Encore Energy Partners 10-Q 2009 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to                 

Commission File Number:001-33676

ENCORE ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	20-8456807
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
777 Main Street, Suite 1400, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 877-9955

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o   No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer þ  Non-accelerated filer o
(Do not check if a smaller reporting company) Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No þ

Number of common units outstanding as of July 31, 2009   45,267,610

ENCORE ENERGY PARTNERS LP

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		1
	Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008		2
	Consolidated Statement of Partners’ Equity and Comprehensive Loss for the six months ended June 30, 2009		3
	Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008		4
	Notes to Consolidated Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		38
Item 4.	Controls and Procedures		39
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		40
Item 1A.	Risk Factors		40
Item 6.	Exhibits		40
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

     Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and our other materials filed with the United States Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements. These forward-looking statements give our current expectations or forecasts of future events. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “may,” “will,” “could,” “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “predict,” “potential,” “pursue,” “target,” “continue,” and other words and terms of similar meaning. You are cautioned not to place undue reliance on such forward-looking statements, which speak only as of the date of this Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, the matters discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K and in our other filings with the SEC. If one or more of these risks or uncertainties materialize (or the consequences of such a development changes), or should underlying assumptions prove incorrect, actual outcomes may vary materially from those forecasted or expected. We undertake no responsibility to update forward-looking statements for changes related to these or any other factors that may occur subsequent to this filing for any reason.

i

ENCORE ENERGY PARTNERS LP

GLOSSARY

     The following are abbreviations and definitions of certain terms used in this Report. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been summarized from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

• Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

• Bbl/D. One Bbl per day.

• BOE.One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

• BOE/D. One BOE per day.

• Completion.The installation of permanent equipment for the production of hydrocarbons.

• Council of Petroleum Accountants Societies (“COPAS”). A professional organization of petroleum accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements. These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.

• Delay Rentals. Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.

• Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

• EAC.Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.

• ENP. Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.

• Exploratory Well. A well drilled to find and produce hydrocarbons in an unproved area, to find a new reservoir in a field previously producing hydrocarbons in another reservoir, or to extend a known reservoir.

• FASB.Financial Accounting Standards Board.

• Field. An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

• GAAP.Accounting principles generally accepted in the United States.

• Gross Acres or Gross Wells.The total acres or wells, as the case may be, in which an entity owns a working interest.

• Lease Operating Expense (“LOE”).All direct and allocated indirect costs of producing hydrocarbons after the completion of drilling and before the commencement of production. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.

• LIBOR.London Interbank Offered Rate.

• MBbl.One thousand Bbls.

• MBOE.One thousand BOE.

• Mcf.One thousand cubic feet, used in reference to natural gas.

• Mcf/D.One Mcf per day.

• MMcf.One million cubic feet, used in reference to natural gas.

• Natural Gas Liquids (“NGLs”).The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

• Net Acres or Net Wells.Gross acres or wells, as the case may be, multiplied by the working interest percentage owned by an entity.

• Net Profits Interest.An interest that entitles the owner to a specified share of net profits from the production of hydrocarbons.

• NYMEX.New York Mercantile Exchange.

• Oil.Crude oil, condensate, and NGLs.

• Operator.The entity responsible for the exploration, development, and production of a well or lease.

• Production Margin.Wellhead revenues less production costs.

• Productive Well or Successful Well.A well capable of producing hydrocarbons in commercial quantities, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

• Proved Developed Reserves.Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

• Proved Reserves.The estimated quantities of hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating

ii

ENCORE ENERGY PARTNERS LP

conditions.

• Proved Undeveloped Reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. Includes unrealized production response from enhanced recovery techniques that have been proved effective by actual tests in the area and in the same reservoir.

• Recompletion.The completion for production from an existing wellbore in another formation from that in which the well has been previously completed.

• Reservoir.A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

• Royalty.An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

• SFAS.Statement of Financial Accounting Standards.

• Working Interest.An interest in an oil or natural gas lease that gives the owner the right to drill for and produce hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.

• Workover.Operations on a producing well to restore or increase production.

iii

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit amounts)
(unaudited)

	June 30,			December 31,
	2009			2008 *
ASSETS
Current assets:
Cash and cash equivalents	$	72		$	619
Accounts receivable:
Trade		18,315			16,309
Affiliate		350			1,168
Derivatives		37,505			75,131
Other		582			831
Total current assets		56,824			94,058
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		612,930			580,731
Unproved properties		50			67
Accumulated depletion, depreciation, and amortization		(134,964	)		(112,742	)
		478,016			468,056
Other property and equipment		802			802
Accumulated depreciation		(341	)		(240	)
		461			562
Goodwill		4,500			4,500
Other intangibles, net		3,489			3,662
Derivatives		24,957			38,497
Other		1,052			1,457
Total assets	$	569,299		$	610,792
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,147		$	1,036
Affiliate		2,620			2,812
Accrued liabilities:
Lease operating expense		4,877			3,104
Development capital		1,838			947
Interest		308			126
Production, ad valorem, and severance taxes		10,819			10,394
Derivatives		4,701			1,297
Oil and natural gas revenues payable		1,885			1,287
Other		3,122			1,502
Total current liabilities		31,317			22,505
Derivatives		6,234			3,491
Future abandonment cost, net of current portion		10,074			9,759
Long-term debt		195,000			150,000
Other		372			605
Total liabilities		242,997			186,360
Commitments and contingencies (see Note 12)
Partners’ equity:
Limited partners - 35,837,610 and 33,077,610 common units issued and outstanding, respectively		329,700			425,749
General partner - 504,851 general partner units issued and outstanding		213			2,942
Accumulated other comprehensive loss		(3,611	)		(4,259	)
Total partners’ equity		326,302			424,432
Total liabilities and partners’ equity	$	569,299		$	610,792

* Recast as discussed in Note 2.

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

1

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
(unaudited)

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008 *			2009			2008 *
Revenues:
Oil	$	23,182		$	51,603		$	38,915		$	92,444
Natural gas		3,955			14,654			7,873			23,743
Marketing		109			903			279			3,762
Total revenues		27,246			67,160			47,067			119,949
Expenses:
Production:
Lease operating		6,949			7,635			14,831			14,329
Production, ad valorem, and severance taxes		3,062			6,308			5,402			11,539
Depletion, depreciation, and amortization		11,294			10,316			22,285			20,520
Exploration		18			38			40			67
General and administrative		2,807			3,252			4,996			6,424
Marketing		61			1,609			191			4,002
Derivative fair value loss		37,440			76,428			26,533			92,015
Other operating		658			391			1,375			793
Total expenses		62,289			105,977			75,653			149,689
Operating loss		(35,043	)		(38,817	)		(28,586	)		(29,740	)
Other income (expenses):
Interest		(2,351	)		(1,909	)		(4,567	)		(3,549	)
Other		1			65			6			82
Total other expenses		(2,350	)		(1,844	)		(4,561	)		(3,467	)
Loss before income taxes		(37,393	)		(40,661	)		(33,147	)		(33,207	)
Income tax benefit (provision)		(200	)		135			(201	)		138
Net loss	$	(37,593	)	$	(40,526	)	$	(33,348	)	$	(33,069	)
Net loss allocation (see Note 9):
Limited partners’ interest in net loss	$	(37,093	)	$	(45,441	)	$	(32,582	)	$	(45,650	)
General partner’s interest in net loss	$	(630	)	$	(735	)	$	(573	)	$	(808	)
Net loss per common unit:
Basic	$	(1.08	)	$	(1.45	)	$	(0.97	)	$	(1.53	)
Diluted	$	(1.08	)	$	(1.45	)	$	(0.97	)	$	(1.53	)
Weighted average common units outstanding:
Basic		34,260			31,260			33,672			29,766
Diluted		34,260			31,260			33,672			29,766
Cash distributions declared per common unit	$	0.5000		$	0.5755		$	1.0000		$	0.9630

* Recast as discussed in Note 2.

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

2

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY AND COMPREHENSIVE LOSS
(in thousands, except per unit amounts)
(unaudited)

											Accumulated
											Other			Total
	Limited Partners					General Partner					Comprehensive			Partners’
	Units		Amount			Units		Amount			Loss			Equity
Balance at December 31, 2008 *		33,078	$	425,749			505	$	2,942		$	(4,259	)	$	424,432
Net distributions to owner		—		(476	)		—		(12	)		—			(488	)
Deemed distributions in connection with acquisition of the Arkoma Basin Assets		—		(45,333	)		—		(1,088	)		—			(46,421	)
Deemed distributions in connection with acquisition of the Williston Basin Assets		—		(25,122	)		—		(606	)		—			(25,728	)
Proceeds from issuance of common units, net of offering costs		2,760		40,558			—		(38	)		—			40,520
Non-cash unit-based compensation		—		266			—		3			—			269
Cash distributions to unitholders ($1.00 per unit)		—		(33,077	)		—		(505	)		—			(33,582	)
Components of comprehensive loss:
Net loss attributable to owners prior to acquisition of Williston Basin Assets		—		(188	)		—		(5	)		—			(193	)
Net loss attributable to unitholders		—		(32,677	)		—		(478	)		—			(33,155	)
Change in deferred hedge loss on interest rate swaps, net of tax of $2		—		—			—		—			648			648
Total comprehensive loss															(32,700	)
Balance at June 30, 2009		35,838	$	329,700			505	$	213		$	(3,611	)	$	326,302

* Recast as discussed in Note 2.

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

3

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Six months ended
	June 30,
	2009			2008*
Cash flows from operating activities:
Net loss	$	(33,348	)	$	(33,069	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, and amortization		22,285			20,520
Non-cash exploration expense		17			41
Non-cash interest		195			243
Deferred taxes		(248	)		(214	)
Non-cash unit-based compensation expense		269			2,180
Non-cash derivative loss		69,055			91,203
Other		444			537
Changes in operating assets and liabilities:
Accounts receivable		(1,188	)		(8,326	)
Current derivatives		(2,020	)		—
Other current assets		(179	)		79
Long-term derivatives		(9,072	)		(1,196	)
Other assets		8			745
Accounts payable		273			(4,136	)
Other current liabilities		4,827			3,939
Net cash provided by operating activities		51,318			72,546
Cash flows from investing activities:
Purchases of other property and equipment		—			(217	)
Acquisition of oil and natural gas properties		(27,538	)		(92	)
Development of oil and natural gas properties		(3,477	)		(13,130	)
Net cash used in investing activities		(31,015	)		(13,439	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		78,000			163,310
Payments on long-term debt		(33,000	)		(60,000	)
Deemed distributions to affiliates in connection with acquisitions		(72,149	)		(124,838	)
Proceeds from issuance of common units, net of offering costs		40,724			—
Cash distributions to unitholders		(33,582	)		(29,137	)
Other		(843	)		(7,819	)
Net cash used in financing activities		(20,850	)		(58,484	)
Increase (decrease) in cash and cash equivalents		(547	)		623
Cash and cash equivalents, beginning of period		619			3
Cash and cash equivalents, end of period	$	72		$	626

* Recast as discussed in Note 2.

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

4

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1. Description of Business

     ENP was formed by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of EAC, serves as ENP’s general partner and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly owned subsidiary of ENP, owns and operates ENP’s properties. ENP’s properties and oil and natural gas reserves are located in four core areas:

• the Big Horn Basin in Wyoming and Montana;

• the Permian Basin in West Texas;

• the Williston Basin in North Dakota and Montana; and

• the Arkoma Basin in Arkansas.

Note 2. Basis of Presentation

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

     In February 2008, ENP acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. In January 2009, ENP acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), from Encore Operating. In June 2009, ENP acquired certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) from Encore Operating. Please read “Note 3. Acquisitions” for additional discussion of these acquisitions.

     Because the Permian and Williston Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and ENP’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 historical results of ENP combined with those of the Permian and Williston Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets for all periods presented.

     The results of operations of the Arkoma Basin Assets and the Williston Basin Assets related to pre-partnership operations were allocated to EAC and its affiliates based on their respective ownership percentages in ENP’s general and limited partner units. The effect of recasting ENP’s consolidated financial statements to account for these common control transactions decreased ENP’s net loss by approximately $4.5 million and $7.8 million for the three and six months ended June 30, 2008, respectively, from amounts previously reported.

     In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, ENP’s financial position as of June 30, 2009 and December 31, 2008, results of operations for the three and six months ended June 30, 2009 and 2008, and cash flows for the six months ended June 30, 2009 and 2008. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

     Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in Exhibit 99.3 to ENP’s Current Report on Form 8-K filed with the SEC on May 7, 2009, which recast ENP’s consolidated financial statements included in its 2008 Annual Report on Form 10-K.

5

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Supplemental Disclosures of Cash Flow Information

     The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

	Six months ended June 30,
	2009		2008
	(In thousands)
Non-cash investing and financing activities:
Issuance of common units in connection with acquisition of the Permian and Williston Basin Assets (a)	$	—	$	125,027
Issuance of common units in connection with acquisition of net profits interest in certain Crockett County properties		—		5,748

(a) Please read “Note 3. Acquisitions” for additional discussion.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. In particular, certain amounts in the Consolidated Financial Statements have been either combined or classified in more detail.

New Accounting Pronouncements

FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). ENP 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. FSP FAS 157-2 was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 on January 1, 2009 did not have a material impact on ENP’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

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

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (1) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies” (“FSP FAS 141R-1”), which amends and clarifies SFAS 141R to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R and FSP FAS 141R-1 were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. The adoption of SFAS 141R and FSP FAS 141R-1 on January 1, 2009 did not have a material impact on ENP’s results of operations or financial condition. However, the application of SFAS 141R and FSP FAS 141R-1 to future acquisitions could impact ENP’s results of operations and financial condition and the reporting of 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 No. 133,“Accounting for Derivative Instruments and Hedging Activities”(“SFAS 133”), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of SFAS 161 on January 1, 2009 required additional disclosures regarding ENP’s derivative instruments; however, it did not impact ENP’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

6

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

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 (“EPU”) using the two-class method in SFAS No. 128,“Earnings per Share”(“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 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The adoption of EITF 07-4 on January 1, 2009 did not have a material impact on ENP’s results of operations or financial condition. All periods presented in the accompanying Consolidated Financial Statements have been restated to reflect the adoption of EITF 07-4. Please read “Note 9. Earnings Per Unit” for additional discussion.

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 for computing basic EPU under the two-class method prescribed by SFAS 128. FSP EITF 03-6-1 was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of FSP EITF 03-6-1 on January 1, 2009 did not have a material impact on ENP’s results of operations or financial condition. All periods presented in the accompanying Consolidated Financial Statements have been restated to reflect the adoption of FSP EITF 03-6-1. Please read “Note 9. Earnings Per Unit” for additional discussion.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”)

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009. ENP is evaluating the impact Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1”)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 is prospectively effective for financial statements issued for interim periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 required additional disclosures regarding ENP’s financial instruments; however, it did not impact ENP’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 165, “Subsequent Events” (“SFAS 165”)

     In June 2009, the FASB issued SFAS 165 to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, SFAS 165 sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 is prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 on June 30, 2009 did not impact ENP’s results of operations or financial condition.

7

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS 168”)

     In June 2009, the FASB issued SFAS 168, which replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS 168 establishes the FASB Accounting Standards Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 is prospectively effective for financial statements for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 on July 1, 2009 did not impact ENP’s results of operations or financial condition.

Note 3. Acquisitions

Williston Basin Assets

     In June 2009, ENP acquired the Williston Basin Assets from Encore Operating for approximately $25.7 million in cash, including post-closing adjustments, which was financed through borrowings under OLLC’s revolving credit facility and proceeds from the issuance of ENP common units to the public. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of May 31, 2009 of approximately $31.9 million and $1.3 million, respectively, and the historical financial information of ENP was recast to include the Williston Basin Assets for all periods presented. As the historical basis in the Williston Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price, as adjusted for post-closing adjustments, was recorded as a deemed distribution when paid to EAC and its affiliates based on their respective ownership percentages in ENP.

Vinegarone Assets

     In May 2009, ENP acquired certain natural gas properties in the Vinegarone Field in Val Verde County, Texas (the “Vinegarone Assets”) from an independent energy company for approximately $27.5 million in cash, including post-closing adjustments, which was financed through proceeds from the issuance of ENP common units to the public. The results of operations of the Vinegarone Assets are included with those of ENP from the date of acquisition.

Arkoma Basin Assets

     In January 2009, ENP acquired the Arkoma Basin Assets from Encore Operating for approximately $46.4 million in cash, including post-closing adjustments, which was financed through borrowings under OLLC’s revolving credit facility. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of December 31, 2008 of approximately $18.1 million and $0.7 million, respectively, and the historical financial information of ENP was recast to include the Arkoma Basin Assets for all periods presented. As the historical basis in the Arkoma Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price, including post-closing adjustments, was recorded as a deemed distribution when paid to EAC and its affiliates based on their respective ownership percentages in ENP.

Permian and Williston Basin Assets

     In February 2008, ENP acquired the Permian and Williston Basin Assets from Encore Operating for approximately $125.0 million in cash, including post-closing adjustments, and the issuance of 6,884,776 ENP common units to Encore Operating. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. The cash portion of the purchase price was financed through borrowings under OLLC’s revolving credit facility. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of December 31, 2007 of approximately $105.0 million and $5.1 million, respectively, and the historical financial information of ENP was recast to include the Permian and Williston Basin Assets for all periods presented. As the historical basis in the Permian and Williston Basin Assets is included in the accompanying Consolidated

8

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Balance Sheets, the cash purchase price, including post-closing adjustments, was recorded as a deemed distribution when paid to EAC and its affiliates based on their respective ownership percentages in ENP.

Note 4. Proved Properties

     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:

	June 30,		December 31,
	2009		2008
	(in thousands)
Proved leasehold costs	$	448,015	$	423,327
Wells and related equipment — Completed		164,599		155,344
Wells and related equipment — In process		316		2,060
Total proved properties	$	612,930	$	580,731

Note 5. Fair Value Measurements

     The following table sets forth ENP’s book value and estimated fair value of financial instruments as of the dates indicated:

	June 30, 2009				December 31, 2008
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	72	$	72	$	619	$	619
Accounts receivable — trade		18,315		18,315		16,309		16,309
Accounts receivable — affiliate		350		350		1,168		1,168
Commodity derivative contracts		62,462		62,462		113,628		113,628
Liabilities:
Accounts payable — trade		1,147		1,147		1,036		1,036
Accounts payable — affiliate		2,620		2,620		2,812		2,812
Revolving credit facility		195,000		195,000		150,000		150,000
Commodity derivative contracts		7,110		7,110		229		229
Interest rate swaps		3,825		3,825		4,559		4,559

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

Derivative Policy

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

     ENP applies the provisions of SFAS 133, which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, changes in fair value can be recognized in accumulated other comprehensive loss until such time as the hedged item is recognized in earnings.

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

9

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     ENP has elected to designate its current interest rate swaps as cash flow hedges. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings as “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

     ENP has not elected to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings as “Derivative fair value loss” in the accompanying Consolidated Statements of Operations.

Commodity Derivative Contracts

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

     From time to time, ENP enters into floor spreads. In a floor spread, ENP purchases puts at a specified price (a “purchased put”) and also sells a put at a lower price (a “short put”). This strategy enables ENP to achieve downside protection for a portion of its production, while funding the cost of such protection by selling a put at a lower price. If the price of the commodity falls below the strike price of the purchased put, then ENP has protection against commodity price decreases for the covered production down to the strike price of the short put. At commodity prices below the strike price of the short put, the benefit from the purchased put is generally offset by the expense associated with the short put. For example, in 2007, ENP purchased oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. As NYMEX prices increased in 2008, ENP wished to protect downside price exposure at the higher price. In order to do this, ENP purchased oil put options for 2,000 Bbls/D in 2010 at $75 per Bbl and simultaneously sold oil put options for 2,000 Bbls/D in 2010 at $65 per Bbl. Thus, after these transactions were completed, ENP had purchased two oil put options for 2,000 Bbls/D in 2010 (one at $65 per Bbl and one at $75 per Bbl) and sold one oil put option for 2,000 Bbls/D in 2010 at $65 per Bbl. However, the net effect resulted in ENP owning one oil put option for 2,000 Bbls/D at $75 per Bbl. In the following tables, the purchased floor component of these floor spreads are shown net and included with ENP’s other floor contracts.

10

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following tables summarize ENP’s open commodity derivative contracts as of June 30, 2009:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(Bbls)		(per Bbl)		(in thousands)
July — Dec. 2009 (a)													$	21,227
		3,130	$	110.00		—	$	—		—	$	—
		—		—		440		97.75		—		—
		—		—		—		—		1,000		68.70
2010														7,934
		880		80.00		440		93.80		760		75.43
		2,000		75.00		1,000		77.23		250		65.95
		760		67.00		—		—		—		—
2011														9,710
		1,880		80.00		1,440		95.41		760		78.46
		1,000		70.00		—		—		—		—
		760		65.00		—		—		250		69.65
2012														1,159
		—		—		500		82.05		210		81.62
		750		70.00		250		79.25		1,300		76.54
		1,510		65.00		—		—		—		—
													$	40,030

(a) In addition, ENP 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		Average		Weighted		Asset
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
July — Dec. 2009													$	5,972
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		—		—		—		—
		1,800		6.76		—		—		—		—
2010														8,336
		3,800		8.20		3,800		9.58		—		—
		4,698		7.26		—		—		5,452		6.20
		—		—		—		—		550		5.86
2011														1,182
		3,398		6.31		—		—		7,952		6.36
		—		—		—		—		550		5.86
2012														(168	)
		898		6.76		—		—		5,452		6.26
		—		—		—		—		550		5.86
													$	15,322

     Counterparty Risk.At June 30, 2009, ENP had committed greater than 10 percent (in terms of fair market value) of either its oil or natural gas derivative contracts to the following counterparties:

11

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

	Percentage of			Percentage of
	Oil Derivative			Natural Gas
	Contracts			Derivative Contracts
Counterparty	Committed			Committed
BNP Paribas		51	%		29	%
Calyon		33	%		38	%
Wachovia Bank		5	%		31	%

     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 each financial transaction between the counterparty and ENP separately, 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: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by ENP; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out. ENP’s accounting policy is to not offset fair value amounts recorded in the accompanying Consolidated Balance Sheets for derivative instruments.

Interest Rate Swaps

     ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under its revolving credit facility to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swaps as of June 30, 2009, all of which were entered into with Bank of America, N.A.:

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

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in accumulated other comprehensive loss due to the fluctuation of interest rates.

Current Period Impact

     ENP recognized derivative fair value gains and losses related to: (1) ineffectiveness on derivative contracts designated as hedges; (2) changes in the fair market value of derivative contracts not designated as hedges; (3) settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss” for the periods indicated:

	Three months ended June 30,					Six months ended June 30,
	2009			2008		2009			2008
				(in thousands)
Ineffectiveness	$	6		$	39	$	(34	)	$	(343	)
Mark-to-market loss		50,251			73,156		57,681			87,159
Premium amortization		5,854			2,250		11,408			4,387
Settlements		(18,671	)		983		(42,522	)		812
Total derivative fair value loss	$	37,440		$	76,428	$	26,533		$	92,015

Accumulated Other Comprehensive Loss

     At June 30, 2009 and December 31, 2008, accumulated other comprehensive loss consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $3.6 million and $4.3 million, respectively. During the twelve months ending June 30, 2010, ENP

12

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

expects to reclassify $3.3 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense.

Tabular Disclosures of Fair Value Measurements

     The following table summarizes the fair value of ENP’s derivative contracts as of the dates indicated (in thousands):

	Asset Derivatives						Liability Derivatives
	June 30, 2009			December 31, 2008			June 30, 2009			December 31, 2008
	Balance Sheet	Fair		Balance Sheet	Fair		Balance Sheet			Balance Sheet
	Location	Value		Location	Value		Location	Fair Value		Location	Fair Value
Derivatives not designated as hedging instruments under SFAS 133
Commodity derivative contracts	Derivatives — current	$	37,505	Derivatives — current	$	75,131	Derivatives — current	$	1,429	Derivatives — current	$	—
Commodity derivative contracts	Derivatives — noncurrent		24,957	Derivatives — noncurrent		38,497	Derivatives — noncurrent		5,681	Derivatives — noncurrent		229
Total derivatives not designated as hedging instruments under SFAS 133		$	62,462		$	113,628		$	7,110		$	229
Derivatives designated as hedging instruments under SFAS 133
Interest rate swaps	Derivatives — current	$	—	Derivatives — current	$	—	Derivatives — current	$	3,272	Derivatives — current	$	1,297
Interest rate swaps	Derivatives — noncurrent		—	Derivatives — noncurrent		—	Derivatives — noncurrent		553	Derivatives — noncurrent		3,262
Total derivatives designated as hedging instruments under SFAS 133		$	—		$	—		$	3,825		$	4,559
Total derivatives		$	62,462		$	113,628		$	10,935		$	4,788

     The following table summarizes the effect of derivative instruments not designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated (in thousands):

		Amount of Loss Recognized In Income
Derivatives Not Designated as	Location of Loss	Three Months Ended June 30,				Six Months Ended June 30,
Hedges Under SFAS 133	Recognized In Income	2009		2008		2009		2008
Commodity derivative contracts	Derivative fair value loss	$	37,434	$	76,389	$	26,567	$	92,358

     The following tables summarize the effect of derivative instruments designated as hedges under SFAS 133 on the Consolidated Statements of Operations for the periods indicated (in thousands):

Amount of Loss

Amount of Gain

Reclassified from

Amount of Loss

Recognized in OCI

Location of Loss

Accumulated OCI into

Recognized In Income

(Effective Portion)

(Gain) Reclassified

Income (Effective Portion)

as Ineffective

Three months ended

from Accumulated

Three months ended

Location of Loss (Gain)

Three months ended

Derivatives Designated as

June 30,

OCI into Income

June 30,

Recognized in Income

June 30,

Hedges Under SFAS 133

2009

2008

(Effective Portion)

2009

2008

as Ineffective

2009

2008

Interest rate swaps

$

440

$

2,427

Interest expense

$

922

$

125

Derivative fair value loss

$

6

$

39

Amount of Loss

Amount of Gain (Loss)

Reclassified from

Amount of Gain

Recognized in OCI

Location of Loss

Accumulated OCI into

Recognized In Income

(Effective Portion)

(Gain) Reclassified

Income (Effective Portion)

as Ineffective

Six months ended

from Accumulated

Six months ended

Location of Loss (Gain)

Six months ended

Derivatives Designated as

June 30,

OCI into Income

June 30,

Recognized in Income

June 30,

Hedges Under SFAS 133

2009

2008

(Effective Portion)

2009

2008

as Ineffective

2009

2008

Interest rate swaps

$

(1,155

)

$

876

Interest expense

$

1,803

$

108

Derivative fair value loss

$

34

$

343

Fair Value Hierarchy

     As discussed in “Note 2. Basis of Presentation,” ENP adopted FSP FAS 157-2 on January 1, 2009, as it relates to nonfinancial assets and liabilities. ENP adopted SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities. SFAS 157 establishes

13

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

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

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

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

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

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

• Level 3 — ENP’s oil and natural gas calls, puts, and short puts are average value options for which settlement is determined by the average underlying price over a predetermined period of time. ENP uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of ENP’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable inputs of ENP’s valuation model include volatility. The implied volatilities for ENP’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

     ENP adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and ENP’s credit quality for liability positions. ENP uses the multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps. ENP considers the impact of netting and offset provisions in the agreements on counterparty credit risk, including whether the position with the counterparty is a net asset or net liability. There have been no changes in the valuation techniques used to measure the fair value of ENP’s oil and natural gas calls, puts, or short puts during 2009.

     The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
	Asset (Liability) at			Identical Assets		Observable Inputs			Unobservable Inputs
Description	June 30, 2009			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(3,609	)	$	—	$	(3,609	)	$	—
Oil derivative contracts — floors and caps		43,639			—		—			43,639
Natural gas derivative contracts — swaps		1,581			—		1,581			—
Natural gas derivative contracts — floors and caps		13,741			—		—			13,741
Interest rate swaps		(3,825	)		—		(3,825	)		—
Total	$	51,527		$	—	$	(5,853	)	$	57,380

14

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the six months ended June 30, 2009:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2009	$	95,430		$	12,741		$	108,171
Total gains (losses):
Included in earnings		(27,939	)		6,693			(21,246	)
Purchases, issuances, and settlements		(23,852	)		(5,693	)		(29,545	)
Balance at June 30, 2009	$	43,639		$	13,741		$	57,380
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	(27,939	)	$	6,693		$	(21,246	)

     Since ENP does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. All fair values have been adjusted for non-performance risk, resulting in a reduction of the net commodity derivative asset of approximately $0.7 million as of June 30, 2009.

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

• Level 3—Fair values of asset retirement obligations are determined using discounted cash flow methodologies based on inputs, such as plugging costs and reserve lives, which are not readily available in public markets. See “Note 6. Asset Retirement Obligations” for additional discussion of ENP’s asset retirement obligations.

     The following table sets forth ENP’s assets and liabilities that were measured at fair value on a nonrecurring basis as of June 30, 2009:

			Fair Value Measurements Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
	Liability at		Identical Assets		Observable Inputs		Unobservable Inputs		Total Gains
Description	June 30, 2009		(Level 1)		(Level 2)		(Level 3)		(Losses)
	(in thousands)
Asset retirement obligations	$	76	$	—	$	—	$	76	$	—

Note 6. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the six months ended June 30, 2009 (in thousands):

Future abandonment liability at January 1, 2009	$	10,148
Wells drilled		15
Acquisition of properties		61
Accretion of discount		316
Revision of previous estimates		12
Plugging and abandonment costs incurred		(47	)
Future abandonment liability at June 30, 2009	$	10,505

15

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     As of June 30, 2009, $10.1 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.4 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $4.6 million of the future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant. ENP expects to continue reserving additional amounts based on the estimated timing to cease operations of the natural gas processing plant.

Note 7. Long-Term Debt

     OLLC is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “OLLC Credit Agreement”). The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. In March 2009, the borrowing base under the OLLC Credit Agreement was redetermined with no change. As of June 30, 2009, the borrowing base was $240 million and there were $195 million of outstanding borrowings and $45 million of borrowing capacity 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 commitment fee percentage under the OLLC Credit Agreement:

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

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s 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 ENP 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 (1) the total amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the OLLC Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the OLLC Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

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

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

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

16

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

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

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

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

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

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

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

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

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

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

• a requirement that ENP and OLLC maintain a ratio of consolidated EBITDA to consolidated senior interest expense of not less than 2.5 to 1.0; and

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

     As of June 30, 2009, OLLC was in compliance with all covenants of the OLLC Credit Agreement.

     The OLLC Credit Agreement contains customary events of default including, among others, the following:

• failure to pay principal on any loan when due;

• failure to pay accrued interest on any loan or fees when due and such failure continues for more than three days;

• failure to observe or perform covenants and agreements contained in the OLLC Credit Agreement, subject in some cases to a 30-day grace period after discovery or notice of such failure;

• failure to make a payment when due on any other debt in a principal amount equal to or greater than $3 million or any other event or condition occurs which results in the acceleration of such debt or entitles the holder of such debt to accelerate the maturity of such debt;

• the commencement of liquidation, reorganization, or similar proceedings with respect to OLLC or any guarantor under bankruptcy or insolvency law, or the failure of OLLC or any guarantor generally to pay its debts as they become due;

• the entry of one or more judgments in excess of $3 million (to the extent not covered by insurance) and such judgment(s) remain unsatisfied and unstayed for 30 days;

• the occurrence of certain ERISA events involving an amount in excess of $3 million;

• there cease to exist liens covering at least 80 percent of the borrowing base properties; or

• the occurrence of a change in control.

     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.

Note 8. Partners’ Equity and Distributions

Distributions

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

17

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

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

			Cash Distribution
	Date		Declared per					Total
	Declared		Common Unit		Date Paid			Distribution
								(in thousands)
2009
Quarter ended June 30		7/27/2009	$	0.5125		8/14/2009	(a)	$	23,481
Quarter ended March 31		4/27/2009	$	0.5000		5/15/2009			16,813
2008
Quarter ended December 31		1/26/2009	$	0.5000		2/13/2009			16,813
Quarter ended September 30		11/7/2008	$	0.6600		11/14/2008			22,191
Quarter ended June 30		8/11/2008	$	0.6881		8/14/2008			23,119
Quarter ended March 31		5/9/2008	$	0.5755		5/15/2008			19,316
2007
Quarter ended December 31		2/6/2008	$	0.3875		2/14/2008			9,843

(a) Represents the date the distribution is expected to be paid with respect to the second quarter of 2009.

Shelf Registration Statement on Form S-3

     In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.

Public Offering of Common Units

     In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.8 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.4 million, to fund the purchase price of the Vinegarone Assets and a portion of the purchase price of the Williston Basin Assets.

Note 9. Earnings Per Unit

     As discussed in “Note 2. Basis of Presentation,” ENP adopted EITF 07-4 and FSP EITF 03-6-1 on January 1, 2009 and all periods presented have been restated to calculate EPU in accordance with these pronouncements. Under the two-class method of calculating EPU, earnings are allocated to participating securities as if all earnings for the period had been distributed. A participating security is any security that may participate in distributions with common units. For purposes of calculating EPU, general partner units, unvested phantom units, and unvested management incentive units are considered 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 common units outstanding. For the six months ended June 30, 2008, basic EPU and diluted EPU each increased $0.02 per common unit as a result of the adoption of EITF 07-4 and FSP EITF 03-6-1. For the three months ended June 30, 2008, basic EPU and diluted EPU were unaffected by the adoption of EITF 07-4 and FSP EITF 03-6-1.

18

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The following table reflects the allocation of net loss to ENP’s limited partners and EPU computations for the periods indicated:

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
	(in thousands, except per unit amounts)
Net loss	$	(37,593	)	$	(40,526	)	$	(33,348	)	$	(33,069	)
Less: net loss (income) for pre-partnership operations of assets acquired from affiliates		(130	)		(4,472	)		193			(11,245	)
Net loss attributable to unitholders	$	(37,723	)	$	(44,998	)	$	(33,155	)	$	(44,314	)
Numerator:
Numerator for basic EPU:
Net loss attributable to unitholders	$	(37,723	)	$	(44,998	)	$	(33,155	)	$	(44,314	)
Less: distributions earned by participating securities		(258	)		(1,525	)		(511	)		(2,782	)
Plus: cash distributions in excess of income allocated to the general partner		888			1,082			1,084			1,446
Net loss allocated to limited partners	$	(37,093	)	$	(45,441	)	$	(32,582	)	$	(45,650	)
Denominator:
Denominator for basic EPU:
Weighted average common units outstanding		34,260			31,260			33,672			29,766
Effect of dilutive phantom units (a)		—			—			—			—
Denominator for diluted EPU		34,260			31,260			33,672			29,766
Net loss per common unit:
Basic	$	(1.08	)	$	(1.45	)	$	(0.97	)	$	(1.53	)
Diluted	$	(1.08	)	$	(1.45	)	$	(0.97	)	$	(1.53	)

(a) For the three and six months ended months ended June 30, 2009, 43,750 phantom units were outstanding but were excluded from the diluted EPU calculations because their effect would have been antidilutive. For the three and six months ended months ended June 30, 2008, 25,000 phantom units were outstanding but were excluded from the diluted EPU calculations because their effect would have been antidilutive. Please read “Note 10. Unit-Based Compensation Plans” for additional discussion of phantom 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. During the fourth quarter of 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.

     During the three and six months ended June 30, 2008, ENP recognized non-cash unit-based compensation expense for the management incentive units of $1.1 million and $2.1 million respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.

Long-Term Incentive Plan

     In September 2007, the board of directors of the General Partner adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of EAC, the General Partner, and any of their subsidiaries and affiliates who perform services for ENP are eligible to be granted awards under the LTIP. The LTIP is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the LTIP, ENP may issue common units, acquire common units in the open market, or use common units owned by EAC and its affiliates.

19

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

     The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. As of June 30, 2009, there were 1,100,000 common units available for issuance under the LTIP.

     Phantom Units.Each October, ENP issues 5,000 phantom units to each member of the General Partner’s board of directors pursuant to the LTIP. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. ENP intends to settle the phantom units at vesting by issuing common units to the grantee; therefore, these phantom units are classified as equity instruments. Phantom units vest equally over a four-year period. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle them to receive cash equal to the amount of any cash distributions made by ENP with respect to a common unit during the period the right is outstanding. During each of the six months ended June 30, 2009 and 2008, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.2 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations.

     The following table summarizes the changes in ENP’s unvested phantom units for the six months ended June 30, 2009:

			Weighted
			Average
	Number of		Grant Date
	Shares		Fair Value
Outstanding at January 1, 2009		43,750	$	18.67
Granted		—		—
Vested		—		—
Forfeited		—		—
Outstanding at June 30, 2009		43,750		18.67

     As of June 30, 2009, ENP had $0.4 million of total unrecognized compensation cost related to unvested phantom units, which is expected to be recognized over a weighted average period of 2.0 years.

Note 11. Comprehensive Loss

     The components of comprehensive loss, net of tax, were as follows for the periods indicated:

	Three months ended						Six months ended
	June 30,						June 30,
	2009			2008			2009			2008
				(in thousands)
Net loss	$	(37,593	)	$	(40,526	)	$	(33,348	)	$	(33,069	)
Change in deferred hedge loss on interest rate swaps		1,361			2,552			648			984
Comprehensive loss	$	(36,232	)	$	(37,974	)	$	(32,700	)	$	(32,085	)

Note 12. Commitments and Contingencies

     ENP is a party to ongoing legal proceedings in the ordinary course of business. The General Partner’s management does not believe the result of these proceedings will have a material adverse effect on ENP’s business, financial condition, results of operations, liquidity, or ability to pay distributions.

     Additionally, ENP has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, derivative contracts, operating leases, and development commitments. Please read “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for ENP’s contractual obligations as of June 30, 2009.

20

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

Note 13. Related Party Transactions

Administrative Services Agreement

     ENP does not have any employees. The employees supporting the operations of ENP are employees of EAC. Encore Operating performs administrative services for ENP, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by ENP. Encore Operating is not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

     Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administration fee was $1.88 per BOE of ENP’s production. Effective April 1, 2009 the administrative fee increased to $2.02 per BOE of ENP’s production. ENP also reimburses Encore Operating for actual third-party expenses incurred on ENP’s behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on ENP’s behalf. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator.

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if ENP or one of its subsidiaries acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of the General Partner upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and the General Partner, with the approval of the conflicts committee of the board of directors of the General Partner.

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

     Administrative fees (including COPAS recovery) paid to Encore Operating pursuant to the administrative services agreement are included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations. The reimbursements of actual third-party expenses incurred by Encore Operating on ENP’s behalf are included in “Lease operating expense” in the accompanying Consolidated Statement of Operations. The following table illustrates amounts paid by ENP to Encore Operating pursuant to the administrative service agreement for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
			(in thousands)
Administrative fees (including COPAS recovery)	$	1,164	$	1,689	$	2,825	$	3,147
Third-party expenses		2,017		2,557		2,973		3,330

     As of June 30, 2009 and December 31, 2008, ENP had a payable to EAC of $2.6 million and $2.8 million, respectively, which is reflected as “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from EAC of $0.4 million and $1.2 million, respectively, which is reflected as “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets.

Acquisitions from EAC

     As previously discussed, ENP acquired the Permian and Williston Basin Assets from Encore Operating in February 2008 for approximately $125.0 million in cash, including post-closing adjustments, and the issuance of 6,884,776 ENP common units to Encore Operating. Also as previously discussed, ENP acquired the Arkoma Basin Assets from Encore Operating in January 2009 for

21

ENCORE ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Continued
(unaudited)

approximately $46.4 million in cash, including post-closing adjustments. Also as previously discussed, ENP acquired the Williston Basin Assets from Encore Operating in June 2009 for approximately $25.7 million in cash, including post-closing adjustments.

     Prior to the acquisitions of the Permian and Williston Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets these properties were owned by EAC and were not separate legal entities. In addition to payroll-related expenses, EAC incurred general and administrative expenses related to leasing office space and other corporate overhead expenses during the period these properties were owned by EAC. A portion of EAC’s consolidated general and administrative expenses were allocated to ENP 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.

Distributions

     During the three and six months ended June 30, 2009, ENP distributed approximately $10.7 million and $21.4 million, respectively, to EAC and its subsidiaries, including the General Partner. During the three and six months ended June 30, 2008, ENP distributed approximately $12.3 million and $18.0 million, respectively, to EAC and its subsidiaries, including the General Partner.

     During the three and six months ended June 30, 2008, ENP distributed approximately $1.0 million and $1.2 million, respectively, to certain executive officers of the General Partner based on their ownership of management incentive units.

Note 14. Subsequent Events

     Subsequent events were evaluated through August 3, 2009, which is the date financial statements were issued.

Distribution

     On July 28, 2009, ENP announced a cash distribution for the second quarter of 2009 to unitholders of record as of the close of business on August 10, 2009 at a rate of $0.5125 per unit. Approximately $23.5 million is expected to be paid to unitholders on or about August 14, 2009.

Acquisition from EAC

     On June 28, 2009, ENP entered into a purchase and sale agreement with Encore Operating, which provides for the acquisition by ENP from Encore Operating of certain oil and natural gas producing properties in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) for $190 million in cash, subject to customary purchase price adjustments. The acquisition will be effective April 1, 2009 and is expected to close in August 2009. In connection with the pending acquisition of the Rockies and Permian Basin Assets, ENP requested the syndicate of lenders underwriting the OLLC Credit Agreement to increase the borrowing base from $240 million to $375 million.

     Because the Rockies and Permian Basin Assets are to be acquired from an affiliate, the acquisition will be accounted for as transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities will be recorded at Encore Operating’s carrying value and ENP’s historical financial information will be recast to include the acquired properties for all periods presented.

Public Offering of Common Units

     In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP expects to use the net proceeds of approximately $129.1 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of $0.4 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets. Pending the closing of the acquisition of the Rockies and Permian Basin Assets from Encore Operating, ENP may use the net proceeds to reduce outstanding borrowings under the OLLC Credit Agreement.

22

ENCORE ENERGY PARTNERS LP

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those discussed in these forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and Exhibit 99.3 to our Current Report onForm 8-K filed with the SEC on May 7, 2009, which recast “Item 8. Financial Statements and Supplementary Data” included in our 2008 Annual Report on Form 10-K.

Introduction

     In this management’s discussion and analysis of financial condition and results of operations, the following are discussed and analyzed:

• Overview of Business

• Results of Operations

• Comparison of Quarter Ended June 30, 2009 to Quarter Ended June 30, 2008

• Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

• New Accounting Pronouncements

Overview of Business

     We are a Delaware limited partnership formed by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Our primary business objective is to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, increase our quarterly cash distributions. Our properties and oil and natural gas reserves are located in four core areas:

• the Big Horn Basin in Wyoming and Montana;

• the Permian Basin in West Texas;

• the Williston Basin in North Dakota and Montana; and

• the Arkoma Basin in Arkansas.

     In February 2008, we acquired the Permian and Williston Basin Assets. In January 2009, we acquired the Arkoma Basin Assets. In June 2009, we acquired the Williston Basin Assets. Because these properties were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and our historical financial information was recast to include the acquired properties for all periods presented. Accordingly, our consolidated financial statements reflect our historical results combined with those of the Permian and Williston Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets for all periods presented.

     These results are not indicative of our future results, which could differ materially from our historical results.

     On June 28, 2009, we entered into a purchase and sale agreement with Encore Operating to acquire the Rockies and Permian Basin Assets. The acquisition is expected to close in August 2009. Our historical results of operations and other operating and financial information do not include any information related to the Rockies and Permian Basin Assets.

23

ENCORE ENERGY PARTNERS LP

Results of Operations

Comparison of Quarter Ended June 30, 2009 to Quarter Ended June 30, 2008

     Revenues.The following table illustrates the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Three months ended June 30,				Decrease
	2009		2008		$			%
Revenues (in thousands):
Oil	$	23,182	$	51,603	$	(28,421	)		-55	%
Natural gas		3,955		14,654		(10,699	)		-73	%
Total oil and natural gas revenues		27,137		66,257		(39,120	)		-59	%
Marketing		109		903		(794	)		-88	%
Total revenues	$	27,246	$	67,160	$	(39,914	)		-59	%
Average realized prices:
Oil ($/Bbl)	$	54.16	$	112.10	$	(57.94	)		-52	%
Natural gas ($/Mcf)	$	3.22	$	10.71	$	(7.49	)		-70	%
Combined ($/BOE)	$	42.89	$	96.24	$	(53.35	)		-55	%
Total production volumes:
Oil (MBbls)		428		460		(32	)		-7	%
Natural gas (MMcf)		1,228		1,369		(141	)		-10	%
Combined (MBOE)		633		688		(55	)		-8	%
Average daily production volumes:
Oil (Bbls/D)		4,704		5,059		(355	)		-7	%
Natural gas (Mcf/D)		13,498		15,042		(1,544	)		-10	%
Combined (BOE/D)		6,953		7,566		(613	)		-8	%
Average NYMEX prices:
Oil (per Bbl)	$	59.83	$	124.30	$	(64.47	)		-52	%
Natural gas (per Mcf)	$	3.49	$	10.94	$	(7.45	)		-68	%

     Oil revenues decreased 55 percent from $51.6 million in the second quarter of 2008 to $23.2 million in the second quarter of 2009 as a result of a $57.94 per Bbl decrease in our average realized oil price and a 32 MBbls decrease in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $24.8 million and was primarily due to a lower average NYMEX price, which decreased from $124.30 per Bbl in the second quarter of 2008 to $59.83 per Bbl in the second quarter of 2009. Our lower oil production volumes decreased oil revenues by approximately $3.6 million and was primarily due to natural production declines in our Elk Basin field.

     Natural gas revenues decreased 73 percent from $14.7 million in the second quarter of 2008 to $4.0 million in the second quarter of 2009 as a result of a $7.49 per Mcf decrease in our average realized natural gas price and a 141 MMcf decrease in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $9.2 million and was primarily due to a lower average NYMEX price, which decreased from $10.94 per Mcf in the second quarter of 2008 to $3.49 per Mcf in the second quarter of 2009. Our lower natural gas production volumes decreased natural gas revenues by approximately $1.5 million and was primarily due to natural production declines in our Crockett County properties.

24

ENCORE ENERGY PARTNERS LP

     The table below illustrates the relationship between our oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

	Three months ended June 30,
	2009			2008
Average realized oil price ($/Bbl)	$	54.16		$	112.10
Average NYMEX ($/Bbl)	$	59.83		$	124.30
Differential to NYMEX	$	(5.67	)	$	(12.20	)
Average realized oil price to NYMEX percentage		91	%		90	%
Average realized natural gas price ($/Mcf)	$	3.22		$	10.71
Average NYMEX ($/Mcf)	$	3.49		$	10.94
Differential to NYMEX	$	(0.27	)	$	(0.23	)
Average realized natural gas price to NYMEX percentage		92	%		98	%

     Our average realized oil price as a percentage of the average NYMEX price was 91 percent in the second quarter of 2009 as compared to 90 percent in the second quarter of 2008.

     Our average realized natural gas price as a percentage of the average NYMEX price was 92 percent in the second quarter of 2009 as compared to 98 percent in the second quarter of 2008. The natural gas index prices related to our West Texas natural gas contracts widened in their relationship to NYMEX causing a wider differential in the second quarter of 2009.

     Marketing revenues decreased 88 percent from $0.9 million in the second quarter of 2008 to $0.1 million in the second quarter of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. 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.

25

ENCORE ENERGY PARTNERS LP

Expenses.The following table summarizes our expenses for the periods indicated:

	Three months ended June 30,					Increase / (Decrease)
	2009		2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	6,949	$	7,635		$	(686	)
Production, ad valorem, and severance taxes		3,062		6,308			(3,246	)
Total production expenses		10,011		13,943			(3,932	)		-28	%
Other:
Depletion, depreciation, and amortization		11,294		10,316			978
Exploration		18		38			(20	)
General and administrative		2,807		3,252			(445	)
Marketing		61		1,609			(1,548	)
Derivative fair value loss		37,440		76,428			(38,988	)
Other operating		658		391			267
Total operating expenses		62,289		105,977			(43,688	)		-41	%
Interest		2,351		1,909			442
Income tax provision (benefit)		200		(135	)		335
Total expenses	$	64,840	$	107,751		$	(42,911	)		-40	%
Expenses (per BOE):
Production:
Lease operating	$	10.98	$	11.09		$	(0.11	)
Production, ad valorem, and severance taxes		4.84		9.16			(4.32	)
Total production expenses		15.82		20.25			(4.43	)		-22	%
Other:
Depletion, depreciation, and amortization		17.85		14.98			2.87
Exploration		0.03		0.06			(0.03	)
General and administrative		4.44		4.72			(0.28	)
Marketing		0.10		2.34			(2.24	)
Derivative fair value loss		59.17		111.01			(51.84	)
Other operating		1.04		0.57			0.47
Total operating expenses		98.45		153.93			(55.48	)		-36	%
Interest		3.72		2.77			0.95
Income tax provision (benefit)		0.32		(0.20	)		0.52
Total expenses	$	102.49	$	156.50		$	(54.01	)		-35	%

     Production expenses.Total production expenses decreased 28 percent from $13.9 million in the second quarter of 2008 to $10.0 million in the second quarter of 2009. Our production margin decreased 67 percent from $52.3 million in the second quarter of 2008 to $17.1 million in the second quarter of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 55 percent and total production expenses per BOE decreased by 22 percent. On a per BOE basis, our production margin decreased 64 percent to $27.07 per BOE in the second quarter of 2009 as compared to $75.99 per BOE in the second quarter of 2008.

     Production expense attributable to LOE decreased $0.7 million from $7.6 million in the second quarter of 2008 to $6.9 million in the second quarter of 2009 primarily as a result of lower production volumes.

     Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) decreased $3.2 million from $6.3 million in the second quarter of 2008 to $3.1 million in the second quarter of 2009 primarily due to lower wellhead revenues. As a percentage of oil and natural gas wellhead revenues, production taxes increased to 11.3 percent in the second quarter of 2009 as compared to 9.5 percent in the second quarter of 2008 primarily due to higher ad valorem taxes, which are based on a flat rate of production volumes as opposed to a percentage of wellhead revenues.

     Depletion, depreciation, and amortization expense (“DD&A”).DD&A expense increased $1.0 million from $10.3 million in the second quarter of 2008 to $11.3 million in the second quarter of 2009, primarily due to a $2.87 increase in the per BOE rate, partially offset by lower production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately

26

ENCORE ENERGY PARTNERS LP

$1.8 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices. Our lower production volumes decreased DD&A expense by approximately $0.8 million.

     General and administrative expense (“G&A”).G&A expense decreased $0.4 million from $3.3 million in the second quarter of 2008 to $2.8 million in the second quarter of 2009 primarily due to a decrease in non-cash unit-based compensation expense.

     Marketing expenses.Marketing expenses decreased $1.5 million from $1.6 million in the second quarter of 2008 to $0.1 million in the second quarter of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline. 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.

     Derivative fair value loss.During the second quarter of 2009, we recorded a $37.4 million derivative fair value loss as compared to $76.4 million in the second quarter of 2008, the components of which were as follows:

	Three months ended June 30,					Increase /
	2009			2008		(Decrease)
	(in thousands)
Ineffectiveness	$	6		$	39	$	(33	)
Mark-to-market loss		50,251			73,156		(22,905	)
Premium amortization		5,854			2,250		3,604
Settlements		(18,671	)		983		(19,654	)
Total derivative fair value loss	$	37,440		$	76,428	$	(38,988	)

     Interest expense.Interest expense increased $0.4 million from $1.9 million in the second quarter of 2008 to $2.4 million in the second quarter of 2009 primarily due to higher weighted average outstanding borrowings under our revolving credit facility. Our weighted average interest rate was 5.0 percent for the second quarter of 2009 as compared to 4.7 percent for the second quarter of 2008.

27

ENCORE ENERGY PARTNERS LP

Comparison of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2008

     Revenues.The following table illustrates the components of our revenues for the periods indicated, as well as each period’s respective production volumes and average prices:

	Six months ended June 30,				Decrease
	2009		2008		$			%
Revenues (in thousands):
Oil	$	38,915	$	92,444	$	(53,529	)		-58	%
Natural gas		7,873		23,743		(15,870	)		-67	%
Total oil and natural gas revenues		46,788		116,187		(69,399	)		-60	%
Marketing		279		3,762		(3,483	)		-93	%
Total revenues	$	47,067	$	119,949	$	(72,882	)		-61	%
Average realized prices:
Oil ($/Bbl)	$	45.61	$	99.81	$	(54.20	)		-54	%
Natural gas ($/Mcf)	$	3.31	$	9.34	$	(6.03	)		-65	%
Combined ($/BOE)	$	37.45	$	86.07	$	(48.62	)		-56	%
Total production volumes:
Oil (MBbls)		853		926		(73	)		-8	%
Natural gas (MMcf)		2,377		2,542		(165	)		-6	%
Combined (MBOE)		1,249		1,350		(101	)		-7	%
Average daily production volumes:
Oil (Bbls/D)		4,714		5,089		(375	)		-7	%
Natural gas (Mcf/D)		13,132		13,967		(835	)		-6	%
Combined (BOE/D)		6,903		7,417		(514	)		-7	%
Average NYMEX prices:
Oil (per Bbl)	$	51.61	$	111.02	$	(59.41	)		-54	%
Natural gas (per Mcf)	$	4.20	$	9.48	$	(5.28	)		-56	%

     Oil revenues decreased 58 percent from $92.4 million in the first six months of 2008 to $38.9 million in the first six months of 2009 as a result of a $54.20 per Bbl decrease in our average realized oil price and a 73 MBbls decrease in our oil production volumes. Our lower average realized oil price decreased oil revenues by approximately $46.2 million and was primarily due to a lower average NYMEX price, which decreased from $111.02 per Bbl in the first six months of 2008 to $51.61 per Bbl in the first six months of 2009. Our lower oil production volumes decreased oil revenues by approximately $7.3 million and was primarily due to natural production declines in our Elk Basin field.

     Natural gas revenues decreased 67 percent from $23.7 million in the first six months of 2008 to $7.9 million in the first six months of 2009 as a result of a $6.03 per Mcf decrease in our average realized natural gas price and a 165 MMcf decrease in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $14.3 million and was primarily due to a lower average NYMEX price, which decreased from $9.48 per Mcf in the first six months of 2008 to $4.20 per Mcf in the first six months of 2009. Our lower natural gas production volumes decreased natural gas revenues by approximately $1.5 million and was primarily due to natural production declines in our Crockett County properties.

28

ENCORE ENERGY PARTNERS LP

     The table below illustrates the relationship between our oil and natural gas realized prices as a percentage of average NYMEX prices for the periods indicated:

	Six months ended June 30,
	2009			2008
Average realized oil price ($/Bbl)	$	45.61		$	99.81
Average NYMEX ($/Bbl)	$	51.61		$	111.02
Differential to NYMEX	$	(6.00	)	$	(11.21	)
Average realized oil price to NYMEX percentage		88	%		90	%
Average realized natural gas price ($/Mcf)	$	3.31		$	9.34
Average NYMEX ($/Mcf)	$	4.20		$	9.48
Differential to NYMEX	$	(0.89	)	$	(0.14	)
Average realized natural gas price to NYMEX percentage		79	%		99	%

     Our average realized oil price as a percentage of the average NYMEX price remained relatively constant at 88 percent in the first six months of 2009 as compared to 90 percent in the first six months of 2008.

     Our average realized natural gas price as a percentage of the average NYMEX price was 79 percent in the first six months of 2009 as compared to 99 percent in the first six months of 2008. The natural gas index prices related to our West Texas natural gas contracts widened in their relationship to NYMEX causing a wider differential in the first six months of 2009.

     Marketing revenues decreased 93 percent from $3.8 million in the first six months of 2008 to $0.3 million in the first six months of 2009 primarily as a result of a reduction in natural gas throughput in our Wildhorse pipeline. 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.

29

ENCORE ENERGY PARTNERS LP

     Expenses.The following table summarizes our expenses for the periods indicated:

	Six months ended June 30,					Increase / (Decrease)
	2009		2008			$			%
Expenses (in thousands):
Production:
Lease operating	$	14,831	$	14,329		$	502
Production, ad valorem, and severance taxes		5,402		11,539			(6,137	)
Total production expenses		20,233		25,868			(5,635	)		-22	%
Other:
Depletion, depreciation, and amortization		22,285		20,520			1,765
Exploration		40		67			(27	)
General and administrative		4,996		6,424			(1,428	)
Marketing		191		4,002			(3,811	)
Derivative fair value loss		26,533		92,015			(65,482	)
Other operating		1,375		793			582
Total operating expenses		75,653		149,689			(74,036	)		-49	%
Interest		4,567		3,549			1,018
Income tax provision (benefit)		201		(138	)		339
Total expenses	$	80,421	$	153,100		$	(72,679	)		-47	%
Expenses (per BOE):
Production:
Lease operating	$	11.87	$	10.62		$	1.25
Production, ad valorem, and severance taxes		4.32		8.55			(4.23	)
Total production expenses		16.19		19.17			(2.98	)		-16	%
Other:
Depletion, depreciation, and amortization		17.84		15.20			2.64
Exploration		0.03		0.05			(0.02	)
General and administrative		4.00		4.76			(0.76	)
Marketing		0.15		2.96			(2.81	)
Derivative fair value loss		21.24		68.17			(46.93	)
Other operating		1.10		0.59			0.51
Total operating expenses		60.55		110.90			(50.35	)		-45	%
Interest		3.66		2.63			1.03
Income tax provision (benefit)		0.16		(0.10	)		0.26
Total expenses	$	64.37	$	113.43		$	(49.06	)		-43	%

     Production expenses.Total production expenses decreased 22 percent from $25.9 million in the first six months of 2008 to $20.2 million in the first six months of 2009. Our production margin decreased 71 percent from $90.3 million in the first six months of 2008 to $26.6 million in the first six months of 2009. Total oil and natural gas wellhead revenues per BOE decreased by 56 percent and total production expenses per BOE decreased by 16 percent. On a per BOE basis, our production margin decreased 68 percent to $21.26 per BOE in the first six months of 2009 as compared to $66.90 per BOE in the first six months of 2008.

     Production expense attributable to LOE increased $0.5 million from $14.3 million in the first six months of 2008 to $14.8 million in the first six months of 2009 as a result of a $1.25 increase in the per BOE rate, partially offset by lower production volumes. Our higher average LOE per BOE rate increased LOE by approximately $1.6 million and was primarily due to an increase of $0.7 million for retention bonuses to be paid in August 2009 related to EAC’s 2008 strategic alternatives process and higher prices paid to oilfield service companies and suppliers during the first quarter of 2009 as compared to the first quarter of 2008, partially offset by decreases in natural gas prices resulting in lower electricity costs and gas plant fuel costs. Our lower production volumes decreased LOE by approximately $1.1 million.

     Production expense attributable to production taxes decreased $6.1 million from $11.5 million in the first six months of 2008 to $5.4 million in the first six months of 2009 primarily due to lower wellhead revenues. As a percentage of oil and natural gas wellhead revenues, production taxes increased to 11.5 percent in the first six months of 2009 as compared to 9.9 percent in the first six months of 2008 primarily due to higher ad valorem taxes, which are based on a flat rate of production volumes as opposed to a percentage of wellhead revenues.

30

ENCORE ENERGY PARTNERS LP

     DD&A expense.DD&A expense increased $1.8 million from $20.5 million in the first six months of 2008 to $22.3 million in the first six months of 2009, primarily due to a $2.64 increase in the per BOE rate, partially offset by lower production volumes. Our higher average DD&A per BOE rate increased DD&A expense by approximately $3.3 million and was primarily due to the decrease in our proved reserves as a result of lower average commodity prices. Our lower production volumes decreased DD&A expense by approximately $1.5 million.

     G&A expense.G&A expense decreased $1.4 million from $6.4 million in the first six months of 2008 to $5.0 million in the first six months of 2009 primarily due to a decrease in non-cash unit-based compensation expense.

     Marketing expenses.Marketing expenses decreased $3.8 million from $4.0 million in the first six months of 2008 to $0.2 million in the first six months of 2009 primarily due to a reduction in natural gas throughput in our Wildhorse pipeline. 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.

     Derivative fair value loss.During the first six months of 2009, we recorded a $26.5 million derivative fair value loss as compared to $92.0 million in the first six months of 2008, the components of which were as follows:

	Six months ended June 30,						Increase /
	2009			2008			(Decrease)
				(in thousands)
Ineffectiveness	$	(34	)	$	(343	)	$	309
Mark-to-market loss		57,681			87,159			(29,478	)
Premium amortization		11,408			4,387			7,021
Settlements		(42,522	)		812			(43,334	)
Total derivative fair value loss	$	26,533		$	92,015		$	(65,482	)

     Interest expense.Interest expense increased $1.0 million from $3.5 million in the first six months of 2008 to $4.6 million in the first six months of 2009 primarily due to higher weighted average outstanding borrowings under our revolving credit facility, partially offset by a reduction in LIBOR. Our weighted average interest rate was 4.8 percent for the first six months of 2009 as compared to 5.0 percent for the first six months of 2008.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments

     Our primary needs for cash are:

• Distributions to unitholders;

• Development, exploitation, and exploration of oil and natural gas properties;

• Acquisitions of oil and natural gas properties;

• Funding of working capital; and

• Contractual obligations.

     Distributions to unitholders.Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs. During the first six months of 2009, we distributed $33.6 million to our unitholders. In February 2009, we distributed $16.8 million with respect to the fourth quarter of 2008 at a rate of $0.50 per unit. In May 2009, we distributed $16.8 million with respect to the first quarter of 2009 at a rate of $0.50 per unit.

     As a general guideline, we plan to distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and

31

ENCORE ENERGY PARTNERS LP

(3) a minimum coverage ratio of 1.10. The board of directors of our general partner may decide to make a fixed quarterly distribution over a specified period pursuant to the preceding formula in order to reduce some of the variability in quarterly distributions over the specified period. Accordingly, we may make a distribution during a quarter even if we have not generated sufficient cash flow to cover such distribution by borrowing under our revolving credit facility, and we may reserve some of our cash during a quarter for distributions in future quarters even if the preceding formula would result in the distribution of a higher amount for such quarter. The board of directors of our general partner also may change our distribution philosophy based on prevailing business conditions. There can be no assurance that we will be able to distribute $0.4325 per unit on a quarterly basis or achieve a minimum coverage ratio of 1.10.

     As a result of our expanded property base and expected increased cash flow from the Rockies and Permian Basin Assets (and assuming the transaction is completed as scheduled), beginning with our quarterly distribution for the third quarter of 2009, we expect our annualized distribution rate to increase to $2.15 per unit.

     On July 28, 2009, we announced a cash distribution for the second quarter of 2009 to unitholders of record as of the close of business on August 10, 2009 at a rate of $0.5125 per unit. Approximately $23.5 million is expected to be paid to unitholders on or about August 14, 2009.

     Development, exploitation, and exploration of oil and natural gas properties.The following table summarizes our costs incurred (excluding asset retirement obligations) related to development, exploitation, and exploration activities for the periods indicated:

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008
	(in thousands)
Development and exploitation	$	2,417	$	10,778	$	4,525	$	16,951
Exploration		28		1,261		294		1,462
Total	$	2,445	$	12,039	$	4,819	$	18,413

     Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the second quarter of 2009 yielded 4 gross (0.6 net) successful wells and no dry holes. Our development and exploitation capital for the first six months of 2009 yielded 8 gross (1.0 net) successful wells and no dry holes.

     Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs. We did not complete any exploratory wells in the second quarter of 2009. Our exploration capital for the first six months of 2009 yielded 4 gross (0.2 net) successful wells and no dry holes.

     Acquisitions of oil and natural gas properties.In June 2009, we acquired the Williston Basin Assets from Encore Operating for approximately $25.7 million in cash, including post-closing adjustments. In May 2009, we acquired the Vinegarone Assets from an independent energy company for approximately $27.5 million, including post-closing adjustments. In January 2009, we acquired the Arkoma Basin Assets from Encore Operating for approximately $46.4 million in cash, including post-closing adjustments. In February 2008, we acquired the Permian and Williston Basin Assets from Encore Operating for total consideration of approximately $125.0 million in cash, including post-closing adjustments, and the issuance of 6,884,776 ENP common units to Encore Operating. In determining the total purchase price, the common units were valued at $125.0 million. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. Because the Permian and Williston Basin Assets, the Arkoma Basin Assets, and the Williston Basin Assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities were recorded at Encore Operating carrying value and our historical financial information was recast to include the acquired properties for all periods presented.

     Funding of working capital.As of June 30, 2009 and December 31, 2008, our working capital (defined as total current assets less total current liabilities) was $25.5 million and $71.6 million, respectively. The decrease was primarily due to higher commodity prices at June 30, 2009 as compared to December 31, 2008, which negatively impacted the fair value of our outstanding commodity derivative contracts.

32

ENCORE ENERGY PARTNERS LP

     For the remainder of 2009, we expect working capital to remain positive, primarily due to the fair value of our outstanding commodity derivative contracts. We anticipate cash reserves to be close to zero because we intend to distribute available cash to unitholders and reduce outstanding borrowings and related interest expense under our revolving credit facility. However, we have availability under our revolving credit facility to fund our obligations as they become due. Our production volumes, commodity prices, and differentials for oil and natural gas will be the largest variables affecting our working capital. Our operating cash flow is determined in large part by production volumes and commodity prices. Given our current commodity derivative contracts, assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2009.

     The board of directors of our general partner approved a capital budget of approximately $7.4 million for 2009, excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow and availability under our revolving credit facility.

     Off-balance sheet arrangements.We have no investments in unconsolidated entities or persons that could materially affect our liquidity or availability of capital resources. We have no off-balance sheet arrangements that are material to our financial position or results of operations.

     Contractual obligations.The following table illustrates our contractual obligations and commitments at June 30, 2009:

	Payments Due by Period
					Years Ending		Years Ending
Contractual Obligations and			Six Months Ending		December 31, 2010 -		December 31, 2012 -
Commitments	Total		December 31, 2009		2011		2013		Thereafter
	(in thousands)
Revolving credit facility (a)	$	208,987	$	2,543	$	10,172	$	196,272	$	—
Commodity derivative contracts (b)		2,101		—		—		2,101		—
Interest rate swaps (c)		3,925		1,772		2,153		—		—
Development commitments (d)		1,556		778		778		—		—
Operating leases (e)		2,231		343		1,373		515		—
Asset retirement obligations (f)		34,924		431		861		646		32,986
Total	$	253,724	$	5,867	$	15,337	$	199,534	$	32,986

(a)	Includes principal and projected interest payments. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our revolving credit facility.
(b)	Represents net liabilities for commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.
(c)	Represents net liabilities for interest rate swaps, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our interest rate swaps.
(d)	Represents authorized purchases for work in process. Also at June 30, 2009, we had approximately $13.3 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table but are budgeted for and expected to be made unless circumstances change.
(e)	Represents equipment obligations that have non-cancelable initial lease terms in excess of one year.
(f)	Represents the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the end of field life. Please read Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.

     Other contingencies and commitments. Encore Operating provides administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provides all personnel, facilities, goods, and equipment necessary to perform these services which are not otherwise provided for by us. Encore Operating initially received an administrative fee of $1.75 per BOE of our production for such services. From April 1, 2008 to March 31, 2009, the administrative fee was $1.88 per BOE of our production. Effective April 1, 2009, the administrative fee increased to $2.02 per BOE of our production as a result of the COPAS Wage Index Adjustment. We also reimburse Encore Operating for actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our 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.

33

ENCORE ENERGY PARTNERS LP

     The administrative fee will increase in the following circumstances:

• beginning on the first day of April in each year by an amount equal to the product of the then-current administrative fee multiplied by the COPAS Wage Index Adjustment for that year;

• if we or one of our subsidiaries acquires additional assets, Encore Operating may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of our General Partner upon the recommendation of its conflicts committee; and

• otherwise as agreed upon by Encore Operating and our General Partner, with the approval of the conflicts committee of the board of directors of our General Partner.

     Capital resources

     Cash flows from operating activities. Cash provided by operating activities decreased $21.2 million from $72.5 million for the first six months of 2008 to $51.3 million for the first six months of 2009, primarily due to a decrease in our production margin, partially offset by decreased settlements paid under our commodity derivative contracts as a result of lower average commodity prices in the first six months of 2009 as compared to the first six months of 2008.

     Cash flows from investing activities. Cash used in investing activities increased $17.6 million from $13.4 million for the first six months of 2008 to $31.0 million for the first six months of 2009 as a result of $27.5 million paid for the acquisition of the Vinegarone Assets, partially offset by a $9.7 million decrease in amounts paid to develop oil and natural gas properties.

     Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on our revolving credit facility, distributions to unitholders, and issuances of our common units. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

     During the first six months of 2009, we used net cash of $20.9 million in financing activities, including $72.1 million in deemed distributions to affiliates in connection with our acquisitions of the Arkoma Basin Assets and the Williston Basin Assets and $33.6 million in distributions to unitholders, partially offset by $40.7 million net proceeds from the issuance of our common units and net borrowings of $45 million under our revolving credit facility. Net borrowings increased the outstanding borrowings under our revolving credit facility from $150 million at December 31, 2008 to $195 million at June 30, 2009.

     During the first six months of 2008, we used net cash of $58.5 million in financing activities, including $124.8 million of deemed distributions to affiliates in connection with our acquisition of the Permian and Williston Basin Assets and $29.1 million in distributions to unitholders, partially offset by net borrowings of $103.5 million under our revolving credit facility.

     Liquidity

     Our primary sources of liquidity are internally generated cash flows and the borrowing capacity under our revolving credit facility. We also have the ability to adjust the level of our capital expenditures. We may use other sources of capital, including the issuance of debt or common units, to fund acquisitions or maintain our financial flexibility. We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures for the foreseeable future. However, should commodity prices decline or the capital markets remain tight, the borrowing capacity under our revolving credit facility could be adversely affected. In the event of a reduction in the borrowing base under our revolving credit facility, we do not believe it will result in any required prepayments of indebtedness.

     Our partnership agreement requires that we distribute all of our available cash quarterly. As a general guideline, we plan to distribute to unitholders 50 percent of the excess distributable cash flow above: (1) maintenance capital requirements; (2) an implied minimum quarterly distribution of $0.4325 per unit, or $1.73 per unit annually; and (3) a minimum coverage ratio of 1.10. The board of directors of our general partner may decide to make a fixed quarterly distribution over a specified period pursuant to the preceding formula in order to reduce some of the variability in quarterly distributions over the specified period. Accordingly, we may make a distribution during a quarter even if we have not generated sufficient cash flow to cover such distribution by borrowing under our revolving credit facility, and we may reserve some of our cash during a quarter for distributions in future quarters even if the preceding formula would result in the distribution of a higher amount for such quarter. The board of directors of our general partner also may change our distribution philosophy based on prevailing business conditions. There can be no assurance that we will be able to distribute $0.4325 on a quarterly basis or achieve a minimum coverage ratio of 1.10. Our partnership agreement permits our

34

ENCORE ENERGY PARTNERS LP

general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

     Internally generated cash flows.Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During the first six months of 2009, our average realized oil and natural gas prices decreased by 54 percent and 65 percent, respectively, as compared to the first six months of 2008. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline or we experience a significant widening of our differentials, then our earnings, our cash flows from operations, the borrowing base under our revolving credit facility, and our ability to pay distributions may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our revolving credit facility and thereby affect our liquidity. However, we have protected approximately two-thirds of our forecasted production through 2012 against declining commodity prices. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.

     Revolving credit facility.The syndicate of lenders underwriting our revolving credit facility includes 12 banking and other financial institutions. None of the lenders are underwriting more than 16 percent of the total commitment. We believe the number of lenders and the small percentage participation of each, provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

     In March 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate including Bank of America, N.A. and other lenders. The OLLC Credit Agreement matures on March 7, 2012. Effective March 10, 2009, OLLC amended the OLLC Credit Agreement to, among other things, increase the interest rate margins and commitment fees applicable to loans made under the OLLC Credit Agreement. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries.

     The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on April 1 and October 1 and upon requested special redeterminations. At June 30, 2009, the borrowing base was $240 million. In July 2009, ENP requested the syndicate of lenders underwriting the OLLC Credit Agreement to increase the borrowing base from $240 million to $375 million.

     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 commitment fee percentage under the OLLC Credit Agreement:

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

(a) In connection with the proposed increase in our borrowing base from $240 million to $375 million, we expect this commitment fee percentage to increase to 0.500 percent.

     OLLC’s obligations under the OLLC Credit Agreement are secured by a first-priority security interest in substantially all of OLLC’s 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 us 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 (1) the total amount outstanding in relation to the borrowing base and (2) 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:

35

ENCORE ENERGY PARTNERS LP

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

(a) In connection with the proposed increase in our borrowing base from $240 million to $375 million, we expect the applicable margin for Eurodollar loans to increase by 0.500 percent at each tier and the applicable margin for base rate loans to increase by 0.500 percent for the first tier and by 0.750 percent for the other three tiers.

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

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

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

• 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 our assets and the assets of OLLC and its 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 we and OLLC maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 (the “Current Ratio”);

• a requirement that we and OLLC maintain a ratio of consolidated EBITDA to the sum of consolidated net interest expense plus letter of credit fees of not less than 1.5 to 1.0 (the “Total Interest Coverage Ratio”);

• a requirement that we and OLLC maintain a ratio of consolidated EBITDA to consolidated senior interest expense of not less than 2.5 to 1.0 (the “Senior Interest Coverage Ratio”); and

• a requirement that we and OLLC maintain a ratio of consolidated funded debt (excluding certain related party debt) to consolidated adjusted EBITDA of not more than 3.5 to 1.0 (the “Leverage Ratio”).

     In order to show our and OLLC’s compliance with the covenants of the OLLC Credit Agreement, the use of non-GAAP financial measures is required. The presentation of these non-GAAP financial measures provides useful information to investors as they allow readers to understand how much cushion there is between the required ratios and the actual ratios. These non-GAAP financial measures should not be considered an alternative to any measure of financial performance presented in accordance with GAAP.

     As of June 30, 2009, we and OLLC were in compliance with all covenants in the OLLC Credit Agreement, including the following financial covenants:

		Actual Ratio as of
Financial Covenant	Required Ratio	June 30, 2009
Current Ratio	Minimum 1.0 to 1.0	3.3 to 1.0
Total Interest Coverage Ratio	Minimum 1.5 to 1.0	13.0 to 1.0
Senior Interest Coverage Ratio	Minimum 2.5 to 1.0	17.2 to 1.0
Leverage Ratio	Maximum 3.5 to 1.0	1.7 to 1.0

36

ENCORE ENERGY PARTNERS LP

     The following table shows the calculation of the Current Ratio as of June 30, 2009 ($ in thousands):

Current assets	$	56,824
Availability under the OLLC Credit Agreement		45,000
Consolidated current assets	$	101,824
Divided by: consolidated current liabilities	$	31,317
Current Ratio		3.3

     The following table shows the calculation of the Total Interest Coverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

Consolidated EBITDA (a)	$	103,785
Divided by:
Consolidated interest expense and letter of credit fees	$	7,987
Consolidated interest income		(23	)
Consolidated net interest expense and letter of credit fees	$	7,964
Total Interest Coverage Ratio		13.0

(a) Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table shows the calculation of the Senior Interest Coverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

Consolidated EBITDA (a)	$	103,785
Divided by:
Consolidated senior interest expense	$	6,045
Consolidated interest income		(23	)
Consolidated net senior interest expense	$	6,022
Senior Interest Coverage Ratio		17.2

(a) Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense. Consolidated EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table shows the calculation of the Leverage Ratio for the twelve months ended June 30, 2009 ($ in thousands):

Consolidated funded debt	$	195,000
Divided by: Consolidated Adjusted EBITDA (a)	$	114,577
Leverage Ratio		1.7

(a) Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, depletion, depreciation, and amortization, and exploration expense, after giving pro forma effect to one or more acquisitions or dispositions in excess of $20 million in the aggregate. Consolidated Adjusted EBITDA is a non-GAAP financial measure, which is reconciled to its most directly comparable GAAP measure below.

     The following table presents a calculation of Consolidated EBITDA and Consolidated Adjusted EBITDA for the twelve months ended June 30, 2009 (in thousands) as required under the OLLC Credit Agreement, together with a reconciliation of such amounts to their most directly comparable financial measures calculated and presented in accordance with GAAP. These EBITDA measures should not be considered an alternative to net income (loss), operating income (loss), cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. These EBITDA measures may not be comparable to similarly titled measures of another company because all companies may not calculate these measures in the same manner.

37

ENCORE ENERGY PARTNERS LP

Consolidated net income	$	180,405
Unrealized non-cash hedge gain		(130,390	)
Consolidated net interest expense		7,964
Income and franchise taxes		998
Depletion, depreciation, amortization, and exploration expense		41,202
Non-cash unit-based compensation		3,321
Other non-cash		285
Consolidated EBITDA		103,785
Pro forma effect of acquisitions	10,792
Consolidated Adjusted EBITDA	$	114,577

     The OLLC Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. 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.

     On June 30, 2009, there were $195 million of outstanding borrowings and $45 million of borrowing capacity under the OLLC Credit Agreement. On July 31, 2009, there were $150 million of outstanding borrowings and $90 million of borrowing capacity under the OLLC Credit Agreement.

     Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our revolving credit facility.

     Debt covenants. At June 30, 2009, we and OLLC were in compliance with all debt covenants.

     Capitalization.At June 30, 2009, we had total assets of $569.3 million and total capitalization of $521.3 million, of which 63 percent was represented by partners’ equity and 37 percent by long-term debt. At December 31, 2008, we had total assets of $610.8 million and total capitalization of $574.4 million, of which 74 percent was represented by partners’ equity and 26 percent by long-term debt. The percentages of our capitalization represented by partners’ equity and long-term debt could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Critical Accounting Policies and Estimates

     Please read Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on May 7, 2009, which recast “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” included in our 2008 Annual Report on Form 10-K, for additional information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

     The effects of new accounting pronouncements are discussed in Note 2 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This information provides indicators of how we view and manage our ongoing market risk exposures. We do not enter into market risk sensitive instruments for speculative trading purposes.

     The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2008 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

38

ENCORE ENERGY PARTNERS LP

Commodity Price Sensitivity

     Our commodity derivative contracts are discussed in Note 5 to the Consolidated Financial Statements included in “Item 1. Financial Statements.” The counterparties to our commodity derivative contracts are a diverse group of five institutions, all of which are currently rated AA- or better by Standard & Poor’s and/or Fitch. As of June 30, 2009, the fair market value of our oil derivative contracts was a net asset of approximately $40.0 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $15.3 million. Based on our open commodity derivative positions at June 30, 2009, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $33.6 million, while a 10 percent decrease in the respective NYMEX prices for oil and natural gas would increase our net commodity derivative asset by approximately $35.2 million.

Interest Rate Sensitivity

     Our long-term debt is discussed in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At June 30, 2009, we had total long-term debt of $195 million, all of which consisted of outstanding borrowings under our revolving credit facility, which are subject to floating market rates of interest that are linked to the Eurodollar rate. At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $0.5 million of interest expense per year, and if the Eurodollar rate decreased by 10 percent, we would incur $0.5 million less.

     Our interest rate swaps are discussed in Note 5 to the Consolidated Financial Statements included in “Item 1. Financial Statements.” As of June 30, 2009, the fair market value of our interest rate swaps was a net liability of approximately $3.8 million. If the Eurodollar rate increased by 10 percent, we estimate the liability would decrease to approximately $3.4 million, and if the Eurodollar rate decreased by 10 percent, we estimate the liability would increase to approximately $4.2 million.

Item 4. Controls and Procedures

     In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of our general partner’s management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of June 30, 2009 to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our general partner, to allow timely decisions regarding required disclosure.

     There were no changes in our internal control over financial reporting during the second quarter of 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

39

ENCORE ENERGY PARTNERS LP

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

     We are a party to ongoing legal proceedings in the ordinary course of business. Our general partner’s management does not believe the result of these legal proceedings will have a material adverse effect on our business, financial condition, results of operations, liquidity, or ability to pay distributions.

Item 1A. Risk Factors

     In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” and elsewhere in our 2008 Annual Report on Form 10-K, which could materially affect our business, financial condition, results of operations, or ability to pay distributions. The risks described in our 2008 Annual Report on Form 10-K are not the only risks we face. Unknown risks and uncertainties or risks and uncertainties that we currently believe to be immaterial may also have a material adverse effect on our business, financial condition, results of operations, or ability to pay distributions.

Item 6. Exhibits

Exhibit No.	Description
3.1	Certificate of Limited Partnership of Encore Energy Partners LP (incorporated by reference from Exhibit 3.1 to Form S-1 (File No. 333-142847) for Encore Energy Partners LP, filed with the SEC on May 11, 2007).
3.2	Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of September 17, 2007 (incorporated by reference from Exhibit 3.1 of ENP’s Current Report on Form 8-K, filed with the SEC on September 21, 2007).
3.2.1	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of May 10, 2007 (incorporated by reference from Exhibit 3.1 to ENP’s Current Report on Form 8-K, filed with the SEC on April 18, 2008).
10.1	Purchase and Sale Agreement, dated May 18, 2009, by and among Encore Energy Partners LP, Encore Energy Partners Operating LLC, and Encore Operating, L.P. (incorporated by reference from Exhibit 2.1 of ENP’s Current Report on Form 8-K, filed with the SEC on June 5, 2009).
10.2	Purchase and Sale Agreement, dated June 28, 2009, by and among Encore Energy Partners LP, Encore Energy Partners Operating LLC, and Encore Operating, L.P. (incorporated by reference from Exhibit 2.1 of ENP’s Current Report on Form 8-K, filed with the SEC on June 29, 2009).
31.1*	Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer of our General Partner).
31.2*	Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer of our General Partner).
32.1*	Section 1350 Certification (Principal Executive Officer of our General Partner).
32.2*	Section 1350 Certification (Principal Financial Officer of our General Partner).
99.1*	Statement showing computation of ratios of loss to fixed charges.

* Filed herewith.

40

ENCORE ENERGY PARTNERS LP

SIGNATURE

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

	ENCORE ENERGY PARTNERS LP By:   Encore Energy Partners GP LLC, its General          Partner
Date: August 3, 2009	/s/ Andrea Hunter
	Andrea Hunter
	Vice President, Controller, and Principal Accounting Officer (Duly Authorized Signatory)

41