Encore Energy Partners 8-K Encore Energy Partners LP

Exhibit 99.4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Encore Energy Partners GP LLC:

We have audited the accompanying consolidated balance sheets of Encore Energy Partners GP LLC (the “Company”) as of December 31, 2008 and 2007. These balance sheets are the responsibility of the Company’s management. Our responsibility is to express an opinion on these balance sheets based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated balance sheets referred to above present fairly, in all material respects, the consolidated financial position of Encore Energy Partners GP LLC at December 31, 2008 and 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated balance sheets, effective January 1, 2007, the Company adopted Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.”

/s/ Ernst & Young LLP

Fort Worth, Texas
May 7, 2009

ENCORE ENERGY PARTNERS GP LLC
CONSOLIDATED BALANCE SHEETS
(in thousands)

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	619		$	3
Accounts receivable:
Trade		15,671			23,845
Affiliate		856			3,290
Derivatives		75,131			3,713
Other		1,022			543
Total current assets		93,299			31,394
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		542,938			519,654
Unproved properties		67			298
Accumulated depletion, depreciation, and amortization		(107,616	)		(68,773	)
		435,389			451,179
Other property and equipment		802			510
Accumulated depreciation		(240	)		(68	)
		562			442
Goodwill		4,500			4,500
Other intangibles, net		3,662			3,969
Derivatives		38,497			21,875
Other		1,457			2,263
Total assets	$	577,366		$	515,622
LIABILITIES AND OWNER’S NET EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,036		$	1,915
Affiliate		2,174			6,682
Accrued liabilities:
Lease operations expense		2,941			2,928
Development capital		856			3,387
Interest		126			147
Production, ad valorem, and severance taxes		10,336			6,358
Marketing		36			1,578
Derivatives		1,297			865
Oil and natural gas revenues payable		1,287			618
Other		1,470			2,280
Total current liabilities		21,559			26,758
Derivatives		3,491			20,447
Future abandonment cost, net of current portion		9,076			8,376
Long-term debt		150,000			47,500
Other		614			219
Total liabilities		184,740			103,300
Commitments and contingencies (see Note 4)
Owner’s net equity:
Owner’s net equity		226,197			289,788
Noncontrolling interest		169,120			122,534
Accumulated other comprehensive loss		(2,691	)		—
Total owner’s net equity		392,626			412,322
Total liabilities and owner’s net equity	$	577,366		$	515,622

The accompanying notes are an integral part of these consolidated balance sheets.

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ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEETS

Note 1. Formation of the Company and Description of Business

     Encore Energy Partners GP LLC, a Delaware limited liability company (the “Company”), was formed in February 2007 to serve as the general partner of Encore Energy Partners LP, a Delaware limited partnership (together with its subsidiaries, “ENP”). The Company is a wholly owned subsidiary of Encore Partners GP Holdings LLC, a Delaware limited liability company (“GP Holdings”). GP Holdings is a direct wholly owned subsidiary of Encore Acquisition Company, a publicly traded Delaware corporation (together with its subsidiaries, “EAC”). As of December 31, 2008 and 2007, EAC also owned approximately 63 percent and 58 percent, respectively, of ENP’s outstanding common units.

     The Company is deemed to control ENP because, under Delaware laws and the partnership agreement, the Company has the power to direct or cause the direction of the management and policies of ENP. As a result of this substantive control, ENP is fully consolidated and therefore, the consolidated balance sheets include all assets and liabilities of ENP and its subsidiaries. The Company does not own an interest in any other entity or have any operations independent from the operations of ENP.

     ENP was formed in February 2007 by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Also in February 2007, Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and direct wholly owned subsidiary of ENP, was formed to own and operate ENP’s properties. ENP’s properties — and oil and natural gas reserves — are located in four core areas:

• the Big Horn Basin in Wyoming and Montana, primarily in the Elk Basin field (the “Elk Basin Assets”);

• the Permian Basin in West Texas;

• the Williston Basin in North Dakota; and

• the Arkoma Basin in Arkansas.

Initial Public Offering and Concurrent Transactions

     In September 2007, ENP completed its initial public offering (“IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. In October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. The net proceeds of approximately $193.5 million, after deducting the underwriters’ discount and a structuring fee of approximately $14.9 million, in the aggregate, and offering expenses of approximately $4.7 million, were used to repay in full $126.4 million of outstanding indebtedness under a subordinated credit agreement with EAP Operating, LLC, and reduce outstanding borrowings under ENP’s revolving credit facility. Please read “Note 7. Long-Term Debt” for additional discussion of ENP’s long-term debt.

     At the closing of the IPO, the following transactions were completed:

(a) ENP entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) with the Company, OLLC, EAC, Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC, and Encore Partners LP Holdings LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC. The following transactions, among others, occurred pursuant to the Contribution Agreement:

• Encore Operating contributed certain oil and natural gas properties and related assets in the Permian Basin in West Texas (the “Permian Basin Assets”) to ENP in exchange for 4,043,478 common units; and

• EAC agreed to indemnify ENP for certain environmental liabilities, tax liabilities, and title defects, as well as defects relating to retained assets and liabilities, occurring or existing before the closing.

These transfers and distributions were made in a series of steps outlined in the Contribution Agreement. In connection with the issuance of the common units by ENP in exchange for the Permian Basin Assets, the IPO, and the exercise of the underwriters’ option to purchase additional common units, the Company exchanged a certain number of common units for general partner units to enable it to maintain its then two percent general partner interest. The Company received the common units through capital contributions from EAC and its subsidiaries of common units they owned.

(b) ENP entered into an administrative services agreement (the “Administrative Services Agreement”) with the Company, OLLC, Encore Operating, and EAC pursuant to which Encore Operating performs administrative services for ENP. Please read “Note 12. Related Party Transactions” for additional discussion regarding the Administrative Services Agreement.

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

(c) The Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”) was adopted by the Company’s board of directors. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion regarding the LTIP.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

     In accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5,“Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,”the Company is deemed to control ENP. Under Delaware law and the partnership agreement, the General Partner has the power to direct or cause the direction of the management and the policies of ENP. As a result of this substantive control, ENP is fully consolidated by the General Partner. The public unitholders’ interest is reflected as “Noncontrolling interest” in the accompany Consolidated Balance Sheets. During 2008 and 2007, the Company reclassified $3.5 million and $77.6 million, respectively, from “Noncontrolling interest” to “Owner’s net equity” on the accompanying Consolidated Balance Sheets to recognize the gain on sale of ENP’s common units. All material intercompany balances and transactions have been eliminated in consolidation.

     In February 2008, ENP completed the acquisition of certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating. In January 2009, ENP completed the acquisition of certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”) from Encore Operating. Please read “Note 3. Acquisitions” for additional discussion of these acquisitions.

     Because the Permian and Williston Basin Assets and the Arkoma Basin Assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating’s historical cost and the Company’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the accompanying Consolidated Balance Sheets and notes thereto reflect the combined financial position of the Company, the Permian Basin Assets, the Permian and Williston Basin Assets, and the Arkoma Basin Assets for all periods presented.

     ENP, the Permian Basin Assets, the Permian and Williston Basin Assets, and the Arkoma Basin Assets were wholly owned by EAC prior to the closing of the IPO, with the exception of management incentive units owned by certain executive officers of the Company.

Use of Estimates

     Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the Consolidated Balance Sheets. Actual results could differ materially from those estimates.

     Estimates made in preparing these Consolidated Balance Sheets include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on reported results in future periods.

Cash and Cash Equivalents

     Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities.

Accounts Receivable

     Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear

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interest. The Company routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2008 and 2007, the Company had no allowance for doubtful accounts.

Properties and Equipment

     Oil and Natural Gas Properties.The Company uses the successful efforts method of accounting for its oil and natural gas properties under Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”(“SFAS 19”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

     If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, the Company continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the costs are charged to expense.

     Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil.

     The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

     Miller and Lents, Ltd., independent reserve engineers, estimates ENP’s reserves annually on December 31. This results in a new DD&A rate which the Company uses for the preceding fourth quarter after adjusting for fourth quarter production. The Company internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.

     In accordance with SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets”(“SFAS 144”), the Company assesses the need for an impairment of capitalized costs of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. The Company uses prices consistent with the prices used in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment. Any impairment charge incurred is expensed and reduces the net basis in the asset. During 2008, events and circumstances indicated that a portion of the Company’s oil and natural gas properties might be impaired. However, the Company’s estimates of undiscounted cash flows based on management’s outlook of future commodity prices at the date of assessment indicated that the remaining carrying amounts of its oil and natural gas properties are expected to be recovered, although in some cases by only a marginal amount. If oil and natural gas prices continue to decline, it is reasonably possible that the Company’s estimates of undiscounted cash flows may change in the near term resulting in the need to record a write down of the Company’s oil and natural gas properties to fair value.

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ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

     Unproved properties, the majority of the costs of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss would be recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized would be determined by amortizing the portion of these properties’ costs which the Company believes will not be transferred to proved over the average life of the lease.

     Amounts shown in the accompanying Consolidated Balance Sheets as “Proved properties, including wells and related equipment” consisted of the following as of the dates indicated:

	December 31,
	2008		2007
	(in thousands)
Proved leasehold costs	$	391,191	$	385,180
Wells and related equipment — Completed		149,778		129,586
Wells and related equipment — In process		1,969		4,888
Total proved properties	$	542,938	$	519,654

     Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years. Gains or losses from the disposal of other property and equipment are recognized in the period realized.

Goodwill and Other Intangible Assets

     The Company accounts for intangible assets under the provisions of SFAS No. 142,“Goodwill and Other Intangible Assets.”Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill and other intangible assets with indefinite useful lives are tested for impairment annually on December 31 or whenever indicators of impairment exist. If impairment is determined to exist, an impairment charge would be recognized for the amount by which the carrying value of the asset exceeds its implied fair value. The goodwill test is performed at the reporting unit level. The Company has determined that it has only one reporting unit, which is oil and natural gas production in the United States. The Company performed its annual impairment test at December 31, 2008 and determined that no impairment existed.

     Intangible assets with definite useful lives are amortized over their estimated useful lives. In accordance with SFAS 144, the Company evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

     The Company is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2008, the gross carrying amount of this contract was approximately $4.2 million, accumulated amortization was approximately $0.6 million, and the net carrying amount was approximately $3.7 million. The net carrying amount is shown as “Other intangibles, net” on the accompanying Consolidated Balance Sheets and is being amortized on a straight-line basis through July 2019.

Asset Retirement Obligations

     In accordance with SFAS No. 143,“Accounting for Asset Retirement Obligations,”the Company recognizes the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of the Company’s oil and natural gas properties. The liability is recorded at its discounted fair value and then accreted each period until it is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. Please read “Note 5. Asset Retirement Obligations” for additional information.

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

Income Taxes

     The Company is not a taxable entity for federal and state income tax purposes. The Company is included in the consolidated return of its parent, EAC, and the tax on the Company’s income is borne by EAC.

     ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of ENP’s taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, ENP is subject to an entity-level tax, the Texas margin tax, at an effective rate of up to 0.7 percent on the portion of its income that is apportioned to Texas beginning with tax reports due on or after January 1, 2008. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective Texas margin tax bases.

     On January 1, 2007, ENP adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation No. 48,“Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109”(“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109,“Accounting for Income Taxes.”FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The adoption of FIN 48 did not impact the Company’s Consolidated Balance Sheets. The Company performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in its Consolidated Balance Sheets. On the date of adoption of FIN 48 and as of December 31, 2008 and 2007, all of the Company’s tax positions met the “more-likely-than-not” threshold prescribed by FIN 48.

Oil and Natural Gas Receivables

     To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - trade” in the accompanying Consolidated Balance Sheets. If the Company’s overproduced imbalance position (i.e., the Company has cumulatively been over-allocated production) is greater than the Company’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used.

     The Company’s net oil inventories in pipelines were immaterial at December 31, 2008 and 2007. Natural gas imbalances at December 31, 2008 were 38,010 million British thermal units over-delivered to the Company. Natural gas imbalances at December 31, 2007 were immaterial.

Derivatives

     The Company uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with its oil and natural gas production. These arrangements are structured to reduce the Company’s exposure to commodity price decreases, but they can also limit the benefit the Company might otherwise receive from commodity price increases. The Company’s risk management activity is generally accomplished through over-the-counter derivative contracts with large financial institutions. The Company also uses derivative instruments in the form of interest rate swaps, which hedge its risk related to interest rate fluctuation.

     The Company applies the provisions of SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”and its amendments (“SFAS 133”), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive loss until such time as the hedged item is recognized in earnings.

     In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Cash flow hedges are marked to market through accumulated other comprehensive loss each period.

     The Company has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings immediately.

     The Company has not elected to designate its current portfolio of commodity derivatives contracts as hedges and therefore, changes in fair value of those instruments are recognized in earnings.

New Accounting Pronouncements

SFAS No. 157, “Fair Value Measurements” (“SFAS 157”)

     In September 2006, the FASB issued SFAS 157, which: (1) standardizes the definition of fair value; (2) establishes a framework for measuring fair value in GAAP; and (3) expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value, but does not require any new fair value measurements. SFAS 157 was prospectively effective for financial assets and liabilities for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2,“Effective Date of FASB Statement No. 157”(“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Company elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including, but not limited to, its asset retirement obligations and indefinite lived assets. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on the Company’s Consolidated Balance Sheets. The adoption of SFAS 157 on January 1, 2009, as it relates to all instruments within the scope of FSP FAS 157-2, did not have a material impact on the Company’s financial condition. Please read “Note 11. Fair Value Measurements” for additional discussion.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” (“SFAS 159”)

     In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 also allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for fiscal years beginning after November 15, 2007. The Company did not elect the fair value option for eligible instruments and therefore, the adoption of SFAS 159 on January 1, 2008 did not impact the Company’s financial condition. The Company will assess the impact of electing the fair value option for eligible instruments acquired in the future. Electing the fair value option for such instruments could have a material impact on the Company’s future financial condition.

FSP on FASB Interpretation (“FIN”) 39-1, “Amendment of FASB Interpretation No. 39” (“FSP FIN 39-1”)

     In April 2007, the FASB issued FSP FIN 39-1, which amends FIN No. 39,“Offsetting of Amounts Related to Certain Contracts”(“FIN 39”), to permit a reporting entity that is party to a master netting arrangement to offset the fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement in accordance with FIN 39. FSP FIN 39-1 was effective for fiscal years beginning after November 15, 2007. The adoption of FSP FIN 39-1 on January 1, 2008 did not impact the Company’s financial condition.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141,“Business Combinations.”SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1”), which amends and clarifies SFAS 141R to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3)

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disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R and FSP FAS 141R-1 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008, with early application prohibited. Subsequent to December 31, 2008, the Company completed an acquisition for certain oil and natural gas producing properties and related assets form Encore Operating. The accounting for transactions between entities under common control is unchanged under SFAS 141R. However, the application of SFAS 141R and FSP FAS 141R-1 to future acquisitions could have an impact on the Company’s financial condition and the reporting of future acquisitions in the Consolidated Balance Sheets.

SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”)

     In December 2007, the FASB issued SFAS 160, which amends Accounting Research Bulletin No. 51, "Consolidated Financial Statements” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported for the amounts attributable to both the parent and the noncontrolling interest on the face of the consolidated statement of operations and gains on a subsidiaries’ issuance of equity to be accounted for as capital transactions. The adoption of SFAS 160 on January 1, 2009 did not have a material impact on the Company’s results of operations or financial condition.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”)

     In March 2008, the FASB issued SFAS 161, which amends SFAS 133, to require enhanced disclosures about: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 was effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding the Company’s derivative instruments; however, it did not impact the Company’s financial condition.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”)

     In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 was effective November 15, 2008. The adoption of SFAS 162 did not impact the Company’s financial condition.

Note 3. Acquisitions

Arkoma Basin Assets

     In December 2008, OLLC entered into a purchase and sale agreement with Encore Operating pursuant to which OLLC acquired the Arkoma Basin Assets. The transaction closed in January 2009. The purchase price was $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million), which OLLC financed through borrowings under its revolving credit facility.

     As discussed in “Note 2. Summary of Significant Accounting Policies,” the transaction was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s historical cost of approximately $18 million, and the historical financial information of ENP was recast to include the Arkoma Basin Assets for all periods presented. As the historical basis in the Arkoma Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price, as adjusted for post-closing adjustments, of the Arkoma Basin Assets was recorded when paid in January 2009 as a deemed distribution to the EAC affiliates based on their respective ownership percentages in ENP’s general and limited partner units.

Permian and Williston Basin Assets

     In December 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

acquired the Permian and Williston Basin Assets. The transaction closed in February 2008. The consideration for the acquisition consisted of approximately $125.3 million in cash, including post-closing adjustments, and 6,884,776 common units representing limited partner interests in ENP. In determining the total purchase price, the common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. OLLC funded the cash portion of the purchase price with borrowings under its revolving credit facility.

     As discussed in “Note 2. Summary of Significant Accounting Policies,” the transaction was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s historical cost of approximately $100 million, and the historical financial information of ENP was recast to include the Permian and Williston Basin Assets for all periods presented. As the historical basis in the Permian and Williston Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price, as adjusted for post-closing adjustments, of the Permian and Williston Basin Assets was recorded when paid in February 2008 as a deemed distribution to the EAC affiliates based on their respective ownership percentages in ENP’s general and limited partner units. No value was ascribed to the common units issued as consideration for the acquired properties as the cash consideration exceeded the historical carrying cost of the properties.

     In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin in West Texas in exchange for 283,700 common units representing limited partner interests in ENP, which were valued at approximately $5.8 million at the time of the acquisition.

Elk Basin Assets

     In January 2007, EAC entered into a purchase and sale agreement with a third party to acquire oil and natural gas properties and related assets in the Big Horn Basin in Wyoming and Montana, which included the Elk Basin Assets. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin Assets to OLLC. The closing of the acquisition occurred in March 2007. The total purchase price for the Elk Basin Assets was approximately $330.7 million, including transaction costs of approximately $1.1 million.

     ENP financed the acquisition of the Elk Basin assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC, and borrowings under OLLC’s revolving credit facility. Please read “Note 7. Long-Term Debt” for additional discussion of ENP’s long-term debt.

Note 4. Commitments and Contingencies

Litigation

     The Company is a party to ongoing legal proceedings in the ordinary course of business. Management does not believe the result of these proceedings will have a material adverse effect on the Company’s financial position.

Leases

     The Company leases equipment that have remaining non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2008 (in thousands):

2009	$	687
2010		687
2011		687
2012		515
2013		—
Thereafter		—
	$	2,576

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

Note 5. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s asset retirement obligations for the periods indicated:

	December 31,
	2008			2007
	(in thousands)
Future abandonment liability at January 1	$	8,766		$	1,814
Acquisition of properties		—			6,343
Wells drilled		38			124
Accretion of discount		427			379
Plugging and abandonment costs incurred		(62	)		(103	)
Revision of previous estimates		295			209
Future abandonment liability at December 31	$	9,464		$	8,766

     As of December 31, 2008, approximately $9.1 million of the Company’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.4 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.4 million of the future abandonment liability as of December 31, 2008 represents the estimated cost for decommissioning the Elk Basin natural gas processing plant. The Company expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.

Note 6. Other Current Liabilities

     Other current liabilities consisted of the following as of the dates indicated:

	December 31,
	2008		2007
	(in thousands)
Current portion of future abandonment liability	$	388	$	390
Income taxes payable		276		10
Deferred taxes		205		—
Other		601		1,880
Total	$	1,470	$	2,280

Note 7. Long-Term Debt

Revolving Credit Facility

     OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. On August 22, 2007, OLLC amended the OLLC Credit Agreement to revise certain financial covenants. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. At December 31, 2008, the borrowing base was $240 million.

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in OLLC’s proved oil and natural gas reserves and in the equity interests in OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the OLLC Credit Agreement are guaranteed by ENP and OLLC’s restricted subsidiaries. Obligations under the OLLC Credit Agreement are non-recourse to EAC and its restricted subsidiaries.

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     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. As of December 31, 2008, Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.000	%		0.000	%
Greater than or equal to .50 to 1 but less than .75 to 1		1.250	%		0.000	%
Greater than or equal to .75 to 1 but less than .90 to 1		1.500	%		0.250	%
Greater than or equal to .90 to 1		1.750	%		0.500	%

     The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate per year equal to the London Interbank Offered Rate (“LIBOR”), as published by Reuters or another source designated by Bank of America, N.A., for deposits in dollars for a similar interest period. The “base rate” is calculated as the higher of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5 percent.

     Any outstanding letters of credit reduce the availability under the OLLC Credit Agreement. Borrowings under the OLLC Credit Agreement may be repaid from time to time without penalty.

     The OLLC Credit Agreement contains covenants that include, among others:

• a prohibition against incurring debt, subject to permitted exceptions;

• a prohibition against purchasing or redeeming capital stock, or prepaying indebtedness, subject to permitted exceptions;

• a restriction on creating liens on the assets of ENP, OLLC and its restricted subsidiaries, subject to permitted exceptions;

• restrictions on merging and selling assets outside the ordinary course of business;

• restrictions on use of proceeds, investments, transactions with affiliates, or change of principal business;

• a provision limiting oil and natural gas hedging transactions (other than puts) to a volume not exceeding 75 percent of anticipated production from proved producing reserves;

• a requirement that ENP and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0;

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA (as defined in the OLLC Credit Agreement) to consolidated senior interest expense of not less than 2.5 to 1.0; and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA (as defined in the OLLC Credit Agreement) of not more than 3.5 to 1.0.

     The OLLC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable.

     OLLC incurs a commitment fee on the unused portion of the OLLC Credit Agreement determined based on the ratio of amounts outstanding under the OLLC Credit Agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the OLLC Credit Agreement as of December 31, 2008:

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .50 to 1		0.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		0.300	%
Greater than or equal to .75 to 1		0.375	%

     On December 31, 2008, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement. As of December 31, 2008, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

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Subordinated Credit Agreement

     In March 2007, OLLC entered into a six-year subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC, pursuant to which a single subordinated term loan was made to ENP in the aggregate amount of $120 million. The total outstanding balance of $126.4 million, including accrued interest, was repaid in September 2007 using a portion of the net proceeds from the IPO.

Long-Term Debt Maturities

     The following table illustrates the Company’s long-term debt maturities at December 31, 2008:

	Payments Due by Period
	Total		2009		2010		2011		2012		2013		Thereafter
	(in thousands)
Revolving credit facility	$	150,000	$	—	$	—	$	—	$	150,000	$	—	$	—

Note 8. Owner’s Net Equity and Distributions

Distributions

     ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in the partnership agreement) to its unitholders. Distributions are not cumulative. ENP distributes available cash to its unitholders and the Company in accordance with their ownership percentages.

     The following table illustrates information regarding ENP’s distributions of available cash for the periods indicated:

			Cash Distribution
	Date		Declared per					Total
	Declared		Common Unit			Date Paid		Distribution
								(in thousands)
2008
Quarter ended December 31		1/26/2009	$	0.5000			2/13/2009	$	16,813
Quarter ended September 30		11/7/2008	$	0.6600			11/14/2008		22,191
Quarter ended June 30		8/11/2008	$	0.6881			8/14/2008		23,119
Quarter ended March 31		5/9/2008	$	0.5755			5/15/2008		19,316
2007
Quarter ended December 31		2/6/2008	$	0.3875			2/14/2008		9,843
Quarter ended September 30		11/8/2007	$	0.0530	(a)		11/14/2007		1,346

(a) Based on an initial quarterly distribution of $0.35 per unit, prorated for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007.

Gain on Issuance of ENP Common Units

     During 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin in West Texas in exchange for 283,700 common units which were valued at $5.8 million at the time of the acquisition. As a result, the Company reclassified $3.5 million from “Noncontrolling interest” to “Owner’s net equity” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.

     In September 2007, ENP completed its IPO of 9,000,000 common units at a price to the public of $21.00 per unit, and in October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. As a result, the Company reclassified $77.6 million from “Noncontrolling interest” to “Owner’s net equity” on the accompanying Consolidated Balance Sheets to recognize gains on the issuance of ENP’s common units.

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Note 9. Unit-Based Compensation Plans

Management Incentive Units

     In May 2007, the board of directors of the Company issued 550,000 management incentive units to certain executive officers of the Company. A management incentive unit is a limited partner interest in ENP that entitles the holder to quarterly distributions to the extent paid to ENP’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in ENP’s distribution rate to common unitholders. On November 14, 2008 the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units. During the fourth quarter of 2008, all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. As of December 31, 2008, there have been no additional issuances of management incentive units.

Long-Term Incentive Plan

     In September 2007, the Company’s board of directors adopted the LTIP, which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, the Company, and any of their subsidiaries and affiliates who perform services for ENP and its subsidiaries and affiliates are eligible to be granted awards under the LTIP. The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. As of December 31, 2008, there were 1,100,000 common units available for issuance under the LTIP. The LTIP is administered by the board of directors of the Company or a committee thereof, referred to as the plan administrator. To satisfy common unit awards, ENP may issue new common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

     Phantom Units.From time to time, ENP issues phantom units to members of the Company’s board of directors pursuant to the LTIP. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units; therefore, these phantom units are classified as equity instruments. Phantom units vest over a four-year period. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding.

     The following table summarizes the changes in the number of ENP’s unvested phantom units and their related weighted average grant date fair value for 2008:

				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Outstanding at January 1, 2008		20,000		$	20.21
Granted		30,000			17.91
Vested		(6,250	)		19.93
Forfeited		—			—
Outstanding at December 31, 2008		43,750			18.67

     During 2008 and 2007, ENP issued 30,000 and 20,000, respectively, phantom units to members of the Company’s board of directors the vesting of which is dependent only on the passage of time and continuation as a board member. The following table illustrates outstanding phantom units at December 31, 2008:

	Year of Vesting
Year of Grant	2009		2010		2011		2012		Total
2007		5,000		5,000		5,000		—		15,000
2008		7,500		7,500		7,500		6,250		28,750
Total		12,500		12,500		12,500		6,250		43,750

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     As of December 31, 2008, ENP had $0.6 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 1.5 years. During 2008, there were 6,250 phantom units that vested, the total fair value of which was $0.1 million.

Note 10. Financial Instruments

     The book value of ENP’s cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of long-term debt approximates fair value as the interest rate is variable. Commodity derivative contracts and interest rate swaps are marked-to-market each quarter.

Derivative Financial Instruments

     Commodity Derivative Contracts.The Company manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collars provide a floor price for a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price.

     From time to time, the Company sells floors with a strike price below the strike price of the purchased floors in order to partially finance the premiums paid on the purchased floors. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with the Company’s other commodity derivative contracts, these are marked-to-market each quarter. In the following tables, the purchased floor component of these floor spreads are shown net and included with the Company’s other floor contracts.

     The following tables summarize the Company’s open commodity derivative instruments as of December 31, 2008:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
2009 (a)													$	67,850
		3,130	$	110.00		440	$	97.75		1,000	$	68.70
2010														17,618
		880		80.00		440		93.80		—		—
		2,000		75.00		1,000		77.23		—		—
2011														15,112
		1,880		80.00		1,440		95.41		—		—
		1,000		70.00		—		—		—		—
													$	100,580

(a) In addition, the Company has a floor contract for 1,000 Bbls/D at $63.00 per Bbl and a short floor contract for 1,000 Bbls/D at $65.00 per Bbl.

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
2009													$	7,281
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		—		—		—		—
		1,800		6.76		—		—		—		—
2010														4,690
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		—		—		902		6.30
2011														424
		898		6.76		—		—		902		6.70
2012														424
		898		6.76		—		—		902		6.66
													$	12,819

     Interest Rate Swaps. The Company uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under the OLLC Credit Agreement to a weighted average fixed rate. These interest rate swaps were designated as cash flow hedges. The following table summarizes the Company’s open interest rate swaps as of December 31, 2008, all of which were entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
Jan. 2009 - Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
Jan. 2009 - Jan. 2011		25,000		2.9650	%	1-month LIBOR
Jan. 2009 - Jan. 2011		25,000		2.9613	%	1-month LIBOR
Jan. 2009 - Mar. 2012		50,000		2.4200	%	1-month LIBOR

     As of December 31, 2008, the fair market value of the Company’s interest rate swaps was a net liability of $4.6 million of which, $1.3 million was current and included in the current liabilities line “Derivatives” and $3.3 million was long-term and included in the other liabilities line “Derivatives” in the accompanying Consolidated Balance Sheets.

     Counterparty Risk.At December 31, 2008, the Company had committed greater than 10 percent (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

	Percentage of			Percentage of
	Oil Derivative			Natural Gas
	Contracts			Derivative Contracts
Counterparty	Committed			Committed
Bank of America, N.A.		27	%		—
BNP Paribas		28	%		24	%
Fortis		11	%		—
Calyon		—			31	%
Goldman Sachs Group		20	%		—
Wachovia Bank		—			38	%

     In order to mitigate the credit risk of financial instruments, the Company enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and the Company. Instead of treating separately each financial transaction between the counterparty and the Company, the master netting agreement enables the counterparty and the Company to aggregate all financial trades and treat them as a single agreement. This arrangement benefits the Company in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

collateral posting by the Company; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces the Company’s credit exposure to a given counterparty in the event of close-out. The Company’s accounting policy is to not offset fair value amounts recognized for derivative instruments.

     Accumulated Other Comprehensive Loss.At December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on the Company’s interest rate swaps that are designated as hedges of $4.3 million. The Company expects to reclassify $1.3 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense during 2009.

Note 11. Fair Value Measurements

     As discussed in “Note 2. Summary of Significant Accounting Policies,” the Company adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

• Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.

• Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.

• Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

     The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the financial assets and liabilities and their placement within the fair value hierarchy levels. The following methods and assumptions are used to estimate the fair values of the Company’s financial assets and liabilities that are accounted for at fair value on a recurring basis:

• Level 2 — Fair values of oil and natural gas swaps were estimated using a combined income and market-based valuation methodology based upon forward commodity price curves obtained from independent pricing services reflecting broker market quotes. Fair values of interest rate swaps were estimated using a combined income and market-based valuation methodology based upon credit ratings and forward interest rate yield curves obtained from independent pricing services reflecting broker market quotes.

• Level 3 — Fair values of oil and natural gas floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.

     The following table sets forth the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008.

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in					Significant
				Active Markets for		Significant Other			Unobservable
				Identical Assets		Observable Inputs			Inputs
	Total			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	5,150		$	—	$	5,150		$	—
Oil derivative contracts — floors and caps		95,430			—		—			95,430
Natural gas derivative contracts — swaps		78			—		78			—
Natural gas derivative contracts — floors and caps		12,741			—		—			12,741
Interest rate swaps		(4,559	)		—		(4,559	)		—
Total	$	108,840		$	—	$	669		$	108,171

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

     The following table summarizes the changes in the fair value of the Company’s Level 3 financial assets and liabilities for 2008:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative		Natural Gas
	Contracts - Floors		Derivative Contracts
	and Caps		- Floors and Caps		Total
	(in thousands)
Balance at January 1, 2008	$	6,466	$	4,533	$	10,999
Total gains (losses):
Included in earnings		79,709		5,590		85,299
Purchases, issuances, and settlements		9,255		2,618		11,873
Balance at December 31, 2008	$	95,430	$	12,741	$	108,171
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	79,709	$	5,590	$	85,299

     Since the Company does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 financial assets and liabilities are included in earnings. All fair values reflected in the tables above and in the accompanying Consolidated Balance Sheet as of December 31, 2008 have been adjusted for non-performance risk, resulting in a reduction of the net commodity derivative asset of approximately $1.4 million as of December 31, 2008.

Note 12. Related Party Transactions

     The Company does not have any employees. The employees supporting the operations of the Company are employees of EAC. As discussed in “Note 1. Formation of the Company and Description of Business,” ENP entered into the Administrative Services Agreement pursuant to which Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering. In addition, Encore Operating provides all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by ENP. Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. Effective April 1, 2008, the administrative fee increased to $1.88 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment. Encore Operating also charges ENP for reimbursement of actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the Administrative Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     ENP also reimburses EAC for any additional state income, franchise, or similar tax incurred by EAC resulting from the inclusion of ENP and its subsidiaries in consolidated tax returns with EAC and its subsidiaries as required by applicable law. The amount of any such reimbursement is limited to the tax that ENP and its subsidiaries would have incurred had it not been included in a combined group with EAC.

     In 2008 and 2007, ENP paid Encore Operating $6.6 million and $2.8 million, respectively, for administrative fees under the Administrative Services Agreement (including payment of any COPAS recovery) and $8.3 million and $3.5 million, respectively, for reimbursement of actual third-party expenses incurred on ENP’s behalf. As of December 31, 2008 and 2007, ENP had a payable to EAC of $2.2 million and $6.7 million, respectively, which is reflected in “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from EAC of $0.9 million and $3.3 million, respectively, which is reflected in “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets.

     As discussed in “Note 3. Acquisitions,” ENP completed the acquisition of the Permian and Williston Basin Assets from Encore Operating in February 2008 for total consideration of approximately $125.3 million in cash, including certain post-closing adjustments, and 6,884,776 common units representing limited partner interests in ENP. In determining the total purchase price, the

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ENCORE ENERGY PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

common units were valued at $125 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s historical carrying value of the properties. Also as discussed in “Note 3. Acquisitions,” ENP completed the acquisition of the Arkoma Basin Assets from Encore Operating in January 2009 for a purchase price of $49 million in cash, subject to customary adjustments (including a reduction in the purchase price for acquisition-related commodity derivative premiums of approximately $3 million).

     During 2008 and 2007, ENP distributed approximately $49.3 million and $0.8 million, respectively, to EAC and certain executive officers of the Company related to quarterly distributions on common units and management incentive units. During 2008 and 2007, ENP distributed approximately $1.2 million and $27 thousand, respectively, to the Company as the holder of all 504,851 general partner units.

     As discussed in “Note 7. Long-Term Debt,” during 2007, ENP had a subordinated credit agreement with a subsidiary of EAC, which was repaid in full from a portion of the net proceeds from the IPO.

     Prior to the contribution of the Permian Basin Assets to ENP, the acquisition by ENP of the Permian and Williston Basin Assets, and the acquisition by ENP of the Arkoma Basin Assets, these properties were wholly owned by EAC and were not separate legal entities.

     EAC (through its subsidiaries) contributed $93.7 million to ENP in March 2007. These proceeds were used by ENP, along with proceeds from the borrowings under ENP’s long-term debt agreements, to purchase the Elk Basin Assets. Additionally, EAC (through its subsidiaries) made a non-cash contribution in March 2007 of derivative oil put contracts representing 2,500 Bbls/D of production at $65.00 per Bbl for the period of April 2007 through December 2008. At the date of transfer, the derivative contracts had a fair value of $9.4 million.

Note 13. Subsequent Events — Unaudited

Distributions

     On January 26, 2009, ENP announced a cash distribution for the fourth quarter of 2008 to unitholders of record as of the close of business on February 6, 2009. Approximately $16.8 million was paid on February 13, 2009 to unitholders at a rate of $0.50 per unit.

     On April 27, 2009, ENP announced a cash distribution for the first quarter of 2009 to unitholders of record as of the close of business on May 11, 2009 at a rate of $0.50 per unit. Approximately $16.8 million is expected to be paid to unitholders on or about May 15, 2009.

Amendment to OLLC Credit Agreement

     In March 2009, the borrowing base under the OLLC Credit Agreement was redetermined with no change. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement.

     Eurodollar loans under the OLLC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the OLLC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

	Applicable Margin for			Applicable Margin for
Ratio of Total Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		1.750	%		0.750	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.000	%		0.750	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.250	%		1.000	%
Greater than or equal to .90 to 1		2.500	%		1.250	%

     The “Eurodollar Rate” for any interest period (either one, two, three, or six months, as selected by ENP) is the rate equal to the British Bankers Association LIBOR Rate for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the federal funds effective rate plus 0.5 percent; or (3) during a “LIBOR Unavailability Period,” the “Eurodollar Rate” (for dollar deposits for a one-month term) for such day plus 1.0 percent.

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NOTES TO CONSOLIDATED BALANCE SHEETS — (Continued)

     The following table summarizes the commitment fee percentage under the OLLC Credit Agreement:

	Commitment
Ratio of Total Outstanding Borrowings to Borrowing Base	Fee Percentage
Less than .90 to 1	0.375%
Greater than or equal to .90 to 1	0.500%

COPAS Wage Index Adjustment

     Effective April 1, 2009, the administrative fee under ENP’s administrative services agreement with Encore Operating increased to $2.02 per BOE of ENP’s production as a result of the COPAS Wage Index Adjustment.

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ENCORE ENERGY PARTNERS GP LLC

SUPPLEMENTARY INFORMATION

Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities

     The capitalized cost of oil and natural gas properties was as follows as for the dates indicated:

	December 31,
	2008			2007
	(in thousands)
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	542,938		$	519,654
Unproved properties		67			298
Accumulated depletion, depreciation, and amortization		(107,616	)		(68,773	)
	$	435,389		$	451,179

     The following table summarizes costs incurred related to oil and natural gas properties for periods indicated:

	Year Ended December 31,
	2008		2007
	(in thousands)
Acquisitions:
Proved properties	$	5,827	$	353,987
Unproved properties		—		105
Asset retirement obligations		—		6,343
Total acquisitions		5,827		360,435
Development:
Drilling and exploitation		15,034		18,637
Asset retirement obligations		29		117
Total development		15,063		18,754
Exploration:
Drilling and exploitation		2,272		3,399
Other		119		101
Total exploration		2,391		3,500
Total costs incurred	$	23,281	$	382,689

Oil & Natural Gas Producing Activities — Unaudited

     The estimates of ENP’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the United States Securities and Exchange Commission (“SEC”) and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.

     Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with SEC guidelines, estimates of future net cash flows from ENP’s properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Year-end prices used in estimating net cash flows for the dates indicated:

	December 31,
	2008		2007
Oil (per Bbl)	$	44.60	$	96.01
Natural gas (per Mcf)		5.62		7.47

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SUPPLEMENTARY INFORMATION — (Continued)

     Net future cash inflows have not been adjusted for commodity derivative contracts outstanding at the end of the year. The future cash flows are reduced by estimated production and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes due to the Texas margin tax. Future federal income taxes have not been deducted from future net revenues in the calculation of ENP’s standardized measure as each partner is separately taxed on his share of ENP’s taxable income.

     There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included herein. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions based on the results of drilling, testing, and production activities. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of DD&A on these properties.

     ENP’s estimated net quantities of proved oil and natural gas reserves were as follows as of the dates indicated:

	December 31,
	2008		2007
Proved reserves:
Oil (MBbls)		16,856		21,590
Natural gas (MMcf)		64,760		69,111
Combined (MBOE)		27,649		33,108
Proved developed reserves:
Oil (MBbls)		15,077		19,333
Natural gas (MMcf)		57,540		59,192
Combined (MBOE)		24,667		29,198

     The changes in ENP’s proved reserves were as follows for the periods indicated:

				Natural			Oil
	Oil			Gas			Equivalent
	(MBbls)			(MMcf)			(MBOE)
Balance, December 31, 2006 (a)		4,263			65,088			15,111
Purchases of minerals-in-place		17,382			3,200			17,915
Extensions and discoveries		425			7,348			1,650
Revisions of previous estimates		974			(2,059	)		630
Production		(1,454	)		(4,466	)		(2,198	)
Balance, December 31, 2007 (a)		21,590			69,111			33,108
Purchases of minerals-in-place		12			2,471			424
Extensions and discoveries		37			2,747			495
Revisions of previous estimates		(3,112	)		(4,659	)		(3,888	)
Production		(1,671	)		(4,910	)		(2,490	)
Balance, December 31, 2008 (a)		16,856			64,760			27,649

(a) Includes 10,658 MBOE and 6,871 MBOE of proved reserves as of December 31, 2007 and 2006, respectively, associated with the Permian and Williston Basin Assets ENP acquired from EAC in February 2008. Also includes 1,585 MBOE, 1,510 MBOE, and 1,952 MBOE of proved reserves as of December 31, 2008, 2007, and 2006, respectively, associated with the Arkoma Basin Assets ENP acquired from EAC in January 2009. The acquisitions of these assets were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby ENP’s historical financial information and proved reserve volumes were recast to include the acquired properties for all periods presented.

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SUPPLEMENTARY INFORMATION — (Continued)

     ENP’s standardized measure of discounted estimated future net cash flows was as follows for the dates indicated:

	December 31,
	2008			2007
	(in thousands)
Future cash inflows	$	956,611		$	2,177,171
Future production costs		(467,049	)		(733,153	)
Future development costs		(36,361	)		(40,244	)
Future abandonment costs, net of salvage		(23,298	)		(23,930	)
Future income tax expense		(61	)		(5,866	)
Future net cash flows		429,842			1,373,978
10% annual discount		(207,883	)		(682,534	)
Standardized measure of discounted estimated future net cash flows	$	221,959		$	691,444

     The changes in ENP’s standardized measure of discounted estimated future net cash flows were as follows for the periods indicated:

	Year Ended December 31,
	2008			2007
	(in thousands)
Net change in prices and production costs	$	(424,027	)	$	91,105
Purchases of minerals-in-place		5,693			484,207
Extensions, discoveries, and improved recovery		3,757			25,399
Revisions of previous quantity estimates		(33,035	)		19,733
Production, net of production costs		(50,897	)		(106,942	)
Development costs incurred during the period		9,577			17,542
Accretion of discount		69,145			16,099
Change in estimated future development costs		(5,694	)		(28,465	)
Net change in income taxes		2,716			(2,071	)
Change in timing and other		(46,720	)		13,850
Net change in standardized measure		(469,485	)		530,457
Standardized measure, beginning of year		691,444			160,987
Standardized measure, end of year	$	221,959		$	691,444

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