Encore Energy Partners 8-K Other Events

Exhibit 99.3

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		2
Consolidated Balance Sheets as of December 31, 2007 and 2006		3
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006, and 2005		4
Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2007, 2006, and 2005		5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006, and 2005		6
Notes to Consolidated Financial Statements		7
Supplementary Information		29

1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Encore Energy Partners GP LLC
and Unitholders of Encore Energy Partners LP:

     We have audited the accompanying consolidated balance sheets of Encore Energy Partners LP (the “Partnership”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, partners’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements 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 financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’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 Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 2 to the consolidated financial statements, on January 1, 2007, the Partnership 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
September 22, 2008

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ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	3		$	—
Accounts receivable:
Trade		21,595			5,530
Affiliate		3,290			1,689
Derivatives		3,713			—
Prepaid expenses and other		448			—
Total current assets		29,049			7,219
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		500,470			119,256
Unproved properties		298			216
Accumulated depletion, depreciation, and amortization		(63,295	)		(31,294	)
		437,473			88,178
Other property and equipment		510			—
Accumulated depreciation		(68	)		—
		442			—
Goodwill		2,648			2,648
Other intangibles, net		3,969			—
Derivatives		21,875			—
Debt issuance costs, net		1,451			—
Other		812			—
Total assets	$	497,719		$	98,045
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,915		$	—
Affiliate		6,709			3,102
Accrued liabilities:
Lease operations expense		2,903			821
Development capital		3,012			653
Interest		147			—
Production, ad valorem, and severance taxes		6,272			995
Marketing		1,578			—
Derivatives		865			—
Other		2,898			400
Total current liabilities		26,299			5,971
Derivatives		20,447			—
Future abandonment cost, net of current portion		8,314			1,708
Long-term debt		47,500			—
Other		146			240
Total liabilities		102,706			7,919
Commitments and contingencies (see Note 4)
Partners’ equity:
Limited partners — 24,187,679 common units issued and outstanding at December 31, 2007		391,956			—
General partner — 504,851 general partner units outstanding at December 31, 2007		3,057			—
Owner’s net equity		—			90,126
Total partners’ equity		395,013			90,126
Total liabilities and partners’ equity	$	497,719		$	98,045

The accompanying notes are an integral part of these consolidated financial statements.

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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2007			2006			2005
	(in thousands, except per unit amounts)
Revenues:
Oil	$	85,110		$	17,776		$	11,620
Natural gas		23,720			23,129			31,607
Marketing		8,582			—			—
Total revenues		117,412			40,905			43,227
Expenses:
Production:
Lease operations		21,539			6,937			5,558
Production, ad valorem, and severance taxes		11,664			3,745			3,504
Depletion, depreciation, and amortization		32,275			5,284			4,592
Exploration		124			22			312
General and administrative		12,204			1,737			1,450
Marketing		6,673			—			—
Derivative fair value loss		26,301			—			—
Other operating		1,087			536			589
Total expenses		111,867			18,261			16,005
Operating income		5,545			22,644			27,222
Other income (expenses):
Interest		(12,702	)		—			—
Other		196			—			—
Total other expenses		(12,506	)		—			—
Income (loss) before income taxes		(6,961	)		22,644			27,222
Income tax provision:
Current		(62	)		—			—
Deferred		—			(240	)		—
Net income (loss)	$	(7,023	)	$	22,404		$	27,222
Net loss allocation (see Note 9):
Limited partners’ interest in net loss	$	(18,617	)
General partner’s interest in net loss	$	(389	)
Net loss per common unit:
Basic	$	(0.78	)
Diluted	$	(0.78	)
Weighted average common units outstanding:
Basic		23,877
Diluted		23,877

The accompanying notes are an integral part of these consolidated financial statements.

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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

	Owner’s									Total
	Net			Limited			General			Partners’
	Equity			Partners			Partner			Equity
	(in thousands)
Balance at December 31, 2004	$	71,343		$	—		$	—		$	71,343
Net income		27,222			—			—			27,222
Net distributions to owner		(4,937	)		—			—			(4,937	)
Equity adjustment due to combination of entities under common control		(269	)		—			—			(269	)
Balance at December 31, 2005		93,359			—			—			93,359
Net income		22,404			—			—			22,404
Net distributions to owner		(25,817	)		—			—			(25,817	)
Equity adjustment due to combination of entities under common control		180			—			—			180
Balance at December 31, 2006		90,126			—			—			90,126
Contributions by EAC in connection with acquisition of Elk Basin Assets		103,062			—			—			103,062
Net contributions from owner		11,227			—			—			11,227
Net income attributable to owner related to pre-partnership and pre-IPO operations		11,953			—			—			11,953
Equity adjustment due to combination of entities under common control		(1,306	)		—			—			(1,306	)
Contribution of Permian Basin Assets by EAC		(26,229	)		26,229			—			—
Allocation of owner’s net equity — Permian Basin Assets		(91,956	)		90,118			1,838			—
Allocation of owner’s net equity — Permian and Williston Basin Assets		(96,877	)		94,979			1,898			—
Issuance of common units to public in IPO		—			213,116			—			213,116
Underwriting and offering costs in conjunction with IPO		—			(19,253	)		(402	)		(19,655	)
Net loss attributable to unitholders subsequent to IPO		—			(18,587	)		(389	)		(18,976	)
Non-cash unit-based compensation		—			6,665			139			6,804
Distributions to unitholders		—			(1,311	)		(27	)		(1,338	)
Balance at December 31, 2007	$	—		$	391,956		$	3,057		$	395,013

The accompanying notes are an integral part of these consolidated financial statements.

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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007			2006			2005
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(7,023	)	$	22,404		$	27,222
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		32,275			5,284			4,592
Non-cash exploration expense		23			22			307
Non-cash unit-based compensation expense		6,804			—			—
Non-cash derivative fair value loss		27,543			—			—
Deferred taxes		—			240			—
Other		589			77			47
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(15,274	)		2,890			(2,436	)
Current derivatives		(2,700	)		—			—
Other current assets		(447	)		—			—
Long-term derivatives		(19,717	)		—			—
Other assets		(812	)		—			—
Accounts payable		3,268			—			—
Other current liabilities		8,837			123			512
Net cash provided by operating activities		33,366			31,040			30,244
Cash flows from investing activities:
Purchases of other property and equipment		(510	)		—			—
Acquisition of oil and natural gas properties		(357,633	)		(422	)		(19,202	)
Development of oil and natural gas properties		(17,986	)		(4,801	)		(6,105	)
Net cash used in investing activities		(376,129	)		(5,223	)		(25,307	)
Cash flows from financing activities:
Proceeds from issuance of common units, net of issuance costs		193,461			—			—
Proceeds from long-term debt, net of issuance costs		270,758			—			—
Payments on long-term debt		(225,000	)		—			—
Distributions to unitholders		(1,338	)		—			—
Contribution by EAC in connection with purchase of Elk Basin Assets		93,658			—			—
Net contributions from (distributions to) owner prior to IPO		11,227			(25,817	)		(4,937	)
Net cash provided by (used in) financing activities		342,766			(25,817	)		(4,937	)
Increase in cash and cash equivalents		3			—			—
Cash and cash equivalents, beginning of period		—			—			—
Cash and cash equivalents, end of period	$	3		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

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ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Formation of the Partnership and Description of Business

     Encore Energy Partners LP (“ENP” or the “Partnership”) was formed in February 2007 by Encore Acquisition Company (“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 GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of EAC, was formed to serve as the general partner of ENP, and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of the Partnership, was formed to own and operate ENP’s properties. The Partnership’s properties — and oil and natural gas reserves — are located in three core areas:

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

• the Permian Basin of West Texas; and

• the Williston Basin of North Dakota.

Initial Public Offering and Concurrent Transactions

     In September 2007, the Partnership completed its initial public offering (“IPO”) of 9,000,000 common units at a price to the public of $21.00 per unit. The net proceeds of $171.0 million, after deducting the underwriters’ discount and a structuring fee of $13.2 million, in the aggregate, and offering expenses of $4.7 million, were used to repay in full $126.4 million, including accrued interest, of outstanding indebtedness under OLLC’S subordinated credit agreement and $43.5 million of outstanding borrowings under OLLC’s revolving credit facility. See “Note 7. Debt” for additional discussion of the Partnership’s long-term debt.

     In October 2007, the underwriters exercised their over-allotment option to purchase an additional 1,148,400 common units. The net proceeds of $22.4 million, after deducting the underwriters’ discount and a structuring fee of $1.7 million, in the aggregate, were used to repay outstanding borrowings under OLLC’s revolving credit facility. After completion of the IPO and the underwriters’ over-allotment exercise, approximately 42 percent of the Partnership’s common units were publicly held.

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

(a) The Partnership entered into a contribution, conveyance and assumption agreement (the “Contribution Agreement”) with the General Partner, 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 transferred certain oil and natural gas properties and related assets in the Permian Basin of West Texas (the “Permian Basin Assets”) to the Partnership in exchange for 4,043,478 common units; and

• EAC agreed to indemnify the Partnership 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 the Partnership in exchange for the Permian Basin Assets, the IPO, and the exercise of the underwriters’ option to purchase additional common units, the General Partner exchanged a certain number of common units for general partner units to enable it to maintain its then 2 percent general partner interest.

(b)

The Partnership entered into an amended and restated administrative services agreement (the “Administrative Services Agreement”) with the General Partner, OLLC, Encore Operating, and EAC. Encore Operating performs administrative services for the Partnership, 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 the Partnership. Encore Operating initially received an administrative fee of $1.75 per BOE of the Partnership’s production for such services and reimbursement of actual third-party expenses incurred on the Partnership’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.

7

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

The Partnership reimburses EAC for any additional state income, franchise, or similar tax paid by EAC resulting from the inclusion of the Partnership (and its subsidiaries) in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement is limited to the tax that the Partnership (and its subsidiaries) would have paid had it not been included in a combined group with EAC. See “Note 12. Related Party Transactions” for additional discussion regarding the Administrative Services Agreement.

(c)

The Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Incentive Plan”) was approved, which applies to employees, consultants, and directors of EAC, the General Partner, and any of their affiliates who perform services for the Partnership. See “Note 10. Unit-Based Compensation Plans” for additional discussion regarding the ENP Incentive Plan.

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

     The Partnership’s consolidated financial statements include the accounts of its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation.

     As discussed above, upon completion of the Partnership’s IPO, EAC contributed the Permian Basin Assets to the Partnership. The Permian Basin Assets are considered the predecessor to the Partnership, and therefore, the historical results of operations of the Partnership include the results of operations of the Permian Basin Assets for all periods presented. The results of operations of the Elk Basin Assets have been included with those of the Partnership from the date of acquisition in March 2007. In February 2008, the Partnership completed the acquisition of additional oil and natural gas properties and related assets in the Permian Basin of West Texas and oil and natural gas properties and related assets in the Williston Basin of North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction 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 Partnership’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes thereto reflect the combined historical results of the Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets throughout the periods presented. The results of operations of the Permian and Williston Basin Assets related to pre-partnership operations were allocated to the EAC affiliates based on their respective ownership percentages in the Partnership’s general and limited partner units. The effect of recasting the Partnership’s consolidated financial statements to account for this common control transaction reduced the Partnership’s net loss by approximately $18.3 million for 2007 and increased the Partnership’s net income by approximately $14.8 million and $15.7 million for 2006 and 2005, respectively.

     The Partnership, the Permian Basin Assets, and the Permian and Williston 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 General Partner.

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 financial statements and the reported amounts of revenues and expenses reported. Actual results could differ materially from those estimates.

     Estimates made in preparing these consolidated financial statements 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; estimates of the fair value of equity-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

8

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

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.

     Prior to the formation of the Partnership, EAC provided cash as needed to support the operations of the predecessor properties and collected cash from sales of production. Consequently, the accompanying Consolidated Balance Sheet as of December 31, 2006 does not include any cash balances. Net cash received or paid during each year by EAC for periods prior to the properties’ ownership by the Partnership is reflected as net contributions from owner or net distributions to owner on the accompanying Consolidated Statements of Partners’ Equity and Consolidated Statements of Cash Flows.

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for 2007 (in thousands):

Cash paid during the period for:
Interest	$	11,857
Non-cash investing and financing activities:
Contribution of derivative contracts from EAC		9,404
Contribution of Permian Basin Assets from EAC		26,229

     The Partnership did not have supplemental disclosures of cash flow information for 2006 or 2005.

Accounts Receivable

     The Partnership’s trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest. The Partnership routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers. A reserve is recorded for amounts it expects will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2007 and 2006, the Partnership did not have any allowance for doubtful accounts.

Properties and Equipment

     Oil and Natural Gas Properties.The Partnership adheres to Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”), utilizing the successful efforts method of accounting for its oil and natural gas properties. 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 are expensed in the Partnership’s Consolidated Statements of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of the Partnership’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, the Partnership 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 neither of these conditions continues to exist, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income in the “Operating activities” section of the Partnership’s Consolidated Statements of Cash Flows 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. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of the Partnership’s Consolidated Statements of Cash Flows.

9

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     Significant tangible equipment added or replaced is capitalized. Expenditures 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 the accumulated DD&A reserve. Gains or losses from the disposal of other properties are recognized in the current period.

     Reserve engineers estimate the Partnership’s reserves annually on December 31. This results in a new DD&A rate which the Partnership uses for the preceding fourth quarter after adjusting for fourth quarter production. The Partnership 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 quarter.

     In accordance with SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets,”(“SFAS 144”) the Partnership is required to assess 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 it is recognized to the extent that the carrying value exceeds fair value. Expected future net cash flows are based on existing proved reserve and production information and pricing assumptions that management believes are representative of future economics. Any impairment charge incurred is expensed and reduces the recorded basis in the asset.

     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 is recognized by providing a valuation allowance at the level consistent with 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 is determined by amortizing the portion of these properties’ costs which ENP 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,
	2007		2006
	(in thousands)
Proved leasehold costs	$	372,076	$	68,216
Wells and related equipment — Completed		124,381		48,370
Wells and related equipment — In process		4,013		2,670
Total proved properties	$	500,470	$	119,256

     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.

Goodwill and Other Intangible Assets

     The Partnership accounts for intangible assets under the provisions of SFAS No. 142,“Goodwill and Other Intangible Assets”(“SFAS 142”). 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, or immediately if conditions indicate that an impairment could exist. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of the indefinite lived intangible asset exceeds its implied fair value. Intangible assets with definite useful lives are amortized over their estimated useful lives. In

10

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

accordance with SFAS 144, the Partnership 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.

     In connection with the Partnership’s acquisition of the Elk Basin Assets, the Partnership acquired a contract to purchase natural gas at a below market price for use as field fuel. The fair value of this contract, net of related amortization, is shown as “Other intangibles, net” on the accompanying Consolidated Balance Sheet as of December 31, 2007. The value of this contract is amortized on a straight-line basis over its estimated useful life of approximately 14 years. As of December 31, 2007, the gross carrying amount of the contract was $4.2 million and accumulated amortization was $0.3 million. For 2007, the Partnership recorded $0.3 million amortization expense related to this contract. For each of the next five years, the Partnership expects amortization expense to be approximately $0.3 million per year.

Asset Retirement Obligations

     SFAS No. 143,“Accounting for Asset Retirement Obligations”requires that the fair value of a liability for an asset retirement obligation be recognized 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 asset retirement obligation is capitalized as part of the carrying amount of the Partnership’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. See “Note 5. Asset Retirement Obligations” for additional information.

Environmental Costs

     The Partnership capitalizes or expenses environmental expenditures, as appropriate, depending on whether the expenditure has a future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for such expenditures are recorded on an undiscounted basis when environmental assessments or clean-ups are probable and the costs can be reliably estimated. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized.

Unit-Based Compensation

     The Partnership does not have any employees. However, the ENP Incentive Plan provides for the grant of unit awards and unit-based awards for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates that perform services for the Partnership. In addition, in May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner.

     The Partnership accounts for unit-based compensation according to the provisions of SFAS No. 123 (revised 2004),“Share-Based Payment”(“SFAS 123R”). SFAS 123R requires the recognition of compensation expense, over the requisite service period, in an amount equal to the fair value of unit-based payments granted. See “Note 10. Unit-Based Compensation Plans” for additional discussion of the Partnership’s unit-based compensation plans.

     For 2006 and 2005, a portion of the general and administrative (“G&A”) expenses and lease operating expenses allocated to the Partnership to reflect the carve out operations of the Permian Basin Assets and the Permian and Williston Basin Assets was non-cash stock-based compensation recorded on the books of EAC. On January 1, 2006, EAC adopted the provisions of SFAS 123R using the “modified prospective” method. SFAS 123R revised SFAS No. 123,“Accounting for Stock-Based Compensation”and superseded Accounting Principles Board (“APB”) Opinion No. 25,“Accounting for Stock Issued to Employees”(“APB 25”). Prior to the adoption of SFAS 123R, employee stock options and restricted stock awards were accounted for according to the provisions of APB 25, which resulted in no compensation expense being recorded by EAC for stock options, as all options that were granted to EAC employees or non-employee directors had an exercise price equal to or greater than the common stock price on the date of grant. However, expense was recorded by EAC and allocated to the Permian Basin Assets and the Permian and Williston Basin Assets related to restricted stock granted to EAC employees. Allocated compensation expense associated with awards to employees who are eligible for retirement was recognized over the explicit service period of the award under APB 25. If EAC had recognized compensation expense at the time an employee became

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eligible for retirement and had satisfied all service requirements, non-cash stock-based compensation expense allocable to the Permian Basin Assets and Permian and Williston Basin Assets would have increased by $83,000 in 2005.

     During 2005, if compensation expense for the stock-based awards had been determined using the provisions of SFAS 123R, the Partnership’s net income would have been as follows on a pro forma basis (in thousands):

As Reported:
Non-cash stock-based compensation	$	337
Net income		27,222
Pro Forma:
Non-cash stock-based compensation	$	468
Net income		27,091

Segment Reporting

     The Partnership has only one operating segment during the years presented — the development and exploitation of oil and natural gas reserves in the United States. A single management team administers all properties as a whole rather than by discrete operating segments. The Partnership does not track all material costs to develop and operate its properties at a level lower than the total Partnership level, nor does its current internal reporting structure allow for accurate tracking at a lower level. Throughout the year, the Partnership allocates capital resources to projects on a project-by-project basis, across its entire asset base to maximize profitability without regard to individual areas.

Major Customers / Concentration of Credit Risk

     In 2007, 2006, and 2005, four purchasers accounted for approximately 70 percent, 71 percent, and 79 percent, respectively, of the Partnership’s total sales of production.

Income Taxes

     ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of the Partnership’s taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, in May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced the Texas franchise tax. The Texas Margin Tax is applicable to numerous types of entities that previously were not subject to the franchise tax. ENP’s provision for income taxes is applicable to these state tax obligations under the Texas Margin Tax. In 2006, a deferred tax liability and related income tax expense was recognized for the expected future tax effect of the Texas Margin Tax due to the difference between the book and tax bases of the Partnership’s properties located in Texas. ENP has not paid any cash taxes for 2007, 2006, or 2005.

     Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership.

     On January 1, 2007, ENP adopted the provisions of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) 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 have an impact on ENP’s financial condition, results of operations, or cash flows. Any interest assessed by the taxing authorities would be included in “Interest expense” and penalties related to income taxes would be included in “Other expense” on the accompanying Consolidated Statements of Operations. ENP has not recognized any interest or penalties for 2007.

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Revenue Recognition

     Revenues are recognized for the Partnership’s share of jointly owned properties as oil and natural gas is produced and sold, net of royalties. Natural gas revenues are also reduced by any processing and other fees paid, except for transportation costs paid to third parties, which are recorded as “Other operating expense” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting, whereby revenue is recognized based on actual sales of natural gas rather than based on the entity’s proportionate share of natural gas production. Royalties and severance taxes are paid based upon the actual price received from the sales. 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 values for those properties are estimated and recorded as accounts receivable in the accompanying Consolidated Balance Sheets. If the Partnership’s overproduced imbalance position (i.e., the Partnership has cumulatively been over-allocated production) is greater than the Partnership’s share of remaining reserves, a liability is recorded for the excess at period-end prices. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in the Partnership’s oil and natural gas properties, or oil in pipelines that has not been delivered to the purchaser. Natural gas imbalances as of December 31, 2007 and 2006 were immaterial. As of December 31, 2007 and 2006, the Partnership did not have any oil inventory in pipelines.

Marketing Revenues and Expenses

     In March 2007, the Partnership acquired a crude oil pipeline and a natural gas pipeline from Anadarko Petroleum Corporation (“Anadarko”) as part of the Elk Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. In addition, pipeline tariffs are collected for transportation through the crude oil pipeline.

     Marketing revenues includes the sales of natural gas purchased from third parties as well as pipeline tariffs charged for transportation volumes through the Partnership’s crude oil pipeline. Revenues derived from sales of natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. Marketing expenses includes the cost of natural gas volumes purchased from third parties. As ENP takes title to the natural gas and has risks and rewards of ownership, these transactions are presented gross in the Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in EITF Issue No. 04-13,“Accounting for Purchases and Sales of Inventory with the Same Counterparty.”The Partnership did not have any marketing activities prior to 2007.

Shipping Costs

     Shipping costs of the Partnership’s production in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Other operating expense” and “Marketing expense,” as applicable, in the Partnership’s Consolidated Statements of Operations.

Derivatives

     ENP uses various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with the Partnership’s oil and natural gas production. These arrangements are structured to reduce the Partnership’s exposure to commodity price decreases, but they can also limit the benefit the Partnership might otherwise receive from commodity price increases. ENP’s risk management activity is generally accomplished through over-the-counter forward derivative or option contracts with large financial institutions.

     The Partnership applies the provisions of SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”and its amendments (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. The Partnership has elected to not designate its portfolio of commodity derivatives as hedges and records mark-to-market gains or losses to “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

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Allocation of Net Income (Loss)

     The Partnership’s net income (loss) is allocated to partner equity accounts in accordance with the provisions of the partnership agreement.

     For purposes of calculating earnings per unit, the Partnership allocates net income (loss) to its limited partners and participating securities, including general partner units, each quarter under the provisions of Emerging Issues Task Force Issue No. 03-6,“Participating Securities and the Two-Class Method under FASB Statement No. 128.”

Earnings Per Unit

     The Partnership calculates net income (loss) per common unit in accordance with SFAS No. 128,“Earnings per Share”(“SFAS 128”). Under the two-class method of calculating earnings per unit as prescribed by SFAS 128, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in undistributed earnings with common units. For purposes of calculating earnings per unit, the general partner units and management incentive units are participating securities. Net income (loss) per common unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of the participating securities, by the weighted average number of common units outstanding. See “Note 9. Earnings Per Common Unit” for additional discussion.

     For periods prior to the IPO, the Partnership was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, earnings per unit is not presented for those periods.

New Accounting Pronouncements

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

     In September 2006, the FASB issued SFAS 157, which standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), and 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. 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 Partnership 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 Partnership will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. 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 Partnership’s results of operations or financial condition.

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 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 the Partnership on January 1, 2008; however, the Partnership did not elect the fair value option for eligible instruments existing on that date. Therefore, the adoption of SFAS 159 did not have an impact on the Partnership’s results of operations or financial condition. In the future, the Partnership will assess the impact of electing the fair value option for any newly acquired eligible instruments. Electing the fair value option for such instruments could have a material impact on the Partnership’s future results of operations or financial condition.

FSP on 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

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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 is effective for fiscal years beginning after November 15, 2007. The Partnership adopted FSP FIN 39-1 effective January 1, 2008. The adoption of FSP FIN 39-1 did not have a material impact on its results of operations or 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: (i) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R applies prospectively to business combinations consummated in fiscal years beginning on or after December 15, 2008 (for acquisitions that close on or after January 1, 2009 for the Partnership). Early application is prohibited. The Partnership is evaluating the impact SFAS 141R will have on its results of operations and financial condition and the reporting of future acquisitions in the consolidated financial statements.

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 (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding the Partnership’s derivative instruments; however, SFAS 161 will not change the Partnership’s accounting for its derivative instruments and therefore, will not have an impact on the Partnership’s results of operations or financial condition.

Emerging Issues Task Force (“EITF”) Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (“EITF 07-4”)

     In March 2008, the EITF ratified its consensus opinion on EITF 07-4, which addresses how master limited partnerships should calculate earnings per unit using the two-class method in SFAS 128 and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and interim periods within those years, and will be applied retrospectively for all periods presented. The Partnership is currently evaluating the impact that EITF 07-4 will have on its earnings per unit calculations.

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 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411,“The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.”The Partnership does not expect the adoption of SFAS 162 to change its current accounting practice; therefore, the adoption of SFAS 162 will not have an impact on the Partnership’s results of operations or financial condition.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”)

     In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing basic earnings per unit under the two-class method prescribed by SFAS 128. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. Upon adoption of FSP EITF 03-6-1, all prior-period earnings per unit data must be adjusted retrospectively to conform with the

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provisions of the standard. Early application is not permitted. The Partnership is currently evaluating the effect FSP EITF 03-6-1 will have on its earnings per unit calculations.

Note 3. Acquisition

     On January 16, 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko to acquire oil and natural gas properties and related assets in the Big Horn Basin of 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 on March 7, 2007 after which the operations of the Elk Basin Assets have been included with those of the Partnership. The total purchase price for the Elk Basin Assets was approximately $330.7 million, including transaction costs of approximately $1.1 million.

     The following displays the calculation of the total purchase price and the allocation to the fair value of the assets acquired and liabilities assumed from Anadarko as of December 31, 2007 (in thousands):

Calculation of total purchase price:
Cash paid to Anadarko	$	329,551
Transaction costs		1,110
Total purchase price	$	330,661
Allocation of purchase price to the fair value of net assets acquired:
Proved properties, including wells and related equipment	$	332,549
Intangibles		4,225
Other property and equipment		346
Accounts receivable		1,444
Total assets acquired		338,564
Current liabilities		(1,120	)
Future abandoment cost and assumed liabilities		(6,783	)
Total liabilities assumed		(7,903	)
Fair value of net assets acquired	$	330,661

     The proved properties amount in the above purchase price allocation includes the fair value of proved leasehold costs, lease and well equipment (including flue gas reinjection facilities used to maintain reservoir pressure by compressing and reinjecting the gas produced), and an oil pipeline and natural gas pipeline used primarily to transport production from the acquired fields. Natural gas liquids are produced as a byproduct of the flue gas tertiary recovery project and are sold at market prices. The revenues generated by these hydrocarbon liquids are included in “Oil revenues” in the accompanying Consolidated Statements of Operations. Third party revenues and expenses related to the pipelines are included in “Marketing revenues” and “Marketing expense,” respectively, in the accompanying Consolidated Statements of Operations.

     The Partnership financed the acquisition of the Elk Basin Assets through a $93.7 million contribution from EAC and borrowings under its long-term debt agreements. See “Note 7. Debt” for additional discussion of the Partnership’s long-term debt.

     The following unaudited pro forma condensed financial data was derived from the historical financial statements of the Partnership and from the accounting records of Anadarko to give effect to the acquisition of the Elk Basin Assets as if it had occurred on January 1, 2005. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the acquisition of the Elk Basin Assets taken place as of the dates indicated and are not intended to be a projection of future results.

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	Year Ended December 31,
	2007			2006		2005
	(in thousands, except per unit amounts)
Pro forma total revenues	$	131,573		$	110,644	$	101,392
Pro forma net income (loss)	$	(9,108	)	$	10,430	$	7,062
Pro forma net loss per common unit:
Basic	$	(0.78	)
Diluted	$	(0.78	)

     For 2006 and 2005, the Partnership was wholly owned by EAC. Accordingly, earnings per unit has not been calculated for those periods.

Note 4. Commitments and Contingencies

     From time to time, the Partnership is a party to various legal proceedings in the ordinary course of business. The Partnership is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its business, financial condition, results of operations, or liquidity.

     Additionally, the Partnership has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, and derivative contracts as discussed more fully in the notes below. For contractual obligations as of December 31, 2007, see the contractual obligations table included in the Partnership’s recast “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included as Exhibit 99.2 to the Current Report on Form 8-K dated September 22, 2008.

Note 5. Asset Retirement Obligations

     The Partnership’s 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 Partnership’s estimated asset retirement obligations for the periods indicated:

	Year Ended December 31,
	2007			2006
	(in thousands)
Future abandonment liability at January 1	$	1,754		$	1,717
Acquisition of properties		6,343			6
Wells drilled		117			15
Accretion of discount		371			75
Plugging and abandonment costs incurred		(103	)		—
Revision of estimates		222			(59	)
Future abandonment liability at December 31	$	8,704		$	1,754

     As of December 31, 2007, approximately $8.3 million of the Partnership’s asset retirement obligations was long-term and recorded in “Future abandonment cost, net of current portion” and $0.4 million was 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, 2007 represents the estimated cost for decommissioning the Elk Basin natural gas processing plant. The Partnership expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant. In addition to the future abandonment liability for the Elk Basin plant, as of December 31, 2007, the Partnership has recorded an estimated liability of $1.0 million related to required environmental plant compliance costs caused by past operations of the plant. The liability was assumed from Anadarko in the acquisition of the Elk Basin Assets, and is reflected as a component of “Other current liabilities” on the Consolidated Balance Sheet as of December 31, 2007. The liability was estimated based on directives from the Bureau of Land

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Management for required cleanup of environmental contamination.

Note 6. Other Current Liabilities

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

	December 31,
	2007		2006
	(in thousands)
Estimated liabilities assumed in Elk Basin acquisition	$	985	$	—
Current portion of future abandonment liability		390		47
Oil and natural gas revenue suspense payable		618		347
Other		905		6
Total	$	2,898	$	400

Note 7. Debt

Revolving Credit Facility

     In conjunction with the closing of the acquisition of the Elk Basin Assets on March 7, 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate comprised of Bank of America, N.A. and other lenders. 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 OLLC Credit Agreement matures on March 7, 2012.

     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 and upon requested special redeterminations. At December 31, 2007, the borrowing base was $145 million.

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

     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (i) the total amount outstanding in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. 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 the Partnership) 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 (i) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (ii) the federal funds effective rate plus 0.5 percent.

     As of December 31, 2007, the aggregate principal amount of loans outstanding under the OLLC Credit Agreement was $47.5 million and there were $0.1 million of outstanding letters of credit. 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.

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     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 the Partnership, 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 OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0;

• a requirement that 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 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 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. At December 31, 2007, OLLC was in compliance with all debt covenants under the OLLC Credit Agreement.

     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:

	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	%

Subordinated Credit Agreement

     On March 7, 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 the subordinated credit agreement, a single subordinated term loan was made on March 7, 2007 to the Partnership in the aggregate amount of $120 million. The total outstanding balance of $126.4 million, including accrued interest, was repaid using a portion of the net proceeds from the IPO.

Long-Term Debt Maturities

     The following table illustrates the Partnership’s long-term debt maturities at December 31, 2007:

	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(in thousands)
Revolving credit facility	$	47,500	$	—	$	—	$	—	$	—	$	47,500	$	—

     For 2007, cash payments for interest totaled $11.9 million. The Partnership did not have any interest payments for 2006 or 2005.

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     During 2007, the weighted average interest rate for total indebtedness was 8.9 percent.

Note 8. Partners’ Equity and 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. The Partnership distributes available cash to its unitholders and the General Partner in accordance with their ownership percentages. In distributing available cash, the Partnership assumes that the holders of management incentive units own the equivalent number of common units into which such units are convertible on the date of distribution, provided that distributions payable to holders of management incentive units are subject to a maximum limit equal to 5.1 percent of all distributions to the Partnership’s unitholders at the time of any such distribution. If the 5.1 percent maximum limit on aggregate distributions to the holders of management incentive units is reached, then any available cash that would have been distributed to such holders will be available for distribution to unitholders. See “Note 10. Unit-Based Compensation Plans” for additional discussion of the management incentive units.

     On November 14, 2007, the Partnership paid a prorated quarterly distribution of $0.053 per unit for the period from and including September 17, 2007 (the closing date of the IPO) through September 30, 2007. The total distribution of $1.3 million was paid to unitholders of record as of the close of business on November 8, 2007.

Note 9. Earnings Per Common Unit (“EPU”)

     The Partnership calculates EPU in accordance with SFAS 128. Under the two-class method of calculating EPU as prescribed by SFAS 128, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in undistributed earnings with common units. For purposes of calculating EPU, the general partner units and management incentive units are participating securities.

     EPU is calculated by dividing the limited partners’ interest in net loss, after deducting the interests of participating securities by the weighted average number of common units outstanding. For 2007, EPU was calculated based on the net loss for the period from the closing of the IPO on September 17, 2007 through December 31, 2007. For periods prior to the IPO, the Partnership was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, EPU is not presented for those periods.

     The following table presents the allocation of net loss to the limited partners and reflects EPU computations for 2007 (in thousands, except per unit data):

Net loss	$	(7,023	)
Less: Net income related to pre-IPO operations and pre-partnership operations of the Permian and Williston Basin Assets		11,953
Net loss attributable to unitholders	$	(18,976	)
Numerator:
Net loss attributable to unitholders	$	(18,976	)
Less: Net loss allocation to participating securities (a)		(359	)
Net loss allocation to limited partners	$	(18,617	)
Denominator:
Denominator for basic EPU:
Weighted average common units outstanding		23,877
Effect of dilutive management incentive units (b)		—
Denominator for diluted EPU		23,877
Net loss per common unit:
Basic	$	(0.78	)
Diluted	$	(0.78	)

(a) The net loss allocation to participating securities includes the General Partner’s interest in the net loss of the Partnership, offset by the quarterly distribution to the General Partner and holders of management incentive units for the third quarter of 2007.

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ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

(b) A total of 550,000 management incentive units, which represented 687,500 common unit equivalents at December 31, 2007, were outstanding at December 31, 2007 but were excluded from the above calculation of diluted EPU for 2007 because their effect would be antidilutive. See additional discussion of management incentive units in “Note 10. Unit-Based Compensation Plans.”

     As discussed in “Note 13. Subsequent Events,” in February 2008, the Partnership completed the acquisition of the Permian and Williston Basin Assets from Encore Operating, and in May 2008, the Partnership acquired an existing net profits interest in certain of its properties in the Permian Basin of West Texas. As partial consideration for the acquisition of the Permian and Williston Basin Assets, the Partnership issued 6,884,776 common units representing limited partner interests to Encore Operating. In connection with the acquisition of the net profits interest in certain Permian Basin properties, the Partnership issued 283,700 common units. As of June 30, 2008, there were 31,356,155 outstanding common units.

Note 10. Unit-Based Compensation Plans

Management Incentive Units

     In May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner. A management incentive unit is a limited partner interest in the Partnership that entitles the holder to quarterly distributions to the extent paid to the Partnership’s common unitholders and to increasing distributions upon the achievement of 10 percent compounding increases in the Partnership’s distribution rate to common unitholders. Management incentive units are convertible into common units of the Partnership upon the occurrence of any of the following events:

• a change in control;

• at the option of the holder, when the Partnership’s aggregate quarterly distributions to unitholders over four consecutive quarters are at least $2.05 per unit; or

• the holder’s death or disability.

     For purposes of the management incentive units, a change in control of the General Partner is defined as the occurrence of one or more of the following events:

• a “Change in Control” as defined in EAC’s 2000 Incentive Stock Plan;

• any person or group, other than EAC and its affiliates, becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization, or otherwise, of 50 percent or more of the combined voting power of the equity interests in the General Partner;

• the limited partners approve, in one or a series of transactions, a plan of complete liquidation of the Partnership;

• the sale or disposition by either the General Partner or the Partnership of all or substantially all of its assets in one or more transactions to any person other than the General Partner or an affiliate of the General Partner; or

• a transaction resulting in a person other than the General Partner or one of its affiliates being the general partner of the Partnership.

     A management incentive unit was initially convertible into one common unit. The conversion rate per management incentive unit is equal to the annualized distribution rate per management incentive unit immediately prior to conversion divided by the annualized distribution rate per common unit, with a maximum conversion rate of 4.7684 common units per management incentive unit. The following table sets forth the annualized distribution rate per management incentive unit after 10 percent compounding increases in the Partnership’s distribution rate to unitholders and the aggregate number of common units into which the management incentive units are convertible:

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ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Annualized Management Incentive Units
Conversion and Distribution Summary

Common Units				Management Incentive Units
Annualized				Annualized
Distribution per	Percentage			Distribution per		Conversion		Common Unit
Unit	Increase			Unit		Rate per Unit		Equivalents
$1.40		—		$	1.40		1.0000		550,000
$1.54		10.0	%	$	1.93		1.2500		687,500
$1.69		10.0	%	$	2.65		1.5625		859,375
$1.86		10.0	%	$	3.64		1.9531		1,074,205
$2.05		10.0	%	$	5.00		2.4414		1,342,770
$2.25		10.0	%	$	6.88		3.0518		1,678,490
$2.48		10.0	%	$	9.46		3.8147		2,098,085
$2.73		10.0	%	$	13.01		4.7684		2,622,620

     In order for distributions payable to the holders of the management incentive units to increase, the distributions payable to common unitholders must increase by 10 percent on a compounded basis. The management incentive units are subject to a maximum limit on the aggregate number of common units issuable to, and the aggregate distributions payable to, holders of management incentive units as follows:

• the holders of management incentive units are not entitled to receive, in the aggregate, common units upon conversion of the management incentive units that exceed a maximum limit of 5.1 percent of all the Partnership’s then-outstanding units; and

• the holders of management incentive units are not entitled to receive, in the aggregate, distributions of the Partnership’s available cash in an amount that exceeds a maximum limit of 5.1 percent of all such distributions to all unitholders at the time of any such distribution.

     The holders of management incentive units do not have any voting rights with respect to the units.

     The fair value of the management incentive units granted in 2007 was estimated on the date of grant using a discounted dividend model. The management incentive units vest in three equal installments. The first installment vested upon the closing of the IPO, and the subsequent vestings occur on September 17, 2008 and 2009. For 2007, the Partnership recognized total compensation expense of $6.8 million for the management incentive units, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2007, ENP had $4.8 million of total unrecognized compensation cost related to unvested, outstanding management incentive units, which is expected to be recognized over a weighted average period of 0.7 years. For each quarter through the third quarter of 2008, the expense will be approximately $1.1 million per quarter, and for the fourth quarter of 2008 through the third quarter of 2009, the expense will be approximately $0.4 million per quarter. There have not been any additional issuances or forfeitures of management incentive units.

ENP Incentive Plan

     As discussed in “Note 1. Formation of the Partnership and Description of Business,” in connection with the IPO, the board of directors of the General Partner adopted the ENP Incentive Plan for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates who perform services for the Partnership. The ENP Incentive Plan provides for the grant of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. An aggregate of 1,150,000 common units may be delivered pursuant to awards under the ENP Incentive Plan. As of December 31, 2007, there were 1,130,000 units available for issuance under the ENP Incentive Plan. The ENP Incentive Plan is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator.

     In October 2007, the board of directors of the General Partner issued 20,000 phantom units to directors of the General Partner pursuant to the ENP Incentive Plan. 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. These phantom units are classified as liability awards under SFAS 123R. Accordingly, the Partnership determines the fair value of these awards

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ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

at each reporting period, based on the closing unit price of the Partnership’s common units, and recognizes the current portion of the liability as a component of “Other current liabilities” and the long-term portion of the liability as a component of “Other noncurrent liabilities” in the accompanying Consolidated Balance Sheets. As of December 31, 2007, the total liability was approximately $31,000. For liability awards, the fair value of the award, which determines the measurement of the liability on the balance sheet, is remeasured at each reporting period until the award is settled. Changes in the fair value of the liability award from period to period are recorded as increases or decreases in compensation expense over the remaining service period. The phantom units vest in four equal annual installments beginning on October 29, 2008. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle the grantee to receive cash equal to the amount of any cash distributions made by the Partnership with respect to a common unit during the period the right is outstanding.

     The Partnership recognized total compensation expense of approximately $31,000 for the phantom units in 2007, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There were no additional issuances or forfeitures under the ENP Incentive Plan during 2007.

     To satisfy common unit awards, the Partnership may issue new common units, acquire common units in the open market, or use common units already owned by EAC and its affiliates.

Note 11. Financial Instruments

     The carrying value of the Partnership’s cash, accounts receivable, and accounts payable approximate their respective fair value due to the relatively short term of the instruments. The carrying amount of long-term debt approximates fair value as the interest rate is variable. Commodity derivative contracts are marked-to-market each quarter in accordance with the provisions of SFAS 133.

Derivative Financial Instruments

     The Partnership manages commodity price risk with swap contracts, put contracts, collars, and floor spreads. Swap contracts provide a fixed price for a notional amount of volume. Put contracts provide a fixed floor price on a notional amount of volume while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide a floor price for a notional amount of volume while allowing some additional price participation if the relevant index price closes above the floor price.

     In connection with the acquisition of the Elk Basin Assets, EAC purchased floor contracts for 2,500 Bbls per day (“Bbls/D”) of production at $65.00 per Bbl for April 2007 through December 2008 that were all later contributed to the Partnership at their fair market value on the date of transfer of $9.4 million. In addition to these contributed derivatives, the Partnership has purchased additional derivative financial instruments as part of its risk management strategy.

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ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

     The following tables summarize the Partnership’s open commodity derivative contracts as of December 31, 2007:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		(Liability) Fair
Period	Volume		Price		Volume		Price		Volume		Price		Market Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
Jan. 2008													$	—
		2,000	$	75.00		—	$	—		—	$	—
		500		65.00		—		—		—		—
Feb. - Dec. 2008														930
		880		80.00		440		107.60		—		—
		2,000		75.00		—		—		—		—
		500		65.00		—		—		—		—
2009														(3,050	)
		880		80.00		440		97.75		—		—
		2,250		74.11		—		—		1,000		68.70
2010														52
		880		80.00		440		93.80		—		—
		2,000		75.00		1,000		77.23		—		—
2011														1,811
		1,000		80.00		1,000		94.65		—		—
		1,000		70.00		—		—		—		—
													$	(257	)

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Fair Market
Period	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
Jan. 2008									$	119
		2,000	$	8.20		2,000	$	9.85
		2,000		7.20		—		—
Feb. - Dec. 2008										1,798
		3,800		8.20		3,800		9.83
		3,800		7.20		—		—
2009										1,376
		3,800		8.20		3,800		9.83
		3,800		7.20		—		—
2010										1,240
		3,800		8.20		3,800		9.58
		3,800		7.20		—		—
									$	4,533

     Commodity Contracts — Mark-to-Market Accounting.In order to partially finance the cost of premiums on certain purchased floors, the Partnership may sell floors with a strike price below the strike price of the purchased floor. 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. During 2007, the Partnership entered into floor spreads with a $75 per

24

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Bbl purchased floor and a $65 per Bbl short floor for 2,000 Bbls/D in 2008 and 2010 and 1,250 Bbls/D in 2009. As with the Partnership’s other derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. In the above table, the purchased floor component and the short floor component of these floor spreads are shown net and included with the Partnership’s other floor contracts. The net cash flows per Bbl upon settlement of the contracts and payment of the related premiums when viewed together change depending on the NYMEX oil price as follows:

• When the NYMEX oil price is greater than $75 per Bbl, the Partnership pays the net purchased floor premium cost per Bbl.

• When the NYMEX oil price is greater than $65 per Bbl but less than $75 per Bbl, the Partnership receives settlements of $75 per Bbl less the NYMEX oil price and pays the net purchased floor premium cost per Bbl.

• When the NYMEX oil price is below $65 per Bbl, the Partnership receives $10 per Bbl less the net purchased floor premium cost per Bbl.

     Commodity Contracts — Current Period Impact.As a result of derivative transactions for oil and natural gas, the Partnership recognized derivative fair value losses related to changes in the market value of commodity derivatives and settlements on derivative contracts for 2007. Prior to 2007, the Partnership did not have any commodity derivative contracts; therefore, no derivative fair value gains or losses are reported for 2006 or 2005. The following table summarizes the components of derivative fair value loss for 2007 (in thousands):

Mark-to-market loss on commodity contracts	$	23,470
Premium amortization		4,073
Settlements on commodity contracts		(1,242	)
Total derivative fair value loss	$	26,301

     Counterparty Risk.At December 31, 2007, the Partnership had committed greater than 10 percent of either its oil or natural gas production represented by 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.		37.6	%		—
BNP Paribas		40.4	%		23.3	%
Calyon		5.7	%		17.8	%
Wachovia		2.5	%		58.9	%

     The Partnership believes the credit-worthiness of its counterparties is sound and does not anticipate any non-performance of contractual obligations. As long as each counterparty maintains an investment grade credit rating, pursuant to ENP’s derivative contracts, no collateral is required.

     In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating separately each financial transaction between the counterparty and ENP, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement benefits ENP in three ways: (i) the netting of the value of all trades reduces the requirements of daily collateral posting by ENP, (ii) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty, and (iii) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out.

Note 12. Related Party Transactions

     The Partnership does not have any employees. The employees supporting the operations of the Partnership are employees of EAC. As discussed in “Note 1. Formation of the Partnership and Description of Business,” at the closing of the IPO, the Partnership entered into the Administrative Services Agreement with Encore Operating, pursuant to which Encore Operating

25

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

performs administrative services for the Partnership. Under the Administrative Services Agreement, Encore Operating initially received an administrative fee of $1.75 per BOE of the Partnership’s production for such services and reimbursement for actual third-party expenses incurred on the Partnership’s behalf. The Partnership also pays its share of expenses that are directly chargeable to wells under joint operating agreements. 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 the Partnership 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.

     In 2007, the Partnership paid $2.8 million to Encore Operating for administrative fees under the Administrative Services Agreement (including payment of any COPAS recovery) and $3.5 million for reimbursement of actual third-party expenses incurred on the Partnership’s behalf. Expenses incurred under the Administrative Services Agreement and third-party expenses billed by EAC to the Partnership are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. As of December 31, 2007 and 2006, the Partnership had a payable to EAC of $6.7 million and $3.1 million, respectively, which is reflected in “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets. As of December 31, 2007 and 2006, the Partnership had a receivable from EAC of $3.3 million and $1.7 million, respectively, which is reflected in “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets.

     During 2007, the Partnership distributed approximately $0.8 million to EAC and certain executive officers of the General Partner related to the third quarter distribution on common units and management incentive units. In addition, the Partnership distributed approximately $27,000 to the General Partner during 2007 as the holder of 504,851 general partner units.

     As discussed in “Note 7. Debt,” during 2007, the Partnership had a subordinated credit agreement held by a related party of the Partnership, 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 the Partnership in September 2007 and the acquisition of the Permian and Williston Basin Assets in February 2008, these properties were wholly owned by EAC and were not separate legal entities. In addition to employee-related expenses, EAC incurred G&A expenses related to leasing office space and other corporate overhead expenses during the period these properties were wholly owned by EAC. A portion of the consolidated G&A expenses reported for EAC were allocated to the Partnership and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the properties in relation to the total BOE produced by EAC on a consolidated basis.

     EAC (through its subsidiaries) contributed $93.7 million to the Partnership in March 2007. These proceeds were used by the Partnership, along with proceeds from the borrowings under the Partnership’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

Acquisitions

     As discussed in “Note 2. Summary of Significant Accounting Policies,” in February 2008, the Partnership completed the acquisition of the Permian and Williston Basin Assets from Encore Operating. The total consideration for the acquisition consisted of approximately $125.3 million in cash and 6,884,776 common units representing limited partner interests in the Partnership, which were valued at $125 million. Upon completion of the acquisition, the borrowing base under OLLC’s revolving credit facility was increased to $240 million. The Partnership financed the cash portion of the purchase price through additional borrowings under the OLLC Credit Agreement. The acquisition was accounted for as a transaction between entities under common control. Therefore, the historical consolidated financial statements of the Partnership have been recast to reflect the historical operating results of the combined entities for all periods presented.

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

26

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Derivative Contracts

Commodity Derivative Contracts

     Subsequent to December 31, 2007, the Partnership increased its oil derivative contract positions by entering into additional commodity derivative contracts. The following tables summarize the Partnership’s open commodity derivative contracts as of September 16, 2008:

     Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average
	Floor		Floor		Cap		Cap		Swap		Swap
Period	Volume (a)		Price		Volume		Price		Volume		Price
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)
Sept. - Dec. 2008		880	$	80.00		440	$	107.60		—	$	—
		2,000		75.00		—		—		—		—
		500		65.00		—		—		—		—
2009		3,130		110.00		440		97.75		1,000		68.70
2010		880		80.00		440		93.80		—		—
		2,000		75.00		1,000		77.23		—		—
2011		1,880		80.00		1,440		95.41		—		—
		1,000		70.00		—		—		—		—

(a) In order to partially finance the cost of premiums on certain purchased floors, the Partnership may sell floors with a strike price below the strike price of the purchased floor, thereby entering into a floor spread. In the above table, the purchased floor component of these floor spreads are shown net and included with the Partnership’s other floor contracts. In addition to the floor contracts shown for 2009, the Partnership 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.

     Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average
	Floor		Floor		Cap		Cap
Period	Volume		Price		Volume		Price
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)
Sept. - Dec. 2008		3,800	$	8.20		3,800	$	9.83
		3,800		7.20		—		—
2009		3,800		8.20		3,800		9.83
		3,800		7.20		—		—
2010		3,800		8.20		3,800		9.58
		3,800		7.20		—		—

27

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued

Interest Rate Swap Agreements

     During the first quarter of 2008, the Partnership entered into interest rate swap agreements whereby it swapped $100 million of floating rate debt on its revolving credit facility to a weighted average fixed rate of 3.06 percent and an expected margin of 1.25 percent. These interest rate swap agreements were designated as cash flow hedges. The following table summarizes the Partnership’s open interest rate swap agreements as of September 16, 2008:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
Sept. 2008 - - Jan. 2011	$	50,000		3.1610	%	1 month LIBOR
Sept. 2008 - Jan. 2011		25,000		2.9650	%	1 month LIBOR
Sept. 2008 - Jan. 2011		25,000		2.9613	%	1 month LIBOR

Distributions

     In May 2008, the board of directors of the General Partner approved a new distribution methodology, which returns additional cash flow to the Partnership’s unitholders during high commodity price environments. The Partnership will distribute to unitholders 50 percent of the excess distributable cash flow above (i) maintenance capital requirements; (ii) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and (iii) a minimum coverage ratio of 1.10.

     During the eight months ended August 31, 2008, the Partnership paid approximately $52.3 million to unitholders for quarterly distributions.

Other Events

     Effective April 1, 2008, the administrative fee paid to Encore Operating under the Administrative Services Agreement increased from $1.75 to $1.88 per BOE of the Partnership’s production as a result of the COPAS Wage Index Adjustment for 2008.

     During the first quarter of 2008, the board of directors of the General Partner issued 5,000 phantom units to a new board member pursuant to the ENP Incentive Plan.

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ENCORE ENERGY PARTNERS LP

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 of the dates indicated:

	December 31,
	2007			2006
	(in thousands)
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment	$	500,470		$	119,256
Unproved properties		298			216
Accumulated depletion, depreciation, and amortization		(63,295	)		(31,294	)
	$	437,473		$	88,178

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

	Year Ended December 31,
	2007		2006		2005
	(in thousands)
Acquisitions:
Proved properties	$	353,985	$	319	$	19,120
Unproved properties		105		103		82
Asset retirement obligations		6,343		6		454
Total acquisitions		360,433		428		19,656
Development:
Drilling and exploitation		17,542		3,898		5,694
Asset retirement obligations		117		17		204
Total development		17,659		3,915		5,898
Exploration:
Drilling and exploitation		3,130		3		816
Geological and seismic		101		—		12
Total exploration		3,231		3		828
Total costs incurred	$	381,323	$	4,346	$	26,382

Oil & Natural Gas Producing Activities — Unaudited

     The estimates of the Partnership’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the FASB. Proved oil and natural gas reserve quantities are derived from estimates prepared by 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 were as follows as of the dates indicated:

	December 31,
	2007		2006		2005
Oil (per Bbl)	$	96.01	$	61.06	$	61.04
Natural gas (per Mcf)	$	7.47	$	5.48	$	9.44

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ENCORE ENERGY PARTNERS LP

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 costs 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 the Partnership’s standardized measure as each partner is separately taxed on his share of the Partnership’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.

     Estimated net quantities of proved oil and natural gas reserves of the Partnership were as follows as of the dates indicated:

	December 31,
	2007		2006		2005
Proved reserves:
Oil (MBbls)		21,397		3,952		3,937
Natural gas (MMcf)		61,207		55,241		63,526
Combined (MBOE)		31,598		13,159		14,525
Proved developed reserves:
Oil (MBbls)		19,140		3,503		3,496
Natural gas (MMcf)		51,288		48,265		51,296
Combined (MBOE)		27,688		11,547		12,045

     The changes in proved reserves were as follows for 2007, 2006, and 2005:

				Natural			Oil
	Oil			Gas			Equivalent
	(MBbls)			(MMcf)			(MBOE)
Balance, December 31, 2004		2,332			56,819			11,802
Purchases of minerals-in-place		1,634			869			1,779
Extensions and discoveries		79			4,095			762
Revisions of previous estimates		116			5,630			1,054
Production		(224	)		(3,887	)		(872	)
Balance, December 31, 2005		3,937			63,526			14,525
Purchases of minerals-in-place		17			—			17
Extensions and discoveries		47			952			206
Revisions of previous estimates		243			(5,939	)		(747	)
Production		(292	)		(3,298	)		(842	)
Balance, December 31, 2006		3,952			55,241			13,159
Purchases of minerals-in-place		17,382			3,200			17,915
Extensions and discoveries		425			6,418			1,495
Revisions of previous estimates		1,074			(234	)		1,035
Production		(1,436	)		(3,418	)		(2,006	)
Balance, December 31, 2007		21,397			61,207			31,598

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ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION — Continued

     The standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves was as follows as of the dates indicated:

	December 31,
	2007			2006			2005
	(in thousands)
Future cash inflows	$	2,106,853		$	504,838		$	756,051
Future production costs		(725,590	)		(183,505	)		(241,927	)
Future development costs		(40,244	)		(13,588	)		(19,157	)
Future abandonment costs, net of salvage		(23,741	)		(3,153	)		(3,101	)
Future income tax expense		(5,866	)		(1,714	)		—
Future net cash flows		1,311,412			302,878			491,866
10% annual discount		(651,544	)		(166,711	)		(249,155	)
Standardized measure of discounted estimated future net cash flows	$	659,868		$	136,167		$	242,711

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

	Year Ended December 31,
	2007			2006			2005
	(in thousands)
Standardized measure, beginning of year	$	136,167		$	242,711		$	142,208
Net change in prices and production costs		80,331			(87,708	)		78,967
Purchases of minerals-in-place		484,207			265			30,910
Extensions, discoveries, and improved recovery		22,667			2,378			14,384
Revisions of previous quantity estimates		29,353			(6,443	)		18,527
Production, net of production costs		(98,955	)		(23,067	)		(34,229	)
Development costs incurred during the period		17,542			3,898			5,694
Accretion of discount		13,617			24,272			14,221
Change in estimated future development costs		(28,465	)		1,670			(13,852	)
Net change in income taxes		(2,071	)		(194	)		—
Change in timing and other		5,475			(21,615	)		(14,119	)
Net increase (decrease)		523,701			(106,544	)		100,503
Standardized measure, end of year	$	659,868		$	136,167		$	242,711

31

ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION — Continued

Selected Quarterly Financial Data — Unaudited

     The following table sets forth selected quarterly financial data for 2007 and 2006:

	Quarter
	First			Second			Third			Fourth
	(in thousands, except per unit data)
2007
Revenues:
As reported	$	8,469		$	22,756		$	23,160		$	25,302
Plus: Permian and Williston Basin Assets		5,542			8,759			10,385			13,039
Adjusted	$	14,011		$	31,515		$	33,545		$	38,341
Operating income (loss):
As reported	$	(1,808	)	$	2,149		$	(3,269	)	$	(10,317	)
Plus: Permian and Williston Basin Assets		2,365			3,933			5,306			7,186
Adjusted	$	557		$	6,082		$	2,037		$	(3,131	)
Net income (loss)
As reported	$	(2,928	)	$	(3,187	)	$	(8,066	)	$	(11,160	)
Plus: Permian and Williston Basin Assets		1,997			3,911			5,246			7,164
Adjusted	$	(931	)	$	724		$	(2,820	)	$	(3,996	)
Net loss allocation (see Note 9):
Limited partners’ interest in net loss							$	(7,597	)	$	(10,960	)
General partner’s interest in net loss							$	(159	)	$	(229	)
Net loss per common unit:
Basic							$	(0.33	)	$	(0.46	)
Diluted							$	(0.33	)	$	(0.46	)
2006
Revenues:
As reported	$	3,814		$	3,079		$	3,134		$	2,719
Plus: Permian and Williston Basin Assets		7,078			7,508			7,374			6,199
Adjusted	$	10,892		$	10,587		$	10,508		$	8,918
Operating income:
As reported	$	2,538		$	1,896		$	1,898		$	1,438
Plus: Permian and Williston Basin Assets		3,865			3,986			4,075			2,948
Adjusted	$	6,403		$	5,882		$	5,973		$	4,386
Net income:
As reported	$	2,538		$	1,896		$	1,898		$	1,316
Plus: Permian and Williston Basin Assets		3,865			3,879			4,070			2,942
Adjusted	$	6,403		$	5,775		$	5,968		$	4,258

     As discussed in “Note 2. Summary of Significant Accounting Policies,” in February 2008, the Partnership completed the acquisition of the Permian and Williston Basin Assets from Encore Operating. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction 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 Partnership’s historical financial information was recast to include the results of operations of the Permian and Williston Basin Assets for all periods presented.

32

ENCORE ENERGY PARTNERS LP

SUPPLEMENTARY INFORMATION — Continued

     The table above presents the allocation of net loss to the limited partners for the period subsequent to the IPO and displays EPU for the applicable periods. For periods prior to the IPO, the Partnership was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, EPU is not presented for those periods.

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