Encore Energy Partners 10Q 2008 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, 2008


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. Yes þ No o

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

Large accelerated filer o

Accelerated filer o

Non-accelerated filer þ
(Do not check if a smaller reporting company)

Smaller reporting company o

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


Number of common units outstanding as of August 1, 2008			31,356,155

ENCORE ENERGY PARTNERS LP

INDEX


	Page

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007		1
Consolidated Statements of Operations for the three and six months ended June 30, 2008 and 2007		2
Consolidated Statement of Partners’ Equity for the six months ended June 30, 2008		3
Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007		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		32

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		33

Item 1A. Risk Factors		33

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 6. Exhibits		33

Signature		34
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification
Statement Showing Computation of Ratio of Earnings (Loss) to Fixed Charges

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain information included in this Quarterly Report on Form 10-Q (the “Report”) and other materials filed with the 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. Readers 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” in our 2007 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.

ENCORE ENERGY PARTNERS LP

GLOSSARY

The following are abbreviations and definitions of certain terms, including oil and natural gas industry terms, used in this Report. The definitions of proved developed reserves, proved reserves, and proved undeveloped reserves have been abbreviated 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.

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

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

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

	•		Dry Hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

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

	•		ENP or the Partnership. Encore Energy Partners LP, a Delaware limited partnership, together with its subsidiaries.

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

	•		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.

	•		Gross Wells.The total number of wells in which an entity owns a working interest.

	•		Lease Operations Expense (“LOE”).All direct and allocated indirect costs of producing oil and natural gas after completion of drilling. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.

	•		LIBOR.London Interbank Offered Rate.

	•		MBbl.One thousand Bbls.

	•		MBOE.One thousand BOE.

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

	•		Mcf/D.One Mcf per day.

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

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

	•		Net Production.An entity’s share of crude oil and natural gas produced from a property, less royalties paid to landowners and production quantities due others.

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

	•		Net Wells.Gross wells multiplied by the percentage working interest 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 an oil or natural gas well or lease.

	•		Production Margin.Oil and natural gas revenues less LOE and production, ad valorem, and severance taxes.

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

	•		Proved Reserves.The estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

	•		Proved Undeveloped Reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves include unrealized

ENCORE ENERGY PARTNERS LP

			production response from fluid injection and other improved recovery techniques, where such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

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

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

	•		Secondary Recovery.Enhanced recovery of oil or natural gas from a reservoir beyond the oil or natural gas that can be recovered by normal flowing and pumping operations. Secondary recovery techniques involve maintaining or enhancing reservoir pressure by injecting water, gas, or other substances into the formation. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding.

	•		Successful Well.A well capable of producing oil and/or natural gas in commercial quantities.

	•		Tertiary Recovery.An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gases are used as the injectant.

	•		Waterflood.A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

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

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

iii

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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


	June 30,			December 31,
	2008			2007 *
ASSETS
Current assets:
Cash and cash equivalents	$	626		$	3
Accounts receivable:
Trade		31,727			21,595
Affiliate		234			3,290
Derivatives		632			3,713
Other		558			448

Total current assets		33,777			29,049


Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment		517,483			500,470
Unproved properties		249			298
Accumulated depletion, depreciation, and amortization		(81,466	)		(63,295	)

		436,266			437,473

Other property and equipment		730			510
Accumulated depreciation		(152	)		(68	)

		578			442


Goodwill		2,648			2,648
Other intangibles, net		3,816			3,969
Derivatives		6,504			21,875
Other		1,483			2,263

Total assets	$	485,072		$	497,719


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,145		$	1,915
Affiliate		2,130			6,709
Accrued liabilities:
Lease operations expense		2,896			2,903
Development capital		2,147			3,012
Interest		247			147
Production, ad valorem, and severance taxes		11,367			6,272
Marketing		944			1,578
Derivatives		23,478			865
Other		2,664			2,898

Total current liabilities		48,018			26,299

Derivatives		68,420			20,447
Future abandonment cost, net of current portion		8,446			8,314
Long-term debt		151,000			47,500
Other		151			146

Total liabilities		276,035			102,706


Commitments and contingencies (see Note 13)

Partners’ equity:
Limited partners - 31,356,155 and 24,187,679 common units issued and outstanding, respectively		209,034			391,956
General partner - 504,851 general partner units outstanding		(981	)		3,057
Accumulated other comprehensive income		984			—

Total partners’ equity		209,037			395,013

Total liabilities and partners’ equity	$	485,072		$	497,719


*		Recast as discussed in Note 2.

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

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,
	2008			2007 *			2008			2007 *
Revenues:
Oil	$	47,141		$	22,212		$	84,336		$	30,372
Natural gas		11,808			5,689			18,810			10,302
Marketing		903			3,614			3,762			4,852

Total revenues		59,852			31,515			106,908			45,526


Expenses:
Production:
Lease operations		6,922			5,728			12,980			8,419
Production, ad valorem, and severance taxes		5,782			3,134			10,580			4,609
Depletion, depreciation, and amortization		9,215			9,173			18,335			12,879
Exploration		38			31			67			62
General and administrative		2,933			1,011			5,855			1,566
Marketing		1,609			3,275			4,002			4,355
Derivative fair value loss		76,428			2,814			92,015			6,497
Other operating		331			288			682			433

Total expenses		103,258			25,454			144,516			38,820


Operating income (loss)		(43,406	)		6,061			(37,608	)		6,706


Other income (expenses):
Interest		(1,909	)		(5,342	)		(3,549	)		(6,444	)
Other		65			27			82			27

Total other expenses		(1,844	)		(5,315	)		(3,467	)		(6,417	)


Income (loss) before income taxes		(45,250	)		746			(41,075	)		289

Income tax benefit (provision)		252			(33	)		162			(65	)


Net income (loss)	$	(44,998	)	$	713		$	(40,913	)	$	224


Net loss allocation (see Note 10):
Limited partners’ interest in net loss	$	(45,233	)				$	(44,808	)

General partner’s interest in net loss	$	(731	)				$	(739	)


Net loss per common unit:
Basic	$	(1.45	)				$	(1.51	)
Diluted	$	(1.45	)				$	(1.51	)

Weighted average common units outstanding:
Basic		31,260						29,766
Diluted		31,260						29,766


*		Recast as discussed in Note 2.

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

ENCORE ENERGY PARTNERS LP
CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY
(in thousands)
(unaudited)


							Accumulated
							Other		Total
	Limited			General			Comprehensive		Partners'
	Partners			Partner			Income		Equity
Balance at December 31, 2007 *	$	391,956		$	3,057		$	—	$	395,013
Deemed distributions to affiliates in connection with acquisition of Permian and Williston Basin assets		(121,894	)		(2,944	)		—		(124,838	)
Issuance of common units in exchange for net profits interest in Crockett County properties		5,748			—			—		5,748
Non-cash unit-based compensation		2,145			35			—		2,180
Cash distributions to unitholders		(28,651	)		(486	)		—		(29,137	)
Components of comprehensive loss:
Net income attributable to affiliates related to pre-partnership operations of the Permian and Williston Basin assets		3,321			80			—		3,401
Net loss attributable to unitholders		(43,591	)		(723	)		—		(44,314	)
Change in unrealized hedge gain on interest rate swap agreements, net of tax of $3		—			—			984		984

Total comprehensive loss										(39,929	)

Balance at June 30, 2008	$	209,034		$	(981	)	$	984	$	209,037


*		Recast as discussed in Note 2.

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

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


	Six months ended
	June 30,
	2008			2007*
Cash flows from operating activities:
Net income (loss)	$	(40,913	)	$	224
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization		18,335			12,879
Non-cash exploration expense		41			11
Non-cash unit-based compensation expense		2,180			—
Non-cash derivative fair value loss		91,203			6,682
Deferred taxes		(290	)		6
Non-cash interest		243			3,749
Other		522			159
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		(7,235	)		(13,197	)
Other current assets		79			(102	)
Long-term derivatives		(1,196	)		(2,051	)
Other assets		745			(2,779	)
Accounts payable		(4,136	)		4,979
Other current liabilities		4,058			3,069

Net cash provided by operating activities		63,636			13,629


Cash flows from investing activities:
Purchases of other property and equipment		(217	)		—
Acquisition of oil and natural gas properties		(81	)		(354,670	)
Development of oil and natural gas properties		(12,050	)		(6,760	)

Net cash used in investing activities		(12,348	)		(361,430	)


Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs		163,310			248,883
Payments on long-term debt		(60,000	)		(15,500	)
Deemed distributions to affiliates in connection with acquisition of Permian and Williston Basin assets		(124,838	)		—
Distributions to unitholders		(29,137	)		—
Net contributions from owner		—			115,766

Net cash provided by (used in) financing activities		(50,665	)		349,149


Increase in cash and cash equivalents		623			1,348
Cash and cash equivalents, beginning of period		3			—

Cash and cash equivalents, end of period	$	626		$	1,348


Non-cash investing and financing activities:
Issuance of common units in connection with acquisition of net profits interest in Crockett County properties	$	5,748		$	—

Issuance of common units in connection with acquisition of Permian and Williston Basin assets (see Note 3)


*		Recast as discussed in Note 2.

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

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

Note 1. Description of Business

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

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

	•		the Permian Basin of West Texas; and

	•		the Williston Basin of North Dakota.

Note 2. Basis of Presentation

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

Upon completion of the Partnership’s initial public offering (“IPO”) in September 2007, EAC contributed to the Partnership certain oil and natural gas properties and related assets in the Permian Basin of West Texas (the “Permian Basin Assets”). The Permian Basin Assets are considered the predecessor to the Partnership, and therefore, the historical results of operations of the Partnership include the results of operations of the Permian Basin Assets for all periods presented. The results of operations of the Elk Basin Assets have been included with those of the Partnership from the date of acquisition in March 2007. In February 2008, the Partnership completed the acquisition of oil and natural gas properties and related assets in the Permian Basin of West Texas and the Williston Basin of North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. See “Note 3. Acquisitions” for additional discussion. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling, whereby the assets and liabilities were recorded at Encore Operating’s historical cost and the Partnership’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes thereto reflect the combined historical results of the Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets throughout the periods presented. The results of operations of the Permian and Williston Basin Assets related to pre-partnership operations were allocated to the EAC affiliates based on their respective ownership percentages in the Partnership’s general and limited partner units. The effect of recasting the Partnership’s consolidated financial statements to account for this common control transaction increased the Partnership’s net income by approximately $3.9 million and $6.3 million for the three and six months ended June 30, 2007, respectively.

The Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets were wholly owned by EAC prior to the closing of the IPO, with the exception of management incentive units owned by certain executive officers of the General Partner.

In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, the Partnership’s financial position as of June 30, 2008 and December 31, 2007, results of operations for the three and six months ended June 30, 2008 and 2007, and cash flows for the six months ended June 30, 2008 and 2007. 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 the related notes thereto included in the Partnership’s 2007 Annual Report on Form 10-K.

New Accounting Pronouncements

Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS 157”)

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

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157. SFAS 157 standardizes the definition of fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), and expands disclosures related to the use of fair value measures in financial statements. SFAS 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not require any new fair value measurements. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2,“Effective Date of FASB Statement No. 157”(“FSP FAS 157-2”), which delayed the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Partnership elected a partial deferral of SFAS 157 for all instruments within the scope of FSP FAS 157-2, including but not limited to, its asset retirement obligations and indefinite lived assets. The Partnership will continue to evaluate the impact of SFAS 157 on these instruments during the deferral period. The adoption of SFAS 157 on January 1, 2008, as it relates to financial assets and liabilities, did not have a material impact on the Partnership’s results of operations or financial condition. See “Note 6. Fair Value Measurements” for additional discussion and related disclosures of the Partnership’s assets and liabilities measured at fair value.

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

In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS 159 allows entities an irrevocable option to measure eligible items at fair value at specified election dates, with resulting changes in fair value reported in earnings. SFAS 159 was effective for the Partnership on January 1, 2008; however, the Partnership did not elect the fair value option for eligible instruments existing on that date. Therefore, the adoption of SFAS 159 did not have an impact on the Partnership’s results of operations or financial condition. In the future, the Partnership will assess the impact of electing the fair value option for any newly acquired eligible instruments. Electing the fair value option for such instruments could have a material impact on the Partnership’s future results of operations or financial condition.

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

In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141,“Business Combinations.”SFAS 141R establishes principles and requirements for the reporting entity in a business combination, including: (i) recognition and measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (ii) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (iii) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. SFAS 141R applies prospectively to business combinations consummated in fiscal years beginning on or after December 15, 2008 (for acquisitions that close on or after January 1, 2009 for the Partnership). Early application is prohibited. The Partnership is evaluating the impact SFAS 141R will have on its results of operations and financial condition and the reporting of future acquisitions in the consolidated financial statements.

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

In March 2008, the FASB issued SFAS 161. SFAS 161 amends SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities,”(“SFAS 133”) to require enhanced disclosures about (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008, with early application encouraged. The adoption of SFAS 161 will require additional disclosures regarding the Partnership’s derivative instruments; however, SFAS 161 does not change the Partnership’s accounting for its derivative instruments.

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

In March 2008, the EITF ratified its consensus opinion on EITF 07-4. EITF 07-4 addresses how master limited partnerships should calculate earnings per unit using the two-class method in SFAS No. 128,“Earnings per Share”(“SFAS 128”) and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other

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

participating securities. EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and interim periods within those years, and will be applied retrospectively for all periods presented. The Partnership is currently evaluating the impact that EITF 07-4 will have on its earnings per unit calculation.

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

In May 2008, the FASB issued SFAS 162, which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411,“The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.”The Partnership does not expect the adoption of SFAS 162 to change its current accounting practice; therefore, the adoption of SFAS 162 is not expected to have an impact on the Partnership’s results of operations or financial condition.

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

In June 2008, the FASB issued FSP EITF 03-6-1, which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing basic earnings per unit under the two-class method prescribed by SFAS 128. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. Upon adoption of FSP EITF 03-6-1, all prior-period earnings per unit data must be adjusted retrospectively to conform with the provisions of the standard. Early application is not permitted. The Partnership is currently evaluating the effect FSP EITF 03-6-1 will have on its earnings per unit calculations.

Note 3. Acquisitions

Permian and Williston Basin Assets

In December 2007, OLLC entered into a purchase and investment agreement with Encore Operating pursuant to which OLLC agreed to acquire the Permian and Williston Basin Assets. The transaction closed in February 2008. The total consideration for the acquisition consisted of approximately $125.3 million in cash, including certain post-closing adjustments, and 6,884,776 common units representing limited partner interests in the Partnership. In determining the total purchase price of the Permian and Williston Basin Assets, the common units were valued at $125 million. The cash portion of the purchase price was financed with borrowings under OLLC’s revolving credit facility.

As discussed in “Note 2. Basis of Presentation,” the transaction was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s historical cost of approximately $100 million, and the historical financial information of the Partnership was recast to include the Permian and Williston Basin Assets for all periods presented. As the historical basis in the Permian and Williston Basin Assets is included in the Consolidated Balance Sheet as of December 31, 2007, the cash purchase price, as adjusted for certain post-closing adjustments, of the Permian and Williston Basin Assets was recorded as a deemed distribution to the EAC affiliates based on their respective ownership percentages in the Partnership’s general and limited partner units. No value was ascribed to the common units issued as consideration for the acquired properties as the cash consideration exceeded the historical carrying cost of the properties.

Elk Basin Assets

In January 2007, EAC entered into a purchase and sale agreement with certain subsidiaries of Anadarko Petroleum Corporation (“Anadarko”) to acquire oil and natural gas properties and related assets in the Big Horn Basin of Wyoming and Montana, which included the Elk Basin Assets. Prior to closing, EAC assigned the rights and duties under the purchase and sale agreement relating to the Elk Basin Assets to OLLC. The closing of the acquisition occurred in March 2007, after which the operations of the Elk Basin Assets have been included with those of the Partnership. The total purchase price for the Elk Basin Assets was approximately $330.7 million, including transaction costs of approximately $1.1 million.

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

The Partnership financed the acquisition of the Elk Basin Assets through a $93.7 million contribution from EAC, $120 million of borrowings under a subordinated credit agreement with EAP Operating, LLC, a Delaware limited liability company and direct wholly owned subsidiary of EAC, and borrowings under OLLC’s revolving credit facility.

The following unaudited pro forma condensed financial data for the six months ended June 30, 2007 was derived from the historical financial statements of the Partnership and from the accounting records of Anadarko to give effect to the acquisition of the Elk Basin Assets as if it had occurred on January 1, 2007. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the acquisition of the Elk Basin Assets taken place as of January 1, 2007 and is not intended to be a projection of future results.


	Six months ended
	June 30, 2007
	(in thousands)

Pro forma total revenues	$	59,687


Pro forma net loss	$	(1,836	)

During the six months ended June 30, 2007, the Partnership was wholly owned by EAC, with the exception of management incentive units owned by certain executive officers of the General Partner. Accordingly, pro forma earnings per unit information is not presented.

Note 4. Proved Properties

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


	June 30,		December 31,
	2008		2007
	(in thousands)

Proved leasehold costs	$	377,923	$	372,076
Wells and related equipment — Completed		137,230		124,381
Wells and related equipment — In process		2,330		4,013

Total proved properties	$	517,483	$	500,470

Note 5. Derivative Financial Instruments

Commodity Derivative Contracts — Mark-to-Market Accounting

In order to partially finance the cost of premiums on certain purchased floors, the Partnership may sell floors with a strike price below the strike price of the purchased floor. Together the two floors, known as a floor spread or put spread, have a lower premium cost than a traditional floor contract but provide price protection only down to the strike price of the short floor. As with the Partnership’s other commodity derivative contracts, these are marked-to-market each quarter through “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. In the following tables, the purchased floor component and the short floor component of these floor spreads are shown net and included with the Partnership’s other floor contracts.

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

The following tables summarize the Partnership’s open commodity derivative contracts as of June 30, 2008:

Oil Derivative Contracts


	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Liability
	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. 2008													$	(2,751	)
		880	$	80.00		440	$	107.60		—	$	—
		2,000		75.00		—		—		—		—
		500		65.00		—		—		—		—
2009														(31,084	)
		880		80.00		440		97.75		—		—
		2,250		74.11		—		—		1,000		68.70
2010														(25,696	)
		880		80.00		440		93.80		—		—
		2,000		75.00		1,000		77.23		—		—
2011														(18,639	)
		1,880		80.00		1,440		95.41		—		—
		1,000		70.00		—		—		—		—


													$	(78,170	)

Natural Gas Derivative Contracts


	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		Liability
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
July — Dec. 2008													$	(2,342	)
		3,800	$	8.20		3,800	$	9.83		—	$	—
		3,800		7.20		—		—		—		—
2009														(3,492	)
		3,800		8.20		3,800		9.83		—		—
		3,800		7.20		—		—		—		—
2010														(2,108	)
		3,800		8.20		3,800		9.58		—		—
		3,800		7.20		—		—		—		—


													$	(7,942	)

Interest Rate Swap Agreements

In the first quarter of 2008, as a result of the increase in debt levels, the Partnership entered into interest rate swap agreements whereby it swapped $100 million of floating rate debt on its revolving credit facility to a weighted average fixed rate of 3.06 percent and an expected margin of 1.25 percent. These interest rate swap agreements were designated as cash flow hedges. The following table summarizes the Partnership’s open interest rate swap agreements as of June 30, 2008:


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

As of June 30, 2008, the fair market value of the Partnership’s interest rate swap agreements was a net asset of $1.4 million. During each of the three and six months ended June 30, 2008, settlements of interest rate swap agreements increased the Partnership’s interest expense by approximately $0.1 million.

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

Current Period Impact

As a result of derivative transactions, the Partnership recognized derivative fair value gains and losses related to (i) changes in the market value of commodity derivative contracts, (ii) settlements on commodity derivative contracts, (iii) premium amortization, and (iv) changes in the market value of interest rate swap agreements prior to designation. The following table summarizes the components of derivative fair value loss for the periods indicated:


	Three months ended June 30,					Six months ended June 30,
	2008		2007			2008			2007
	(in thousands)
Mark-to-market loss on commodity derivative contracts	$	73,195	$	1,806		$	87,197		$	5,489
Premium amortization		2,250		1,194			4,387			1,194
Change in fair value of interest rate swap agreements prior to designation		—		—			(381	)		—
Settlements on commodity derivative contracts		983		(186	)		812			(186	)

Total derivative fair value loss	$	76,428	$	2,814		$	92,015		$	6,497

Accumulated Other Comprehensive Income (“AOCI”)

At June 30, 2008, AOCI consisted entirely of deferred gains, net of tax, on the Partnership’s interest rate swap agreements that are designated as hedges. The Partnership expects to reclassify $0.1 million of deferred gains associated with its interest rate swap agreements from AOCI to offset interest expense during the twelve months ending June 30, 2009.

Note 6. Fair Value Measurements

As discussed in “Note 2. Basis of Presentation,” the Partnership adopted SFAS 157, as it relates to financial assets and liabilities, on January 1, 2008. As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Partnership primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Accordingly, the Partnership utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Partnership has reviewed its recurring transactions and found that its markets and financial instruments are fairly liquid and has established that they are able to transact at the midpoint of the bid/ask spread. The Partnership is able to classify fair value balances based on the observability of those inputs.

SFAS 157 establishes a three-tier fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

	•		Level 1— Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

	•		Level 2— Pricing inputs, other than quoted prices within Level 1, that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

	•		Level3 — Pricing inputs include significant unobservable inputs. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

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

The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008.


				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
	Total			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts — swaps	$	(25,132	)	$	—	$	(25,132	)	$	—
Oil derivative contracts — floors and caps		(53,038	)		—		—			(53,038	)
Natural gas derivative contracts — floors and caps		(7,942	)		—		—			(7,942	)
Interest rate swap agreements		1,350			—		1,350			—

Total	$	(84,762	)	$	—	$	(23,782	)	$	(60,980	)

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Partnership’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 table summarizes the changes in the Partnership’s net financial liabilities measured at fair value using Level 3 inputs for the six months ended June 30, 2008:


	Fair Value Measurements Using Significant Unobservable Inputs
	(Level 3)
				Natural Gas
	Oil Derivative			Derivative
	Contracts - Floors			Contracts - Floors
	and Caps			and Caps			Total
				(in thousands)
Balance at January 1, 2008	$	6,466		$	4,533		$	10,999
Total gains (losses):
Included in earnings		(61,357	)		(12,631	)		(73,988	)
Purchases, issuances, and settlements		1,853			156			2,009

Balance at June 30, 2008	$	(53,038	)	$	(7,942	)	$	(60,980	)


The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	(61,357	)	$	(12,631	)	$	(73,988	)

The Partnership does not use hedge accounting for its commodity derivative contracts; therefore, all derivative fair value gains and losses related to such contracts are included in “Derivative fair value loss” in the accompanying Consolidated Statements of Operations. All fair values reflected in the tables above and in the accompanying Consolidated Balance Sheet as of June 30, 2008 have been adjusted for non-performance risk. The adjustment to fair value related to non-performance risk as of June 30, 2008 was a reduction of the net liability value of approximately $2.1 million.

The following methods and assumptions were used to estimate the fair values of the financial assets and liabilities in the tables above.

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

Level 2 Fair Value Measurements

Oil derivative contracts — swaps— The fair value of the Partnership’s oil commodity derivative swap was estimated using a combined income and market-based valuation methodology based upon forward commodity prices. Forward curves were obtained from independent pricing services reflecting broker market quotes.

Interest rate swap agreements— The fair values of the interest rate swap agreements were estimated using a combined income and market-based valuation methodology based upon forward interest rate yield curves and credit. The curves were obtained from independent pricing services reflecting broker market quotes.

Level 3 Fair Value Measurements

Oil and natural gas derivative contracts — floors and caps— The fair values of the Partnership’s oil and natural gas commodity derivative floors and caps were estimated using pricing models and discounted cash flow methodologies based on inputs that are not readily available in public markets.

Note 7. Asset Retirement Obligations

The Partnership’s asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Partnership’s estimated asset retirement obligations for the six months ended June 30, 2008 (in thousands):


Future abandonment liability at January 1, 2008	$	8,704
Wells drilled		26
Accretion of discount		239
Revision of previous estimates		(233	)

Future abandonment liability at June 30, 2008	$	8,736

As of June 30, 2008, $8.4 million of the Partnership’s asset retirement obligations was long-term and recorded in “Future abandonment cost, net of current portion” and $0.3 million was current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.

Note 8. Debt

Revolving Credit Facility

In conjunction with the closing of the acquisition of the Elk Basin Assets on March 7, 2007, OLLC entered into a five-year credit agreement (as amended, the “OLLC Credit Agreement”) with a bank syndicate comprised of Bank of America, N.A. and other lenders. The OLLC Credit Agreement provides for revolving credit loans to be made to OLLC from time to time and letters of credit to be issued from time to time for the account of OLLC or any of its restricted subsidiaries. The OLLC Credit Agreement matures on March 7, 2012.

The aggregate amount of the commitments of the lenders under the OLLC Credit Agreement is $300 million. Availability under the OLLC Credit Agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. At June 30, 2008, the borrowing base was $240 million.

As of June 30, 2008, there were $151 million of outstanding borrowings and $88.9 million of borrowing capacity under the OLLC Credit Agreement. As of June 30, 2008, there were $0.1 million of outstanding letters of credit.

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

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

The OLLC Credit Agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the OLLC Credit Agreement to be immediately due and payable. At June 30, 2008, OLLC was in compliance with all debt covenants under the OLLC Credit Agreement.

Subordinated Credit Agreement

On March 7, 2007, OLLC entered into a six-year subordinated credit agreement with EAP Operating, LLC. Pursuant to the subordinated credit agreement, a single subordinated term loan was made on March 7, 2007 to the Partnership in the aggregate amount of $120 million. The total outstanding balance of $126.4 million was repaid in September 2007 using a portion of the net proceeds from the IPO.

Note 9. Partners’ Equity and Distributions

ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in the partnership agreement) to its unitholders. Distributions are not cumulative. The Partnership distributes available cash to its unitholders and the General Partner in accordance with their ownership percentages. In distributing available cash, the Partnership assumes that the holders of management incentive units own the equivalent number of common units into which such units are convertible on the date of distribution, provided that distributions payable to the holders of management incentive units are subject to a maximum limit equal to 5.1 percent of all distributions to the Partnership’s unitholders at the time of any such distribution. If the 5.1 percent maximum limit on aggregate distributions to the holders of management incentive units is reached, then any available cash that would have been distributed to such holders will be available for distribution to unitholders. See “Note 11. Unit-Based Compensation Plans” for additional discussion of the management incentive units.

On February 14, 2008, the Partnership paid a quarterly distribution of $0.3875 per unit with respect to the fourth quarter of 2007. The total distribution of $9.8 million was paid to unitholders of record as of the close of business on February 6, 2008. On May 15, 2008, the Partnership paid a quarterly distribution of $0.5755 per unit with respect to the first quarter of 2008. The total distribution of $19.3 million was paid to unitholders of record as of the close of business on May 9, 2008.

Note 10. Earnings Per Common Unit (“EPU”)

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

EPU is calculated by dividing the limited partners’ interest in net loss, after deducting the interests of participating securities, by the weighted average number of common units outstanding. Prior to its IPO in September 2007, the Partnership was wholly owned by EAC, other than management incentive units owned by certain executive officers of the General Partner. Accordingly, EPU is not presented for the three and six months ended June 30, 2007.

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

The following table presents the allocation of net loss to the limited partners and reflects EPU computations for the three and six months ended June 30, 2008 (in thousands, except per unit data):


	Three months ended			Six months ended
	June 30, 2008			June 30, 2008
Net loss	$	(44,998	)	$	(40,913	)
Less: Net income related to pre-partnership operations of the Permian and Williston Basin Assets		—			3,401

Net loss attributable to unitholders	$	(44,998	)	$	(44,314	)


Numerator:
Net loss attributable to unitholders	$	(44,998	)	$	(44,314	)
Less: Distributions to participating securities		1,257			1,719
Less: Undistributed losses allocated to participating securities		(1,022	)		(1,225	)

Net loss allocation to limited partners	$	(45,233	)	$	(44,808	)


Denominator:
Denominator for basic EPU:
Weighted average common units outstanding		31,260			29,766
Effect of dilutive management incentive units (a)		—			—

Denominator for diluted EPU		31,260			29,766


Net loss per common unit:
Basic	$	(1.45	)	$	(1.51	)
Diluted	$	(1.45	)	$	(1.51	)


(a)		A total of 550,000 management incentive units, which represented 1,678,490 common unit equivalents as of June 30, 2008, were outstanding at June 30, 2008 but were excluded from the above calculation of diluted EPU for the second quarter of 2008 because their effect would be antidilutive. See additional discussion of management incentive units in “Note 11. Unit-Based Compensation Plans.”

Note 11. Unit-Based Compensation Plans

Management Incentive Units

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

	•		a change in control;

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

	•		the holder’s death or disability.

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

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

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

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

the time of any such distribution.

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

The management incentive units vest in three equal installments. The first installment vested upon the closing of the IPO, and the subsequent vestings will occur on September 17, 2008 and 2009. For the three and six months ended June 30, 2008, the Partnership recognized total compensation expense of $1.1 million and $2.1 million, respectively, for the management incentive units, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of June 30, 2008, ENP had $2.6 million of total unrecognized compensation cost related to unvested management incentive units, which is expected to be recognized over a weighted average period of 0.5 years. For the third quarter of 2008, the expense will be approximately $1.1 million, and for the fourth quarter of 2008 through the third quarter of 2009, the expense will be approximately $0.4 million per quarter. There have not been any additional issuances or forfeitures of management incentive units.

ENP Incentive Plan

In connection with the IPO, the board of directors of the General Partner adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP Incentive Plan”) for employees, consultants, and directors of EAC, the General Partner, and any of their affiliates who perform services for the Partnership. The ENP Incentive Plan provides for the grant of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. An aggregate of 1,150,000 common units may be delivered pursuant to awards under the ENP Incentive Plan. As of June 30, 2008, there were 1,125,000 common units available for issuance under the ENP Incentive Plan. The ENP Incentive Plan is administered by the board of directors of the General Partner or a committee thereof, referred to as the plan administrator.

In October 2007, the board of directors of the General Partner issued 20,000 phantom units to directors of the General Partner pursuant to the ENP Incentive Plan. During the first quarter of 2008, the board of directors of the General Partner issued 5,000 phantom units to a new board member pursuant to the ENP Incentive Plan. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the plan administrator, cash equivalent to the value of a common unit. These phantom units are classified as liability awards under SFAS No. 123 (revised 2004),“Share-Based Payment.”Accordingly, the Partnership determines the fair value of these awards at each reporting period, based on the closing unit price of the Partnership, and recognizes the current portion of the liability as a component of “Other current liabilities” and the long-term portion of the liability as a component of “Other noncurrent liabilities” in the accompanying Consolidated Balance Sheet. As of June 30, 2008, the total liability was $0.2 million. For liability awards, the fair value of the award, which determines the measurement of the liability on the balance sheet, is remeasured at each reporting period until the award is settled. Changes in the fair value of the liability award from period to period are recorded as increases or decreases in compensation expense, over the remaining service period. The phantom units vest in four equal installments on October 29, 2008, 2009, 2010, and 2011. The holders of phantom units are also entitled to receive distribution equivalent rights prior to vesting, which entitle the grantee to receive cash equal to the amount of any cash distributions made by the Partnership with respect to a common unit during the period the right is outstanding.

The Partnership recognized total compensation expense of $0.1 million and $0.2 million for the phantom units for the three and six months ended June 30, 2008, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have not been any additional issuances or forfeitures under the ENP Incentive Plan.

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

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

Note 12. Comprehensive Income (Loss)

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


	Three months ended					Six months ended
	June 30,					June 30,
	2008			2007		2008			2007
	(in thousands)
Net income (loss)	$	(44,998	)	$	713	$	(40,913	)	$	224
Change in deferred hedge gain on interest rate swap agreements		2,552			—		984			—

Comprehensive income (loss)	$	(42,446	)	$	713	$	(39,929	)	$	224

Note 13. Commitments and Contingencies

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

Additionally, the Partnership has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, long-term debt, and derivative contracts as discussed more fully in the notes above. See the contractual obligations and commitments table included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Report for contractual obligations as of June 30, 2008.

Note 14. Related Party Transactions

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

The Partnership reimburses EAC for any additional state income, franchise, or similar tax paid by EAC resulting from the inclusion of the Partnership in a combined state income, franchise, or similar tax report with EAC as required by applicable law. The amount of any such reimbursement is limited to the tax that the Partnership would have paid had it not been included in a combined group with EAC.

During the three and six months ended June 30, 2008, the Partnership paid $1.7 million and $3.1 million, respectively, to Encore Operating for administrative fees under the Administrative Services Agreement (including payment of COPAS recovery) and $2.6 million and $3.3 million, respectively, for reimbursement of actual third-party expenses incurred on the Partnership’s behalf. Prior to entering into the Administrative Services Agreement, the Partnership paid Encore Operating an administrative fee for administrative services provided to the Partnership. For each of the three and six months ended June 30, 2007, the Partnership paid $0.9 million to Encore Operating for administrative services and $2.4 million for reimbursement of actual third-party expenses incurred on the Partnership’s behalf, primarily related to expenses incurred for the acquisition of the Elk Basin Assets and ENP’s IPO. Expenses incurred under the Administrative Services Agreement and third-party expenses invoiced by EAC to the Partnership are included in “General and administrative expenses” in the accompanying Consolidated Statements of

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

Operations. As of June 30, 2008, the Partnership had a payable to EAC of $2.1 million for services provided by Encore Operating, which is reflected in “Accounts payable — affiliate” in the accompanying Consolidated Balance Sheet, and a receivable from EAC of $0.2 million, which is reflected in “Accounts receivable — affiliate” in the accompanying Consolidated Balance Sheet, primarily related to receivables for natural gas production marketed by Encore Operating.

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

During the three and six months ended June 30, 2008, the Partnership distributed approximately $13.0 million and $18.7 million, respectively, to EAC and certain executive officers of the General Partner related to quarterly distributions on common units and management incentive units. For the three and six months ended June 30, 2008, the Partnership distributed $0.3 million and $0.5 million, respectively, to the General Partner as the holder of 504,851 general partner units.

Prior to the contribution of the Permian Basin Assets to the Partnership in September 2007 and the acquisition of the Permian and Williston Basin Assets in February 2008, these properties were wholly owned by EAC and were not separate legal entities. In addition to employee payroll-related expenses, EAC incurred general and administrative (“G&A”) expenses related to leasing office space and other corporate overhead expenses during the period these properties were wholly owned by EAC. A portion of the consolidated G&A expenses reported for EAC were allocated to the Partnership and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the properties in relation to the total BOE produced by EAC on a consolidated basis.

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

Note 15. Subsequent Event

On August 4, 2008, the board of directors of the General Partner declared a distribution for the second quarter of 2008 to unitholders of record as of the close of business on August 11, 2008. Approximately $23.1 million will be paid on or about August 14, 2008 to unitholders at a rate of $0.6881 per unit.

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” in our 2007 Annual Report onForm 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report and in “Item 8. Financial Statements and Supplementary Data” of our 2007 Annual Report onForm 10-K.

Introduction

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

	•		Overview of Business

	•		Results of Operations

	•		Comparison of Quarter Ended June 30, 2008 to Quarter Ended June 30, 2007

	•		Comparison of Six Months Ended June 30, 2008 to Six Months Ended June 30, 2007

	•		Liquidity and Capital Resources

	•		Capital Commitments and Contingencies

	•		Critical Accounting Policies and Estimates

	•		New Accounting Pronouncements

Overview of Business

We are a growth-oriented Delaware limited partnership formed in February 2007 by EAC to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Our primary business objective is to make quarterly cash distributions to our unitholders at our current distribution rate and, over time, increase our quarterly cash distributions. Our assets consist primarily of producing and non-producing oil and natural gas properties in the Big Horn Basin of Wyoming and Montana, the Permian Basin of West Texas, and the Williston Basin of North Dakota.

In September 2007, we completed our IPO. Upon the closing of the IPO, Encore Operating contributed the Permian Basin Assets to us. The Permian Basin Assets are considered our predecessor and our historical results of operations include the results of operations of the Permian Basin Assets for all periods presented. In February 2008, we completed the acquisition of the Permian and Williston Basin Assets from Encore Operating. Because the Permian and Williston Basin Assets were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling, whereby the assets and liabilities were recorded at EAC’s historical cost and our historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes reflect the combined historical results of the Partnership, the Permian Basin Assets, and the Permian and Williston Basin Assets throughout the periods presented. The results of operations of the Elk Basin Assets are included in the consolidated financial statements from the date of acquisition in March 2007. These results are not indicative of our future results and our future results could differ materially from our historical results.

ENCORE ENERGY PARTNERS LP

Results of Operations

Comparison of Quarter Ended June 30, 2008 to Quarter Ended June 30, 2007

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


	Three months ended June 30,				*Increase / (Decrease)*
	2008		2007		$			%
Revenues (in thousands):
Oil	$	47,141	$	22,212	$	24,929			112	%
Natural gas		11,808		5,689		6,119			108	%

Total combined oil and natural gas revenues		58,949		27,901		31,048			111	%
Marketing		903		3,614		(2,711	)		-75	%

Total revenues	$	59,852	$	31,515	$	28,337			90	%


Average realized prices:
Oil ($/Bbl)	$	111.53	$	52.09	$	59.44			114	%
Natural gas ($/Mcf)	$	11.06	$	7.45	$	3.61			48	%
Combined ($/BOE)	$	98.15	$	50.39	$	47.76			95	%

Total production volumes:
Oil (MBbls)		423		426		(3	)		-1	%
Natural gas (MMcf)		1,067		764		303			40	%
Combined (MBOE)		601		554		47			8	%

Average daily production volumes:
Oil (Bbls/D)		4,645		4,686		(41	)		-1	%
Natural gas (Mcf/D)		11,729		8,393		3,336			40	%
Combined (BOE/D)		6,600		6,085		515			8	%

Average NYMEX prices:
Oil (per Bbl)	$	124.30	$	65.06	$	59.24			91	%
Natural gas (per Mcf)	$	10.94	$	7.55	$	3.39			45	%

Oil revenues increased $24.9 million from $22.2 million in the second quarter of 2007 to $47.1 million in the second quarter of 2008 as a result of an increase in average realized oil prices, which contributed approximately $25.1 million in additional oil revenues, partially offset by a reduction in oil production volumes of 3 MBbls, which decreased oil revenues by approximately $0.2 million. Our average realized oil price increased $59.44 per Bbl primarily as a result of increases in the overall market price for oil, as reflected in the increase in the average NYMEX price from $65.06 per Bbl in the second quarter of 2007 to $124.30 per Bbl in the second quarter of 2008.

Natural gas revenues increased $6.1 million from $5.7 million in the second quarter of 2007 to $11.8 million in the second quarter of 2008 primarily as a result of an increase in average realized natural gas prices, which contributed approximately $3.8 million in additional natural gas revenues, and an increase in production volumes of 303 MMcf, which contributed approximately $2.3 million in additional natural gas revenues. Our average realized natural gas price increased primarily as a result of increases in the overall market price for natural gas, as reflected in the increase in the average NYMEX price from $7.55 per Mcf in the second quarter of 2007 to $10.94 per Mcf in the second quarter of 2008. The increase in natural gas production volumes was primarily due to an increase in production from operated properties as a result of wells drilled during the second half of 2007 and the first quarter of 2008.

Marketing revenues decreased by $2.7 million from $3.6 million in the second quarter of 2007 to $0.9 million in the second quarter of 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas
producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

ENCORE ENERGY PARTNERS LP

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


	Three months ended June 30,
	2008			2007
Average realized oil price ($/Bbl)	$	111.53		$	52.09
Average NYMEX ($/Bbl)	$	124.30		$	65.06
Differential to NYMEX	$	(12.77	)	$	(12.97	)
Average realized oil price to NYMEX percentage		90	%		80	%

Average realized natural gas price ($/Mcf)	$	11.06		$	7.45
Average NYMEX ($/Mcf)	$	10.94		$	7.55
Differential to NYMEX	$	0.12		$	(0.10	)
Average realized natural gas price to NYMEX percentage		101	%		99	%

In the second quarter of 2008, our average realized oil price as a percentage of the average NYMEX price improved to 90 percent from 80 percent in the second quarter of 2007. The differential tightened as a result of improved pricing in the Rocky Mountain area. We expect our oil differentials to begin widening in the third quarter of 2008 as compared to the second quarter of 2008, which is historically common.

Our average realized natural gas price as a percentage of the average NYMEX price increased to 101 percent in the second quarter of 2008 from 99 percent in the second quarter of 2007. We expect our natural gas differentials to remain approximately constant or to widen slightly in the third quarter of 2008 as compared to the second quarter of 2008.

ENCORE ENERGY PARTNERS LP

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


	Three months ended June 30,					*Increase / (Decrease)*
	2008			2007		$			%
Expenses (in thousands):
Production:
Lease operations	$	6,922		$	5,728	$	1,194
Production, ad valorem, and severance taxes		5,782			3,134		2,648

Total production expenses		12,704			8,862		3,842			43	%
Other:
Depletion, depreciation, and amortization		9,215			9,173		42
Exploration		38			31		7
General and administrative		2,933			1,011		1,922
Marketing		1,609			3,275		(1,666	)
Derivative fair value loss		76,428			2,814		73,614
Other operating		331			288		43

Total operating		103,258			25,454		77,804			306	%
Interest		1,909			5,342		(3,433	)
Income tax (benefit) provision		(252	)		33		(285	)

Total expenses	$	104,915		$	30,829	$	74,086			240	%


Expenses (per BOE):
Production:
Lease operations	$	11.53		$	10.34	$	1.19
Production, ad valorem, and severance taxes		9.63			5.66		3.97

Total production expenses		21.16			16.00		5.16			32	%
Other:
Depletion, depreciation, and amortization		15.34			16.57		(1.23	)
Exploration		0.06			0.06		-
General and administrative		4.88			1.83		3.05
Marketing		2.68			5.91		(3.23	)
Derivative fair value loss		127.26			5.08		122.18
Other operating		0.55			0.52		0.03

Total operating		171.93			45.97		125.96			274	%
Interest		3.18			9.65		(6.47	)
Income tax (benefit) provision		(0.42	)		0.06		(0.48	)

Total expenses	$	174.69		$	55.68	$	119.01			214	%

Production expenses.Total production expenses increased $3.8 million from $8.9 million in the second quarter of 2007 to $12.7 million in the second quarter of 2008 as a result of a $5.16 increase in production expenses per BOE and an increase in total production volumes. Our production margin (defined as oil and natural gas revenues less production expenses) for the second quarter of 2008 increased by $27.2 million (143 percent) to $46.2 million as compared to $19.0 million for the second quarter of 2007. On a per BOE basis, our production margin increased 124 percent to $76.99 per BOE as compared to $34.39 per BOE for the second quarter of 2007. Total oil and natural gas revenues per BOE increased by 95 percent while total production expenses per BOE increased by only 32 percent.

Production expense attributable to LOE increased $1.2 million from $5.7 million in the second quarter of 2007 to $6.9 million in the second quarter of 2008, primarily due to a $1.19 increase in the average LOE per BOE rate, which contributed approximately $0.7 million in additional LOE, as well as an increase in production volumes, which contributed approximately $0.5 million of additional LOE. The increase in our average LOE per BOE rate was attributable to a general increase in industry costs.

Production expense attributable to production, ad valorem, and severance taxes (“production taxes”) increased $2.6 million from $3.1 million in the second quarter of 2007 to $5.8 million in the second quarter of 2008 primarily due to increased oil and natural gas revenues. As a percentage of oil and natural gas revenues, production taxes decreased to 9.8 percent in the second quarter of 2008 as compared to 11.2 percent in the second quarter of 2007, primarily due to increased production volumes from our properties in the Permian Basin of West Texas, which have a lower production tax rate.

ENCORE ENERGY PARTNERS LP

Depletion, depreciation, and amortization (“DD&A”) expense.DD&A expense remained flat at $9.2 million in the second quarter of 2008 as compared to the second quarter of 2007. The decrease in DD&A expense as a result of a $1.23 decrease in the per BOE rate was offset by additional DD&A expense attributable to increased production volumes of 47 MBOE. The decrease in our average DD&A per BOE rate was due to better than expected drilling results.

G&A expense.G&A expense increased $1.9 million from $1.0 million in the second quarter of 2007 to $2.9 million in the second quarter of 2008 primarily due to $1.1 million of compensation expense recognized for management incentive units, increased production volumes resulting in an increase of $0.5 million in administrative fees due to Encore Operating pursuant to the Administrative Services Agreement, and $0.5 million of expenses associated with being a publicly traded partnership.

Marketing expense.Marketing expense decreased $1.7 million from $3.3 million in the second quarter of 2007 to $1.6 million in the second quarter of 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

Derivative fair value loss.During the second quarter of 2008, we recorded a $76.4 million derivative fair value loss as compared to a $2.8 million loss in the second quarter of 2007, the components of which were as follows:


	Three months ended June 30,					*Increase /*
	2008		2007			*(Decrease)*
	(in thousands)
Mark-to-market loss on commodity derivative contracts	$	73,195	$	1,806		$	71,389
Premium amortization		2,250		1,194			1,056
Settlements on commodity derivative contracts		983		(186	)		1,169

Total derivative fair value loss	$	76,428	$	2,814		$	73,614

Interest expense.Interest expense decreased $3.4 million from $5.3 million in the second quarter of 2007 to $1.9 million in the second quarter of 2008 primarily as a result of a reduction in average outstanding debt due to the payoff of our subordinated credit agreement in September 2007 using proceeds from our IPO. In addition to the payoff of the subordinated credit agreement, interest expense incurred on the revolving credit facility during the second quarter of 2008 was less than the second quarter of 2007 due to a reduction in LIBOR rates over the corresponding time period. All interest expense incurred during the second quarter of 2008 related to our revolving credit facility and interest rate swap agreements. Of the $5.3 million total interest expense in the second quarter of 2007, $2.1 million related to our revolving credit facility and $3.2 million related to our subordinated credit agreement. The weighted average interest rate for all long-term debt for the second quarter of 2008 was 4.7 percent as compared to 9.0 percent for the second quarter of 2007.

Income taxes.In the second quarter of 2008, we recorded an income tax benefit of $0.3 million compared to an income tax provision of $33,000 in the second quarter of 2007. The deferred tax benefit for the second quarter of 2008 resulted from book losses that will be realized for tax in future periods.

ENCORE ENERGY PARTNERS LP

Comparison of Six Months Ended June 30, 2008 to Six Months Ended June 30, 2007

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


	Six months ended June 30,				*Increase / (Decrease)*
	2008		2007		$			%
Revenues (in thousands):
Oil	$	84,336	$	30,372	$	53,964			178	%
Natural gas		18,810		10,302		8,508			83	%

Total combined oil and natural gas revenues		103,146		40,674		62,472			154	%
Marketing		3,762		4,852		(1,090	)		-22	%

Total revenues	$	106,908	$	45,526	$	61,382			135	%


Average realized prices:
Oil ($/Bbl)	$	99.37	$	50.57	$	48.80			97	%
Natural gas ($/Mcf)	$	9.62	$	7.21	$	2.41			33	%
Combined ($/BOE)	$	87.81	$	48.49	$	39.32			81	%

Total production volumes:
Oil (MBbls)		849		601		248			41	%
Natural gas (MMcf)		1,956		1,429		527			37	%
Combined (MBOE)		1,175		839		336			40	%

Average daily production volumes:
Oil (Bbls/D)		4,663		4,639		24			1	%
Natural gas (Mcf/D)		10,745		8,186		2,559			31	%
Combined (BOE/D)		6,454		6,004		450			7	%

Average NYMEX prices:
Oil (per Bbl)	$	111.02	$	61.70	$	49.32			80	%
Natural gas (per Mcf)	$	9.48	$	7.16	$	2.32			32	%

Oil revenues increased $54.0 million from $30.4 million for the first six months of 2007 to $84.3 million for the first six months of 2008 primarily as a result of an increase in average realized oil prices, which contributed approximately $41.4 million in additional oil revenues, and an increase in oil production volumes of 248 MBbls, which increased oil revenues by approximately $12.6 million. Our average realized oil price increased $48.80 per Bbl as a result of increases in the overall market price for oil, as reflected in the increase in the average NYMEX price from $61.70 per Bbl for the six months ended June 30, 2007 to $111.02 per Bbl for the six months ended June 30, 2008. The increase in oil production volumes was primarily due to a full six months of production from our Elk Basin Assets in the first half of 2008. For the six months ended June 30, 2008, approximately 75 percent of our oil production was from our Elk Basin Assets. As the Elk Basin Assets were purchased in March 2007, only four months of oil production are included in the six months ended June 30, 2007.

Natural gas revenues increased $8.5 million from $10.3 million for the first six months of 2007 to $18.8 million for the first six months of 2008 as a result of an increase in average realized natural gas prices, which increased natural gas revenues by approximately $4.7 million, and an increase in production volumes of 527 MMcf, which contributed approximately $3.8 million in additional natural gas revenues. Our average realized natural gas price increased as a result of increases in the overall market price for natural gas, as reflected in the increase in the average NYMEX price from $7.16 per Mcf for the six months ended June 30, 2007 to $9.48 per Mcf for the six months ended June 30, 2008. The increase in natural gas production volumes was primarily due to an increase in production from operated properties as a result of wells drilled in the Permian Basin during the second half of 2007 and the first half of 2008.

Marketing revenues decreased by $1.1 million from $4.9 million for the first six months of 2007 to $3.8 million for the first six months of 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

ENCORE ENERGY PARTNERS LP

our oil and natural gas revenues.


	Six months ended June 30,
	2008			2007
Average realized oil price ($/Bbl)	$	99.37		$	50.57
Average NYMEX ($/Bbl)	$	111.02		$	61.70
Differential to NYMEX	$	(11.65	)	$	(11.13	)
Average realized oil price to NYMEX percentage		90	%		82	%

Average realized natural gas price ($/Mcf)	$	9.62		$	7.21
Average NYMEX ($/Mcf)	$	9.48		$	7.16
Differential to NYMEX	$	0.14		$	0.05
Average realized natural gas price to NYMEX percentage		101	%		101	%

For the first six months of 2008, our average realized oil price as a percentage of the average NYMEX price improved to 90 percent from 82 percent for the first six months of 2007. The differential tightened as a result of improved pricing in the Rocky Mountain area.

Our average realized natural gas price as a percentage of the average NYMEX price remained consistent at 101 percent for the first six months of 2008.

ENCORE ENERGY PARTNERS LP

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


	Six months ended June 30,					*Increase / (Decrease)*
	2008			2007		$			%
Expenses (in thousands):
Production:
Lease operations	$	12,980		$	8,419	$	4,561
Production, ad valorem, and severance taxes		10,580			4,609		5,971

Total production expenses		23,560			13,028		10,532			81	%
Other:
Depletion, depreciation, and amortization		18,335			12,879		5,456
Exploration		67			62		5
General and administrative		5,855			1,566		4,289
Marketing		4,002			4,355		(353	)
Derivative fair value loss		92,015			6,497		85,518
Other operating		682			433		249

Total operating		144,516			38,820		105,696			272	%
Interest		3,549			6,444		(2,895	)
Income tax (benefit) provision		(162	)		65		(227	)

Total expenses	$	147,903		$	45,329	$	102,574			226	%


Expenses (per BOE):
Production:
Lease operations	$	11.05		$	10.04	$	1.01
Production, ad valorem, and severance taxes		9.01			5.49		3.52

Total production expenses		20.06			15.53		4.53			29	%
Other:
Depletion, depreciation, and amortization		15.61			15.35		0.26
Exploration		0.06			0.07		(0.01	)
General and administrative		4.98			1.87		3.11
Marketing		3.41			5.19		(1.78	)
Derivative fair value loss		78.33			7.75		70.58
Other operating		0.58			0.52		0.06

Total operating		123.03			46.28		76.75			166	%
Interest		3.02			7.68		(4.66	)
Income tax (benefit) provision		(0.14	)		0.08		(0.22	)

Total expenses	$	125.91		$	54.04	$	71.87			133	%

Production expenses.Total production expenses increased $10.5 million from $13.0 million for the first six months of 2007 to $23.6 million for the first six months of 2008 as a result of an increase in total production volumes and a $4.53 increase in production expenses per BOE. Our production margin for the six months ended June 30, 2008 increased by $51.9 million (188 percent) to $79.6 million as compared to $27.7 million for the six months ended June 30, 2007. On a per BOE basis, our production margin increased 106 percent to $67.75 per BOE as compared to $32.96 per BOE for the six months ended June 30, 2007. Total oil and natural gas revenues per BOE increased by 81 percent while total production expenses per BOE increased by only 29 percent.

Production expense attributable to LOE increased $4.6 million from $8.4 million for the first six months of 2007 to $13.0 million for the first six months of 2008, primarily due to an increase in production volumes, which contributed approximately $3.4 million of additional LOE, as well as a $1.01 increase in the average LOE per BOE rate, which contributed approximately $1.2 million in additional LOE. The increase in our average LOE per BOE rate was attributable to a general increase in industry costs.

Production expense attributable to production taxes increased $6.0 million from $4.6 million for the first six months of 2007 to $10.6 million for the first six months of 2008 primarily due to increased oil and natural gas revenues. As a percentage of oil and natural gas revenues, production taxes decreased to 10.3 percent for the six months ended June 30, 2008 as compared to 11.3

ENCORE ENERGY PARTNERS LP

percent for the six months ended June 30, 2007, primarily due to increased production volumes from our properties in the Permian Basin of West Texas, which have a lower production tax rate.

DD&A expense.DD&A expense increased $5.5 million from $12.9 million for the first six months of 2007 to $18.3 million for the six months ended June 30, 2008 as a result of increased production volumes, which contributed approximately $5.2 million of additional DD&A expense, and an increase of $0.26 in the per BOE rate, which contributed approximately $0.3 million of additional DD&A expense.

G&A expense.G&A expense increased $4.3 million from $1.6 million for the first six months of 2007 to $5.9 million for the first six months of 2008 primarily due to $2.1 million of compensation expense recognized for management incentive units, increased production volumes resulting in an increase of $1.4 million in administrative fees due to Encore Operating pursuant to the Administrative Services Agreement, and $1.2 million of expenses associated with being a publicly traded partnership.

Marketing expense.Marketing expense decreased $0.4 million from $4.4 million in the first half of 2007 to $4.0 million in the first half of 2008 as a result of a reduction in natural gas throughput in our Wildhorse pipeline. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets.

Derivative fair value loss.During the six months ended June 30, 2008, we recorded a $92.0 million derivative fair value loss as compared to a $6.5 million loss for the six months ended June 30, 2007, the components of which were as follows:


	Six months ended June 30,						*Increase /*
	2008			2007			*(Decrease)*
	(in thousands)
Mark-to-market loss on commodity derivative contracts	$	87,197		$	5,489		$	81,708
Premium amortization		4,387			1,194			3,193
Change in fair value of interest rate swap agreements prior to designation		(381	)		—			(381	)
Settlements on commodity derivative contracts		812			(186	)		998

Total derivative fair value loss	$	92,015		$	6,497		$	85,518

Interest expense.Interest expense decreased $2.9 million from $6.4 million for the first six months of 2007 to $3.5 million for the first six months of 2008 primarily as a result of a reduction in average outstanding debt due to the payoff of our subordinated credit agreement in September 2007 using proceeds from our IPO. Interest expense incurred on the subordinated credit agreement in the first six months of 2007 was approximately $3.6 million. In addition to the payoff of the subordinated credit agreement, interest expense incurred on the revolving credit facility during the first six months of 2008 was less than the first six months of 2007 due to a reduction in LIBOR rates over the corresponding time period. All interest expense incurred during the first six months of 2008 related to our revolving credit facility and interest rate swap agreements. Of the $6.4 million total interest expense in the first six months of 2007, $2.8 million related to our revolving credit facility, $3.6 million related to our subordinated credit agreement, and $0.1 million related to other fees. The weighted average interest rate for all long-term debt for the six months ended June 30, 2008 was 5.0 percent as compared to 8.7 percent for the six months ended June 30, 2007.

Income taxes.In the first six months of 2008, we recorded an income tax benefit of $0.2 million compared to an income tax provision of $0.1 million in the first six months of 2007. The deferred tax benefit for the first six months of 2008 resulted from book losses that will be realized for tax in future periods.

Liquidity and Capital Resources

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 our level of capital expenditures. We may use other sources of capital, including the issuance of debt or additional common units, to fund acquisitions and to maintain our financial flexibility.

Our partnership agreement requires that we distribute all of our available cash quarterly. In May 2008, the board of directors of our General Partner approved a new distribution methodology, which returns additional cash flow to our unitholders during high commodity price environments. We will distribute to unitholders 50 percent of the excess distributable cash flow above: (i) maintenance capital requirements; (ii) an implied minimum quarterly distribution of $1.73 per unit annually, or $0.4325 per

ENCORE ENERGY PARTNERS LP

unit quarterly; and (iii) a minimum coverage ratio of 1.10. Our partnership agreement allows our General Partner to borrow funds to make distributions.

We plan to make substantial capital expenditures in the future for the acquisition, exploitation, and development of oil and natural gas properties. We intend to finance these capital expenditures with cash flows from operations. We intend to finance our acquisition and future development and exploitation activities with a combination of cash flows from operations and issuances of debt, equity, or a combination of the two.

Cash Flows

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 commodity prices. During the first six months of 2008, our average realized oil and natural gas prices increased by 97 percent and 33 percent, respectively, as compared to the first six months of 2007. Realized oil and natural gas prices fluctuate widely in response to changing market forces. For the first six months of 2008, approximately 72 percent of our production was oil. To the extent oil and natural gas prices decline or we experience a significant widening of our differentials, our earnings, cash flows from operations, and availability under our revolving credit facility may be adversely impacted. Prolonged periods of low 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.

We believe that our internally generated cash flows and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures and distributions for the foreseeable future.

Cash flows from operating activities. Cash provided by operating activities increased $50.0 million from $13.6 million for the six months ended June 30, 2007 to $63.6 million for the six months ended 2008, primarily due to an increase in our production margin, partially offset by an increase in accounts payable as a result of higher activity levels.

Cash flows from investing activities. Cash used in investing activities decreased $349.1 million from $361.4 million for the first six months of 2007 to $12.3 million for the first six months of 2008, primarily due to a $354.7 million decrease in amounts paid for the acquisition of oil and natural gas properties. In March 2007, OLLC paid approximately $329.4 million, including transaction costs, in connection with the acquisition of the Elk Basin Assets. In April 2007, we used cash of approximately $27.3 million in connection with the purchase of certain properties in the Williston Basin. The Williston Basin properties were acquired from EAC in February 2008 as part of the Permian and Williston Basin Assets and, as the transaction was accounted for as a transaction between entities under common control, the purchase price of the properties are shown in the period they were originally purchased by EAC.

Cash flows from financing activities. Cash flows from financing activities consist primarily of proceeds from and payments on long-term debt and distributions to unitholders. We periodically draw on our revolving credit facility to fund acquisitions and other capital commitments.

During the first six months of 2008, we used net cash of $50.7 million in financing activities as a result of $124.8 million in deemed distributions to affiliates in connection with our acquisition of the Permian and Williston Basin Assets and $29.1 million in distributions to unitholders, offset by net borrowings of $103.3 million under our revolving credit facility. Net borrowings on our revolving credit facility resulted in a net increase in outstanding borrowings under our revolving credit facility from $47.5 million at December 31, 2007 to $151 million at June 30, 2008.

During the first six months of 2007, we received net cash of $349.1 million from financing activities, including net borrowings on our long-term debt of $233.4 million and net contributions from EAC of $115.8 million, which were used to finance the acquisition of the Elk Basin Assets and certain properties in the Williston Basin.

Revolving Credit Facility

Our principal source of short-term liquidity is our revolving credit facility.

In conjunction with the closing of the acquisition of the Elk Basin Assets on March 7, 2007, OLLC entered into a five-year credit agreement with a bank syndicate comprised of Bank of America, N.A. and other lenders. The 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.

ENCORE ENERGY PARTNERS LP

The aggregate amount of the commitments of the lenders under the credit agreement is $300 million. Availability under the credit agreement is subject to a borrowing base, which is redetermined semi-annually and upon requested special redeterminations. At June 30, 2008, the borrowing base was $240 million.

The credit agreement matures on March 7, 2012. OLLC’s obligations under the credit agreement are secured by a first-priority security interest in OLLC’s and its restricted subsidiaries’ proved oil and natural gas reserves and in the equity interests of OLLC and its restricted subsidiaries. In addition, OLLC’s obligations under the credit agreement are guaranteed by us and OLLC’s restricted subsidiaries. Obligations under the credit agreement are non-recourse to EAC and its restricted subsidiaries.

Loans under the credit agreement are subject to varying rates of interest based on (i) the total amount outstanding in relation to the borrowing base and (ii) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:


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

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

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

The credit agreement, as amended on August 22, 2007, contains covenants that include, among others:

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

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

	•		a restriction on creating liens on our assets and the assets of our subsidiaries, subject to permitted exceptions;

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

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

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

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

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

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

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

The credit agreement contains customary events of default. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the credit agreement to be immediately due and payable. At June 30, 2008, we were in compliance with all of our debt covenants.

OLLC incurs a commitment fee on the unused portion of the credit agreement determined based on the ratio of amounts outstanding under the credit agreement to the borrowing base in effect on such date. The following table summarizes the calculation of the commitment fee under the credit agreement:

ENCORE ENERGY PARTNERS LP


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

On June 30, 2008, we had $151 million of outstanding borrowings and $88.9 million available to borrow under our revolving credit facility. On August 1, 2008, we had $140 million outstanding and $99.9 million available to borrow under our revolving credit facility. As of June 30, 2008 and August 1, 2008, we had $0.1 million outstanding letters of credit.

Current capitalization.At June 30, 2008, we had total assets of $485.1 million and total capitalization was $360.0 million, of which 58 percent was represented by partners’ equity and 42 percent by long-term debt. At December 31, 2007, we had total assets of $497.7 million and total capitalization was $442.5 million, of which 89 percent was represented by partners’ equity and 11 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 future capital projects or acquisitions.

Capital Commitments and Contingencies

Capital Commitments

Our primary needs for cash are as follows:

	•		Distributions to unitholders;

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

	•		Acquisitions of oil and natural gas properties;

	•		Funding of necessary 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 the partnership agreement). Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs. During the first six months of 2008, we distributed $29.1 million to our unitholders. On February 14, 2008, we distributed $9.8 million with respect to the fourth quarter of 2007 at a rate of $0.3875 per unit. On May 15, 2008, we paid a quarterly distribution of $0.5755 per unit with respect to the first quarter of 2008, which amounted to a total distribution of $19.3 million.

On August 4, 2008, the board of directors of our General Partner declared a distribution with respect to the second quarter of 2008 to unitholders of record as of the close of business on August 11, 2008. The $23.1 million total distribution will be paid to unitholders on or about August 14, 2008 at a rate of $0.6881 per unit.

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


	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
	(in thousands)
Development and exploitation	$	4,507	$	5,584	$	10,356	$	9,259
Exploration		1,179		1,376		1,188		1,406

Total	$	5,686	$	6,960	$	11,544	$	10,665

Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Our development and exploitation capital for the second quarter of 2008 yielded 8 gross (2.3 net) successful wells. Our development and exploitation capital for the first six months of 2008 yielded 33 gross (9.2

ENCORE ENERGY PARTNERS LP

net) successful wells.

Our exploration expenditures primarily relate to drilling exploratory wells, seismic costs, delay rentals, and geological and geophysical costs.

Acquisitions of oil and natural gas properties.On May 1, 2008, we acquired an existing net profits interest in certain of our properties in the Permian Basin of West Texas in exchange for 283,700 common units representing limited partner interests in us, valued at $5.8 million. On February 7, 2008, we acquired the Permian and Williston Basin Assets for total consideration of approximately $125.3 million in cash, including certain post-closing adjustments, and 6,884,776 common units representing limited partner interests in us. Because the assets acquired from EAC in the Permian and Williston Basins were acquired from an affiliate, the acquisition was accounted for as a transaction between entities under common control, similar to a pooling, whereby the assets and liabilities were recorded at EAC’s historical cost and our historical financial information was recast to include the acquired properties. As a result, our historical financial information presents the properties as if they were owned by us for all periods owned by EAC.

In March 2007, we acquired the Elk Basin Assets for a purchase price of approximately $329.4 million, including transaction costs.

Funding of necessary working capital.At June 30, 2008, our working capital (defined as total current assets less total current liabilities) was negative $14.2 million, a reduction of $17.0 million from positive working capital of $2.8 million at December 31, 2007. The decrease was primarily attributable to an increase in commodity prices, which negatively impacted the fair value of our outstanding derivative contracts, partially offset by an increase in accounts receivable as a result of increased oil and natural gas revenues.

For the remainder of 2008, we expect working capital to remain negative, primarily due to the fair values of our commodity derivative contracts. Our production volumes, commodity prices, and differentials will be the largest variables affecting our working capital. We anticipate cash reserves to be close to zero because we intend to use any excess cash to pay distributions to our unitholders, fund capital obligations, and reduce outstanding borrowings under our revolving credit facility. Our operating cash flow is determined in large part by production volumes and commodity prices. Assuming relatively stable commodity prices and constant or increasing production volumes, our operating cash flow should remain positive for the remainder of 2008.

Off-balance sheet arrangements.We do not have any off-balance sheet arrangements that are material to our financial position or results of operations.

Contractual obligations.The following table illustrates our contractual obligations and commitments at June 30, 2008:


	Payments Due by Period
Contractual Obligations and			Six Months Ending
Commitments	Total		December 31, 2008		2009 - 2010		2011-2012		Thereafter
	(in thousands)
Revolving credit facility (a)	$	172,759	$	2,967	$	11,869	$	157,923	$	—
Commodity derivative contracts (b)		88,484		4,979		64,283		19,222		—
Interest rate swap agreements		106		106		—		—		—
Development commitments (c)		2,147		2,147		—		—		—
Asset retirement obligations (d)		32,545		145		579		579		31,242

Total	$	296,041	$	10,344	$	76,731	$	177,724	$	31,242


(a)		Amounts include principal and projected interest payments. Please read Note 8 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt.

(b)		Represents net liabilities for commodity derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.

(c)		Development commitments represent authorized purchases for work in process. Also at June 30, 2008, we had $11.1 million of authorized purchases not placed to vendors (authorized AFEs), which were not accrued and are excluded from the above table, but are budgeted for and expected to be made unless circumstances change.

(d)		Asset retirement obligations represent the undiscounted future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal at the completion of field life. Please read Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our asset retirement obligations.

ENCORE ENERGY PARTNERS LP

Other contingencies and commitments. We are a party to an amended and restated administrative services agreement with Encore Operating, pursuant to which Encore Operating performs administrative services for us, such as accounting, corporate development, finance, land, legal, and engineering. Under the amended and restated administrative services agreement, Encore Operating initially received an administrative fee of $1.75 per BOE of our production for such services and reimbursement of actual third-party expenses incurred on our behalf. Encore Operating has substantial discretion in determining which third-party expenses to incur on our behalf. We also pay our share of expenses that are directly chargeable to wells under joint operating agreements. In addition, Encore Operating is entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator of a well.

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 the current year;

	•		if we or one of our subsidiaries acquires any 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 our General Partner upon the recommendation of the conflicts committee of our General Partner; and

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

Effective April 1, 2008, the administrative fee paid to Encore Operating under the amended and restated administrative services agreement increased to $1.88 per BOE of our production as a result of the COPAS Wage Index Adjustment for the current year.

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” in our 2007 Annual Report on Form 10-K for more information regarding our critical accounting policies and estimates.

New Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking 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 potential exposure, but rather indicators of potential exposure. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2007 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 outstanding commodity derivative contracts as of June 30, 2008 are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of June 30, 2008, the fair market value of our oil and natural gas derivative contracts was a net liability of $78.2 million and $7.9 million, respectively. Based on our open commodity derivative positions at June 30, 2008, a $1.00 increase in the respective NYMEX prices for oil and natural gas would increase our net derivative fair value liability by approximately $4.7 million, while a $1.00 decrease in the respective NYMEX prices for oil and natural gas would decrease our net derivative fair value liability by approximately $4.7 million.

ENCORE ENERGY PARTNERS LP

Interest Rate Sensitivity

At June 30, 2008, we had total long-term debt of $151 million, all of which was outstanding under our revolving credit facility. Our revolving credit facility is subject to floating market rates of interest that are linked to LIBOR. At this level of floating rate debt, if LIBOR increased one percent, we would incur an additional $1.5 million of interest expense per year, and if the rate decreased one percent, we would incur $1.5 million less.

In the first quarter of 2008, as a result of the increase in debt levels resulting from the purchase of the Permian and Williston Basin Assets, we entered into interest rate swap agreements whereby we swapped $100 million of floating rate debt to a weighted average fixed rate of 3.06 percent and an expected margin of 1.25 percent under our revolving credit facility. As of June 30, 2008, the unrealized gain on our interest rate swap agreements was approximately $1.0 million and is included in AOCI in our Consolidated Balance Sheet. As of June 30, 2008, the fair market value of our interest rate swap agreements was a net asset of $1.4 million. If LIBOR increased one percent, the net asset position of our interest rate swap agreements at June 30, 2008 would increase by approximately $2.5 million, and if LIBOR decreased one percent, the fair value of our interest rate swap agreements would be a net liability of approximately $1.2 million.

Item 4. Controls and Procedures

In accordance with the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of our disclosure controls and procedures as of June 30, 2008. 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, 2008 to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ENCORE ENERGY PARTNERS LP

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any legal or governmental claims that management believes will have a material adverse effect on our results of operations or financial position.

Item 1A. Risk Factors

In addition to the other information set forth in this Report, readers should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2007 Annual Report on Form 10-K, which could materially affect our business, financial condition, or results of operations. The risks described in our 2007 Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

In connection with the acquisition of an existing net profits interest in certain of our properties in Crockett County, Texas on May 1, 2008, we issued 283,700 common units representing limited partner interests in us to the limited partners of the seller. The issuance of the common units was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

Item 6. Exhibits


Exhibits

3.1		Certificate of Limited Partnership of Encore Energy Partners LP (incorporated by reference to Exhibit 3.1 to Form S-1 (File No. 333-142847) for Encore Energy Partners LP, filed with the SEC on May 11, 2007).
3.2		Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of September 17, 2007 (incorporated by reference to Exhibit 3.1 to the 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 the 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 ratio of earnings (loss) to fixed charges.


*		Filed herewith.

ENCORE ENERGY PARTNERS LP

SIGNATURE

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


	ENCORE ENERGY PARTNERS LP By: Encore Energy Partners GP LLC, its General Partner
Date: August 8, 2008	/s/ Andrea Hunter
	Andrea Hunter
	Vice President, Controller, and Principal Accounting Officer

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Encore Energy Partners Inactive 10-Q2008 Q2 Quarterly report

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