Encore Energy Partners 10-Q 2010 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, 2010

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 incorporation or organization)	(I.R.S. Employer 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.

Yesþ Noo

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).

Yeso Noo

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 filero Accelerated filerþ Non-accelerated filero(Do not check if a smaller reporting company) Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).	Yeso Noþ
Number of common units outstanding as of August 5, 2010	45,341,597

ENCORE ENERGY PARTNERS LP

INDEX

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009		1
Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009		2
Consolidated Statement of Partners’ Equity and Comprehensive Income for the six months ended June 30, 2010		3
Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3. Quantitative and Qualitative Disclosures About Market Risk		31
Item 4. Controls and Procedures		31
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		32
Item 1A. Risk Factors		32
Item 6. Exhibits		32
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 2009 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.

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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.

• CO₂. Carbon dioxide.

• 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.

• 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.

• Dry Hole.An exploratory, development, or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

• Denbury.Denbury Resources Inc., a publicly traded Delaware corporation, together with its subsidiaries.

• EAC.Encore Acquisition Company, together with its subsidiaries. EAC merged with and into Denbury on March 9, 2010.

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

• Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously producing oil or natural gas in another reservoir.

• FASB.Financial Accounting Standards Board.

• FASC. FASB Accounting Standards Codification.

• 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 ad valorem taxes, 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.

• 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.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 or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

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ENCORE ENERGY PARTNERS LP

• Proved Reserves.The estimated quantities of hydrocarbons, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing conditions and operating methods.

• 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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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

• Reliable Technology.A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

• Reserves.Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to the economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

• 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.

• 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS
(in thousands, except unit amounts)

	June 30,			December 31,
	2010			2009
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	14,704		$	1,754
Accounts receivable:
Trade		16,249			24,543
Affiliate		1,358			8,213
Derivatives		16,164			12,881
Other		557			857
Total current assets		49,032			48,248
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		854,293			851,833
Unproved properties		19			55
Accumulated depletion, depreciation, and amortization		(235,322	)		(210,417	)
		618,990			641,471
Other property and equipment		865			863
Accumulated depreciation		(524	)		(419	)
		341			444
Goodwill		9,290			9,290
Other intangibles, net		3,164			3,316
Derivatives		13,429			13,423
Other		2,663			3,459
Total assets	$	696,909		$	719,651
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	660		$	577
Affiliate		1,595			2,780
Accrued liabilities:
Lease operating		6,430			4,157
Development capital		742			1,484
Interest		363			429
Production taxes and marketing		9,860			10,218
Derivatives		4,268			9,815
Oil and natural gas revenues payable		2,480			1,598
Other		2,627			1,632
Total current liabilities		29,025			32,690
Derivatives		4,946			13,401
Future abandonment cost, net of current portion		12,805			12,556
Long-term debt		245,000			255,000
Total liabilities		291,776			313,647
Commitments and contingencies (see Note 11)
Partners’ equity:
Limited partners - 45,341,597 and 45,285,347 common units issued and outstanding, respectively		407,193			409,777
General partner - 504,851 general partner units issued and outstanding		544			(353	)
Accumulated other comprehensive loss		(2,604	)		(3,420	)
Total partners’ equity		405,133			406,004
Total liabilities and partners’ equity	$	696,909		$	719,651

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

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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,
	2010			2009 *			2010			2009*
Revenues:
Oil	$	38,494		$	31,991		$	78,447		$	53,458
Natural gas		6,288			4,526			14,910			9,188
Marketing		77			109			147			279
Total revenues		44,859			36,626			93,504			62,925
Expenses:
Production:
Lease operating		10,475			10,740			22,094			22,897
Production taxes and marketing		4,678			4,122			9,744			7,342
Depletion, depreciation, and amortization		12,839			15,077			25,690			29,586
Exploration		55			18			76			40
General and administrative		3,543			3,228			7,271			6,243
Derivative fair value loss (gain)		(16,543	)		37,440			(21,956	)		26,533
Total expenses		15,047			70,625			42,919			92,641
Operating income (loss)		29,812			(33,999	)		50,585			(29,716	)
Other income (expenses):
Interest		(3,276	)		(2,351	)		(6,635	)		(4,567	)
Other		13			1			38			11
Total other expenses		(3,263	)		(2,350	)		(6,597	)		(4,556	)
Income (loss) before income taxes		26,549			(36,349	)		43,988			(34,272	)
Income tax provision		(85	)		(200	)		(111	)		(201	)
Net income (loss)	$	26,464		$	(36,549	)	$	43,877		$	(34,473	)
Net income (loss) allocation (see Note 8):
Limited partners’ interest in net income (loss)	$	26,173		$	(37,093	)	$	43,394		$	(32,582	)
General partner’s interest in net income (loss)	$	291		$	(630	)	$	483		$	(573	)
Net income (loss) per common unit:
Basic	$	0.58		$	(1.08	)	$	0.96		$	(0.97	)
Diluted	$	0.58		$	(1.08	)	$	0.96		$	(0.97	)
Weighted average common units outstanding:
Basic		45,342			34,260			45,320			33,672
Diluted		45,342			34,260			45,333			33,672
Cash distributions declared per common unit	$	0.5000		$	0.5000		$	1.0375		$	1.0000

* Recast for August 2009 acquisition as discussed in Note 2.

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

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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY AND COMPREHENSIVE INCOME
(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, 2009		45,285	$	409,777			505	$	(353	)	$	(3,420	)	$	406,004
Owner contributions		—		(4	)		—		935			—			931
Non-cash equity-based compensation		—		1,033			—		8			—			1,041
Vesting of phantom units		57		—			—		—			—			—
Cash distributions to unitholders ($1.0375 per unit)		—		(47,012	)		—		(524	)		—			(47,536	)
Components of comprehensive income:
Net income attributable to unitholders		—		43,399			—		478			—			43,877
Change in deferred hedge loss on interest rate swaps, net of tax of $6		—		—			—		—			816			816
Total comprehensive income															44,693
Balance at June 30, 2010		45,342	$	407,193			505	$	544		$	(2,604	)	$	405,133

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

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ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)

	Six months ended
	June 30,
	2010			2009*
Cash flows from operating activities:
Net income (loss)	$	43,877		$	(34,473	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		25,690			29,586
Deferred taxes		2			(248	)
Non-cash exploration expense		35			17
Non-cash equity-based compensation expense		1,041			269
Non-cash derivative loss (gain)		(16,471	)		69,055
Other		1,750			323
Changes in operating assets and liabilities:
Accounts receivable		15,046			827
Current derivatives		—			(2,020	)
Other current assets		66			(179	)
Long-term derivatives		—			(9,072	)
Other assets		(15	)		8
Accounts payable		(1,102	)		(2,383	)
Other current liabilities		3,695			5,311
Net cash provided by operating activities		73,614			57,021
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(279	)		(27,538	)
Development of oil and natural gas properties		(2,843	)		(4,911	)
Net cash used in investing activities		(3,122	)		(32,449	)
Cash flows from financing activities:
Proceeds from issuance of common units, net of offering costs		—			40,724
Proceeds from long-term debt		10,000			78,000
Payments on long-term debt		(20,000	)		(33,000	)
Deemed distributions to affiliates in connection with acquisitions		—			(72,149	)
Cash distributions to unitholders		(47,536	)		(33,582	)
Other		(6	)		(5,112	)
Net cash used in financing activities		(57,542	)		(25,119	)
Increase (decrease) in cash and cash equivalents		12,950			(547	)
Cash and cash equivalents, beginning of period		1,754			619
Cash and cash equivalents, end of period	$	14,704		$	72

* Recast for August 2009 acquisition as discussed in Note 2.

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

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ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1. Description of Business

     ENP is engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States. Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of Denbury, 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 and New Mexico;

• the Williston Basin in North Dakota and Montana; and

• the Arkoma Basin in Arkansas and Oklahoma.

EAC’s Merger with Denbury

     On March 9, 2010, Encore Acquisition Company (“EAC”), the former parent of the General Partner, was merged with and into Denbury (the “Merger”), with Denbury surviving the Merger. As part of the Merger, Denbury became the owner of the General Partner and approximately 46 percent of ENP’s outstanding common units. The Merger did not impact the accompanying Consolidated Financial Statements.

Strategic Alternatives and Asset Transaction Processes

     On April 30, 2010, ENP and Denbury, the ultimate parent of the General Partner, announced the intent to explore a broad range of strategic alternatives (the “strategic process”) to enhance the value of ENP’s common units, including, but not limited to, those alternatives involving a possible merger, sale, or other transaction involving ENP, Denbury’s interest in the General Partner, or all or part of the ENP common units that Denbury owns. Additionally, ENP and Denbury also intend to explore a sale or other transaction involving one or more of ENP’s assets (the “asset process”), initiated in light of the substantial projected capital requirements required to recognize the full potential value of certain fields owned by ENP which are possible CO₂ tertiary projects, such as the Elk Basin field. In May 2010, the Conflicts Committee of the board of directors of the General Partner engaged an investment bank to assist in its responsibilities with regard to the asset process. In conjunction with entering into this agreement, ENP incurred a $1 million non-refundable retainer fee, which is included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations. Although either or both of these processes may result in one or more transactions involving ENP, Denbury, and/or a third party, there is no assurance that a review of strategic alternatives or consideration of an asset transaction will result in the proposal or completion of any transaction with acceptable terms.

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 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, L.P. (“Encore Operating”), at the time a subsidiary of EAC. In August 2009, ENP acquired certain oil and natural gas properties and related assets 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”) from Encore Operating. Because these 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, including the three and six months ended June 30, 2009, was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating. Accordingly, the consolidated financial statements and notes thereto presented for the 2009 periods reflect the historical results of ENP combined with those of the Williston Basin Assets and the Rockies and Permian Basin Assets.

     For the 2009 periods shown, the results of operations of the Williston Basin Assets and the Rockies and Permian Basin Assets related to periods prior to the transfer of those assets to ENP in August 2009 were allocated to those EAC entities holding general and limited partner interests based on their respective ownership percentages in ENP. The effect of recasting ENP’s consolidated financial statements to account for these common control transactions reduced ENP’s net loss by approximately $1.2 million for the three months ended June 30, 2009 and increased ENP’s net loss by approximately $1.3 million for the six months ended June 30, 2009.

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

     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, 2010, results of operations for the three and six months ended June 30, 2010 and 2009, and cash flows for the six months ended June 30, 2010 and 2009. 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 ENP’s 2009 Annual Report on Form 10-K.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform to the current period presentation. On the accompanying Consolidated Statements of Operations, NGL revenues were reclassed from “Natural gas revenues” to “Oil revenues,” marketing expenses were reclassed to “Lease operating expenses,” ad valorem taxes were reclassed to “Lease operating expenses,” and transportation expenses were reclassed to “Production taxes and marketing.”

Note 3. 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,
	2010		2009
	(in thousands)
Proved leasehold costs	$	609,910	$	609,692
Wells and related equipment — Completed		244,280		241,953
Wells and related equipment — In process		103		188
Total proved properties	$	854,293	$	851,833

Note 4. 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, 2010				December 31, 2009
	Book		Fair		Book		Fair
	Value		Value		Value		Value
			(in thousands)
Assets:
Cash and cash equivalents	$	14,704	$	14,704	$	1,754	$	1,754
Accounts receivable — trade		16,249		16,249		24,543		24,543
Accounts receivable — affiliate		1,358		1,358		8,213		8,213
Commodity derivative contracts		29,593		29,593		26,304		26,304
Liabilities:
Accounts payable — trade		660		660		577		577
Accounts payable — affiliate		1,595		1,595		2,780		2,780
Revolving credit facility		245,000		240,485		255,000		252,047
Commodity derivative contracts		6,262		6,262		19,547		19,547
Interest rate swaps		2,952		2,952		3,669		3,669

     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; however, ENP adjusted the estimated fair value for estimated nonperformance risk of approximately $4.5 million and $3.0 million at June 30, 2010 and December 31, 2009, respectively. The nonperformance risk was determined using industry credit default swaps. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

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

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, all of which are lenders underwriting the ENP’s revolving credit facility. 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 the “Derivatives” topic of the FASC, 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, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss within partners’ equity 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.

     ENP has elected to designate its outstanding 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 and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

     ENP has elected not to designate its current portfolio of commodity derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included in “Derivative fair value loss (gain)” 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 some 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 result is ENP effectively owning one oil put option for 2,000 Bbls/D in 2010 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.

7

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, 2010:

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. 2010													$	1,189
		880	$	80.00		440	$	93.80		760	$	75.43
		2,000		75.00		1,000		77.23		250		65.95
		760		67.00		—		—		—		—
2011														7,189
		1,880		80.00		1,440		95.41		760		78.46
		1,000		70.00		—		—		—		—
		760		65.00		—		—		250		69.65
2012														145
		750		70.00		500		82.05		210		81.62
		1,510		65.00		250		79.25		1,300		76.54
													$	8,523

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Asset
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
July — Dec. 2010													$	6,631
		3,800	$	8.20		3,800	$	9.58		5,452	$	6.20
		4,698		7.26		—		—		550		5.86
2011														5,729
		3,398		6.31		—		—		7,952		6.36
		—		—		—		—		550		5.86
2012														2,448
		898		6.76		—		—		5,452		6.26
		—		—		—		—		550		5.86
													$	14,808

     Counterparty Risk.At June 30, 2010, ENP had committed 10 percent or greater (in terms of fair market value) of either its oil or natural gas derivative contracts in asset positions to the following counterparties:

	Fair Market Value of		Fair Market Value of
	Oil Derivative		Natural Gas
	Contracts		Derivative Contracts
Counterparty	Committed		Committed
	(in thousands)
BNP Paribas	$	7,642	$	3,763
Calyon		3,191		7,351
RBC		3,403		3,046

     In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with certain 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 is intended to benefit ENP in three ways: (1) the

8

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

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 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, 2010, all of which were entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
July 2010 — Jan. 2011	$	50,000		3.1610	%	1-month LIBOR
July 2010 — Jan. 2011		25,000		2.9650	%	1-month LIBOR
July 2010 — Jan. 2011		25,000		2.9613	%	1-month LIBOR
July 2010 — Mar. 2012		50,000		2.4200	%	1-month LIBOR

Current Period Impact

     ENP recognizes 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) receipts and settlements on derivative contracts not designated as hedges; and (4) premium amortization. The following table summarizes the components of “Derivative fair value loss (gain)” for the periods indicated:

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Ineffectiveness on interest rate swaps	$	45		$	6		$	104		$	(34	)
Mark-to-market loss (gain)		(15,264	)		50,251			(21,443	)		57,681
Premium amortization		2,448			5,854			4,868			11,408
Receipts, net of settlements		(3,772	)		(18,671	)		(5,485	)		(42,522	)
Total derivative fair value loss (gain)	$	(16,543	)	$	37,440		$	(21,956	)	$	26,533

Accumulated Other Comprehensive Loss

     At June 30, 2010 and December 31, 2009, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $2.6 million and $3.4 million, respectively. During the twelve months ending June 30, 2011, ENP expects to reclassify $2.4 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense. The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to fluctuations in interest rates.

9

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

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
		Fair Value					Fair Value
	Balance Sheet Location	June 30 2010		December 31, 2009		Balance Sheet Location	June 30, 2010		December 31, 2009
Derivatives not designated as hedges
Commodity derivative contracts	Derivatives — current	$	16,164	$	12,881	Derivatives — current	$	1,850	$	6,393
Commodity derivative contracts	Derivatives — noncurrent		13,429		13,423	Derivatives — noncurrent		4,412		13,154
Total derivatives not designated as hedges		$	29,593	$	26,304		$	6,262	$	19,547
Derivatives designated as hedges
Interest rate swaps	Derivatives — current	$	—	$	—	Derivatives — current	$	2,418	$	3,422
Interest rate swaps	Derivatives — noncurrent		—		—	Derivatives — noncurrent		534		247
Total derivatives designated as hedges		$	—	$	—		$	2,952	$	3,669
Total derivatives		$	29,593	$	26,304		$	9,214	$	23,216
									��

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

		Amount of Loss (Gain) Recognized in Income					Amount of Loss (Gain) Recognized in Income
		Three Months Ended June 30,					Six Months Ended June 30,
	Location of Loss (Gain)
Derivatives Not Designated as Hedges	Recognized in Income	2010			2009		2010			2009
Commodity derivative contracts	Derivative fair value loss (gain)	$	(16,588	)	$	37,434	$	(22,060	)	$	26,567

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

	Amount of Loss (Gain) Recognized in						Amount of Loss (Gain) Recognized in
	Accumulated OCI (Effective Portion)						Accumulated OCI (Effective Portion)
	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives Designated as Hedges	2010			2009			2010			2009
Interest rate swaps	$	(325	)	$	(440	)	$	(1,135	)	$	1,155

	Amount of Loss Reclassified from Accumulated				Amount of Loss Reclassified from Accumulated
	OCI into Income (Effective Portion)				OCI into Income (Effective Portion)
Location of Loss Reclassified from Accumulated	Three Months Ended June 30,				Six Months Ended June 30,
OCI into Income (Effective Portion)	2010		2009		2010		2009
Interest expense	$	969	$	922	$	1,951	$	1,803

	Amount of Loss Recognized				Amount of Loss (Gain) Recognized
	in Income as Ineffective				in Income as Ineffective
	Three Months Ended June 30,				Six Months Ended June 30,
Location of Loss Recognized in Income as Ineffective	2010		2009		2010		2009
Derivative fair value loss (gain)	$	45	$	6	$	104	$	(34	)

Fair Value Hierarchy

     The FASC established a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy 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.

10

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

     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-based 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, which are not exchange—traded contracts. 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 multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

     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, 2010:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
Description	Asset (Liability)			(Level 1)		(Level 2)			(Level 3)
				(in thousands)
Oil derivative contracts — swaps	$	(3,991	)	$	—	$	(3,991	)	$	—
Oil derivative contracts — floors and caps		12,514			—		—			12,514
Natural gas derivative contracts — swaps		7,666			—		7,666			—
Natural gas derivative contracts — floors and caps		7,142			—		—			7,142
Interest rate swaps		(2,952	)		—		(2,952	)		—
Total	$	20,379		$	—	$	723		$	19,656

11

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, 2010:

	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, 2010	$	8,585		$	8,528		$	17,113
Total gains (losses):
Included in earnings		3,989			3,232			7,221
Settlements		(60	)		(4,618	)		(4,678	)
Balance at June 30, 2010	$	12,514		$	7,142		$	19,656
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	3,989		$	3,232		$	7,221

     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 (gain)” in the accompanying Consolidated Statements of Operations.

     All fair values have been adjusted for nonperformance risk resulting in an decrease of the net commodity derivative asset of approximately $0.3 million as of June 30, 2010. For commodity derivative contracts which are in an asset position, ENP uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, ENP uses the average credit default swap rating of its peer companies as ENP does not have its own credit default swap rating.

Note 5. Asset Retirement Obligations

     Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the six months ended June 30, 2010 (in thousands):

Future abandonment liability at January 1, 2010	$	13,130
Accretion of discount		363
Revision of previous estimates		20
Plugging and abandonment costs incurred		(60	)
Future abandonment liability at June 30, 2010	$	13,453

     As of June 30, 2010, $12.8 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.6 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheet. Approximately $4.9 million of the long-term future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant.

Note 6. 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. In November 2009, OLLC amended the OLLC Credit Agreement, which was effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger from being a “Change of Control” under the OLLC Credit Agreement. In conjunction with this amendment, Denbury paid a fee of approximately $0.9 million to JP Morgan, which had provided a guaranty of credit in the event the OLLC Credit Agreement was not amended to permit the consummation of the Merger from being a “Change of Control.” Denbury is not seeking reimbursement from ENP for this payment. As such, the $0.9 million paid by Denbury is reflected as a capital contribution to ENP by Denbury in its capacity as the parent of the General Partner and is included in “General and administrative expense” in the accompanying Consolidated Statement of Operations for the six months ended June 30, 2010 as a non-cash expense.

12

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

     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 $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. On June 14, 2010, the borrowing base under the OLLC Credit Agreement was reaffirmed at $375 million. As of June 30, 2010, there were $245 million of outstanding borrowings and $130 million of borrowing capacity under the OLLC Credit Agreement.

     OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

     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, 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 Denbury and its restricted subsidiaries.

     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) 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 Outstanding Borrowings to Borrowing Base	Eurodollar Loans			Base Rate Loans
Less than .50 to 1		2.250	%		1.250	%
Greater than or equal to .50 to 1 but less than .75 to 1		2.500	%		1.500	%
Greater than or equal to .75 to 1 but less than .90 to 1		2.750	%		1.750	%
Greater than or equal to .90 to 1		3.000	%		2.000	%

     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 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 several restrictive covenants including, among others, the following:

• 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 2.5 to 1.0; and

• a requirement that ENP and OLLC maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA of not more than 3.5 to 1.0.

     As of June 30, 2010, ENP and OLLC were in compliance with all covenants of the OLLC Credit Agreement.

13

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

     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 7. 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.

     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)
2010
Quarter ended June 30	7/29/2010	$	0.5000	8/13/2010 (a)	$	22,923	(a)
Quarter ended March 31	4/30/2010	$	0.5000	5/14/2010		22,923
2009
Quarter ended December 31	1/25/2010	$	0.5375	2/12/2010		24,642
Quarter ended September 30	10/26/2009	$	0.5375	11/13/2009		24,642
Quarter ended June 30	7/27/2009	$	0.5125	8/14/2009		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

(a) Represents the date the distribution is expected to be paid and the total amount of the distribution that is expected to be paid.

Note 8. Earnings Per Unit

     ENP applies the provisions of the “Earnings Per Share” topic of the FASC, which requires earnings per unit to be calculated using the two-class method. Under the two-class method of calculating earnings per unit, 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 earnings per unit, general partner units and unvested phantom units are considered participating securities. Earnings per unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common units outstanding.

14

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

     The following table reflects the allocation of net income (loss) to ENP’s limited partners and earnings per unit computations for the periods indicated:

	Three months ended						Six months ended
	June 30,						June 30,
	2010			2009			2010			2009
	(in thousands, except per unit amounts)
Net income (loss)	$	26,464		$	(36,549	)	$	43,877		$	(34,473	)
Less: net loss (income) for pre-partnership operations of assets acquired from affiliates		—			(1,174	)		—			1,318
Net income (loss) attributable to unitholders	$	26,464		$	(37,723	)	$	43,877		$	(33,155	)
Numerator:
Numerator for basic earnings per unit:
Net income (loss) attributable to unitholders	$	26,464		$	(37,723	)	$	43,877		$	(33,155	)
Less: distributions earned by participating securities		(252	)		(258	)		(504	)		(511	)
Plus: cash distributions in excess of (less than) income allocated to the general partner		(39	)		888			21			1,084
Net income (loss) allocated to limited partners	$	26,173		$	(37,093	)	$	43,394		$	(32,582	)
Denominator:
Denominator for basic earnings per unit:
Weighted average common units outstanding		45,342			34,260			45,320			33,672
Effect of dilutive phantom units (a)		—			—			13			—
Denominator for diluted earnings per unit		45,342			34,260			45,333			33,672
Net income (loss) per common unit:
Basic	$	0.58		$	(1.08	)	$	0.96		$	(0.97	)
Diluted	$	0.58		$	(1.08	)	$	0.96		$	(0.97	)

(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. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of phantom units.

Note 9. Unit-Based Compensation Plans

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 and consultants of Denbury, 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 acquire common units in the open market, use common units owned by the General Partner, or use common units acquired by the General Partner from ENP or from any other person.

     The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. As of June 30, 2010, there were 1,075,000 common units available for issuance under the LTIP with none outstanding.

     Phantom Units.As a result of the change of control of the General Partner in conjunction with the Merger of EAC with and into Denbury, all of ENP’s outstanding phantom units vested and were settled in common units. The acceleration of the phantom unit vesting resulted in the recognition of the remaining unrecognized unit-based compensation expense of approximately $0.7 million during March 2010. The fair value of these phantom units was approximately $1.2 million on the date of the Merger. Historically, each October, ENP issued 5,000 phantom units to each member of the General Partner’s board of directors pursuant to the LTIP. A phantom unit entitled the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan

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

administrator, the cash equivalent equal to the value of a common unit on the vest date. ENP intended to settle any outstanding phantom units at vesting by issuing common units to the grantee; therefore, phantom units were classified as equity instruments. Phantom units vested equally over a four-year period. The holders of phantom units were also entitled to distribution equivalent rights prior to vesting, which entitled 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 was outstanding. During the six months ended June 30, 2010 and 2009, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.7 million (upon closing of the Merger on March 9, 2010) and $0.2 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of June 30, 2010, there are no outstanding phantom units.

Note 10. Comprehensive Income (Loss)

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

	Three months ended					Six months ended
	June 30,					June 30,
	2010		2009			2010		2009
	(in thousands)
Net income (loss)	$	26,464	$	(36,549	)	$	43,877	$	(34,473	)
Change in deferred hedge loss on interest rate swaps		658		1,361			816		648
Comprehensive income (loss)	$	27,122	$	(35,188	)	$	44,693	$	(33,825	)

Note 11. 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, 2010.

Note 12. Related Party Transactions

Administrative Services Agreement

     ENP does not have any employees. The employees supporting the operations of ENP are employees of Denbury. 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.

     From April 1, 2008 to March 31, 2009, the administrative fee was $1.88 per BOE of ENP’s production. From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production. Effective April 1, 2010, the administrative fee increased to $2.06 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;

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

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

     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” or “General and administrative expenses” in the accompanying Consolidated Statement of Operations based on the nature of the expense. 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,
	2010		2009		2010		2009
	(in thousands)
Administrative fees (including COPAS recovery)	$	2,381	$	1,163	$	5,441	$	2,825
Third-party expenses		553		2,017		3,315		2,973

     As of June 30, 2010, ENP had a payable to Denbury of $1.6 million which is reflected as “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from Denbury of $1.4 million which is reflected as “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets. As of December 31, 2009, ENP had a payable to EAC of $2.8 million which is reflected as “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from EAC of $8.2 million which is reflected as “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheets.

Acquisitions

     As previously discussed, ENP acquired the Williston Basin Assets from Encore Operating in June 2009 for approximately $25.2 million and ENP acquired the Rockies and Permian Basin Assets from Encore Operating in August 2009 for approximately $179.6 million in cash. Prior to the acquisition by ENP, the properties were owned by EAC and were not separate legal entities.

     In addition to payroll-related expenses, prior to the Merger, 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 was 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. A portion of EAC’s consolidated indirect lease operating overhead expenses was allocated to ENP included in the accompanying Consolidated Statements of Operations based on its share of EAC’s direct lease operating expense.

Distributions

     Each quarter, ENP pays cash distributions with respect to operations in the previous quarter on all of its outstanding units, including those common units held by the General Partner and its affiliates, and pays cash distributions to the General Partner based upon its general partner interest. On May 14, 2010, ENP paid cash distributions of approximately $22.9 million, of which $10.7 million was paid to the General Partner and its affiliates. On February 12, 2010, ENP paid cash distributions of approximately $24.6 million, of which $11.5 million was paid to the General Partner and its affiliates. On each of May 15, 2009 and February 13, 2009, ENP paid cash distributions of approximately $16.8 million, of which $10.7 million was paid to the General Partner and its affiliates.

Note 13. Subsequent Events

     On July 29, 2010, the board of directors of the General Partner declared an ENP cash distribution for the second quarter of 2010 to unitholders of record as of the close of business on August 9, 2010 of $0.50 per unit or approximately $22.9 million of which $10.7 million is expected to be paid to the General Partner and its affiliates. The distribution is expected to be paid to unitholders on or about August 13, 2010.

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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 2009 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.

Introduction

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

• Recent Developments

• Overview of Business

• Second Quarter 2010 Highlights

• Results of Operations

• Comparison of Quarter Ended June 30, 2010 to Quarter Ended June 30, 2009

• Comparison of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2009

• Capital Commitments, Capital Resources, and Liquidity

• Critical Accounting Policies and Estimates

Recent Developments

     On April 30, 2010, ENP and Denbury, the ultimate parent of our general partner, announced the intent to explore a broad range of strategic alternatives (the “strategic process”) to enhance the value of our common units, including, but not limited to, those alternatives involving a possible merger, sale, or other transaction involving us, Denbury’s interest in our general partner, or all or part of our common units that Denbury owns. Additionally, we and Denbury also intend to explore a sale or other transaction involving one or more of our assets (the “asset process”), initiated in light of the substantial projected capital requirements required to recognize the full potential value of certain fields owned by us which are possible CO₂ tertiary projects, such as the Elk Basin field. In May 2010, the Conflicts Committee of the board of directors of our general partner engaged an investment bank to assist in its responsibilities with regard to the asset process. In conjunction with entering into this agreement, we incurred a $1 million non-refundable retainer fee. Although either or both of these processes may result in one or more transactions involving us, Denbury, and/or a third party, there is no assurance that a review of strategic alternatives or consideration of an asset transaction will result in the proposal or completion of any transaction with acceptable terms.

Overview of Business

     We are a Delaware limited partnership engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States. Our primary business objective is to make quarterly cash distributions to our unitholders in accordance with our guideline as discussed in “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Distributions to unitholders.” 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 and New Mexico;

• the Williston Basin in North Dakota and Montana; and

• the Arkoma Basin in Arkansas and Oklahoma.

     On March 9, 2010, Encore Acquisition Company, the former parent of our general partner, was merged (the “Merger”) with and into Denbury, with Denbury surviving the Merger. As part of the Merger, Denbury became the owner of our general partner and approximately 46 percent of our outstanding common units. Upon the effectiveness of the Merger, I. Jon Brumley and Jon S. Brumley resigned from the board of directors of our general partner resulting in a decrease in the number of directors from seven to five.

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     In June 2009, we acquired the Williston Basin Assets, from Encore Operating for approximately $25.2 million in cash, which was financed though borrowings under our revolving credit facility. In August 2009, we acquired the Rockies and Permian Basin Assets from Encore Operating for approximately $179.6 million in cash, which was financed though borrowings under our revolving credit facility and a portion of proceeds from the issuance of 9,430,000 common units to the public. Because these 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 our historical financial information, including the three and six months ended June 30, 2009, was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating. Accordingly, our financial condition and results of operations presented for the 2009 periods reflect our historical results combined with those of the Williston Basin Assets and the Rockies and Permian Basin Assets.

Second Quarter 2010 Highlights

     Our financial and operating results for the second quarter of 2010 included the following:

• Our net income increased to $26.5 million ($0.58 per common unit) as compared to a net loss of $36.5 million ($1.08 per common unit) for the second quarter of 2009.

• Our oil and natural gas revenues increased 23 percent to $44.8 million as compared to $36.5 million in the second quarter of 2009. Oil represented approximately 70 percent and 71 percent of our total production in the second quarter of 2010 and 2009, respectively.

• Our average realized oil price increased 28 percent to $68.53 per Bbl as compared to $53.50 per Bbl in the second quarter of 2009. Our average realized natural gas price increased 38 percent to $4.32 per Mcf as compared to $3.13 per Mcf in the second quarter of 2009.

• Our production margin increased 37 percent to $29.6 million as compared to $21.7 million in the second quarter of 2009. Total oil and natural gas wellhead revenues per BOE increased by 28 percent while total production expenses per BOE increased by only six percent. On a per BOE basis, our production margin increased 43 percent to $36.82 per BOE as compared to $25.81 per BOE for the second quarter of 2009.

• We invested $1.7 million in development and exploitation activities.

     See “Results of Operations” and “Capital Commitments, Capital Resources, and Liquidity” for additional discussion of these items.

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Results of Operations

Comparison of Quarter Ended June 30, 2010 to Quarter Ended June 30, 2009

     Revenues.The following table provides 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,				Increase / (Decrease)
	2010		2009 (a)		$			%
Revenues (in thousands):
Oil	$	38,494	$	31,991	$	6,503			20	%
Natural gas		6,288		4,526		1,762			39	%
Total oil and natural gas revenues		44,782		36,517		8,265			23	%
Marketing		77		109		(32	)		-29	%
Total revenues	$	44,859	$	36,626	$	8,233			22	%
Average realized prices:
Oil ($/Bbl)	$	68.53	$	53.50	$	15.03			28	%
Natural gas ($/Mcf)	$	4.32	$	3.13	$	1.19			38	%
Combined ($/BOE)	$	55.66	$	43.52	$	12.14			28	%
Total production volumes:
Oil (MBbls)		562		598		(36	)		-6	%
Natural gas (MMcf)		1,457		1,447		10			1	%
Combined (MBOE)		805		839		(34	)		-4	%
Average daily production volumes:
Oil (Bbls/D)		6,173		6,571		(398	)		-6	%
Natural gas (Mcf/D)		16,011		15,897		114			1	%
Combined (BOE/D)		8,841		9,221		(380	)		-4	%
Average NYMEX prices:
Oil (per Bbl)	$	78.12	$	59.83	$	18.29			31	%
Natural gas (per Mcf)	$	4.35	$	3.49	$	0.86			25	%

(a) In order to conform to the current period presentation, NGL revenues were reclassed from natural gas revenues to oil revenues.

     The following table shows 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,
	2010			2009
Average realized oil price ($/Bbl)	$	68.53		$	53.50
Average NYMEX ($/Bbl)	$	78.12		$	59.83
Differential to NYMEX	$	(9.59	)	$	(6.33	)
Average realized oil price to NYMEX percentage		88	%		89	%
Average realized natural gas price ($/Mcf)	$	4.32		$	3.13
Average NYMEX ($/Mcf)	$	4.35		$	3.49
Differential to NYMEX	$	(0.03	)	$	(0.36	)
Average realized natural gas price to NYMEX percentage		99	%		90	%

     Our average realized oil price as a percentage of the average NYMEX price was 88 percent in the second quarter of 2010 as compared to 89 percent in the second quarter of 2009. Our average realized natural gas price as a percentage of the average NYMEX price was 106 percent in the second quarter of 2010 as compared to 90 percent in the second quarter of 2009. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. In the second quarter of 2010, the natural gas index prices related to our natural gas contracts all improved in their relationship to NYMEX compared to the second quarter of 2009, narrowing the average differential. As a result of

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ENCORE ENERGY PARTNERS LP

the incremental NGLs value and the narrower differential, the price we were paid per Mcf for natural gas sold under certain contracts during the second quarter of 2010 increased to a level above NYMEX.

     Oil revenues increased 20 percent from $32.0 million in the second quarter of 2009 to $38.5 million in the second quarter of 2010 as a result of a $15.03 per Bbl increase in our average realized oil price partially offset by a 36 MBbls decrease in our oil production volumes. Our higher average realized oil price increased oil revenues by approximately $8.4 million and was primarily due to a higher average NYMEX price, which increased from $59.83 per Bbl in the second quarter of 2009 to $78.12 per Bbl in the second quarter of 2010. Our lower oil production volumes decreased oil revenues by approximately $1.9 million and were primarily due to natural production declines in our Elk Basin field.

     Natural gas revenues increased 39 percent from $4.5 million in the second quarter of 2009 to $6.3 million in the second quarter of 2010 as a result of a $1.19 per Mcf increase in our average realized natural gas price and a 10 MMcf increase in our natural gas production volumes. Our higher average realized natural gas price increased natural gas revenues by approximately $1.7 million and was primarily due to a higher average NYMEX price, which increased from $3.49 per Mcf in the second quarter of 2009 to $4.35 per Mcf in the second quarter of 2010, and the overall improvement in our natural gas differential as discussed above. Our higher natural gas production volumes were primarily due to our acquisition of certain natural gas properties in the Vinegarone Field in Val Verde County, Texas in May 2009.

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

	Three months ended June 30,					Increase / (Decrease)
	2010			2009 (a)		$			%
Expenses (in thousands):
Production:
Lease operating	$	10,475		$	10,740	$	(265	)
Production taxes and marketing		4,678			4,122		556
Total production expenses		15,153			14,862		291			2	%
Other:
Depletion, depreciation, and amortization		12,839			15,077		(2,238	)
Exploration		55			18		37
General and administrative		3,543			3,228		315
Derivative fair value loss (gain)		(16,543	)		37,440		(53,983	)
Total operating expenses		15,047			70,625		(55,578	)		-79	%
Interest		3,276			2,351		925
Income tax provision		85			200		(115	)
Total expenses	$	18,408		$	73,176	$	(54,768	)		-75	%
Expenses (per BOE):
Production:
Lease operating	$	13.02		$	12.80	$	0.22
Production taxes and marketing		5.82			4.91		0.91
Total production expenses		18.84			17.71		1.13			6	%
Other:
Depletion, depreciation, and amortization		15.96			17.97		(2.01	)
Exploration		0.07			0.02		0.05
General and administrative		4.40			3.85		0.55
Derivative fair value loss (gain)		(20.56	)		44.62		(65.18	)
Total operating expenses		18.71			84.17		(65.46	)		-78	%
Interest		4.07			2.80		1.27
Income tax provision		0.11			0.24		(0.13	)
Total expenses	$	22.89		$	87.21	$	(64.32	)		-74	%

(a) In order to conform to the current period presentation, marketing expenses were reclassed to lease operating expenses, ad valorem taxes were reclassed to lease operating expenses, and transportation expenses were reclassed to production taxes and marketing.

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     Production expenses.Production expense attributable to LOE decreased $0.3 million from $10.7 million in the second quarter of 2009 to $10.5 million in the second quarter of 2010 primarily due to retention bonuses paid in August 2009 related to EAC’s 2008 strategic alternatives process.

     Production expense attributable to production taxes and marketing increased $0.6 million from $4.1 million in the second quarter of 2009 to $4.7 million in the second quarter of 2010 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production, severance, and ad valorem taxes remained approximately constant at 10.9 percent in the second quarter of 2010 as compared to 10.8 percent in the second quarter of 2009.

     Depletion, depreciation, and amortization (“DD&A”) expense.DD&A expense decreased $2.2 million from $15.1 million in the second quarter of 2009 to $12.8 million in the second quarter of 2010 primarily due to the increase in our proved reserves in the second quarter of 2010 as a result of higher average commodity prices.

     General and administrative (“G&A”) expense.G&A expense increased $0.3 million to $3.5 million in the second quarter of 2010 as compared to $3.2 million in the second quarter of 2009 primarily due to a $1 million non-refundable retainer fee paid to an investment bank to assist the Conflicts Committee of the board of directors of our general partner in its responsibilities with regard to consideration of possible related party asset transactions, partially offset by professional fees incurred in the second quarter of 2009 related to the acquisition of properties from Encore Operating.

     Derivative fair value loss (gain).During the second quarter of 2010, we recorded a $16.5 million derivative fair value gain as compared to $37.4 million derivative fair value loss in the second quarter of 2009, the components of which were as follows:

	Three months ended June 30,						Increase /
	2010			2009			(Decrease)
	(in thousands)
Ineffectiveness on interest rate swaps	$	45		$	6		$	39
Mark-to-market loss (gain)		(15,264	)		50,251			(65,515	)
Premium amortization		2,448			5,854			(3,406	)
Receipts, net of settlements		(3,772	)		(18,671	)		14,899
Total derivative fair value loss (gain)	$	(16,543	)	$	37,440		$	(53,983	)

     Please read Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our derivative contracts.

     Interest expense.Interest expense increased $0.9 million from $2.4 million in the second quarter of 2009 to $3.3 million in the second quarter of 2010 primarily due to higher weighted average outstanding borrowings under our revolving credit facility, an increase in the amortization of debt issuance costs, and increases in the applicable margins under our revolving credit facility. Our weighted average interest rate was 5.3 percent for the second quarter of 2010 as compared to 5.0 percent for the second quarter of 2009.

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ENCORE ENERGY PARTNERS LP

Comparison of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2009

     Revenues.The following table provides 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,				Increase / (Decrease)
	2010		2009 (a)		$			%
Revenues (in thousands):
Oil	$	78,447	$	53,458	$	24,989			47	%
Natural gas		14,910		9,188		5,722			62	%
Total oil and natural gas revenues		93,357		62,646		30,711			49	%
Marketing		147		279		(132	)		-47	%
Total revenues	$	93,504	$	62,925	$	30,579			49	%
Average realized prices:
Oil ($/Bbl)	$	69.90	$	44.96	$	24.94			55	%
Natural gas ($/Mcf)	$	5.02	$	3.27	$	1.75			54	%
Combined ($/BOE)	$	57.71	$	37.81	$	19.90			53	%
Total production volumes:
Oil (MBbls)		1,122		1,189		(67	)		-6	%
Natural gas (MMcf)		2,972		2,807		165			6	%
Combined (MBOE)		1,618		1,657		(39	)		-2	%
Average daily production volumes:
Oil (Bbls/D)		6,200		6,570		(370	)		-6	%
Natural gas (Mcf/D)		16,420		15,510		910			6	%
Combined (BOE/D)		8,937		9,155		(218	)		-2	%
Average NYMEX prices:
Oil (per Bbl)	$	78.37	$	51.61	$	26.76			52	%
Natural gas (per Mcf)	$	4.69	$	4.20	$	0.49			12	%

(a) In order to conform to the current period presentation, NGL revenues were reclassed from natural gas revenues to oil revenues.

     The following table shows 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,
	2010			2009
Average realized oil price ($/Bbl)	$	69.90		$	44.96
Average NYMEX ($/Bbl)	$	78.37		$	51.61
Differential to NYMEX	$	(8.47	)	$	(6.65	)
Average realized oil price to NYMEX percentage		89	%		87	%
Average realized natural gas price ($/Mcf)	$	5.02		$	3.27
Average NYMEX ($/Mcf)	$	4.69		$	4.20
Differential to NYMEX	$	0.33		$	(0.93	)
Average realized natural gas price to NYMEX percentage		107	%		78	%

     Our average realized oil price as a percentage of the average NYMEX price was 89 percent in the first six months of 2010 as compared to 87 percent in the first six months of 2009. Our average realized natural gas price as a percentage of the average NYMEX price was 107 percent in the first six months of 2010 as compared to 78 percent in the first six months of 2009. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. In the first six months of 2010, the natural gas index prices related to our natural gas contracts all improved in their relationship to NYMEX compared to the first six months of 2009, improving the average differential. As a result of the incremental NGLs value and the improved differential, the price we were paid per Mcf for natural gas sold under certain contracts during the first six months of 2010 increased to a level above NYMEX.

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     Oil revenues increased 47 percent from $53.5 million in the first six months of 2009 to $78.4 million in the first six months of 2010 as a result of a $24.94 per Bbl increase in our average realized oil price partially offset by a 67 MBbls decrease in our oil production volumes. Our higher average realized oil price increased oil revenues by approximately $28.0 million and was primarily due to a higher average NYMEX price, which increased from $51.61 per Bbl in the first six months of 2009 to $78.37 per Bbl in the first six months of 2010. Our lower oil production volumes decreased oil revenues by approximately $3.0 million and were primarily due to natural production declines in our Elk Basin field.

     Natural gas revenues increased 62 percent from $9.2 million in the first six months of 2009 to $14.9 million in the first six months of 2010 as a result of a $1.75 per Mcf increase in our average realized natural gas price and a 165 MMcf increase in our natural gas production volumes. Our higher average realized natural gas price increased natural gas revenues by approximately $5.2 million and was primarily due to a higher average NYMEX price, which increased from $4.20 per Mcf in the first six months of 2009 to $4.69 per Mcf in the first six months of 2010, and the overall improvement in our natural gas differential as discussed above. Our higher natural gas production volumes increased natural gas revenues by approximately $0.5 million and were primarily due to our acquisition of certain natural gas properties in the Vinegarone Field in Val Verde County, Texas in May 2009.

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

	Six months ended June 30,					Increase / (Decrease)
	2010			2009 (a)		$			%
Expenses (in thousands):
Production:
Lease operating	$	22,094		$	22,897	$	(803	)
Production taxes and marketing		9,744			7,342		2,402
Total production expenses		31,838			30,239		1,599			5	%
Other:
Depletion, depreciation, and amortization		25,690			29,586		(3,896	)
Exploration		76			40		36
General and administrative		7,271			6,243		1,028
Derivative fair value loss (gain)		(21,956	)		26,533		(48,489	)
Total operating expenses		42,919			92,641		(49,722	)		-54	%
Interest		6,635			4,567		2,068
Income tax provision		111			201		(90	)
Total expenses	$	49,665		$	97,409	$	(47,744	)		-49	%
Expenses (per BOE):
Production:
Lease operating	$	13.66		$	13.82	$	(0.16	)
Production taxes and marketing		6.02			4.43		1.59
Total production expenses		19.68			18.25		1.43			8	%
Other:
Depletion, depreciation, and amortization		15.88			17.86		(1.98	)
Exploration		0.05			0.02		0.03
General and administrative		4.49			3.77		0.72
Derivative fair value loss (gain)		(13.57	)		16.01		(29.58	)
Total operating expenses		26.53			55.91		(29.38	)		-53	%
Interest		4.10			2.76		1.34
Income tax provision		0.07			0.12		(0.05	)
Total expenses	$	30.70		$	58.79	$	(28.09	)		-48	%

(a) In order to conform to the current period presentation, marketing expenses were reclassed to lease operating expenses, ad valorem taxes were reclassed to lease operating expenses, and transportation expenses were reclassed to production taxes and marketing.

     Production expenses.Production expense attributable to LOE decreased $0.8 million from $22.9 million in the first six months of 2009 to $22.1 million in the first six months of 2010 primarily due to retention bonuses paid in August 2009 related to EAC’s 2008 strategic alternatives process.

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     Production expense attributable to production taxes and marketing increased $2.4 million from $7.3 million in the first six months of 2009 to $9.7 million in the first six months of 2010 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production, severance, and ad valorem taxes remained approximately constant at 11.7 percent in the first six months of 2010 as compared to 11.0 percent in the first six months of 2009.

     DD&A expense.DD&A expense decreased $3.9 million from $29.6 million in the first six months of 2009 to $25.7 million in the first six months of 2010 primarily due to the increase in our proved reserves in the first six months of 2010 as a result of higher average commodity prices.

     G&A expense.G&A expense increased $1.0 million from $6.2 million in the first six months of 2009 to $7.3 million in the first six months of 2010 primarily due to a $1 million non-refundable retainer fee paid to an investment bank to assist the Conflicts Committee of the board of directors of our general partner in its responsibilities with regard to consideration of possible related party asset transactions.

     Derivative fair value loss (gain).During the first six months of 2010, we recorded a $22.0 million derivative fair value gain as compared to $26.5 million derivative fair value loss in the first six months of 2009, the components of which were as follows:

	Six months ended June 30,						Increase /
	2010			2009			(Decrease)
	(in thousands)
Ineffectiveness on interest rate swaps	$	104		$	(34	)	$	138
Mark-to-market loss (gain)		(21,443	)		57,681			(79,124	)
Premium amortization		4,868			11,408			(6,540	)
Receipts, net of settlements		(5,485	)		(42,522	)		37,037
Total derivative fair value loss (gain)	$	(21,956	)	$	26,533		$	(48,489	)

     Please read Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our derivative contracts.

     Interest expense.Interest expense increased $2.1 million from $4.6 million in the first six months of 2009 to $6.6 million in the first six months of 2010 primarily due to higher weighted average outstanding borrowings under our revolving credit facility, an increase in the amortization of debt issuance costs, and increases in the applicable margins under our revolving credit facility. Our weighted average interest rate was 5.3 percent for the first six months of 2010 as compared to 4.8 percent for the first six months of 2009.

Capital Commitments, Capital Resources, and Liquidity

     Capital commitments

     Our primary uses of 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.

     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

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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. Our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. To date, our cash available for distribution for any four consecutive quarters has exceeded the amount of cash we have distributed, while exceeding a coverage ratio of 1.10. 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.

     The following table illustrates information regarding our distributions of available cash for the periods indicated:

			Cash Distribution
	Date		Declared per					Total
	Declared		Common Unit		Date Paid			Distribution
								(in thousands)
2010
Quarter ended June 30		7/29/2010	$	0.5000		8/13/2010	(a)	$	22,923	(a)
Quarter ended March 31		4/30/2010	$	0.5000		5/14/2010			22,923
2009
Quarter ended December 31		1/25/2010	$	0.5375		2/12/2010			24,642
Quarter ended September 30		10/26/2009	$	0.5375		11/13/2009			24,642
Quarter ended June 30		7/27/2009	$	0.5125		8/14/2009			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

(a) Represents the date the distribution is expected to be paid and the total amount of the distribution that is expected to be paid.

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

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)
Development and exploitation	$	1,709	$	2,905	$	2,240	$	5,427
Exploration		46		28		66		294
Total	$	1,755	$	2,933	$	2,306	$	5,721

     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 first six months of 2010 yielded 1.0 gross (0.1 net) productive well 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 $25.2 million in cash. In August 2009, we acquired the Rockies and Permian Basin Assets from Encore Operating for approximately $179.6 million in cash. Because these 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, including the three and six months ended June 30, 2009, was recast to include the acquired properties for all periods in which the properties were owned by Encore Operating.

     Funding of working capital.As of June 30, 2010 and December 31, 2009, our working capital (defined as total current assets less total current liabilities) was $20.0 million and $15.6 million, respectively. For the remainder of 2010, we expect working capital to remain positive primarily due to the fair value of our outstanding commodity derivative contracts, and based on current commodity prices, we expect our operating cash flows will be sufficient to fund our working capital and capital expenditures. 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

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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.

     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.We have 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. Neither the amounts nor the terms of any other commitments or contingent obligations have changed significantly from the year-end amounts reflected in our 2009 Annual Report on Form 10-K. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

     Please read “Capital Commitments, Capital Resources, and Liquidity — Capital commitments — Contractual obligations” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2009 Annual Report on Form 10-K for additional information regarding our commitments and 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. From April 1, 2008 to March 31, 2009, the administrative fee was $1.88 per BOE of ENP’s production. From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production. Effective April 1, 2010, the administrative fee increased to $2.06 per BOE of ENP’s production. 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.

     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 acquire 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 increased $16.6 million from $57.0 million for the first six months of 2009 to $73.6 million for the first six months of 2010, primarily due to an increase in our production margin, partially offset by decreased settlements received on our commodity derivative contracts of $37.0 million as a result of higher commodity prices in the first six months of 2010.

     Cash flows from investing activities. Cash used in investing activities decreased $29.3 million from $32.4 million for the first six months of 2009 to $3.1 million for the first six months of 2010, primarily due to a $27.3 million decrease in amounts paid to acquire 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 2010, we used net cash of $57.5 million in financing activities, including $47.5 million in distributions to unitholders and net repayments of $10 million under our revolving credit facility. Net repayments decreased the outstanding borrowings under our revolving credit facility from $255 million at December 31, 2009 to $245 million at June 30, 2010.

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     During the first six months of 2009, we used net cash of $25.1 million in financing activities, including $72.1 million of deemed distributions to affiliates in connection with acquisitions and $33.6 million in distributions to unitholders, partially offset by net borrowings of $45 million under our revolving credit facility and $40.7 million of net proceeds from the issuance of our common units to the public.

     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 currently believe that we have sufficient liquidity as to not result in any required prepayments of indebtedness.

     Our 2010 capital budget is approximately $6.5 million to $7.5 million, 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.

     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 2010, our average realized oil and natural gas prices increased by 55 percent and 54 percent, respectively, as compared to the first six months of 2009. 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, cash flows from operations, borrowing base under our revolving credit facility, and 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 using commodity derivative contracts. On the other hand, an increase in commodity prices above the ceiling prices in our commodity derivative contracts would result in a loss. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Sensitivity” and Note 4 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 15 banking and other financial institutions. None of the lenders are underwriting more than eight 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.

     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. In November 2009, OLLC amended the OLLC Credit Agreement, which was effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger from being a “Change of Control” under the OLLC Credit Agreement. In conjunction with this amendment, Denbury paid a fee of approximately $0.9 million to JP Morgan, which had provided a guaranty of credit in the event the OLLC Credit Agreement was not amended to permit the consummation of the Merger from being a “Change of Control.” Denbury is not seeking reimbursement from ENP for this payment. As such, the $0.9 million paid by Denbury is reflected as a capital contribution to us by Denbury in its capacity as the parent of our general partner.

     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 $475 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. On June 14, 2010, the borrowing base under the OLLC Credit Agreement was reaffirmed at $375 million. On June 30, 2010 and August 5, 2010, there were $245 million of outstanding borrowings and $130 million of borrowing capacity under the OLLC Credit Agreement.

     OLLC incurs a commitment fee of 0.5 percent on the unused portion of the OLLC Credit Agreement.

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     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, 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 Denbury and its restricted subsidiaries.

     Loans under the OLLC Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings 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:

	Applicable Margin for	Applicable Margin for
Ratio of Outstanding Borrowings to Borrowing Base	Eurodollar Loans	Base Rate Loans
Less than .50 to 1	2.250%	1.250%
Greater than or equal to .50 to 1 but less than .75 to 1	2.500%	1.500%
Greater than or equal to .75 to 1 but less than .90 to 1	2.750%	1.750%
Greater than or equal to .90 to 1	3.000%	2.000%

     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 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 several restrictive covenants including, among others, the following:

• 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 2.5 to 1.0 (the “Interest Coverage Ratio”); and

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

     In order to show 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, 2010, 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, 2010
Current Ratio	Minimum 1.0 to 1.0	6.2 to 1.0
Interest Coverage Ratio	Minimum 2.5 to 1.0	9.5 to 1.0
Leverage Ratio	Maximum 3.5 to 1.0	1.9 to 1.0

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     The following table shows the calculation of the Current Ratio as of June 30, 2010 ($ in thousands):

Current assets	$	49,032
Availability under the OLLC Credit Agreement		130,000
Consolidated current assets	$	179,032
Divided by: consolidated current liabilities	$	29,025
Current Ratio		6.2

     The following table shows the calculation of the Interest Coverage Ratio for the twelve months ended June 30, 2010 ($ in thousands):

Consolidated EBITDA (a)	$	122,789
Divided by: Consolidated net interest expense and letter of credit fees	$	12,988
Interest Coverage Ratio		9.5

(a) Consolidated EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, DD&A, 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, 2010 ($ in thousands):

Consolidated funded debt	$	245,000
Divided by: Consolidated Adjusted EBITDA (a)	$	125,965
Leverage Ratio		1.9

(a) Consolidated Adjusted EBITDA is defined in the OLLC Credit Agreement and generally means earnings before interest, income taxes, DD&A, and amortization, and exploration expense, after giving pro forma effect to 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, 2010 (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, operating income, 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.

Consolidated net income	$	36,526
Unrealized non-cash hedge loss		15,456
Consolidated net interest expense		12,988
Income and franchise taxes		(76	)
DD&A and exploration expense		55,072
Non-cash unit-based compensation		1,337
Other non-cash		1,486
Consolidated EBITDA		122,789
Pro forma effect of acquisitions		3,176
Consolidated Adjusted EBITDA	$	125,965

     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.

     Capitalization.At June 30, 2010, we had total assets of $696.9 million and total capitalization of $650.1 million, of which 62 percent was represented by partners’ equity and 38 percent by long-term debt. At December 31, 2009, we had total assets of $719.7 million and total capitalization of $661.0 million, of which 61 percent was represented by partners’ equity and 39 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.

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Critical Accounting Policies and Estimates

     Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” of our 2009 Annual Report on Form 10-K, for information regarding our critical accounting policies and estimates.

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” of our 2009 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.

Commodity Price Sensitivity

     Our commodity derivative contracts are discussed in Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The counterparties to our commodity derivative contracts are comprised of four institutions, all of which are currently rated AA- or better by Standard & Poor’s and/or Fitch and all of which are lenders underwriting the ENP’s revolving credit facility. As of June 30, 2010, the fair market value of our oil derivative contracts was a net asset of approximately $8.5 million and the fair market value of our natural gas derivative contracts was a net asset of approximately $14.8 million. Based on our open commodity derivative positions at June 30, 2010, a 10 percent increase in the respective NYMEX prices for oil and natural gas would decrease our net commodity derivative asset by approximately $22.4 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 $24.0 million.

Interest Rate Sensitivity

     Our long-term debt is discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At June 30, 2010, we had outstanding borrowings under our revolving credit facility of $245 million, $95 million of which is subject to floating market rates of interest that are linked to the Eurodollar rate after taking into consideration the effect of our interest rate swaps. At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $0.3 million of interest expense per year, and if the Eurodollar rate decreased by 10 percent, we would incur $0.3 million less.

     Our interest rate swaps are discussed in Note 4 of Notes to the Consolidated Financial Statements included in “Item 1. Financial Statements.” As of June 30, 2010, the fair market value of our interest rate swaps was a net liability of approximately $3.0 million. If the Eurodollar rate increased by 10 percent, we estimate the liability would decrease to approximately $2.9 million, and if the Eurodollar rate decreased by 10 percent, we estimate the liability would remain approximately $3.0 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, 2010 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

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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 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 2009 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 2009 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 to Exhibit 3.1 to ENP’s Registration Statement on Form S-1 (File No. 333-142847), 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 to 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 to Exhibit 3.1 to ENP’s Current Report on Form 8-K, filed with the SEC on April 18, 2008).
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 earnings (loss) to fixed charges.

* Filed herewith.

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SIGNATURES

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

ENCORE ENERGY PARTNERS LP
By:	Encore Energy Partners GP LLC, its General Partner
/s/ Mark C. Allen
Mark C. Allen
Senior Vice President and Chief Financial Officer
/s/ Alan Rhoades
Alan Rhoades
Vice President, Accounting

Date: August 9, 2010

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