10.0%. The impairment was caused by the impact of lower future natural gas prices. Particularly during the third quarter of 2010, future natural gas price curves shifted significantly lower in the Cherokee Basin, especially in the years 5 through 15, and an impairment was recorded. Cash flow estimates for the impairment testing exclude derivative instruments used to mitigate the risk of lower future natural gas prices. Our unproved properties in the Cherokee Basin were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices, our limited future capital budgets, and our future expected drilling schedules. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves included in the third party reserve report, future expected natural gas prices and basis differentials, and our anticipated drilling schedules and capital availability. The impairment of our other non-current assets was recorded because the net capitalized costs of the intangible assets exceeded the fair value of the assets as measured by estimated cash flows based on lower observable future expected natural gas prices adjusted for basis differentials, which are Level 2 inputs. These asset impairments have no impact on our cash flows, liquidity position, or debt covenants. If expected future oil and natural gas prices continue to decline during 2011, the estimated undiscounted future cash flows for our proved oil and natural gas properties may not exceed the net capitalized costs for our properties in the Cherokee Basin or in the Woodford Shale and a non-cash impairment charge may be required to be recognized in future periods. As of December 31, 2010, we reviewed our other properties for impairment and the

estimated undiscounted future cash flows exceeded the net capitalized costs, thus no impairment was required to be recognized.

     In 2009, we recorded a charge of approximately $4.8 million to impair the value of certain of our wells located in the Woodford Shale in Oklahoma and approximately $0.3 million to impair the value of certain obsolete inventory and straight-line assets. This charge is included in depreciation, depletion and amortization in the Consolidated Statement of Operations. This impairment was recorded because the carrying value of certain of the wells exceeded the fair value of the wells as measured by estimated cash flows reported in a third party reserve report that was based upon future expected oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 2 inputs. The impairment is primarily caused by the impact of lower future expected natural gas prices. Cash flow estimates for the impairment testing exclude derivative instruments. As of December 31, 2009, we reviewed our other properties for impairment and the estimated undiscounted future cash flows exceeded the net capitalized costs, thus no impairment was required to be recognized.

     Asset Sales

     In 2010, we sold miscellaneous equipment and surplus inventory for approximately $0.1 million and recorded a gain of approximately $0.02 million on the sales.

     In 2009, we sold two tractors, casing, a ditch witch, and other miscellaneous equipment for approximately $0.1 million and recorded a loss of approximately $0.03 million on the sales.

     Useful Lives

     Our furniture, fixtures, and equipment are depreciated over a life of one to five years, buildings are depreciated over a life of twenty years, and pipeline and gathering systems are depreciated over a life of twenty-five to forty years.

     Exploration and Dry Hole Costs

     Our exploration and dry hole costs were $0.8 million and $0.9 million in 2010 and 2009, respectively. These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment associated with leases on our unproved properties.

6. BENEFIT PLANS

     Eligible employees of CEP participate in an employment savings plan. Matching contributions made by us were approximately $0.5 million and $0.4 million for the years ended December 31, 2010 and 2009, respectively.

7. RELATED PARTY TRANSACTIONS

Management Services Agreement

     In November 2006, we entered into a management services agreement with Constellation Energy Partners Management, LLC (“CEPM”), a subsidiary of Constellation, to provide certain management, technical and administrative services. CEPM terminated the management services agreement effective December 15, 2009. Each quarter, CEPM charged us an amount for services provided to us. This amount was agreed to annually and included a portion of the compensation paid by CEPM and its affiliates to personnel who spent time on our business and affairs. The conflicts committee of our board of managers determined that the amounts paid by us for the services performed were fair to and in the best interests of the Company. The cost totaled approximately $1.4 million for the year ended December 31, 2009.

     We had a payable to Constellation of $0.2 million as of December 31, 2009. This payable balance is included in current liabilities in the accompanying balance sheets.

Natural Gas Purchases

     Through March 31, 2009, CCG purchased natural gas from us in the Cherokee Basin. The arrangement was reviewed by the conflicts committee of our board of managers. The committee found that the arrangement was fair to and in the best interests of the Company. For the twelve months ended December 31, 2009, CCG paid us $5.7 million for natural gas purchases.

Management Incentive Interests

     CEPM holds the management incentive interests in CEP. These management incentive interests represent the right to receive 15% of quarterly distributions of available cash from operating surplus after the Target Distribution (as defined in our limited liability company agreement) has been achieved and certain other tests have been met. For the twelve months ended December 31, 2010, none of these applicable tests have been met, and, as a result, CEPM was not entitled to receive any management incentive interest distributions. Through December 31, 2008, a cash reserve of $0.7 million had been established to fund future distributions on the management incentive interests. In February 2009, we reduced our distribution rate to $0.13 per unit. This decrease in the distribution rate terminated the initial management incentive interest vesting period. After the February 13, 2009 distribution was paid, the reserve was reduced to zero.

CoLa Acquisition

     As further described in Note 2, on March 31, 2008, we acquired 83 non-operated producing oil and natural gas wells in the Woodford Shale in the Arkoma Basin in Oklahoma from CoLa for approximately $50.1 million, including purchase price adjustments. CoLa is an affiliate of CEG, our former sponsor. The transaction was reviewed and approved by our conflicts committee. In its review, our conflicts committee considered various economic factors (including historical and estimated future production, estimated proved reserves, future pricing estimates and operating cost estimates) regarding the transaction, and determined that the transaction was fair to and in the best interests of the Company.

     At December 31, 2010 and 2009, we had a payable to CCG of less than $0.1 million and $0.4 million, respectively, for revenues and tax credits received for time periods when CCG owned the 83 well bores. These payable balances are included in current liabilities in the accompanying balance sheets.

8. COMMITMENTS AND CONTINGENCIES

     In the course of its normal business affairs, we are subject to possible loss contingencies arising from federal, state and local environmental, health and safety laws and regulations and third-party litigation. As of December 31, 2010 and December 31, 2009, other than the matters discussed below, there were no matters which, in the opinion of management, would have a material adverse effect on the financial position, results of operations or cash flows of CEP, and its subsidiaries, taken as a whole.

     Certain of our wells in the Robinson’s Bend Field are subject to a net profits interest (“NPI”) held by Torch Energy Royalty Trust (the “Trust”) (See Note 10). The royalty payment to the Trust is calculated using a sharing arrangement with a pricing formula that has had the effect of keeping our payments to the Trust lower than if such payments had been calculated based on prevailing market prices. We are uncertain of the financial impact of the NPI over the life of the Robinson’s Bend Field as it has volumetric and price risk variables. However, in order to address a portion of the risk of the potential adverse impact on our operating results from a termination of the sharing arrangement, Constellation Holdings, Inc. (“CHI”) contributed $8.0 million to us in exchange for all of our Class D interests at the closing of its initial public offering in November 2006 for the purpose of partially protecting the distributions to the common unit holders in the event the sharing arrangement is terminated. This contribution will be returned to CHI in 24 special quarterly distributions as long as the sharing agreement remains in effect for the distribution period. As discussed in Note 10 and Note 17, the Class D interest special quarterly distributions have been suspended for all quarters commencing on or after January 1, 2008. This suspension includes approximately $3.6 million which represents the distributions that were suspended for the quarterly periods ended September 30, June 30, and March 31, 2010, and December 31, September 30, June 30, and March, 31, 2009, and December 31, September 30, June 30, and March 31, 2008. Including the suspended distributions, the remaining undistributed amount of the Class D interests is $6.7 million. See Note 17 for additional information.

9. ASSET RETIREMENT OBLIGATION

     We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our natural gas properties equipment and facilities. Subsequently, the ARC is depreciated using a systematic and rational method over the asset’s useful life. The ARO’s recorded by us relate to the plugging and abandonment of natural gas wells, and decommissioning of the gas gathering and processing facilities.

     Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance.

     The following table is a reconciliation of the ARO:

		December 31,				December 31,
		2010				2009
		(In 000’s)
Asset retirement obligation, beginning balance		$	12,129			$	6,754
Liabilities incurred from acquisition of the properties (Note 2)			32				—
Liabilities incurred			83				3,873
Liabilities settled			(42	)			(12	)
Revisions to prior estimates			—				1,108
Accretion expense			822				406
Asset retirement obligation, ending balance		$	13,024			$	12,129

     Additional retirement obligations increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligation. In 2010 and 2009, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations.

10. NET PROFITS INTEREST

     Certain of our wells in the Robinson’s Bend Field are subject to a non-operating NPI. The holder of the NPI, the Trust, does not have the right to receive production from the applicable wells in the Robinson’s Bend Field. Instead, the Trust only has the right to receive a specified portion of the future natural gas sales revenues from specified wells as defined by the Net Overriding Royalty Conveyance Agreement. We record the NPI as an overriding royalty interest net in revenue in the Consolidated Statements of Operations.

     Amounts due to the Trust with respect to NPI are comprised of the sum of the Net Proceeds and the Infill Net Proceeds, which are described below.

     The Net Proceeds equal the lesser of (i) 95% of the net proceeds from 393 producing wells in the Robinson’s Bend Field and (ii) the net proceeds from the sale of 912.5 MMcf of natural gas for the quarter. Net proceeds equal gross proceeds, currently calculated by reference to the gas purchase contract, less specified costs attributable to the Robinson’s Bend Assets. The specified costs deducted for purposes of calculating net proceeds for purposes of clause (i) of the first sentence of this paragraph (the NPI Net Proceeds Calculation) include: (a) delay rentals, shut-in royalties and similar payments, (b) property, production, severance and similar taxes and related audit charges, (c) specified refunds, interest or penalties paid to purchasers of hydrocarbons or governmental agencies, (d) certain liabilities for environmental damage, personal injury and property damage, (e) certain litigation costs, (f) costs of environmental compliance, (g) specified operating costs incurred to produce hydrocarbons, (h) specified development costs (including costs to increase recoverable reserves or the timing of recovery of such reserves), (i) costs of specified lease renewals and extensions and unitization costs and (j) the unrecovered portion, if any, of the foregoing costs for preceding time periods plus interest on such unrecovered portion at a rate equal to the base rate (compounded quarterly) as announced from time to time by Citibank, N.A. The specified costs deducted for purposes of calculating net proceeds for purposes of clause (ii) of the first sentence of this paragraph include: (a) property, production, severance and similar taxes, (b) specified refunds, interest or penalties paid to purchasers of hydrocarbons or governmental agencies and (c) the unrecovered portion, if any, of the foregoing costs for preceding time periods plus interest on such unrecovered portion at a rate equal to the base rate (compounded quarterly) as announced from time to time by Citibank, N.A. Net proceeds are calculated quarterly and any negative balance (expenses in excess of revenues) within the “net proceeds” calculation accumulates and is charged interest as described above.

     The cumulative “Net NPI Proceeds” balance must be greater than $0 before any payments are made to the Trust. The cumulative Net Proceeds was a deficit for the twelve months ended December 31, 2010 and 2009. As a result, no payments were made to the Trust with respect to the NPI for the twelve months ended December 31, 2010 and 2009. The calculation of the Infill Net Proceeds uses the same methodology as the NPI Net Proceeds Calculation described above except that the proceeds and costs are attributable not to the NPI Net Proceeds Wells, but to the remaining wells in the Robinson’s Bend Field that are subject to the NPI and that have been drilled since the Trust was formed and wells that will be drilled (other than wells drilled to replace damaged or destroyed wells), in each case on leases subject to the NPI. The NPI in the Infill Wells entitles the Trust to receive 20% of the Infill Net Proceeds. There has never been a payout on the Infill Net Proceeds.

     The Gas Purchase Contract

     A gas purchase contract was executed in connection with the formation of the Trust in 1993, which established a minimum price for the purchase of the gas from the Trust Wells, as well as, a sharing arrangement when the applicable index price for gas increased over a specified sharing price. Torch Energy Marketing, Inc., an affiliate of the original sponsor of the Trust (“TEMI”) as buyer, and another affiliate of TEMI, as seller, entered into the gas purchase contract pursuant to which the parties were obligated to purchase and sell, as the case may be, all net production attributable to the properties subject to the NPI, including the Trust Wells, for an amount equal to the greater of (a) the minimum price of $1.70 per MMBtu, adjusted for inflation, and (b) 97% of a specified index price for natural gas, less certain specified permitted deductions for gathering, treating and transportation that are calculated monthly. The index price for Black Warrior Basin production equals the SONAT Inside FERC price. In addition, if 97% of the index price exceeds the sharing price specified in the gas purchase contract as adjusted for inflation, which we refer to as the sharing price, the purchase price for the gas is equal to the sharing price plus 50% of the difference between 97% of the index price and the sharing price. As a result, the purchaser is entitled to retain 50% of that difference between 97% of the index price and sharing price. The sharing price was $2.43, $2.40, $2.30, $2.26, $2.22, and $2.18 per MMBtu in 2010, 2009, 2008, 2007, 2006, and 2005, respectively. Despite increases in spot prices for natural gas in certain years, the sharing arrangement under the gas purchase contract has had the effect of keeping the payments to the Trust significantly lower than if the NPI were calculated using the prevailing market price for production from the Trust Wells.

     In connection with the acquisition of our initial properties in the Black Warrior Basin from Everlast, our subsidiary, Robinson’s Bend Marketing II, LLC (now merged into our subsidiary Robinson’s Bend Operating II, LLC), assumed TEMI’s obligations under the gas purchase contract and our subsidiary, Robinson’s Bend Production II, LLC (“RBP”), assumed the TEMI affiliate’s obligations under the gas purchase contract, in each case in respect of the Black Warrior Basin for production from and after June 13, 2005. As a result, we were obligated to sell and to purchase all production from the Trust Wells on the terms and conditions set forth in the gas purchase contract until termination of the gas purchase contract on January 29, 2008.

     Termination of the Trust and Gas Purchase Contract

     On January 29, 2008, the unitholders of the Trust voted to terminate the Trust and the trust agreement and authorized the Trustee to wind up, liquidate and distribute the assets held by the Trust under the terms of the trust agreement. The gas purchase contract, by its terms, was also terminated on January 29, 2008 as a result of the termination of the Trust. With the gas purchase contract terminated, we are no longer obligated to sell gas produced from our interest in the Black Warrior Basin pursuant to the gas purchase contract. Notwithstanding the termination of the gas purchase contract, the NPI will continue to burden the Trust Wells, and it should continue to be calculated as if the gas purchase contract were still in effect, regardless of what proceeds may actually be received by us as the seller of the gas. As a result of the termination of the Trust, certain water gathering, separation and disposal costs, which are a component of the NPI calculation, increased from $0.53 per barrel to $1.00 per barrel pursuant to the Water Gathering and Disposal Agreement dated August 9, 1990, as amended; the amounts of the water gathering, separation and disposal costs are set forth in such agreement.

     Litigation Related to Trust Termination

     On January 25, 2008, Torch Royalty Company, Torch E&P Company, and CEP (collectively, the “Claimants”) commenced an arbitration proceeding before Judicial Arbitration and Mediation Services against Wilmington Trust Company, as Trustee (“Trustee”) for the Trust, and to Capital One, NA, as successor to Hibernia National Bank, as trustee for Torch Energy Louisiana Royalty Trust, pursuant to the operative dispute resolution provisions of the agreement governing the Trust, the NPI and the Conveyances (as defined below). The Claimants

were working interest owners in certain oil and gas fields located in Texas, Louisiana and Alabama. The working interests owned by the other Claimants were similarly subject to net profit interests (the “Other NPIs”) that were also based on the gas purchase contract. The Claimants sought a declaratory judgment that the NPI payments as well as the payments owed in respect of the Other NPIs will continue to be calculated using the sharing arrangement under the gas purchase contract even though the Trust and the gas purchase contract were terminated. The Trustee took the position that the sharing arrangement under the gas purchase contract terminated upon the termination of the gas purchase contract. Trust Venture Company, LLC (“Trust Venture”) was permitted to intervene in the proceeding under an agreement whereby Trust Venture and its affiliates agreed to be bound by the formal award in the proceeding. On July 18, 2008, the arbitration panel issued its final award which, among other things, found and concluded that the sharing arrangement and other pricing terms of the gas purchase contract will continue to control the amount owed to the holder of the NPI, and on December 10, 2008, the District Court of Harris County, Texas, 152nd Judicial District, dismissed the appeal of the final award filed by the Trustee and Trust Venture and confirmed the final award.

     On January 8, 2009, we were served by Trust Venture, on behalf of the Trust, with a purported derivative action filed in Alabama state court demanding an audited statement of revenues and expenses associated with the NPI, alleging a breach of contract under the conveyance associated with the NPI and the agreement establishing the Trust and asserting that above market rates for services were paid, reducing the amounts paid to the Trust in connection with the NPI. The lawsuit seeks unspecified damages and an accounting of the NPI. The Alabama court has made the Trust a nominal party to the Alabama litigation. On August 18, 2009, Trust Venture filed an application for preliminary injunction requesting that the Alabama court enter an injunction requiring the Company to deposit into an escrow account all fees, less expenses, that it receives from water disposal under the Water Gathering and Disposal Agreement pending judgment in the lawsuit and asserting damages of approximately $11.6 million from June 2005 to May 2009. These alleged damages appear to be calculated based on a water gathering, separation and disposal fee of $0.05 per barrel notwithstanding the provisions of the Water Gathering and Disposal Agreement. After hearing, the Alabama court denied Trust Venture’s application. On February 9, 2010, Trust Venture filed a motion for partial summary judgment seeking a determination regarding the applicability of a provision in the Conveyance related to the calculation of water handling charges, which motion the court denied on May 28, 2010, with the court ruling that our position with respect to the Conveyance provision was correct.

     See Note 17 for additional information.

11. ENVIRONMENTAL LIABILITY

     We are subject to costs resulting from federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. As of December 31, 2010, we had no accrued environmental obligations. As of December 31, 2009, accrued environmental obligations were $0.2 million. This obligation was classified as a current liability on our Consolidated Balance Sheet.

12. UNIT-BASED COMPENSATION

     We recognized approximately $1.8 million and $1.3 million of expense related to our unit-based compensation plans in the twelve months ended December 31, 2010, and December 31, 2009, respectively. As of December 31, 2010, we had approximately $4.2 million in unrecognized compensation expense related to our unit-based compensation plans expected to be recognized through the first quarter of 2015.

2010 Grants

     Grants under the 2009 Omnibus Incentive Compensation Plan

     In March 2010, we granted approximately 498,000 restricted common unit awards to certain employees in Texas under the 2009 Omnibus Incentive Compensation Plan. These units had a total fair market value of approximately $1.7 million based on the closing price of our common units on NYSE Arca on March 1, 2010. All of these service-based restricted units will vest on a five year ratable schedule beginning on March 1, 2010.

     Grants under the Long-Term Incentive Program

     We granted approximately 195,852 restricted common unit awards under the Long-Term Incentive Plan on March 1, 2010, to certain field employees in Alabama, Kansas, and Oklahoma and to certain employees in Texas.

These units had a total fair market value of approximately $0.7 million based on the closing price of our common units on NYSE Arca on March 1, 2010. These service-based restricted units will vest on a three year ratable schedule beginning on March 1, 2010, except for certain employees in Texas which will vest on a five year ratable schedule beginning on March 1, 2010.

     We granted approximately 54,747 restricted common unit awards under the Long-Term Incentive Plan on March 1, 2010, to our three independent managers. These units had a total fair market value of approximately $0.2 million based on the closing price of our common units on NYSE Arca on March 1, 2010. These awards will vest in full in March 2011.

2009 Grants

     Grants under the 2009 Omnibus Incentive Compensation Plan

     We granted approximately 959,914 notional unit awards to certain employees in Texas and 80,937 notional unit awards to our three independent managers under the 2009 Omnibus Incentive Compensation Plan prior to the plan’s approval by our common unitholders. Upon the plan’s approval on December 1, 2009, these notional units were converted into restricted common units. These units had a total fair market value of approximately $3,518,076 based on the closing price of our common units on NYSE Arca on December 1, 2009. Additionally, in December 2009 we granted approximately 36,170 restricted common units to certain employees in Texas. These units had a total fair market value of approximately $127,327 based on the closing price of our common units on NYSE Arca on their grant dates. All of these service-based restricted units will vest on a five year ratable schedule beginning in 2010 expect those granted to our three independent managers which vested in full in March 2010.

     Prior to vesting, these restricted common units do not have the right to receive distributions paid by us on our common units. Instead, each such unvested restricted common unit carries the right to receive distribution credits when any distributions are made by us on our common units. Any distribution credits will accrue and be settled in cash or common units, in the discretion of the compensation committee, upon the vesting of the underlying restricted common unit. As of December 31, 2009, a total of 33,467 notional units have been issued as distribution credits.

     Until the notional units granted under 2009 Omnibus Incentive Compensation Plan were converted into restricted common units upon unitholder approval, the notional units were accounted for using the variable plan accounting method. Under the variable method, compensation costs were measured using the quoted market price of our common units on each measurement date and multiplying the compensation cost by the percentage of the vesting period served through the measurement date. Increases or decreases in the quoted market price of the common units between the date of the grant and each measurement date resulted in a change in the compensation expense recognized for the notional units.

     Grants under the Executive Inducement Bonus Program

     On May 1, 2009, we made grants of an aggregate of 161,871 restricted common units under the Executive Inducement Bonus Program to induce four executives to become employed by us, with an approximate aggregate grant-date value of $500,181 based on the closing price per unit on May 1, 2009. The units vested 50% on January 1, 2010, and 50% will vest on January 1, 2011.

     Prior to vesting, these restricted common units do not have the right to receive distributions paid by us on our common units. Instead, each such unvested restricted common unit carries the right to receive distribution credits when any distributions are made by us on our common units. Any distribution credits will accrue and be settled in cash or common units, in the discretion of the compensation committee, upon the vesting of the underlying restricted common unit. As of December 31, 2009, a total of 5,612 restricted units have been issued as distribution credits.

2009 Grants

     Grants under the Long-Term Incentive Program

     We granted approximately 163,340 restricted common unit awards under the Long-Term Incentive Plan on August 1, 2009, to certain field employees in Alabama, Kansas, and Oklahoma. These units had a total fair market value of approximately $529,222 based on the average of the high and low trading price of our common units on NYSE Arca on August 3, 2009. These service-based restricted units will vest on a three year ratable schedule beginning on August 1, 2010.

13. DISTRIBUTIONS TO UNITHOLDERS

     Distributions through December 31, 2010

     Beginning in June 2009, we have suspended our quarterly distributions to unitholders. For the quarter ended September 30, 2010, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions. See Note 17 for additional information.

     Distributions through December 31, 2009

     We suspended our quarterly distributions to unitholders for the quarters ended December 31, September 30, and June 30, 2009, to remain in compliance with the covenants associated with our reserve-based credit facility.

     On May 15, 2009, we paid a distribution for the first quarter of 2009 to the unitholders of record at May 8, 2009. The distribution was paid to holders of common units and Class A units at a rate of $0.13 per unit.

     On February 13, 2009, we paid a distribution for the fourth quarter of 2008 to the unitholders of record at February 6, 2009. The distribution was paid to holders of common units and Class A units at a rate of $0.13 per unit.

14. MEMBERS’ EQUITY

     2010 Equity

     At December 31, 2010, we had 487,750 Class A units and 23,899,758 Class B units outstanding, which included 309,225 unvested restricted common units issued under our Long-Term Incentive Plan, 83,745 unvested restricted common units issued under our Executive Inducement Bonus Program, and 1,248,803 unvested restricted common units under our 2009 Omnibus Incentive Compensation Plan. See Note 17 for additional information.

     At December 31, 2010, we had granted 376,845 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 67,620 have vested.

     At December 31, 2010, we had granted 146,551 common units of the 300,000 common units available under our Executive Inducement Bonus Program. Of these grants, 62,807 have vested.

     At December 31, 2010, we had granted 1,477,598 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 228,795 have vested.

     For the twelve months ended December 31, 2010, 92,353 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.4 million, have been returned to their respective plan and are available for future grants.

     2009 Equity

     At December 31, 2009, we had 476,950 Class A units and 23,376,136 Class B units outstanding, which included 177,674 unvested restricted common units issued under our Long-Term Incentive Plan, 167,484 unvested restricted common units issued under our Executive Inducement Bonus Program, and 1,110,488 unvested restricted common units under our 2009 Omnibus Incentive Compensation Plan.

     At December 31, 2009, we had granted 199,401 common units of the 450,000 common units available under our Long-term Incentive Plan. Of these grants, 21,727 have vested.

     At December 31, 2009, we had granted 167,484 common units of the 300,000 common units available under our Executive Inducement Bonus Program. Of these grants, none have vested.

     At December 31, 2009, we had granted 1,110,488 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, none have vested.

15.

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)

     The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance. The supplemental information includes capitalized costs related to oil and natural

gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities.

     Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves.

     Costs

     The following table sets forth capitalized costs for the years ended December 31, 2010 and 2009:

		December 31,				December 31,
		2010				2009
		(In 000’s)
Capitalized costs at the end of the period:(a)
Oil and natural gas properties and related equipment (successful efforts method)
Property (acreage) costs
Proved property		$	772,450			$	756,461
Unproved property			698				37,147
Total property costs			773,148				793,608
Materials and supplies			2,073				4,312
Land			912				912
Total			776,133				798,832
Less: Accumulated depreciation, depletion, amortization and impairments			(499,214	)			(186,207	)
Net capitalized cost		$	276,919			$	612,625

     The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2010 and 2009:

		For the year				For the year
		ended				ended
		December 31,				December 31,
		2010				2009
		(In 000’s)
Costs incurred for the period:
Acquisition of properties
Proved		$	5,691			$	170
Unproved			678				121
Development costs			7,973				22,913
Total costs incurred		$	14,342			$	23,204

     The development costs for the years ended December 31, 2010 and 2009, primarily represent costs to develop our proved undeveloped reserves. During 2010, substantially all of our development expenditures were for locations in the Cherokee Basin that were not included as proved undeveloped reserves in our 2009 SEC reserve report because they were uneconomic at the SEC-required price. We estimate that we will spend $7.2 million, $20.5 million, and $18.5 million to develop our proved undeveloped reserves in 2011, 2012, and 2013, respectively.

     Our exploration and dry hole costs were $0.8 million and $0.9 million in 2010 and 2009, respectively.

Results of Operations

     The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our operations are oil and natural gas producing activities located in the United States.

Net Proved Oil and Natural Gas Reserves

     The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States.

		For the year				For the year
		ended				ended
		December 31,				December 31,
		2010				2009
		(In MMcfe)
Beginning Balance			131,180				232,414
Extensions and discoveries			226				1,103
Purchases of reserves in place			805				—
Sales of reserves in place			—				—
Revisions of previous estimates			49,027				(85,276	)
Production			(12,231	)			(17,061	)
Ending Balance			169,007				131,180
Total proved developed reserves			127,627				112,059

Reserves and Related Estimates

     Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our 2010 and 2009 reserve estimates were prepared in accordance with the new FASB and SEC rules for oil and gas reporting effective at December 31, 2009 using the SEC-required price.

     Our 2010 and 2009 proved reserve estimates were 169.0 Bcfe and 131.2 Bcfe. For these years, NSAI, an independent petroleum engineering firm, prepared an estimate of our proved reserves. These estimates of our 2010 and 2009 proved reserves were used to prepare our financial statements.

     Our 2010 estimates of proved reserves increased 37.8 Bcfe from 2009 primarily due to reserve revisions due to a higher SEC-required price for natural gas. Our reserves are 98% natural gas and are sensitive to higher prices for natural gas and basis differentials in the Mid-Continent region. Although we utilize swaps and basis swaps to mitigate commodity price risk and basis differentials, these derivatives are not used when preparing our reserve report based on SEC rules. The natural gas price used to prepare our reserve report was $4.55 in the Black Warrior Basin and $3.98 in the Cherokee Basin. The SEC-required price in the Cherokee Basin increased $0.88 from 2009 to 2010 which now makes 30.2 Bcfe of our proved undeveloped locations economic in the Cherokee Basin. These locations had previously been classified as probable reserves. We also removed approximately 8.0 Bcfe in proven undeveloped locations in the Black Warrior Basin because of approximately $3.0 million in lower capital being deployed in the last four years of our five year plan. As in 2009, any of our locations that are scheduled to be drilled after 5 years are classified as probable or possible reserves to the extent they are economic. The remainder of the change in our reserves from 2009 to 2010 was 0.8 Bcfe in proved producing reserves acquired in Kansas and Nebraska, additional price-related revisions to our proved producing and proved non-producing of 26.8 Bcfe which were offset by production from wells included in our 2009 reserve report of 12.2 Bcfe. Due to the low SEC-required prices used to prepare our reserve reports, certain of our wells that actually produced natural gas in 2010 were not included in our 2009 reserve report as they were deemed uneconomic at the SEC-required price which excludes the impact of our swaps and basis swaps used to mitigate commodity price risk and basis differentials. Our actual 2010 production of 15.0 Bcfe is 3.0 Bcfe higher than what our 2009 reserve report estimated for 2010. No reserves were attributed to the Torch NPI in 2010.

     Our 2009 estimates of proved reserves decreased 101.2 Bcfe from 2008 primarily due to reserve revisions due to a significantly lower SEC-required price for natural gas. Our reserves are 99% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. The natural gas price used to prepare our reserve report was $3.92 for NYMEX and $3.11 in the Cherokee Basin. Although we utilize swaps and basis swaps to mitigate commodity price risk and basis differentials, these derivatives are not used when preparing our reserve report based on SEC rules. This low SEC-required price makes all of our proved undeveloped locations uneconomic in the Cherokee Basin. These locations are now classified as probable reserves. We also removed approximately 23.9 Bcfe in proven undeveloped locations in the Black Warrior Basin because of the new SEC requirement to only record locations that are scheduled to be drilled within the next 5 years. Any of our locations that are scheduled to be drilled after 5 years are classified as probable or possible reserves to the extent they are economic. These declines were partially offset by additional proved undeveloped reserve additions in the Black Warrior Basin because of a state ruling allowing 40-acre spacing throughout the Robinson’s Bend Field. No reserves were attributed to the Torch NPI in 2009.

     The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.

     Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas, relating to the proved reserves, to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because CEP 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 our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

     The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties:

		For the year				For the year
		ended				ended
		December 31,				December 31,
		2010				2009
		(In 000’s)
Future cash inflows		$	751,384			$	522,145
Future production costs			(404,350	)			(277,881	)
Future estimated development costs			(77,055	)			(33,055	)
Future net cash flows			269,979				211,209
10% annual discount for estimated timing of cash flows			(138,292	)			(114,009	)
Standardized measure of discounted estimated future net cash flows related to proved gas reserves		$	131,687			$	97,200

     The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows:

		For the year				For the year
		Ended				Ended
		December 31,				December 31,
		2010				2009
		(In 000’s)
Beginning of the period		$	97,200			$	228,914
Sales and transfers of natural gas, net of production costs			(22,017	)			(48,396	)
Net changes in prices and production costs related to future production			9,480				(98,905	)
Development costs incurred during the period			6,920				26,004
Changes in extensions and discoveries			424				1,022
Revisions of previous quantity estimates			45,556				(72,767	)
Purchase of reserves in place			4,773				—
Accretion discount			9,720				22,891
Other			(20,369	)			38,437
Standardized measure of discounted future net cash flows related to proved gas reserves		$	131,687			$	97,200

		2010 Quarters Ended
		March 31,				June 30,				September 30,				December 31,
		(In 000’s)
Total revenue		$	64,518			$	22,529			$	47,743			$	15,983
Operating expenses			37,307				35,924				305,980				15,793
General and administrative expenses			5,062				4,188				5,027				6,074
Net income (loss)		$	18,058			$	(21,092	)		$	(267,123	)		$	(6,753	)
Earnings per unit—Basic		$	0.75			$	(0.87	)		$	(10.91	)		$	(0.28	)
Earnings per unit—Diluted		$	0.75			$	(0.87	)		$	(10.91	)		$	(0.28	)

		2009 Quarters Ended
		March 31,				June 30,				September 30,				December 31,
		(In 000’s)
Total revenue		$	52,193			$	18,564			$	24,295			$	47,484
Operating expenses			25,140				27,709				25,034				38,135
General and administrative expenses			5,233				4,208				4,568				4,497
Net income (loss)		$	18,933			$	(16,744	)		$	(9,101	)		$	(2,111	)
Earnings per unit—Basic		$	0.85			$	(0.74	)		$	(0.40	)		$	(0.11	)
Earnings per unit—Diluted		$	0.85			$	(0.74	)		$	(0.40	)		$	(0.11	)

     The following subsequent events have occurred between January 1, 2011, and February 25, 2011:

Members’ Equity

     2010 Equity

     At February 25, 2011, we had 486,435 Class A units and 23,835,303 Class B units outstanding, which included 309,225 unvested restricted common units issued under our Long-Term Incentive Plan and 1,074,717 unvested restricted common units under our 2009 Omnibus Incentive Compensation Plan.

     At February 25, 2011, we had granted 376,845 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 67,620 have vested.

     At February 25, 2011, 125,615 common units have vested out of the 300,000 common units available under our Executive Inducement Bonus Program. This program has now terminated and the remaining 174,385 have been cancelled.

     At February 25, 2011, we had granted 1,434,080 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 359,363 have vested.

     During 2011, 64,862 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants.

Distribution

     Our board of managers has suspended the quarterly distribution to our unitholders for the quarter ended December 31, 2010, which continues the temporary suspension we first announced in June 2009.

Litigation Related to Trust Termination

     As previously disclosed, on January 8, 2009, we were served by Trust Venture, on behalf of the Trust, with a purported derivative action filed in the Circuit Court of Tuscaloosa County, Alabama (the “Court”). The lawsuit relates to the non-operating net profits interest (“NPI”) held by the Trust on certain wells owned by Robinson’s Bend Production II, LLC (“RBP II”), a subsidiary of the company, in the Robinson’s Bend Field in Alabama, and alleges, among other things, a breach of contract under the conveyance associated with the NPI and the agreement establishing the Trust and asserting that above market rates for services were paid, reducing the amounts paid to the Trust in connection with the NPI. The lawsuit seeks unspecified damages and an accounting of the NPI. The Alabama court has made the Trust a nominal party to the lawsuit. At a preliminary hearing on February 17, 2011, the Court approved a form of notice of a settlement among the parties to be sent by the Trust to its unitholders. A final hearing on the settlement is set for April 11, 2011. No assurance can be made that the Court will approve settlement or that the Trust will sell the NPI to RBP II. The settlement with Trust Venture, its successor and the Trust provides, among other things:

•

RBP II will make a payment of $1.2 million to reimburse Trust Venture and its successor for their legal fees and expenses incurred in prosecuting the lawsuit;

•

RBP II will make an irrevocable offer to purchase the NPI relating to the Robinson’s Bend Field from the Trust for at least $1 million, when it is separately offered for sale by the Trust at public auction within 180 days of the effective date of the settlement, with such bid amount to be deposited by RBP II in a third-party escrow account pending the public auction. RBP II, as well as any other bidders at the auction, shall have a right to submit a higher topping bid;

•

The parties agree that the cumulative deficit balance in the NPI account is approximately $5.8 million as of September 30, 2010, and that no further payments will be due to the Trust with respect to the NPI unless and until the cumulative deficit balance is reduced to zero;

•

Trust Venture and its successor agree, on behalf of the Trust, that all prior and current calculations, charges and deductions contained in such cumulative deficit NPI balance are in compliance with the terms of the Conveyance and, to the extent applicable thereunder, do not exceed competitive contract charges prevailing in the area for any such operations and services;

•

The Water Gathering and Disposal Agreement between RBP II and another subsidiary of the Company will be amended to reduce the fee from $1.00 per barrel to $0.53 per barrel beginning on the first day of the month following the effective date of the settlement and to extend the term for an additional ten years, and Trust Venture and its successor agree, on behalf of the Trust, that the fees under such agreement do not exceed competitive contract charges prevailing in the area for the operations and services provided under such agreement during the extended term of such agreement;

•

A mutual release among the parties and a dismissal with prejudice of the lawsuit; and

•

An effective date of the settlement upon final approval by the Court.

Class D Interests

     We have suspended all quarterly cash contributions with respect to our Class D interests. This suspension, approved by our board of managers, includes the $0.3 million quarterly cash distribution for the three months ended December 31, 2010 and $3.6 million which represents the distributions that were suspended for the quarterly periods ended September 30, June 30, and March, 31, 2010, and December 31, September 30, June 30, and March, 31, 2009,

and December 31, September 30, June 30, and March 31, 2008. The remaining undistributed amount of the Class D interests is $6.7 million.

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

FINANCIAL STATEMENTS

FOR THE QUARTERS AND PERIODS ENDED JUNE 30, 2011 and 2010

INDEX TO PART II			Page
Constellation Energy Partners LLC and Subsidiaries:
Consolidated Statements of Operations and Comprehensive Income (Loss)			37
Consolidated Balance Sheets			38
Consolidated Statements of Cash Flows			39
Consolidated Statements of Changes in Members’ Equity			40
Notes to Consolidated Financial Statements			41

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(In 000’s except unit data)
Revenues
Natural gas, oil and liquids sales		$	68,080			$	27,078			$	93,993			$	56,315
Gain / (Loss) from mark-to-market activities (see Note 4)			(43,656	)			(4,549	)			(53,765	)			30,732
Total revenues			24,424				22,529				40,228				87,047
Expenses:
Operating expenses:
Lease operating expenses			6,602				7,729				14,022				15,692
Cost of sales			542				585				1,061				1,357
Production taxes			660				677				1,431				1,802
General and administrative			4,012				4,188				8,235				9,250
Exploration costs			—				224				131				447
(Gain) / Loss on sale of assets			14				(5	)			21				(13	)
Depreciation, depletion, and amortization			5,893				26,733				11,758				53,981
Accretion expense			226				205				452				412
Total operating expenses			17,949				40,336				37,111				82,928
Other expenses (income)
Interest expense			2,691				3,275				5,214				6,814
Interest expense-(Gain)/Loss from mark-to-market activities (see Note 4)			505				113				(165	)			630
Interest (income)			—				(1	)			(1	)			(1	)
Other expense (income)			(68	)			(102	)			(126	)			(290	)
Total other expenses / (income)			3,128				3,285				4,922				7,153
Total expenses			21,077				43,621				42,033				90,081
Net income (loss)		$	3,347			$	(21,092	)		$	(1,805	)		$	(3,034	)
Other comprehensive income (loss)			(1,885	)			(4,264	)			(2,585	)			(9,550	)
Comprehensive income (loss)		$	1,462			$	(25,356	)		$	(4,390	)		$	(12,584	)
Earnings (loss) per unit (see Note 2)
Earnings (loss) per unit—Basic		$	0.14			$	(0.87	)		$	(0.07	)		$	(0.12	)
Units outstanding—Basic			24,273,244				24,538,151				24,291,246				24,271,742
Earnings (loss) per unit—Diluted		$	0.14			$	(0.87	)		$	(0.07	)		$	(0.12	)
Units outstanding—Diluted			24,273,244				24,538,151				24,291,246				24,271,742
Distributions declared and paid per unit		$	0.00			$	0.00			$	0.00			$	0.00