ENP Encore Energy Partners Lp

 

 

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 September 30, 2009

or

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

For the transition period from _______ to ________

Commission File Number: 001-33676

ENCORE ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware		20-8456807
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

777 Main Street, Suite 1400, Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(817) 877-9955

Not applicable

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

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

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

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

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

Number of common units outstanding as of October 27, 2009		45,267,610

 

 

ENCORE ENERGY PARTNERS LP

INDEX

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

ENCORE ENERGY PARTNERS LP

GLOSSARY

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

	•		ASC . FASB Accounting Standards Codification.
	•		Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
	•		Bbl/D . One Bbl per day.
	•		BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
	•		BOE/D . One BOE per day.
	•		Completion. The installation of permanent equipment for the production of hydrocarbons.
	•		Council of Petroleum Accountants Societies (“COPAS”) . A professional organization of petroleum accountants that maintains consistency in accounting procedures and interpretations, including the procedures that are part of most joint operating agreements. These procedures establish a drilling rate and an overhead rate to reimburse the operator of a well for overhead costs, such as accounting and engineering.
	•		Delay Rentals . Fees paid to the lessor of an oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.
	•		Development Well . A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
	•		Dry Hole or Unsuccessful Well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production costs.
	•		EAC. Encore Acquisition Company, a publicly traded Delaware corporation, together with its subsidiaries.
	•		ENP . Encore Energy Partners LP, a publicly traded Delaware limited partnership, together with its subsidiaries.
	•		Exploratory Well . A well drilled to find and produce hydrocarbons in an unproved area, to find a new reservoir in a field previously producing hydrocarbons in another reservoir, or to extend a known reservoir.
	•		FASB. Financial Accounting Standards Board.
	•		Field . An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
	•		GAAP. Accounting principles generally accepted in the United States.
	•		Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which an entity owns a working interest.
	•		Lease Operating Expense (“LOE”). All direct and allocated indirect costs of producing hydrocarbons after the completion of drilling and before the commencement of production. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
	•		LIBOR. London Interbank Offered Rate.
	•		MBbl. One thousand Bbls.
	•		MBOE. One thousand BOE.
	•		Mcf. One thousand cubic feet, used in reference to natural gas.
	•		Mcf/D. One Mcf per day.
	•		MMcf. One million cubic feet, used in reference to natural gas.
	•		Natural Gas Liquids (“NGLs”). The combination of ethane, propane, butane, and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
	•		Net Acres or Net Wells. Gross acres or wells, as the case may be, multiplied by the working interest percentage owned by an entity.
	•		NYMEX. New York Mercantile Exchange.
	•		Oil. Crude oil, condensate, and NGLs.
	•		Operator. The entity responsible for the exploration, development, and production of a well or lease.
	•		Production Margin. Wellhead revenues less production costs.
	•		Production Taxes. Production expense attributable to production, ad valorem, and severance taxes.
	•		Productive Well or Successful Well. A well capable of producing hydrocarbons in commercial quantities, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
	•		Proved Developed Reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

ENCORE ENERGY PARTNERS LP

	•		Proved Reserves. The estimated quantities of hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions.
	•		Proved Undeveloped Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion. Includes unrealized production response from enhanced recovery techniques that have been proved effective by actual tests in the area and in the same reservoir.
	•		Recompletion. The completion for production from an existing wellbore in another formation from that in which the well has been previously completed.
	•		Reservoir. A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
	•		Royalty. An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
	•		SFAS. Statement of Financial Accounting Standards.
	•		Working Interest. An interest in an oil or natural gas lease that gives the owner the right to drill for and produce hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.
	•		Workover. Operations on a producing well to restore or increase production.

PART I. FINANCIAL INFORMATION

Item 1.		Financial Statements

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS
(in thousands, except unit amounts)
(unaudited)

		September 30,				December 31,
		2009				2008 *
ASSETS
Current assets:
Cash and cash equivalents		$	3,437			$	619
Accounts receivable:
Trade			20,591				18,965
Affiliate			2,359				3,896
Derivatives			27,668				75,131
Other			751				831
Total current assets			54,806				99,442
Properties and equipment, at cost — successful efforts method:
Proved properties, including wells and related equipment			851,511				814,903
Unproved properties			61				84
Accumulated depletion, depreciation, and amortization			(198,138	)			(154,584	)
			653,434				660,403
Other property and equipment			802				802
Accumulated depreciation			(391	)			(240	)
			411				562
Goodwill			9,290				9,290
Other intangibles, net			3,402				3,662
Derivatives			23,122				38,497
Other			3,737				1,457
Total assets		$	748,202			$	813,313
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable:
Trade		$	898			$	1,036
Affiliate			2,259				5,468
Accrued liabilities:
Lease operating			4,106				4,252
Development capital			1,835				2,277
Interest			370				126
Production, ad valorem, and severance taxes			13,270				10,634
Derivatives			4,837				1,297
Oil and natural gas revenues payable			3,851				1,287
Other			2,141				1,502
Total current liabilities			33,567				27,879
Derivatives			5,626				3,491
Future abandonment cost, net of current portion			12,496				11,987
Long-term debt			260,000				150,000
Other			511				605
Total liabilities			312,200				193,962
Commitments and contingencies (see Note 12)
Partners’ equity:
Limited partners — 45,267,610 and 33,077,610 common units issued and outstanding, respectively			440,024				616,076
General partner — 504,851 general partner units issued and outstanding			(105	)			7,534
Accumulated other comprehensive loss			(3,917	)			(4,259	)
Total partners’ equity			436,002				619,351
Total liabilities and partners’ equity		$	748,202			$	813,313

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								Nine months ended
		September 30,								September 30,
		2009				2008 *				2009				2008 *
Revenues:
Oil		$	35,280			$	67,221			$	88,433			$	197,587
Natural gas			5,650				15,444				15,143				45,410
Marketing			102				1,445				381				5,207
Total revenues			41,032				84,110				103,957				248,204
Expenses:
Production:
Lease operating			9,017				12,967				31,120				34,069
Production, ad valorem, and severance taxes			4,693				8,210				11,586				23,711
Depletion, depreciation, and amortization			14,458				13,820				43,684				42,496
Exploration			3,034				47				3,074				115
General and administrative			2,912				3,772				9,135				11,899
Marketing			54				1,316				245				5,318
Derivative fair value loss (gain)			(4,822	)			(70,443	)			21,711				21,572
Other operating			1,303				440				2,730				1,294
Total expenses			30,649				(29,871	)			123,285				140,474
Operating income (loss)			10,383				113,981				(19,328	)			107,730
Other income (expenses):
Interest			(2,984	)			(1,767	)			(7,551	)			(5,316	)
Other			23				10				29				92
Total other expenses			(2,961	)			(1,757	)			(7,522	)			(5,224	)
Income (loss) before income taxes			7,422				112,224				(26,850	)			102,506
Income tax benefit (provision)			38				(332	)			(163	)			(194	)
Net income (loss)		$	7,460			$	111,892			$	(27,013	)		$	102,312
Net income (loss) allocation (see Note 9):
Limited partners’ interest in net income (loss)		$	5,904			$	89,716			$	(26,745	)		$	47,767
General partner’s interest in net income (loss)		$	63			$	1,444			$	(444	)		$	762
Net income (loss) per common unit:
Basic		$	0.13			$	2.86			$	(0.72	)		$	1.58
Diluted		$	0.13			$	2.86			$	(0.72	)		$	1.58
Weighted average common units outstanding:
Basic			44,653				31,356				37,373				30,300
Diluted			44,675				31,356				37,373				30,305
Cash distributions declared per common unit		$	0.5125			$	0.6881			$	1.5125			$	1.6511

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

ENCORE ENERGY PARTNERS LP

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

																		Accumulated
																		Other				Total
		Limited Partners								General Partner								Comprehensive				Partners’
		Units				Amount				Units				Amount				Loss				Equity
Balance at December 31, 2008 *			33,078			$	616,076				505			$	7,534			$	(4,259	)		$	619,351
Net distributions to owner			—				(11,284	)			—				(274	)			—				(11,558	)
Deemed distributions in connection with acquisition of the Arkoma Basin Assets			—				(45,333	)			—				(1,088	)			—				(46,421	)
Deemed distributions in connection with acquisition of the Williston Basin Assets			—				(24,593	)			—				(593	)			—				(25,186	)
Deemed distributions in connectoin with acquisition of the Rockies and Permian Basin Assets			—				(182,421	)			—				(4,401	)			—				(186,822	)
Proceeds from issuance of common units, net of offering costs			12,190				170,059				—				(113	)			—				169,946
Non-cash unit-based compensation			—				400				—				4				—				404
Cash distributions to unitholders ($1.5125 per unit)			—				(56,277	)			—				(764	)			—				(57,041	)
Components of comprehensive loss:
Net loss attributable to owners prior to acquisition of the Williston Basin Assets			—				(188	)			—				(5	)			—				(193	)
Net income attributable to owners prior to acquisition of the Rockies and Permian Basin Assets			—				360				—				9				—				369
Net loss attributable to unitholders			—				(26,775	)			—				(414	)			—				(27,189	)
Change in deferred hedge loss on interest rate swaps, net of tax of $1			—				—				—				—				342				342
Total comprehensive loss																							(26,671	)
Balance at September 30, 2009			45,268			$	440,024				505			$	(105	)		$	(3,917	)		$	436,002

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

ENCORE ENERGY PARTNERS LP

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

		Nine months ended
		September 30,
		2009				2008*
Cash flows from operating activities:
Net income (loss)		$	(27,013	)		$	102,312
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization			43,684				42,496
Non-cash exploration expense			2,991				52
Deferred taxes			(342	)			(110	)
Non-cash unit-based compensation expense			404				3,528
Non-cash derivative loss			79,948				19,943
Other			1,829				856
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable			(744	)			(525	)
Current derivatives			(2,020	)			(8,100	)
Other current assets			(196	)			(45	)
Long-term derivatives			(9,072	)			(5,308	)
Other assets			(18	)			712
Accounts payable			(2,755	)			(3,867	)
Other current liabilities			5,846				7,180
Net cash provided by operating activities			92,542				159,124
Cash flows from investing activities:
Purchases of other property and equipment			—				(302	)
Acquisition of oil and natural gas properties			(31,984	)			(157	)
Development of oil and natural gas properties			(7,330	)			(27,540	)
Net cash used in investing activities			(39,314	)			(27,999	)
Cash flows from financing activities:
Proceeds from long-term debt, net of issuance costs			203,061				205,310
Payments on long-term debt			(96,000	)			(113,000	)
Deemed distributions to affiliates in connection with acquisitions			(258,429	)			(125,027	)
Proceeds from issuance of common units, net of offering costs			170,149				—
Cash distributions to unitholders			(57,041	)			(52,239	)
Other			(12,150	)			(46,015	)
Net cash used in financing activities			(50,410	)			(130,971	)
Increase in cash and cash equivalents			2,818				154
Cash and cash equivalents, beginning of period			619				3
Cash and cash equivalents, end of period		$	3,437			$	157

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

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

	•		the Big Horn Basin in Wyoming and Montana;
	•		the Permian Basin in West Texas and New Mexico;
	•		the Williston Basin in North Dakota and Montana; and
	•		the Arkoma Basin in Arkansas and Oklahoma.

Note 2. Basis of Presentation

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

     In February 2008, ENP acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating, L.P. (“Encore Operating”), a Texas limited partnership and indirect wholly owned subsidiary of EAC. In January 2009, ENP acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”), from Encore Operating. In June 2009, ENP acquired certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) from Encore Operating. In August 2009, ENP acquired certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) from Encore Operating. Because these assets were acquired from an affiliate, the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value and ENP’s historical financial information was recast to include the acquired properties for all periods presented. Accordingly, the consolidated financial statements and notes thereto reflect the historical results of ENP combined with those of the Permian and Williston Basin Assets, the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets for all periods presented.

     The results of operations of the Arkoma Basin Assets, the Williston Basin Assets, and the Rockies and Permian Basin Assets related to pre-partnership operations were allocated to EAC and its affiliates based on their respective partnership percentages in ENP. The effect of recasting ENP’s consolidated financial statements to account for these common control transactions increased ENP’s net income by approximately $15.8 million and $47.1 million for the three and nine months ended September 30, 2008, respectively.

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

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

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

Supplemental Disclosures of Non-cash Investing and Financing Activities

     The following table sets forth supplemental disclosures of non-cash investing and financing activities for the periods indicated:

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

Reclassifications

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

FASB Launches Accounting Standards Codification

     In June 2009, the FASB issued SFAS No. 168, “ The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles ” (“SFAS 168” or ASC 105-10). SFAS 168 (ASC 105-10) establishes the Codification as the sole source of authoritative accounting principles recognized by the FASB to be applied by all nongovernmental entities in the preparation of financial statements in conformity with GAAP. SFAS 168 (ASC 105-10) was prospectively effective for financial statements issued for fiscal years ending on or after September 15, 2009, and interim periods within those fiscal years. The adoption of SFAS 168 (ASC 105-10) on July 1, 2009 did not impact ENP’s results of operations or financial condition.

     Following the Codification, the FASB will not issue new standards in the form of Statements, FASB Staff Positions (“FSP”), or Emerging Issues Task Force (“EITF”) Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”), which will serve to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the changes to the Codification.

     The Codification did not change GAAP; however, it did change the way GAAP is organized and presented. As a result, these changes impact how companies, including ENP, reference GAAP in their financial statements and in their significant accounting policies. ENP implemented the Codification in this Report by providing references to the Codification topics alongside references to the corresponding standards.

New Accounting Pronouncements

FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2” or ASC 820-10)

     In February 2008, the FASB issued FSP FAS 157-2, which delayed the effective date of SFAS No. 157, “ Fair Value Measurements ” (“SFAS 157” or ASC 820-10) for one year for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). ENP elected a partial deferral of SFAS 157 (ASC 820-10) for all instruments within the scope of FSP FAS 157-2 (ASC 820-10), including, but not limited to, its asset retirement obligations and indefinite lived assets. FSP FAS 157-2 (ASC 820-10) was prospectively effective for financial statements issued for fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The adoption of FSP FAS 157-2 (ASC 820-10) on January 1, 2009 did not have a material impact on ENP’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R” or ASC 805)

     In December 2007, the FASB issued SFAS 141R, which replaces SFAS No. 141, “ Business Combinations ” (ASC 805). SFAS 141R (ASC 805) establishes principles and requirements for the acquiror in a business combination, including: (1) recognition and

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

measurement in the financial statements of the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognition and measurement of goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determination of the information to be disclosed to enable financial statement users to evaluate the nature and financial effects of the business combination. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “ Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arises from Contingencies ” (“FSP FAS 141R-1” or ASC 805), which amends and clarifies SFAS 141R (ASC 805) to address application issues, including: (1) initial recognition and measurement; (2) subsequent measurement and accounting; and (3) disclosure of assets and liabilities arising from contingencies in a business combination. SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) were prospectively effective for business combinations consummated in fiscal years beginning on or after December 15, 2008. Subsequent to December 31, 2008, ENP acquired certain oil and natural gas producing properties and related assets from Encore Operating. The accounting for transactions between entities under common control is unchanged under SFAS 141R. However, the application of SFAS 141R (ASC 805) and FSP FAS 141R-1 (ASC 805) to future acquisitions could impact ENP’s results of operations and financial condition and the reporting of acquisitions in the consolidated financial statements.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS 161” or ASC 815-10-65-1)

     In March 2008, the FASB issued SFAS 161 (ASC 815-10-65-1), which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133” or ASC 815), to require enhanced disclosures, including: (1) how and why an entity uses derivative instruments; (2) how derivative instruments and related hedged items are accounted for under SFAS 133 (ASC 815) and its related interpretations; and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 (ASC 815-10-65-1) was prospectively effective for financial statements issued for fiscal years beginning on or after November 15, 2008, and interim periods within those fiscal years. The adoption of SFAS 161 (ASC 815-10-65-1) on January 1, 2009 required additional disclosures regarding ENP’s derivative instruments; however, it did not impact ENP’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

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” or ASC 260-10)

     In March 2008, the EITF ratified its consensus opinion on EITF 07-4 (ASC 260-10), which addresses how master limited partnerships should calculate earnings per unit (“EPU”) using the two-class method in SFAS No. 128, “Earnings per Share” (“SFAS 128” or ASC 260-10) and how current period earnings of a master limited partnership should be allocated to the general partner, limited partners, and other participating securities. EITF 07-4 (ASC 260-10) was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The adoption of EITF 07-4 (ASC 260-10) on January 1, 2009 did not have a material impact on ENP’s EPU calculations. In the accompanying Consolidated Financial Statements, periods prior to the adoption of EITF 07-4 (ASC 260-10) have been restated to calculate EPU in accordance with this pronouncement. Please read “Note 9. Earnings Per Unit” for additional discussion.

FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1” or ASC 260-10)

     In June 2008, the FASB issued FSP EITF 03-6-1 (ASC 260-10), which addresses whether instruments granted in equity-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation for computing basic EPU under the two-class method prescribed by SFAS 128 (ASC 260-10). FSP EITF 03-6-1 (ASC 260-10) was retroactively effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. The adoption of FSP EITF 03-6-1(ASC 260-10) on January 1, 2009 did not have a material impact on ENP’s EPU calculations. In the accompanying Consolidated Financial Statements, periods prior to the adoption of FSP EITF 03-6-1 (ASC 260-10) have been restated to calculate EPU in accordance with this pronouncement. Please read “Note 9. Earnings Per Unit” for additional discussion.

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

     In December 2008, the SEC issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-

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

8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 is prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009. ENP is evaluating the impact Release 33-8995 will have on its financial condition, results of operations, and disclosures.

FSP No. FAS 107-1 and APB 28-1, “Disclosure of Fair Value of Financial Instruments in Interim Statements” (“FSP FAS 107-1 and APB 28-1” or ASC 825-10-65-1)

     In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1), which requires that disclosures concerning the fair value of financial instruments be presented in interim as well as annual financial statements. FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1) was prospectively effective for financial statements issued for interim periods ending after June 15, 2009. The adoption of FSP FAS 107-1 and APB 28-1 (ASC 825-10-65-1) on June 30, 2009 required additional disclosures regarding ENP’s financial instruments; however, it did not impact ENP’s results of operations or financial condition. Please read “Note 5. Fair Value Measurements” for additional discussion.

SFAS No. 165, “Subsequent Events” (“SFAS 165” or ASC 855-10)

     In June 2009, the FASB issued SFAS 165 (ASC 855-10) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. In particular, SFAS 165 (ASC 855-10) sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. SFAS 165 (ASC 855-10) was prospectively effective for financial statements issued for interim or annual periods ending after June 15, 2009. The adoption of SFAS 165 (ASC 855-10) on June 30, 2009 did not impact ENP’s results of operations or financial condition.

ASU No. 2009-05, “Fair Value Measurement and Disclosure: Measuring Liabilities at Fair Value” (“ASU 2009-05” or ASC 820-10)

     In August 2009, the FASB issued ASU 2009-05 (ASC 820-10) to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. In particular, ASU 2009-05 specifies that a valuation technique should be applied that uses either the quote of the liability when traded as an asset, the quoted prices for similar liabilities when traded as assets, or another valuation technique consistent with existing fair value measurement guidance. ASU 2009-05 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods ending after October 1, 2009. The adoption of ASU 2009-05 (ASC 820-10) on December 31, 2009 will not impact ENP’s results of operations or financial condition.

Note 3. Acquisitions

Rockies and Permian Basin Assets

     In August 2009, ENP acquired the Rockies and Permian Basin Assets from Encore Operating for approximately $186.8 million in cash, which was financed through borrowings under OLLC’s revolving credit facility and proceeds from the issuance of ENP common units to the public. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of July 31, 2009 of approximately $194.4 million and $4.2 million, respectively, and the historical financial information of ENP was recast to include the Rockies and Permian Basin Assets for all periods presented. As the historical basis in the Rockies and Permian Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price was recorded as a deemed distribution when paid to EAC and its affiliates based on their respective ownership percentages in ENP.

Williston Basin Assets

     In June 2009, ENP acquired the Williston Basin Assets from Encore Operating for approximately $25.2 million in cash, which was financed through borrowings under OLLC’s revolving credit facility and proceeds from the issuance of ENP common units to the

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

public. As previously discussed, the acquisition was accounted for as a transaction between entities under common control. Therefore, the assets and liabilities of the acquired properties were recorded at Encore Operating’s carrying value as of May 31, 2009 of approximately $31.9 million and $1.3 million, respectively, and the historical financial information of ENP was recast to include the Williston Basin Assets for all periods presented. As the historical basis in the Williston Basin Assets is included in the accompanying Consolidated Balance Sheets, the cash purchase price was recorded as a deemed distribution when paid to EAC and its affiliates based on their respective ownership percentages in ENP.

Vinegarone Assets

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

Arkoma Basin Assets

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

Permian and Williston Basin Assets

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

Note 4. Proved Properties

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

		September 30,				December 31,
		2009				2008
		(in thousands)
Proved leasehold costs		$	609,666			$	580,695
Wells and related equipment — Completed			241,701				227,970
Wells and related equipment — In process			144				6,238
Total proved properties		$	851,511			$	814,903

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

Note 5. Fair Value Measurements

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

		September 30, 2009								December 31, 2008
		Book				Fair				Book				Fair
		Value				Value				Value				Value
						(in thousands)
Assets:
Cash and cash equivalents		$	3,437			$	3,437			$	619			$	619
Accounts receivable — trade			20,591				20,591				18,965				18,965
Accounts receivable — affiliate			2,359				2,359				3,896				3,896
Commodity derivative contracts			50,790				50,790				113,628				113,628
Liabilities:
Accounts payable — trade			898				898				1,036				1,036
Accounts payable — affiliate			2,259				2,259				5,468				5,468
Revolving credit facility			260,000				260,000				150,000				150,000
Commodity derivative contracts			6,313				6,313				229				229
Interest rate swaps			4,150				4,150				4,559				4,559

     The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of the revolving credit facility approximates fair value as the interest rate is variable. ENP’s credit risk has not changed materially from the date the revolving credit facility was entered into. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

Derivative Policy

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

     ENP applies the provisions of SFAS 133 (ASC 815), which requires each derivative instrument to be recorded in the balance sheet at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative qualifies for hedge accounting, depending on the nature of the hedge, the effective portion of changes in fair value can be recognized in accumulated other comprehensive income or loss until such time as the hedged item is recognized in earnings. In order to qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically.

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

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

Commodity Derivative Contracts

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

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

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

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

           Oil Derivative Contracts

		Average				Weighted					Average				Weighted					Average				Weighted
		Daily				Average					Daily				Average					Daily				Average					Asset
		Floor				Floor					Cap				Cap					Swap				Swap					Fair Market
Period		Volume				Price					Volume				Price					Volume				Price					Value
		(Bbls)				(per Bbl)					(Bbls)				(per Bbl)					(Bbls)				(per Bbl)					(in thousands)
Oct. — Dec. 2009 (a)																													$	10,940
			3,130			$	110.00					440			$	97.75					1,000			$	68.70
2010																														9,501
			880				80.00					440				93.80					760				75.43
			2,000				75.00					1,000				77.23					250				65.95
			760				67.00					—				—					—				—
2011																														11,626
			1,880				80.00					1,440				95.41					760				78.46
			1,000				70.00					—				—					—				—
			760				65.00					—				—					250				69.65
2012																														2,394
			750				70.00					500				82.05					210				81.62
			1,510				65.00					250				79.25					1,300				76.54
																													$	34,461

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

      Natural Gas Derivative Contracts

		Average				Weighted					Average				Weighted					Average				Weighted					Asset
		Daily				Average					Daily				Average					Daily				Average					(Liability)
		Floor				Floor					Cap				Cap					Swap				Swap					Fair Market
Period		Volume				Price					Volume				Price					Volume				Price					Value
		(Mcf)				(per Mcf)					(Mcf)				(per Mcf)					(Mcf)				(per Mcf)					(in thousands)
Oct. — Dec. 2009																													$	2,546
			3,800			$	8.20					3,800			$	9.83					—			$	—
			3,800				7.20					—				—					—				—
			1,800				6.76					—				—					—				—
2010																														6,860
			3,800				8.20					3,800				9.58					5,452				6.20
			4,698				7.26					—				—					550				5.86
2011																														703
			3,398				6.31					—				—					7,952				6.36
			—				—					—				—					550				5.86
2012																														(93	)
			898				6.76					—				—					5,452				6.26
			—				—					—				—					550				5.86
																													$	10,016

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

		Percentage of				Percentage of
		Oil Derivative				Natural Gas
		Contracts				Derivative Contracts
Counterparty		Committed				Committed
BNP Paribas			50	%			26	%
Calyon			28	%			48	%
RBC			14	%			3	%
Wachovia Bank			8	%			24	%

     In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating each financial transaction between the counterparty and ENP separately, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement benefits ENP in three ways: (1) the netting of the value of all trades reduces the likelihood of counterparties requiring daily collateral posting by ENP; (2) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (3) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out. ENP’s accounting policy is to not offset fair value amounts for derivative instruments.

Interest Rate Swaps

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

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

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

     The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred loss recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to the fluctuation of interest rates.

Current Period Impact

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

		Three months ended September 30,								Nine months ended September 30,
		2009				2008				2009				2008
		(in thousands)
Ineffectiveness		$	18			$	(6	)		$	(16	)		$	(349	)
Mark-to-market loss (gain)			4,957				822				62,638				1,978
Premium amortization			5,918				2,275				17,326				6,662
Settlements			(15,715	)			(73,534	)			(58,237	)			13,281
Total derivative fair value loss (gain)		$	(4,822	)		$	(70,443	)		$	21,711			$	21,572

Accumulated Other Comprehensive Loss

     At September 30, 2009 and December 31, 2008, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $3.9 million and $4.3 million, respectively. During the twelve months ending September 30, 2010, ENP expects to reclassify $3.5 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense.

Tabular Disclosures of Fair Value Measurements

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

		Asset Derivatives																	Liability Derivatives
		September 30, 2009								December 31, 2008									September 30, 2009								December 31, 2008
		Balance Sheet				Fair				Balance Sheet				Fair					Balance Sheet								Balance Sheet
		Location				Value				Location				Value					Location				Fair Value				Location				Fair Value
Derivatives not designated as hedging instruments under SFAS 133(ASC 815)
Commodity derivative contracts		Derivatives — current				$	27,668			Derivatives — current				$	75,131				Derivatives — current				$	1,367			Derivatives — current				$	—
Commodity derivative contracts		Derivatives — noncurrent					23,122			Derivatives — noncurrent					38,497				Derivatives — noncurrent					4,946			Derivatives — noncurrent					229
Total derivatives not designated as hedging instruments under SFAS 133 (ASC 815)						$	50,790							$	113,628								$	6,313							$	229
Derivatives designated as hedging instruments under SFAS 133 (ASC 815)
Interest rate swaps		Derivatives — current				$	—			Derivatives — current				$	—				Derivatives — current				$	3,470			Derivatives — current				$	1,297
Interest rate swaps		Derivatives —        noncurrent					—			Derivatives —        noncurrent					—				Derivatives —        noncurrent					680			Derivatives —        noncurrent					3,262
Total derivatives designated as hedging instruments under SFAS 133 (ASC 815)						$	—							$	—								$	4,150							$	4,559
Total derivatives						$	50,790							$	113,628								$	10,463							$	4,788

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

     The following table summarizes the effect of derivative instruments not designated as hedges under SFAS 133 (ASC 815) on the Consolidated Statements of Operations for the periods indicated (in thousands):

						Amount of Loss (Gain) Recognized In Income
Derivatives Not Designated as		Location of Loss				Three Months Ended September 30,								Nine Months Ended September 30,
Hedges Under SFAS 133 (ASC815)		Recognized In Income				2009				2008				2009				2008
Commodity derivative contracts		Derivative fair value loss (gain)				$	(4,840	)		$	(70,437	)		$	21,727			$	21,921

     The following tables summarize the effect of derivative instruments designated as hedges under SFAS 133 (ASC 815) on the Consolidated Statements of Operations for the periods indicated (in thousands):

Amount of Loss

Amount of Loss

Reclassified from

Amount of Loss (Gain)

Recognized in Accumulated OCI

Location of Loss

Accumulated OCI into

Recognized In Income

(Effective Portion)

(Gain) Reclassified

Income (Effective Portion)

as Ineffective

Three months ended

from Accumulated

Three months ended

Location of Loss (Gain)

Three months ended

Derivatives Designated as

September 30,

OCI into Income

September 30,

Recognized in Income

September 30,

Hedges Under SFAS 133 (ASC 815)

2009

2008

(Effective Portion)

2009

2008

as Ineffective

2009

2008

Interest rate swaps

$

1,289

$

714

Interest expense

$

983

$

117

Derivative fair value loss (gain)

$

18

$

(6

)

Amount of Loss

Amount of Loss (Gain)

Reclassified from

Amount of Gain

Recognized in Accumulated OCI

Location of Loss

Accumulated OCI into

Recognized In Income

(Effective Portion)

(Gain) Reclassified

Income (Effective Portion)

as Ineffective

Nine months ended

from Accumulated

Nine months ended

Location of Gain

Nine months ended

Derivatives Designated as

September 30,

OCI into Income

September 30,

Recognized in Income

September 30,

Hedges Under SFAS 133 (ASC 815)

2009

2008

(Effective Portion)

2009

2008

as Ineffective

2009

2008

Interest rate swaps

$

2,444

$

(163

)

Interest expense

$

2,786

$

224

Derivative fair value gain

$

16

$

349

Fair Value Hierarchy

     As discussed in “Note 2. Basis of Presentation,” ENP adopted FSP FAS 157-2 (ASC 820-10) on January 1, 2009 and SFAS 157 (ASC 820-10) on January 1, 2008. SFAS 157 (ASC 820-10) establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy defined by SFAS 157 (ASC 820-10) are as follows:

	•		Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities.
	•		Level 2 — Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable.
	•		Level 3 — Pricing inputs that are unobservable requiring the use of valuation methodologies that result in management’s best estimate of fair value.

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

•

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

•

Level 3 — ENP’s oil and natural gas calls, puts, and short puts are average value options, which are not exchange-traded contracts. Settlement is determined by the average underlying price over a predetermined period of time. ENP uses both observable and unobservable inputs in a Black-Scholes valuation model to determine fair value. Accordingly, these derivative instruments are classified within the Level 3 valuation hierarchy. The observable inputs of ENP’s valuation model include: (1) current market and contractual prices for the underlying instruments; (2) quoted forward prices for oil and natural gas; and (3) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract. The unobservable inputs of ENP’s valuation model include volatility. The implied volatilities for ENP’s calls, puts, and short puts with comparable strike prices are based on the settlement values from certain exchange-traded contracts. The implied volatilities for calls, puts, and short puts where there are no exchange-traded contracts with the same strike price are extrapolated from exchange-traded implied volatilities by an independent party.

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

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

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

						Fair Value Measurements at Reporting Date Using
						Quoted Prices in
						Active Markets for				Significant Other				Significant
		Asset (Liability) at				Identical Assets				Observable Inputs				Unobservable Inputs
Description		September 30, 2009				(Level 1)				(Level 2)				(Level 3)
		(in thousands)
Oil derivative contracts — swaps		$	(2,149	)		$	—			$	(2,149	)		$	—
Oil derivative contracts — floors and caps			36,610				—				—				36,610
Natural gas derivative contracts — swaps			336				—				336				—
Natural gas derivative contracts — floors and caps			9,680				—				—				9,680
Interest rate swaps			(4,150	)			—				(4,150	)			—
Total		$	40,327			$	—			$	(5,963	)		$	46,290