- Quarterly Report (10-Q)

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, 2011

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.)

5847 San Felipe, Suite 3000, Houston, Texas	77057
(Address of principal executive offices)	(Zip Code)

(832) 327-2255

(Registrant’s telephone number, including area code)

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 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.

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 November 4, 2011: 45,484,863

ENCORE ENERGY PARTNERS LP

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Unaudited Financial Statements
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statement of Partners’ Equity and Comprehensive Income	3
	Consolidated Statements of Cash Flows	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	37
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3.	Defaults Upon Senior Securities	38
Item 4.	Removed and Reserved	38
Item 5.	Other Information	38
Item 6.	Exhibits	38

ENCORE ENERGY PARTNERS LP

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements and information in this Quarterly Report on Form 10-Q (the “Report”) may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

·	our ability to pay distributions at the then-current distribution rate;

·	our operating results;

·	volatility in oil and natural gas prices;

·	our ability to protect ourselves from changes in commodity prices using commodity derivative contract positions;

·	performance of counterparties to our derivative contracts;

·	our estimates of proved reserves;

·	our ability to effectively develop our oil and natural gas reserves;

·	availability of rigs, equipment and crews to support our operations;

·	competitive conditions;

·	our ability to acquire assets on acceptable terms; and

·	legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal and state environmental laws and regulations.

Other factors that could cause our actual results to differ from our projected results are described in (1) “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 Annual Report”), (2) our Quarterly Reports on Forms 10-Q for the periods ended March 31, 2011 and June 30, 2011, (3) our reports and registration statements filed from time to time with the Securities and Exchange Commission (the “SEC”) and (4) other public announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

ENCORE ENERGY PARTNERS LP

GLOSSARY

The following are abbreviations and definitions of certain terms used in this Report.

·	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 gas to oil equivalent barrels at a ratio of six Mcf of gas to one Bbl of oil.

·	BOE/D . One BOE per day.

·	Completion. The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

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.

·	DD&A . Depletion, depreciation and amortization.

Developed Oil and Gas Reserves. Reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

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

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

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

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

·	Exploratory Well . A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. For a complete definition of exploratory well, refer to Regulation S-X, Rule 4-10(a)(13).

·	Extension Well . A well drilled to extend the limits of a known reservoir.

·	FASB. Financial Accounting Standards Board.

·	FASC . FASB Accounting Standards Codification.

·	Field . An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of field, refer to Regulation S-X, Rule 4-10(a)(15).

·	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. Such costs include ad valorem taxes, labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.

·	LIBOR. London Interbank Offered Rate.

·	MBbl. One thousand Bbls.

·	MBOE. One thousand BOE.

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

·	Mcf/D. One Mcf per day.

·	MMBOE . One million BOE.

·	MMcf. One million cubic feet, used in reference to 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 and condensate.

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

·	Production Costs. Costs incurred to operate and maintain wells and related equipment and facilities. For a complete definition of production costs, refer to Regulation S-X, Rule 4-10(a)(20).

·	Production Margin. Wellhead revenues less production costs.

·	Productive Well. An exploratory, development, or extension well that is not a dry well.

Proved Oil and Gas Reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and gas reserves, refer to Regulation S-X, Rule 4-10(a)(22).

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

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

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

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

Undeveloped Oil and Gas Reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of undeveloped oil and gas reserves, refer to Regulation S-X, Rule 4-10(a)(31).

·	Vanguard. Vanguard Natural Resources, LLC, a publicly traded Delaware limited liability company, together with its subsidiaries.

·	VNG. Vanguard Natural Gas, LLC, a wholly-owned subsidiary of Vanguard.

·	Working Interest. An interest in an oil or 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. Unaudited Financial Statements

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

	September 30,			December 31,
	2011			2010
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	651		$	1,380
Accounts receivable - trade		34,260			22,795
Derivatives		14,813			2,604
Other		2,172			470
Total current assets		51,896			27,249

Properties and equipment, at cost - successful efforts method:
Proved properties, including wells and related equipment		1,002,851			857,999
Unproved properties		41			17
Accumulated depletion, depreciation, and amortization		(294,014	)		(259,575	)
		708,878			598,441
Other property and equipment		1,694			1,327
Accumulated depreciation		(669	)		(613	)
		1,025			714

Goodwill		9,290			9,290
Other intangibles, net		2,784			3,012
Derivatives		15,884			836
Other		318			1,778
Total assets	$	790,075		$	641,320

LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,021		$	2,103
Affiliate		1,490			98
Accrued liabilities:
Lease operating		4,717			4,550
Development capital		1,736			890
Interest		375			298
Production and other taxes		14,235			10,109
Derivatives		66			3,530
Oil and natural gas revenues payable		3,276			1,730
Credit agreement		356,000			-
Other		2,497			1,278
Total current liabilities		386,413			24,586

Derivatives		241			20,681
Future abandonment cost, net of current portion		16,785			13,080
Deferred taxes		63			11
Credit agreement		-			234,000
Total liabilities		403,502			292,358

Commitments and contingencies (see Note 12)

Partners' equity:
Limited partners - public, 24,560,808 and 24,417,542 common units issued
and outstanding, respectively		349,912			340,126
Limited partners - affiliates, 20,924,055 common units issued and outstanding		36,674			10,125
General partner - 504,851 general partner units issued and outstanding		309			(94	)
Accumulated other comprehensive loss		(322	)		(1,195	)
Total partners' equity		386,573			348,962
Total liabilities and partners' equity	$	790,075		$	641,320

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,
	2011			2010			2011			2010
Revenues:
Oil	$	38,814		$	33,765		$	122,869		$	105,732
Natural gas		8,811			6,497			20,872			21,407
Natural gas liquids		3,554			2,521			8,978			9,001
Marketing		126			60			207			207
Commodity derivative fair value gain (loss) - realized		(2,818	)		1,342			(7,616	)		1,959
Commodity derivative fair value gain (loss) - unrealized		82,914			(8,922	)		58,318			12,521
Total revenues		131,401			35,263			203,628			150,827

Expenses:
Production:
Lease operating		10,451			9,268			29,198			30,907
Production and other taxes		5,647			4,752			15,672			14,951
Depletion, depreciation, amortization and accretion		12,500			12,782			35,568			38,472
Exploration		-			53			-			129
General and administrative		4,451			2,817			12,710			10,088
Total expenses		33,049			29,672			93,148			94,547

Operating income		98,352			5,591			110,480			56,280

Other income (expenses):
Interest		(2,646	)		(2,303	)		(7,030	)		(6,987	)
Interest rate derivative fair value loss - realized		(445	)		(974	)		(1,858	)		(2,925	)
Interest rate derivative fair value gain (loss) - unrealized		523			(29	)		1,146			(133	)
Net gain on acquisition of oil and natural gas properties		815			-			815			-
Other		70			9			79			47
Total other expenses		(1,683	)		(3,297	)		(6,848	)		(9,998	)

Income before income taxes		96,669			2,294			103,632			46,282
Income tax benefit (provision)		(220	)		147			(415	)		36

Net income	$	96,449		$	2,441		$	103,217		$	46,318

Net income allocation (see Note 9):
Limited partners' interest in net income	$	95,391		$	2,419		$	102,084		$	45,813
General partner's interest in net income	$	1,058		$	22		$	1,133		$	505

Net income per common unit:
Basic	$	2.10		$	0.05		$	2.24		$	1.01
Diluted	$	2.10		$	0.05		$	2.24		$	1.01

Weighted average common units outstanding:
Basic		45,487			45,342			45,481			45,328
Diluted		45,487			45,342			45,481			45,336

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY AND COMPREHENSIVE INCOME

(in thousands, except per unit amounts)

(unaudited)

											Accumulated
											Other			Total
	Limited Partners					General Partner					Comprehensive			Partners'
	Units		Amount			Units		Amount			Loss			Equity

Balance at January 1, 2010		45,285	$	409,777			505	$	(353	)	$	(3,420	)	$	406,004
Net contributions from owners		-		(2	)		-		935			-			933
Non-cash equity-based compensation		-		1,323			-		8			-			1,331
Vesting of phantom units		57		-			-		-			-			-
Other		-		(216	)		-		(3	)		-			(219	)
Cash distributions to unitholders ($2.0375 per unit)		-		(92,353	)		-		(1,029	)		-			(93,382	)
Components of comprehensive income:
Net income attributable to unitholders		-		31,722			-		348			-			32,070
Change in deferred hedge loss on interest rate swaps,
net of tax of $7		-		-			-		-			2,225			2,225
Total comprehensive income															34,295
Balance at December 31, 2010		45,342		350,251			505		(94	)		(1,195	)		348,962
Non-cash equity-based compensation		143		660			-		7			-			667
Cash distributions to unitholders ($0.50 per unit to unitholders
of record February 7, 2011, $0.49 per unit to
unitholders of record May 6, 2011 and $0.47 per unit
to unitholders of record August 5, 2011)		-		(66,409	)		-		(737	)		-			(67,146	)
Components of comprehensive income:
Net income attributable to unitholders		-		102,084			-		1,133			-			103,217
Settlement of interest rate cash flow hedges in
comprehensive loss		-		-			-		-			873			873
Total comprehensive income															104,090
Balance at September 30, 2011		45,485	$	386,586			505	$	309		$	(322	)	$	386,573

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,
	2011			2010
Cash flows from operating activities:
Net income	$	103,217		$	46,318
Adjustments to reconcile net income to net cash provided
by operating activities:
Depletion, depreciation, amortization and accretion		35,568			38,472
Deferred taxes		127			(55	)
Non-cash equity-based compensation expense		667			1,043
Non-cash derivative gain		(50,424	)		(5,046	)
Gain on acquisitions of oil and natural gas properties		(815	)		-
Other		1,143			2,182
Changes in operating assets and liabilities:
Accounts receivable		(12,616	)		13,169
Other current assets		(514	)		(36	)
Other assets		-			(15	)
Accounts payable		2,461			(583	)
Other current liabilities		7,135			2,981
Net cash provided by operating activities		85,949			98,430

Cash flows from investing activities:
Purchase of other property and equipment		(508	)		(125	)
Acquisition of oil and natural gas properties		(130,860	)		(280	)
Deposits and prepayments of oil and natural gas properties		(312	)		-
Development of oil and natural gas properties		(9,852	)		(3,843	)
Net cash used in investing activities		(141,532	)		(4,248	)

Cash flows from financing activities:
Proceeds from credit agreement		183,500			10,000
Payments of credit agreement		(61,500	)		(25,000	)
Cash distributions to unitholders		(67,146	)		(70,459	)
Other		-			(194	)
Net cash provided by (used in) financing activities		54,854			(85,653	)

(Decrease) increase in cash and cash equivalents		(729	)		8,529
Cash and cash equivalents, beginning of period		1,380			1,754
Cash and cash equivalents, end of period	$	651		$	10,283

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 (together with its subsidiaries, “ENP”) is engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States. Encore Energy Partners GP LLC (the “General Partner” or “ENP GP”), a Delaware limited liability company which is a wholly-owned subsidiary of Vanguard Natural Resources, LLC (together with its subsidiaries, “Vanguard” or “VNR”), a publicly traded Delaware limited liability company, 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 operating areas:

·	the Big Horn Basin in Wyoming and Montana;

·	the Permian Basin in West Texas and New Mexico;

·	the Williston Basin in North Dakota and Montana; and

·	the Arkoma Basin in Arkansas and Oklahoma.

On December 31, 2010, Denbury Resources Inc. (together with its subsidiaries, “Denbury”), a publicly traded Delaware corporation, sold its ownership interests in ENP and the General Partner to Vanguard Natural Gas, LLC (“VNG”), a wholly-owned subsidiary of Vanguard, for $300.0 million in cash and approximately 3.14 million Vanguard common units (the “Vanguard Acquisition”). Denbury sold the entity which owns 100 percent of the General Partner and approximately 20.9 million ENP common units, or approximately 46.1 percent of ENP’s outstanding common units.

On July 11, 2011, Vanguard and ENP announced the execution of a definitive agreement that would result in a merger whereby ENP would become a wholly-owned subsidiary of VNG through a unit-for-unit exchange. Under the terms of the definitive agreement, ENP’s public unitholders will receive 0.75 Vanguard common units in exchange for each ENP common unit they own at closing. The transaction will result in approximately 18.4 million additional common units being issued by Vanguard. The terms of the definitive agreement were unanimously approved by the members of the ENP Conflicts Committee, who negotiated the terms on behalf of ENP and is comprised solely of independent directors. In addition, Jefferies & Company, Inc., has issued a fairness opinion to the ENP Conflicts Committee stating that they believe the exchange ratio is fair, from a financial point of view, to the unaffiliated unitholders of ENP.

The completion of the merger is subject to approval by a majority of the outstanding ENP common unitholders and also subject to the approval of the issuance of additional Vanguard common units in connection with the merger by the affirmative vote of a majority of the votes cast by Vanguard unitholders. Completion of the merger, assuming the requisite unitholder votes are obtained and subject to other customary terms and conditions, is expected to occur on November 30, 2011. On August 2, 2011, ENP and Vanguard filed a Registration Statement on Form S-4 (the “Form S-4”) with the SEC, which was declared effective on October 31, 2011. The Form S-4 incorporates a joint proxy statement/prospectus which ENP and Vanguard mailed to their respective unitholders in connection with obtaining unitholder approval of the proposed merger. On November 1, 2011, Vanguard and ENP announced that both companies have established a record date and a meeting date for the special meetings of unitholders to consider and vote upon the previously-announced merger agreement. Pending completion of the merger, ENP has agreed to customary restrictions in the way it conducts its business.

Note 2. Summary of Significant Accounting Policies

(a)	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 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, 2011, results of operations for the three and nine months ended September 30, 2011 and 2010, respectively, and cash flows for the nine months ended September 30, 2011 and 2010, respectively. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

Certain amounts and disclosures have been condensed or omitted from these consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in ENP’s 2010 Annual Report.

(b)	New Pronouncements Issued But Not Yet Adopted

In May 2011, the FASB issued authoritative guidance to achieve common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The guidance changes the wording used to describe the requirements in GAAP for measuring fair value and disclosures about fair value. The guidance includes clarification of the application of existing fair value measurements and disclosure requirements related to a) the application of highest and best use and valuation premise concepts; b) measuring the fair value of an instrument classified in a reporting entity’s stockholders’ equity, and c) disclosure of quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. Additionally, the guidance changes particular principles or requirements for measuring fair value and disclosing information about fair value measurements related to a) measuring the fair value of financial instruments that are managed within a portfolio, b) application of premiums and discounts in a fair value measurement, and c) additional requirements to expand the disclosures about fair value measurements. The guidance is effective for each reporting entity for interim and annual periods beginning after December 15, 2011. The adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

In June 2011, the FASB issued authoritative guidance intended to improve the comparability, consistency, and transparency of financial reporting. The guidance is also intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence of GAAP and IFRS by eliminating the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. Under this guidance, entities are given two options for presenting other comprehensive income. The statement of other comprehensive income can be included with the statement of net income, which together will comprise the statement of total comprehensive income. Alternatively, the statement of other comprehensive income can be presented separate from the statement of net income. However, the guidance requires that the statement of other comprehensive income should immediately follow the statement of net income. The guidance also requires entities to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented. The guidance is effective for each reporting entity for interim and annual periods beginning after December 15, 2011. As this guidance provides only presentation requirements, the adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

In September 2011, the FASB issued authoritative guidance intended to simplify how entities, both public and nonpublic, test goodwill for impairment. The guidance permits an entity to first assess qualitative factors to determine whether it is "more likely than not" that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in FASC Topic 350, Intangibles-Goodwill and Other. The more-likely-than-not threshold is defined as having a likelihood of more than 50%. The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. As this guidance only provides changes in the procedures for testing the impairment of goodwill, the adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

(c)	Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization, and accretion. Actual results could differ from those estimates.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current period presentation. These reclassifications did not impact our reported net income or partners’ equity.

Note 3. Acquisitions

On June 22, 2011, pursuant to two Purchase and Sale Agreements, ENP agreed to acquire producing oil and natural gas assets in the Permian Basin of West Texas (the “Purchased Assets”) from a private seller. We refer to this acquisition as the “Permian Basin Acquisition I.” ENP and Vanguard agreed to purchase 50% of the Purchased Assets for an aggregate of $85.0 million and each paid the seller a non-refundable deposit of $4.25 million. The effective date of this acquisition is May 1, 2011. We completed this acquisition on July 29, 2011 for an adjusted purchase price of $40.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our Credit Agreement (defined below). In accordance with the guidance contained within FASC Topic 805, Business Combinations (“FASC Topic 805”), the measurement of the fair value at acquisition date of the assets acquired in the Permian Basin Acquisition I as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $0.3 million, which was immediately impaired and recorded as a loss. The loss resulted from the changes in oil prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

On August 8, 2011, we entered into assignment agreements and completed the acquisition of certain oil and natural gas properties located in the Permian Basin of West Texas from a private seller. We refer to this acquisition as the “Permian Basin Acquisition II.” The adjusted purchase price for the assets was $14.8 million with an effective date of May 1, 2011. This acquisition was funded with borrowings under our Credit Agreement. In accordance with the guidance contained within FASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Permian Basin Acquisition II approximates the fair value of consideration transferred, and therefore no gain or goodwill resulted from the acquisition.

On August 15, 2011, we entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Wyoming. We refer to this acquisition as the “Wyoming Acquisition.” The purchase price for the assets was $28.5 million with an effective date of June 1, 2011. We completed this acquisition on September 1, 2011 for an adjusted purchase price of $27.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our Credit Agreement. In accordance with the guidance contained within FASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Wyoming Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $1.1 million, which has been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

On August 31, 2011, we entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the Texas and Louisiana Gulf Coast area from a private seller. We refer to this acquisition as the “Gulf Coast Acquisition.” The adjusted purchase price for the assets was $47.6 million with an effective date of August 1, 2011. This acquisition was funded with borrowings under our Credit Agreement. In accordance with the guidance contained within FASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Gulf Coast Acquisition approximates the fair value of consideration transferred, and therefore no gain or goodwill resulted from the acquisition.

The following unaudited pro forma results for each of the three and nine months ended September 30, 2011 and September 30, 2010 show the effect on our consolidated results of operations as if the Permian Basin Acquisition I, Permian Basin Acquisition II, Wyoming Acquisition and Gulf Coast Acquisition had occurred on January 1, 2010. The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and gas properties acquired, adjusted for (1) depletion expense applied to the adjusted basis of the properties acquired and (2) interest expense on additional borrowings necessary to finance the acquisitions. The net gain on acquisition of oil and natural gas properties was excluded from the pro forma results for the three and nine month periods ended September 30, 2011 and 2010. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:

	Pro forma (in thousands, except per unit data)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010			2011		2010
Total revenues	$	137,048	$	44,755	$	226,913	$	177,531
Net income	$	97,877	$	5,443	$	110,096	$	54,328
Net income per unit:
Common units – basic & diluted	$	2.13	$	0.12	$	2.39	$	1.19

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for the Permian Basin Acquisition I, Permian Basin Acquisition II, Wyoming Acquisition and Gulf Coast Acquisition are shown in the table that follows (in thousands). Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

	Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011
Permian Basin Acquisition I
Revenues	$	1,277	$	1,277
Excess of revenues over direct operating expenses	$	751	$	751
Permian Basin Acquisition II
Revenues	$	370	$	370
Excess of revenues over direct operating expenses	$	213	$	213
Wyoming Acquisition
Revenues	$	405	$	405
Excess of revenues over direct operating expenses	$	381	$	381
Gulf Coast Acquisition
Revenues	$	841	$	841
Excess of revenues over direct operating expenses	$	770	$	770

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,
	2011		2010
	(in thousands)
Proved leasehold costs	$	741,421	$	609,910
Wells and related equipment - completed		261,386		248,017
Wells and related equipment - in process		44		72
Total proved properties	$	1,002,851	$	857,999

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, 2011				December 31, 2010
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	651	$	651	$	1,380	$	1,380
Accounts receivable - trade		34,260		34,260		22,795		22,795
Commodity derivative contracts		30,697		30,697		3,440		3,440
Liabilities:
Accounts payable - trade		2,021		2,021		2,103		2,103
Accounts payable - affiliate		1,490		1,490		98		98
Credit Agreement		356,000		356,000		234,000		232,517
Commodity derivative contracts		11		11		22,769		22,769
Interest rate swaps		296		296		1,442		1,442

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 ENP’s five-year credit agreement (as amended, the “Credit Agreement”) approximates fair value as the interest rate is variable; however, ENP adjusted the estimated fair value for estimated nonperformance risk of approximately $1.5 million at December 31, 2010. The nonperformance risk was determined using industry credit default swaps. No adjustment for nonperformance risk was made at September 30, 2011 as the Credit Agreement matures within one year and any adjustment would be considered insignificant. 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, all of which are currently lenders under ENP’s Credit Agreement. ENP also uses derivative instruments in the form of interest rate swaps, which hedge risks related to interest rate fluctuation.

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

Effective January 1, 2011, ENP elected to de-designate its outstanding interest rate swaps as cash flow hedges and from that date began recognizing changes in the fair market value of its interest rate swaps in the accompanying Consolidated Statements of Operations. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive loss and is being reclassified to earnings in the month in which the transactions settle. Prior to January 1, 2011, ENP 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 was recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and was reclassified into earnings in the same period in which the hedged transaction affected earnings. Any ineffective portion of the mark-to-market gain or loss was recognized in earnings and included in “Interest rate derivative fair value gain (loss) - unrealized” in the accompanying Consolidated Statements of Operations.

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

Commodity Derivative Contracts

ENP manages commodity price risk with swap contracts, put contracts, collars, three-way collars, basis swaps and swaptions. 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. Three-way collar contracts combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price of NYMEX West Texas Intermediate (“WTI”) crude oil drops below the price of the short put. This allows us to settle for WTI market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. Basis swap contracts guarantees a price differential between the NYMEX prices and the ENP’s physical pricing points. ENP receives a payment from the counterparty or makes a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. Under swaption agreements, we provide options to counterparties to extend swap contracts into subsequent years.

In January 2011, we elected to monetize all of our $65 and $70 oil puts for 2011 and 2012 and used the proceeds to raise the floor price to $80 on a smaller volume of oil in 2012 and also slightly raise the swap price for oil in 2011 and 2012. During the second and third quarters of 2011, we entered into NYMEX WTI crude oil derivative three-way collar contracts, which provide that if the market price falls below the short put fixed price, we will receive the market price plus $20 per barrel.

The following tables summarize ENP’s open commodity derivative contracts as of September 30, 2011:

	October 1, - December 31, 2011		Year 2012		Year 2013		Year 2014
Gas Positions:
Fixed Price Swaps:
Notional Volume (MMBtu)		1,168,584		4,648,932		4,270,500		452,500
Fixed Price ($/MMBtu)	$	5.81	$	5.52	$	5.05	$	4.80
Puts:
Notional Volume (MMBtu)		312,616		328,668		—		—
Fixed Price ($/MMBtu)	$	6.31	$	6.76	$	—	$	—
Total Gas Positions:
Notional Volume (MMBtu)		1,481,200		4,977,600		4,270,500		452,500

Oil Positions:
Fixed Price Swaps:
Notional Volume (Bbls)		141,220		1,021,140		1,332,250		1,204,500
Fixed Price ($/Bbl)	$	83.15	$	84.49	$	89.11	$	89.14
Collars:
Notional Volume (Bbls)		172,960		475,800		—		—
Floor Price ($/Bbl)	$	80.00	$	74.23	$	—	$	—
Ceiling Price ($/Bbl)	$	96.49	$	90.98	$	—	$	—
Three-way Collars:
Notional Volume (Bbls)		48,300		192,150		191,625		54,750
Floor Price ($/Bbl)	$	90.00	$	90.00	$	90.00	$	90.00
Ceiling Price ($/Bbl)	$	102.56	$	106.76	$	106.76	$	105.00
Put Sold ($/Bbl)	$	70.00	$	70.00	$	70.00	$	70.00
Total Oil Positions:
Notional Volume (Bbls)		362,480		1,689,090		1,523,875		1,259,250

Basis Swaps

As of September 30, 2011, ENP had the following open basis swap contracts:

	October 1, - December 31, 2011			Year 2012			Year 2013			Year 2014
Gas Positions:
Notional Volume (MMBtu)		230,000			915,000			912,500			452,500
Weighted Avg. Basis Differential ($/MMBtu) (1)	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	(0.32	)

Oil Positions:
Notional Volume (Bbls)		21,000			84,000			84,000			—
Weighted Avg. Basis Differential ($/Bbls) (2)	$	19.10		$	15.15		$	9.60		$	—

(1)	Natural gas basis swap contracts represent a weighted average differential between prices primarily against Rocky Mountains (CIGC) and NYMEX Henry Hub prices

(2)	Oil basis swap contracts represent a weighted average differential between prices primarily against Light Louisiana Sweet Crude (LLS) and NYMEX WTI prices

Swaptions

Options were provided to counterparties under swaption agreements to extend swaps into 2013 on 36,500 Bbls of oil at a fixed price of $105.00 per Bbl, into 2015 on 36,500 Bbls of oil at a fixed price of $95.00 per Bbl and into 2014 on 365,000 MMBtu of gas at a fixed price of $5.40 per MMBtu.

Interest Rate Swaps

ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby the interest due on certain floating rate debt under the Credit Agreement is converted to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swap as of September 30, 2011, which was entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
October 1, 2011 - March 7, 2016 (1)	$	75,000		1.0800	%	1-month LIBOR

(1)	ENP entered into this interest rate swap on September 21, 2011, and the terms became effective on October 7, 2011.

Current Period Impact

ENP recognizes realized and unrealized commodity and interest rate derivative fair value gains and losses related to: (1) changes in the fair market value of derivative contracts not designated as hedges; (2) premium amortization; (3) receipts and settlements on derivative contracts not designated as hedges; (4) settlements of de-designated interest rate hedges; and (5) the ineffectiveness of derivative contracts designated as hedges prior to January 1, 2011. The following table summarizes the components of our realized and unrealized commodity and interest rate derivative fair value gains and losses for the periods indicated:

	Location of Gain (Loss)	Three months ended September 30,						Nine months ended September 30,
	Recognized in Income	2011			2010			2011			2010
		(in thousands)						(in thousands)
Realized gains (losses):
Premium amortization	Commodity derivative fair value loss - realized	$	(4,210	)	$	(2,474	)	$	(8,163	)	$	(7,342	)
Receipts, net of settlements	Commodity derivative fair value gain - realized		1,392			3,816			547			9,301
Receipts, net of settlements	Interest rate derivative fair value loss - realized		(445	)		(974	)		(1,858	)		(2,925	)
		$	(3,263	)	$	368		$	(9,474	)	$	(966	)
Unrealized gains (losses):
Mark-to-market gain (loss)	Commodity derivative fair value gain (loss) - unrealized	$	82,914		$	(8,922	)	$	58,318		$	12,521
Mark-to-market gain	Interest rate derivative fair value gain - unrealized		523			-			1,146			-
Ineffectiveness on interest rate swaps	Interest rate derivative fair value loss - unrealized		-			(29	)		-			(133	)
		$	83,437		$	(8,951	)	$	59,464		$	12,388
Total gains (losses):
Commodity derivatives		$	80,096		$	(7,580	)	$	50,702		$	14,480
Interest rate derivatives			78			(1,003	)		(712	)		(3,058	)
		$	80,174		$	(8,583	)	$	49,990		$	11,422

Accumulated Other Comprehensive Loss

At September 30, 2011 and December 31, 2010, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of losses on ENP’s interest rate swaps of $0.3 million and $1.2 million, respectively. During the twelve months ending September 30, 2012, ENP expects to reclassify $0.3 million of losses associated with its interest rate swaps from accumulated other comprehensive loss to realized interest rate derivative fair value gain (loss). The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheets due to fluctuations in interest rates.

Tabular Disclosures of Fair Value Measurements

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following summarizes the fair value of derivatives outstanding on a gross basis as of the dates indicated (in thousands):

	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
		September 30, 2011		December 31, 2010			September 30, 2011		December 31, 2010
Derivatives not designated as hedges
Commodity derivative contracts	Derivatives - current	$	20,769	$	10,196	Derivatives - current	$	5,956	$	9,906
Interest rate swaps	Derivatives - current		-		-	Derivatives - current		66		-
Interest rate swaps	Derivatives - noncurrent		-		-	Derivatives - noncurrent		230		-
Commodity derivative contracts	Derivatives - noncurrent		22,162		5,486	Derivatives - noncurrent		6,289		25,105
Total derivatives not designated as hedges		$	42,931	$	15,682		$	12,541	$	35,011

Derivatives designated as hedges
Interest rate swaps	Derivatives - current	$	-	$	-	Derivatives - current	$	-	$	1,216
Interest rate swaps	Derivatives - noncurrent		-		-	Derivatives - noncurrent		-		226
Total derivatives designated as hedges		$	-	$	-		$	-	$	1,442
Total derivatives		$	42,931	$	15,682		$	12,541	$	36,453

The following tables summarize the effect of derivative instruments designated as hedges prior to January 1, 2011 on the accompanying Consolidated Statements of Operations for the periods indicated (in thousands):

	Amount of Gain (Loss) Recognized in					Amount of Gain (Loss) Recognized in
	Accumulated OCI (Effective Portion)					Accumulated OCI (Effective Portion)
	Three months ended September 30,					Nine months ended September 30,
Derivatives Designated as Hedges	2011		2010			2011		2010
Interest rate swaps	$	161	$	(401	)	$	873	$	(1,536	)

	Amount of Loss Recognized					Amount of Loss Recognized
	in Income as Ineffective					in Income as Ineffective
	Three months ended September 30,					Nine months ended September 30,
Location of Loss Recognized in Income as Ineffective	2011		2010			2011		2010
Derivative fair value loss	$	-	$	(29	)	$	-	$	(133	)

Fair Value Hierarchy

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

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

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

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

As required by FASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Our commodity derivative instruments consist of oil and natural gas swap contracts, put contracts, collars and swaptions. We estimate the fair values of the swaps and swaptions based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest rate swap market data. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows. We have classified the fair values of all of our derivative contracts as Level 2.

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, 2011:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
Description	Asset (Liability)			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts - swaps	$	16,323		$	-	$	16,323		$	-
Oil derivative contracts - floors and caps		3,365			-		3,365			-
Oil basis swap		(115	)		-		(115	)		-
Natural gas derivative contracts - swaps		9,546			-		9,546			-
Natural gas derivative contracts - floors and caps		1,701			-		1,701			-
Natural gas basis swap		(134	)		-		(134	)		-
Interest rate swaps		(296	)		-		(296	)		-
Total	$	30,390		$	-	$	30,390		$	-

The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the nine months ended September 30, 2011:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2011	$	(3,666	)	$	3,067		$	(599	)
Transfers out of level 3 *		3,666			(3,067	)		599
Balance at September 30, 2011	$	-		$	-		$	-

* Transferred from Level 3 to Level 2 due to a change in management's assessment of the valuation methodology and its placement within the fair value hierarchy levels. The company’s policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer. Management's change in policy occurred on January 1, 2011.

The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the nine months ended September 30, 2010:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2010	$	8,585		$	8,528		$	17,113
Total gains (losses):
Included in earnings		(4,996	)		(9,566	)		(14,562	)
Settlements		330			7,254			7,584
Balance at September 30, 2010	$	3,919		$	6,216		$	10,135
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	(4,996	)	$	(9,566	)	$	(14,562	)

Note 6. Asset Retirement Obligations

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the nine months ended September 30, 2011 (in thousands):

Future abandonment liability at January 1, 2011	$	13,838
Liabilities added during the current period		3,373
Accretion of discount		592
Retirements		(8	)
Total future abandonment costs at September 30, 2011		17,795
Less: current obligations		(1,010	)
Long-term future abandonment liability at September 30, 2011	$	16,785

As of September 30, 2011, $16.8 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $1.0 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheets. Approximately $5.3 million of the total future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant near Powell, Wyoming.

Note 7. Credit Agreement

ENP is a party to a five-year Credit Agreement dated March 7, 2007 (as amended, the “Credit Agreement”). The Credit Agreement matures on March 7, 2012; therefore, all outstanding borrowings under the Credit Agreement are reflected as a current liability at September 30, 2011. In July 2011, Vanguard began the syndication of a new credit facility that would retire all of the outstanding debt of ENP upon the consummation of the proposed merger with Vanguard. On September 30, 2011, Vanguard entered into a Third Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amends and restates its existing facility. The execution of the Amended Credit Agreement will only be effective upon the satisfaction of certain conditions including, but not limited to, the successful consummation of the previously announced merger between Vanguard and ENP. The Amended Credit Agreement provides for an initial borrowing base of $765 million and a maturity of October 31, 2016. Under the terms of the Amended Credit Agreement, Vanguard has agreed that a portion of the proceeds of the credit facility created by this Amended Credit Agreement be used to repay amounts outstanding under ENP’s Credit Agreement. In the event that the merger is not consummated, we will continue to evaluate our options which, based on discussions with lenders, include extending the term of the Credit Agreement or refinancing under a new revolving credit facility.

In December 2010, ENP amended the Credit Agreement to, among other things, amend the definition of “Change of Control” to eliminate references to the “Selling Parties” and include change of control covenants that require the acceleration of payments upon (1) the failure of Vanguard to continue to control the General Partner, (2) the acquisition by any person or group, directly or indirectly, of equity interests representing more than 35% of the total voting power in Vanguard, or (3) the occupation of a majority of the seats on the board of directors of Vanguard by persons who were neither (x) nominated by the board of directors of Vanguard nor (y) appointed by directors so nominated. This amendment also modifies the covenant governing transactions with affiliates to eliminate all references to the “Selling Parties” and instead reference transactions with Vanguard, VNG, and their subsidiaries.

The Credit Agreement provides for revolving credit loans to be made to ENP from time to time and letters of credit to be issued from time to time for the account of ENP or any of its restricted subsidiaries. The aggregate amount of the commitments of the lenders under the Credit Agreement is $475.0 million. Availability under the Credit Agreement is subject to a borrowing base of $400.0 million, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2011, there were $356.0 million of outstanding borrowings and $44.0 million of borrowing capacity under the Credit Agreement.

ENP incurs a quarterly commitment fee at a rate of 0.5 percent per year on the unused portion of the Credit Agreement.

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

Loans under the Credit Agreement are subject to varying rates of interest based on (1) amount outstanding in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans under the Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

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

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

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

The Credit Agreement contains several restrictive covenants including, among others, the following:

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

·	a prohibition against purchasing or redeeming partnership units, or prepaying indebtedness, subject to permitted exceptions;

·	a restriction on creating liens on ENP’s assets and its restricted subsidiaries, subject to permitted exceptions;

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

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

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

·	a requirement that ENP maintain a ratio of consolidated current assets to consolidated current liabilities, as defined in the Credit Agreement which excludes the current portion of long term debt, of not less than 1.0 to 1.0;

·	a requirement that ENP maintain a ratio of consolidated EBITDAX to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

·	a requirement that ENP maintain a ratio of consolidated funded debt to consolidated adjusted EBITDAX of not more than 3.5 to 1.0.

As of September 30, 2011, ENP was in compliance with all covenants under its Credit Agreement.

The Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within the applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the Credit Agreement to be immediately due and payable.

Note 8. Partners’ Equity and Distributions

Distributions

ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in ENP’s partnership agreement) to its unitholders. ENP’s available cash is its cash on hand at the end of a quarter after the payment of its expenses and the establishment of reserves for future capital expenditures and operational needs. Distributions are not cumulative. ENP distributes available cash to its unitholders in accordance with their ownership percentages.

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

		Cash Distribution
	Date	Declared per				Total
	Declared	Common Unit		Date Paid		Distribution
2011						(in thousands)
Quarter ended September 30	10/27/2011	$	0.4700	11/14/2011	(a)	$	21,615	(a)
Quarter ended June 30	7/26/2011	$	0.4700	8/12/2011		$	21,617
Quarter ended March 31	4/28/2011	$	0.4900	5/13/2011		$	22,537

2010
Quarter ended December 31	1/27/2011	$	0.5000	2/14/2011		$	22,992
Quarter ended September 30	10/28/2010	$	0.5000	11/12/2010		$	22,923
Quarter ended June 30	7/29/2010	$	0.5000	8/13/2010		$	22,923
Quarter ended March 31	4/30/2010	$	0.5000	5/14/2010		$	22,923

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

Note 9. Earnings Per Unit

ENP applies the provisions of the “Earnings Per Share” Topic 260 of the FASC, which requires earnings per unit to be calculated using the two-class method. Under the two-class method of calculating earnings per unit, earnings are allocated to participating securities as if all earnings for the period had been distributed. A participating security is any security that may participate in distributions with common units. For purposes of calculating earnings per unit, general partner units, unvested restricted units and unvested phantom units in 2010 are considered participating securities. Earnings per unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common units outstanding.

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2011			2010			2011			2010
	(in thousands, except per unit amounts)
Net income attributable to unitholders	$	96,449		$	2,441		$	103,217		$	46,318

Numerator:
Numerator for basic earnings per unit:
Net income attributable to unitholders	$	96,449		$	2,441		$	103,217		$	46,318
Less: distributions earned by participating securities		(237	)		(253	)		(737	)		(757	)
Plus: cash distributions in excess of (less than)
income allocated to the general partner		(821	)		231			(396	)		252
Net income allocated to limited partners	$	95,391		$	2,419		$	102,084		$	45,813

Denominator:
Denominator for basic earnings per unit:
Weighted average common units outstanding		45,487			45,342			45,481			45,328
Effect of dilutive phantom units		-			-			-			8
Denominator for diluted earnings per unit		45,487			45,342			45,481			45,336

Net income per common unit:
Basic	$	2.10		$	0.05		$	2.24		$	1.01
Diluted	$	2.10		$	0.05		$	2.24		$	1.01

Note 10. Unit-Based Compensation Plans

Long-Term Incentive Plan

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

The total number of common units reserved for issuance pursuant to the LTIP is 1,150,000. In January and February 2011, ENP issued 140,007 restricted units under the LTIP to Vanguard field employees performing services on ENP’s properties. These awards vest equally over a four-year period but have distribution equivalent rights that provide the employees with a bonus equal to the distribution on unvested units. The fair value of these units was approximately $3.1 million on the date of grant.

In February 2011, ENP issued 7,980 units under the LTIP to three members of the board of directors of the General Partner which will vest within one year, but have distribution equivalent rights that provide the board members with a bonus equal to the distribution on unvested units. The fair value of these units was approximately $0.2 million on the date of grant.

These common units and restricted units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under FASC Topic 718 . The fair value of restricted units issued is determined based on the fair market value of common units on the date of the grant. This value is amortized over the vesting period as referenced above. A summary of the status of the non-vested units as of September 30, 2011 is presented below:

	Number of Non-vested Units			Weighted Average Grant Date Fair Value
Non-vested units at January 1, 2011		—		$	—
Granted		147,987		$	22.25
Forfeited		(4,721	)	$	22.19
Vested		—		$	—
Non-vested units at September 30, 2011		143,266		$	22.26

As of September 30, 2011, there was approximately $2.5 million of unrecognized compensation cost related to non-vested restricted units, which is expected to be recognized over a period of 2.3 years. The accompanying Consolidated Statements of Operations reflects non-cash compensation of $0.2 million and $0.7 million in “General and administrative expense” for the three and nine months ended September 30, 2011, respectively. As of September 30, 2011, there were 927,013 common units available for issuance under the LTIP.

Phantom Units. As a result of the change of control of the General Partner in conjunction with the merger of EAC with and into Denbury on March 9, 2010, all 56,250 of ENP’s outstanding phantom units vested and were settled in an equal number of ENP’s common units. The acceleration of the phantom unit vesting resulted in the recognition of the remaining unrecognized unit-based compensation expense of approximately $0.7 million during the nine months ended September 30, 2010, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. The fair value of these phantom units was approximately $1.2 million on March 9, 2010. As of September 30, 2011, there were no outstanding phantom units.

Note 11. Comprehensive Income

The components of comprehensive income were as follows for the periods indicated:

	Three months ended				Nine months ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in thousands)
Net income	$	96,449	$	2,441	$	103,217	$	46,318
Change in deferred hedge loss on interest rate swaps		161		573		873		1,389
Comprehensive income	$	96,610	$	3,014	$	104,090	$	47,707

Note 12. Commitments and Contingencies

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

Additionally, the following pending litigation is outstanding related to the proposed merger with Vanguard. On March 29, 2011, John O’Neal, a purported unitholder of ENP, filed a putative class action petition in the 125th Judicial District of Harris County, Texas on behalf of unitholders of ENP. Similar petitions were filed on April 4, 2011 by Jerry P. Morgan and on April 5, 2011 by Herbert F. Rower in other Harris County district courts. The O’Neal , Morgan , and Rower lawsuits were consolidated on June 5, 2011 as John O’Neal v. Encore Energy Partners, L.P., et al. , Case Number 2011-19340, which is pending in the 125th Judicial District Court of Harris County. On July 28, 2011, Michael Gilas filed a class action petition in intervention. On July 26, 2011, the current plaintiffs in the consolidated O’Neal action filed an amended putative class action petition against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action petition and Gilas’s petition in intervention both allege that the named defendants are (i) violating duties owed to ENP’s public unitholders by, among other things, failing to properly value Encore and failing to protect against conflicts of interest or (ii) are aiding and abetting such breaches. Plaintiffs seek an injunction prohibiting the merger from going forward and compensatory damages if the merger is consummated. On October 3, 2011, the Court appointed Bull & Lifshitz, counsel for plaintiff-intervenor Gilas, as interim lead counsel on behalf of the putative class. On October 21, 2011, the court signed an order staying this lawsuit pending resolution of the Delaware State Court Action (defined below), subject to plaintiffs’ right to seek to lift the stay for good cause. The defendants named in the Texas lawsuits intend to defend vigorously against them.

On April 5, 2011, Stephen Bushansky, a purported unitholder of ENP, filed a putative class action complaint in the Delaware Court of Chancery on behalf of the unitholders of ENP. Another purported unitholder of ENP, William Allen, filed a similar action in the same court on April 14, 2011. The Bushansky and Allen actions have been consolidated under the caption In re: Encore Energy Partners LP Unitholder Litigation , C.A. No. 6347-VCP (the “Delaware State Court Action”). On August 12, 2011, those plaintiffs jointly filed an amended consolidated class action complaint naming as defendants Encore, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action complaint alleges, among other things, that defendants breached the partnership agreement by proposing a transaction that is not fair and reasonable and that the preliminary joint proxy statement/prospectus omitted material information. Plaintiffs seek an injunction prohibiting the proposed merger from going forward and compensatory damages if the proposed merger is consummated. In response, Vanguard has filed a motion to dismiss and it intends to defend vigorously against this lawsuit.

On August 28, 2011, Herman Goldstein, a purported unitholder of ENP, filed a putative class action complaint against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard in the United States District Court for the Southern District of Texas on behalf of the unitholders of ENP. That lawsuit is captioned Goldstein v. Encore Energy Partners LP. et al., United States District Court for the Southern District of Texas, 4:11-cv-03198. Goldstein alleges that the named defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder by disseminating a false and materially misleading proxy statement in connection with the merger. Plaintiff seeks an injunction prohibiting the proposed merger from going forward. The defendants named in this lawsuit intend to defend vigorously against it.

On September 6, 2011, Donald A. Hysong, a purported unitholder of ENP, filed a putative class action complaint against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard on behalf of the unitholders of ENP in the United States District Court for the District of Delaware that is captioned Hysong v. Encore Energy Partners LP. et al. , 1:11-cv-00781-SD. Hysong alleges that the named defendants violated either Section 14(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder or Section 20(a) of the Securities Exchange Act of 1934 by disseminating a false and materially misleading proxy statement in connection with the merger. Plaintiff seeks an injunction prohibiting the proposed merger from going forward. On September 14, 2011, in accordance with recent practice in Delaware, this case was assigned to Judge Stewart Dalzell of the Eastern District of Pennsylvania. On September 29, 2011, Plaintiff filed a motion seeking to preliminarily enjoin the merger. Pursuant to the Private Securities Litigation Reform Act, all discovery and proceedings have been stayed pending resolution of Defendants’ Motion to Dismiss or a showing by the plaintiff that he is entitled to have the stay lifted. The defendants named in this lawsuit intend to defend vigorously against it.

Vanguard and ENP cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of this filing, nor can Vanguard and ENP predict the amount of time and expense that will be required to resolve these lawsuits. Vanguard, ENP and the other defendants named in these lawsuits intend to defend vigorously against these and any other actions.

Additionally, ENP has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, the Credit Agreement, derivative contracts, operating leases, and development commitments. Please read “Capital Commitments, Capital Resources, and Liquidity – Capital commitments – Contractual obligations” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2010 Annual Report for ENP’s contractual obligations.

Note 13. Related Party Transactions

Administrative Services Agreement

ENP does not have any employees. The employees supporting the operations of ENP were: the employees of EAC prior to March 2010, the employees of Denbury from March 2010 to December 31, 2010, and the employees of VNG on and after December 31, 2010 in connection with the Vanguard Acquisition. During 2010, Encore Operating, L. P. (“Encore Operating”), a wholly-owned subsidiary of Denbury, provided administrative services for ENP, including accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provided all personnel, facilities, goods, and equipment necessary to perform these services which were not otherwise provided for by ENP. Encore Operating was not liable to ENP for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constituted gross negligence or willful misconduct. On December 31, 2010, Encore Operating’s duties under the administrative services agreement were assigned to VNG pursuant to the Vanguard Acquisition.

From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production, and from April 1, 2010 through March 31, 2011, the fee was increased to $2.06 per BOE. Effective April 1, 2011, the administrative fee decreased to $2.05 per BOE of ENP’s production. ENP also reimbursed Encore Operating for actual third-party expenses incurred on ENP’s behalf. In addition, Encore Operating was 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. Pursuant to the Vanguard Acquisition, VNG received the same fees and reimbursements for services performed during the first nine months of 2011 as previously received by Encore Operating.

The administrative fee will increase in the following circumstances:

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

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

·	otherwise as agreed upon by VNG and the General Partner, with the approval of the conflicts committee of the board of directors of the General Partner.

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

Administrative fees paid pursuant to the administrative services agreement are included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. The reimbursements of actual third-party expenses incurred on ENP’s behalf are also included in “General and administrative expenses” in the accompanying Consolidated Statements of Operations. The following table illustrates amounts paid by ENP pursuant to the administrative service agreement for the periods indicated:

	Three months ended				Nine months ended
	September 30,				September 30,
	2011		2010		2011		2010
	(in thousands)
Administrative fees	$	1,677	$	1,635	$	4,825	$	4,934
COPAS recovery		1,559		638		3,485		1,964
Third Party Expenses		1,996		1,212		5,293		4,527

As of September 30, 2011 and December 31, 2010, ENP had accounts payable to Vanguard of $1.5 million and $0.1 million, respectively, which is reflected as “Accounts payable – affiliate” in the accompanying Consolidated Balance Sheets.

Distributions

Each quarter, ENP pays cash distributions with respect to operations in the previous quarter on all of its outstanding units, including those common units held by the General Partner and its affiliates, and pays cash distributions to the General Partner based upon its general partner interest. On August 12, 2011, ENP paid cash distributions of $21.6 million, of which $10.1 million was paid to the General Partner and its affiliates. On May 13, 2011, ENP paid cash distributions of approximately $22.5 million, of which $10.5 million was paid to the General Partner and its affiliates. On February 14, 2011, ENP paid cash distributions of approximately $23.0 million, of which $10.7 million was paid to the General Partner and its affiliates. On each of August 13, 2010 and May 14, 2010, ENP paid cash distributions of approximately $22.9 million, of which $10.7 million was paid to the General Partner and its affiliates. On February 12, 2010, ENP paid cash distributions of approximately $24.6 million, of which $11.5 million was paid to the General Partner and its affiliates.

Note 14. Subsequent Events

On October 27, 2011, the board of directors of the General Partner declared an ENP cash distribution for the third quarter of 2011 to unitholders of record as of the close of business on November 7, 2011 of $0.47 per unit or approximately $21.6 million, of which $10.1 million is expected to be paid to the General Partner and its affiliates. The distribution is expected to be paid to unitholders on or about November 14, 2011.

On October 31, 2011, the SEC declared the Form S-4 effective, and on November 1, 2011, Vanguard and ENP announced that both companies have established a record date and a meeting date for the special meetings of unitholders to consider and vote upon the previously-announced merger agreement.

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)

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

The following discussion and analysis contains forward-looking statements, which give our current expectations or forecasts of future events. Actual results could differ materially from those discussed in these forward-looking statements due to many factors, including, but not limited to, those set forth under “Item 1A. Risk Factors” and elsewhere in our 2010 Annual Report on Form 10-K. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto included in “Item 1. Financial Statements” of this Report.

Introduction

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

· Recent Developments

· Acquisitions

· Overview of Business

· Third Quarter 2011 Highlights

· Results of Operations

o	Comparison of Three Months Ended September 30, 2011 to Three Months Ended September 30, 2010

o	Comparison of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2010

· Capital Commitments, Capital Resources, and Liquidity

· Non-GAAP Financial Measure

· Critical Accounting Policies and Estimates

Recent Developments

On July 11, 2011, Vanguard and ENP announced the execution of a definitive agreement that would result in a merger whereby ENP would become a wholly-owned subsidiary of VNG, through a unit-for-unit exchange. Under the terms of the definitive agreement, ENP’s public unitholders would receive 0.75 Vanguard common units in exchange for each ENP common unit they own at closing. The transaction will result in approximately 18.4 million additional common units being issued by Vanguard. The terms of the definitive agreement were unanimously approved by the members of the ENP Conflicts Committee, who negotiated the terms on behalf of ENP and is comprised solely of independent directors. In addition, Jefferies & Company, Inc., has issued a fairness opinion to the ENP Conflicts Committee stating that they believe the exchange ratio is fair, from a financial point of view, to the unaffiliated unitholders of ENP.

The completion of the merger is subject to approval by a majority of the outstanding ENP common units and also subject to the approval of the issuance of additional Vanguard common units in connection with the merger by the affirmative vote of a majority of the votes cast by Vanguard unitholders. Completion of the merger, assuming the requisite unitholder votes are obtained and subject to other customary terms and conditions, is expected to occur on November 30, 2011. On August 2, 2011, ENP and Vanguard filed a Registration Statement on Form S-4 (the “Form S-4”) with the SEC, which was declared effective on October 31, 2011. The Form S-4 incorporates a joint proxy statement/prospectus which ENP and Vanguard mailed to their respective unitholders in connection with obtaining unitholder approval of the proposed merger. On November 1, 2011, Vanguard and ENP announced that both companies have established a record date and a meeting date for the special meetings of unitholders to consider and vote upon the previously-announced merger agreement. Pending completion of the merger, ENP has agreed to customary restrictions in the way it conducts its business.

On September 30, 2011, Vanguard entered into a Third Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amends and restates its existing facility. The execution of the Amended Credit Agreement will only be effective upon the satisfaction of certain conditions including, but not limited to, the successful consummation of the previously announced merger between Vanguard and ENP. The Amended Credit Agreement provides for an initial borrowing base of $765 million and a maturity of October 31, 2016. Under the terms of the Amended Credit Agreement, Vanguard has agreed that a portion of the proceeds of the credit facility created by the Amended Credit Agreement be used to repay amounts outstanding under ENP’s Credit Agreement.

Acquisitions

On June 22, 2011, pursuant to two Purchase and Sale Agreements, ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. We refer to this acquisition as the “Permian Basin Acquisition I.” ENP and Vanguard agreed to purchase 50% of the Purchased Assets for an aggregate of $85.0 million and each paid the seller a non-refundable deposit of $4.25 million. The effective date of this acquisition is May 1, 2011. We completed this acquisition on July 29, 2011 for an adjusted purchase price of $40.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 2.64 MMBOE, of which approximately 70% are oil and NGLs reserves and are 100% proved developed.

On August 8, 2011, we entered into assignment agreements and completed the acquisition of certain oil and natural gas properties located in the Permian Basin of West Texas from a private seller. We refer to this acquisition as the “Permian Basin Acquisition II.” The adjusted purchase price for the assets was $14.8 million with an effective date of May 1, 2011. This acquisition was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 1.02 MMBOE, of which approximately 87% are oil and are 50% proved developed.

On August 15, 2011, we entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Wyoming. We refer to this acquisition as the “Wyoming Acquisition.” The purchase price for the assets was $28.5 million with an effective date of June 1, 2011. We completed this acquisition on September 1, 2011 for an adjusted purchase price of $27.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 3.91 MMBOE, of which approximately 65% are natural gas reserves and are 100% proved developed producing.

On August 31, 2011, we entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the Texas and Louisiana Gulf Coast area from a private seller. We refer to this acquisition as the “Gulf Coast Acquisition.” The adjusted purchase price for the assets was $47.6 million with an effective date of August 1, 2011. This acquisition was funded with borrowings under our Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 2.13 MMBOE, of which approximately 83% are oil and NGLs reserves and are 100% proved developed.

Overview of Business

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

Third Quarter 2011 Highlights

Our financial and operating results for the third quarter of 2011 included the following:

Our average realized oil price increased 15 percent to $75.95 per Bbl after consideration of a negative 15 percent ($13.64 per Bbl) oil differential to NYMEX as compared to $66.20 per Bbl and a negative 13 percent ($9.90 per Bbl) oil differential to NYMEX in the third quarter of 2010. Our average realized natural gas price was $5.66 per Mcf for the third quarter 2011 as compared to $4.48 per Mcf in the third quarter of 2010.

·	Our oil, natural gas and NGLs revenues increased 20 percent to $51.2 million as compared to $42.8 million in the third quarter of 2010. Oil represented approximately 62 percent and 64 percent of our total production in the third quarter of 2011 and 2010, respectively.

·	Average daily production volumes increased four percent on a BOE basis from 8,630 BOE/D during the third quarter of 2010 to 8,991 BOE/D during the third quarter of 2011.

Our combined production margin increased 22 percent to $35.1 million as compared to $28.8 million in the third quarter of 2010. Total oil and natural gas wellhead revenues per BOE increased by 15 percent while total production expenses per BOE increased by 10 percent. On a per BOE basis, our production margin increased 17 percent to $42.42 per BOE as compared to $36.23 per BOE for the third quarter of 2010.

·	We invested $7.1 million in development and exploitation activities during the third quarter of 2011.

·	We completed four acquisitions of oil and natural gas properties during the third quarter of 2011.

Our net income was $96.4 million ($2.10 per common unit) as compared to a net income of $2.4 million ($0.05 per common unit) for the third quarter of 2010 primarily due to a $8.4 million increase in our oil, natural gas and NGLs revenues and a $91.8 million increase in mark-to-market gains on our commodity derivatives contracts.

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

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)

Results of Operations

Comparison of Three Months Ended September 30, 2011 to Three Months Ended September 30, 2010

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

	Three months ended September 30,						Increase / (Decrease)
	2011			2010			$			%
Revenues (in thousands):
Oil	$	38,814		$	33,765		$	5,049		15	%
Natural gas		8,811			6,497			2,314		36	%
Natural gas liquids		3,554			2,521			1,033		41	%
Total oil, natural gas and natural gas liquids revenues		51,179			42,783			8,396		20	%
Marketing		126			60			66		110	%
Commodity derivatve fair value gain (loss) - realized		(2,818	)		1,342			(4,160	)	-310	%
Commodity derivatve fair value gain (loss) - unrealized		82,914			(8,922	)		91,836		-1029	%
Total revenues	$	131,401		$	35,263		$	96,138		273	%

Average realized prices:
Oil ($/Bbl)	$	75.95		$	66.20		$	9.75		15	%
Natural gas ($/Mcf)	$	5.66		$	4.48		$	1.18		26	%
Natural gas liquids ($/Bbl)	$	62.59		$	59.54		$	3.05		5	%
Combined ($/BOE)	$	61.87		$	53.89		$	7.98		15	%

Total production volumes:
Oil (MBbls)		511			510			1		0	%
Natural gas (MMcf)		1,556			1,449			107		7	%
Natural gas liquids (MBbls)		57			42			15		36	%
Combined (MBOE)		827			794			33		4	%

Average daily production volumes:
Oil (Bbls/D)		5,555			5,544			11		0	%
Natural gas (Mcf/D)		16,912			15,755			1,157		7	%
Natural gas liquids (Bbls/D)		617			460			157		34	%
Combined (BOE/D)		8,991			8,630			361		4	%

Average NYMEX prices:
Oil (per Bbl)	$	89.59		$	76.10		$	13.49		18	%
Natural gas (per Mcf)	$	4.17		$	4.24		$	(0.07	)	-2	%

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

	Three months ended September 30,
	2011			2010
Average realized oil price ($/Bbl)	$	75.95		$	66.20
Average NYMEX ($/Bbl)	$	89.59		$	76.10
Differential to NYMEX	$	(13.64	)	$	(9.90	)
Average realized oil price to NYMEX percentage		85	%		87	%


Average realized natural gas price ($/Mcf)	$	5.66		$	4.48
Average NYMEX ($/Mcf)	$	4.17		$	4.24
Differential to NYMEX	$	1.49		$	0.24
Average realized natural gas price to NYMEX percentage		136	%		106	%

Our average realized oil price as a percentage of the average NYMEX price was 85 percent in the third quarter of 2011 as compared to 87 percent in the third quarter of 2010. Our average realized natural gas price as a percentage of the average NYMEX price was 136 percent in the third quarter of 2011 as compared to 106 percent in the third quarter of 2010. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas as production.

Oil revenues increased 15 percent from $33.8 million in the third quarter of 2010 to $38.8 million in the third quarter of 2011 as a result of a $9.75 per Bbl increase in our average realized oil price. Our higher average realized oil price increased oil revenues by approximately $5.0 million and was primarily due to a higher average NYMEX price, which increased from $76.10 per Bbl in the third quarter of 2010 to $89.59 per Bbl in the third quarter of 2011. However, we did not reap the entire benefit of the 18 percent increase in the NYMEX oil price due to significant widening of the basis differential received on our oil. Our negative differential to NYMEX oil pricing increased from $9.90 in third quarter of 2010 to $13.64 in the third quarter of 2011 primarily as a result of the closure of Exxon's pipelines in Wyoming due to leaks which affected production from our Elk Basin field where we had to settle for a lower price per barrel of oil produced during the closure.

Natural gas revenues increased 36 percent from $6.5 million in the third quarter of 2010 to $8.8 million in the third quarter of 2011 as a result of a $1.18 per Mcf increase in our average realized natural gas price and a 107 MMcf increase in our natural gas production volumes. Our higher average realized natural gas price increased natural gas revenues by approximately $1.7 million and our higher natural gas production volumes increased natural gas revenues by approximately $0.6 million and were primarily due to production from the acquisitions of oil and natural gas properties in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast.

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)

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

	Three months ended September 30,						Increase / (Decrease)
	2011			2010			$			%
Expenses (in thousands):
Production:
Lease operating	$	10,451		$	9,268		$	1,183		13	%
Production and other taxes		5,647			4,752			895		19	%
Total production expenses		16,098			14,020			2,078		15	%
Other:
Depletion, depreciation, and amortization		12,500			12,782			(282	)	-2	%
Exploration		-			53			(53	)	-100	%
General and administrative		4,451			2,817			1,634		58	%
Total operating expenses		33,049			29,672			3,377		11	%
Interest		2,646			2,303			343		15	%
Interest rate derivative fair value loss - realized		445			974			(529	)	-54	%
Interest rate derivative fair value (gain) loss - unrealized		(523	)		29			(552	)	-1903	%
Gain on acquisition of oil and natural gas properties		(815	)		-			(815	)	-
Other		(70	)		(9	)		(61	)	678	%
Income tax provision (benefit)		220			(147	)		367		-250	%
Total expenses	$	34,952		$	32,822		$	2,130		6	%

Expenses (per BOE):
Production:
Lease operating	$	12.63		$	11.67		$	0.96		8	%
Production and other taxes		6.83			5.99			0.84		14	%
Total production expenses		19.46			17.66			1.80		10	%
Other:
Depletion, depreciation, and amortization		15.11			16.10			(0.99	)	-6	%
Exploration		-			0.07			(0.07	)	-100	%
General and administrative		5.38			3.55			1.83		52	%
Total operating expenses		39.95			37.38			2.57		7	%
Interest		3.20			2.90			0.30		10	%
Interest rate derivative fair value loss - realized		0.54			1.23			(0.69	)	-56	%
Interest rate derivative fair value (gain) loss - unrealized		(0.63	)		0.04			(0.67	)	-1675	%
Gain on acquisition of oil and natural gas properties		(0.99	)		-			(0.99	)	-
Other		(0.08	)		(0.01	)		(0.07	)	700	%
Income tax provision (benefit)		0.27			(0.19	)		0.46		-242	%
Total expenses	$	42.26		$	41.35		$	0.91		2	%

Production expenses. Production expenses attributable to LOE increased from $9.3 million in the third quarter of 2010 to $10.5 million in the third quarter of 2011 primarily due to costs associated with the acquisitions of oil and natural gas properties in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast as well as workover and maintenance work on properties located in West Texas.

Production expenses attributable to production and other taxes increased from $4.8 million in the third quarter of 2010 to $5.6 million in the third quarter of 2011 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production, severance, and ad valorem taxes slightly decreased from 11.1 percent in the third quarter of 2010 to 11.0 percent in the third quarter of 2011.

Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense decreased $0.3 million from $12.8 million in the third quarter of 2010 to $12.5 million in the third quarter of 2011 primarily due to higher proved reserves in the third quarter of 2011 as compared to the same period in 2010, resulting from the acquisitions of oil and natural gas properties in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast.

General and administrative (“G&A”) expense. G&A expense increased $1.6 million to $4.5 million in the third quarter of 2011 as compared to $2.8 million in the third quarter of 2010. Higher corporate costs related to the merger and higher rent, compensation related expenses and insurance expenses in the third quarter of 2011 were offset by lower professional fees when compared to the third quarter of 2010. Professional fees incurred in the third quarter 2010 included acquisition and divestiture costs related to the acquisition of properties from Encore Operating.

Interest expense. Interest expense increased from $2.3 million in the third quarter of 2010 to $2.6 million in the third quarter of 2011 primarily due to higher weighted average outstanding borrowings under our Credit Agreement.

Interest rate derivative fair value gain (loss). Please read Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our derivative contracts.

Comparison of Nine Months Ended September 30, 2011 to Nine Months Ended September 30, 2010

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

	Nine months ended September 30,					Increase / (Decrease)
	2011			2010		$			%
Revenues (in thousands):
Oil	$	122,869		$	105,732	$	17,137		16	%
Natural gas		20,872			21,407		(535	)	-2	%
Natural gas liquids		8,978			9,001		(23	)	0	%
Total oil, natural gas and natural gas liquids revenues		152,719			136,140		16,579		12	%
Marketing		207			207		-		0	%
Commodity derivatve fair value gain (loss) - realized		(7,616	)		1,959		(9,575	)	-489	%
Commodity derivatve fair value gain (loss) - unrealized		58,318			12,521		45,797		366	%
Total revenues	$	203,628		$	150,827	$	52,801		35	%

Average realized prices:
Oil ($/Bbl)	$	82.11		$	69.63	$	12.48		18	%
Natural gas ($/Mcf)	$	4.75		$	4.84	$	(0.09	)	-2	%
Natural gas liquids ($/Bbl)	$	65.67		$	57.68	$	7.99		14	%
Combined ($/BOE)	$	64.56		$	56.45	$	8.11		14	%

Total production volumes:
Oil (MBbls)		1,496			1,519		(23	)	-2	%
Natural gas (MMcf)		4,394			4,421		(27	)	-1	%
Natural gas liquids (MBbls)		137			156		(19	)	-12	%
Combined (MBOE)		2,365			2,411		(46	)	-2	%

Average daily production volumes:
Oil (Bbls/D)		5,481			5,563		(82	)	-1	%
Natural gas (Mcf/D)		16,094			16,196		(102	)	-1	%
Natural gas liquids (Bbls/D)		501			571		(70	)	-12	%
Combined (BOE/D)		8,665			8,833		(168	)	-2	%

Average NYMEX prices:
Oil (per Bbl)	$	95.31		$	77.60	$	17.71		23	%
Natural gas (per Mcf)	$	4.19		$	4.54	$	(0.35	)	-8	%

	Nine months ended September 30,
	2011			2010
Average realized oil price ($/Bbl)	$	82.11		$	69.63
Average NYMEX ($/Bbl)	$	95.31		$	77.60
Differential to NYMEX	$	(13.20	)	$	(7.97	)
Average realized oil price to NYMEX percentage		86	%		90	%


Average realized natural gas price ($/Mcf)	$	4.75		$	4.84
Average NYMEX ($/Mcf)	$	4.19		$	4.54
Differential to NYMEX	$	0.56		$	0.30
Average realized natural gas price to NYMEX percentage		113	%		107	%

Our average realized oil price as a percentage of the average NYMEX price was 86 percent in the first nine months of 2011 as compared to 90 percent in the nine months of 2010. Our average realized natural gas price as a percentage of the average NYMEX price was 113 percent in the first nine months of 2011 as compared to 107 percent in the first nine months of 2010. Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas as production.

Oil revenues increased 16 percent from $105.7 million in the first nine months of 2010 to $122.9 million in the first nine months of 2011 as a result of a $12.48 per Bbl increase in our average realized oil price partially offset by a 23 MBbls decrease in our oil production volumes. Our higher average realized oil price increased oil revenues by approximately $19.0 million and was primarily due to a higher average NYMEX price, which increased from $77.60 per Bbl in the first nine months of 2010 to $95.31 per Bbl in the first nine months of 2011. However, we did not reap the entire benefit of the 23 percent increase in the NYMEX oil price due to significant widening of the basis differential received on our oil. Our negative differential to NYMEX oil pricing increased from $7.97 in first nine months of 2010 to $13.20 in the first nine months of 2011 primarily as a result of the closure of Exxon's pipelines in Wyoming due to leaks which affected production from our Elk Basin field where we had to settle for a lower price per barrel of oil produced during the closure. Our lower oil production volumes decreased oil revenues by approximately $1.9 million and were primarily due to some weather related production outages in the Big Horn Basin and Williston areas during the first half of 2011.

Natural gas revenues decreased 2 percent from $21.4 million in the first nine months of 2010 to $20.9 million in the first nine months of 2011 as a result of a $0.09 per Mcf decrease in our average realized natural gas price and a 27 MMcf decrease in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $0.4 million and was primarily due to a lower average NYMEX price, which decreased from $4.54 per Mcf in the first nine months of 2010 to $4.19 per Mcf in the first nine months of 2011. Our lower natural gas production volumes were primarily due to natural production declines in our Permian Basin area and some weather related production outages in the Big Horn Basin during the first half of 2011.

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)

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

	Nine months ended September 30,						Increase / (Decrease)
	2011			2010			$			%
Expenses (in thousands):
Production:
Lease operating	$	29,198		$	30,907		$	(1,709	)	-6	%
Production and other taxes		15,672			14,951			721		5	%
Total production expenses		44,870			45,858			(988	)	-2	%
Other:
Depletion, depreciation, and amortization		35,568			38,472			(2,904	)	-8	%
Exploration		-			129			(129	)	-100	%
General and administrative		12,710			10,088			2,622		26	%
Total operating expenses		93,148			94,547			(1,399	)	-1	%
Interest		7,030			6,987			43		1	%
Interest rate derivative fair value loss - realized		1,858			2,925			(1,067	)	-36	%
Interest rate derivative fair value (gain) loss - unrealized		(1,146	)		133			(1,279	)	-962	%
Gain on acquisition of oil and natural gas properties		(815	)		-			(815	)	-
Other		(79	)		(47	)		(32	)	68	%
Income tax provision (benefit)		415			(36	)		451		-1253	%
Total expenses	$	100,411		$	104,509		$	(4,098	)	-4	%

Expenses (per BOE):
Production:
Lease operating	$	12.34		$	12.82		$	(0.48	)	-4	%
Production and other taxes		6.63			6.20			0.43		7	%
Total production expenses		18.97			19.02			(0.05	)	0	%
Other:
Depletion, depreciation, and amortization		15.04			15.95			(0.91	)	-6	%
Exploration		-			0.05			(0.05	)	-100	%
General and administrative		5.37			4.18			1.19		28	%
Total operating expenses		39.38			39.20			0.18		0	%
Interest		2.97			2.90			0.07		2	%
Interest rate derivative fair value loss - realized		0.79			1.21			(0.42	)	-35	%
Interest rate derivative fair value gain (loss) - unrealized		(0.48	)		0.06			(0.54	)	-900	%
Gain on acquisition of oil and natural gas properties		(0.34	)		-			(0.34	)	-
Other		(0.03	)		(0.02	)		(0.01	)	50	%
Income tax provision (benefit)		0.18			(0.01	)		0.19		-1900	%
Total expenses	$	42.47		$	43.34		$	(0.87	)	-2	%

Production expenses. Production expenses attributable to LOE decreased $1.7 million from $30.9 million in the first nine months of 2010 to $29.2 million in the first nine months of 2011 primarily due to lower than anticipated costs for work in progress at year end, resulting in a $1.6 million offset to current year activity. Current year LOE excluding this offset was $30.8 million, which was consistent with management’s expectations. This amount was still lower than the prior year period due to workover costs in the Big Horn Basin in the first quarter of 2010 as well as bonus and non-cash stock compensation costs associated with the field employees in the first quarter of 2010 that were not incurred for the same period in 2011.

Production expense attributable to production and other taxes increased from $15.0 million in the first nine months of 2010 to $15.7 million in the first nine months of 2011 primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. As a percentage of wellhead revenues, production, severance, and ad valorem taxes decreased from 11.0 percent in the first nine months of 2010 to 10.3 percent in the first nine months of 2011.

Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense decreased $2.9 million from $38.5 million in the first nine months of 2010 to $35.6 million in the first nine months of 2011 primarily due to higher proved reserves in the third quarter of 2011 as compared to the same period in 2010, resulting from the acquisitions of oil and natural gas properties in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast.

General and administrative (“G&A”) expense. G&A expense increased $2.6 million from $10.1 million in the first nine months of 2010 to $12.7 million in the first nine months of 2011. Higher corporate costs related to the proposed merger with Vanguard and higher rent, compensation related expenses and insurance expenses in the first nine months of 2011 were offset by lower professional fees and non-cash compensation related expenses when compared to the first nine months of 2010. A $1.0 million non-refundable retainer fee was paid to an investment bank in the first nine months of 2010 related to the acquisition of properties from Encore Operating and the acceleration of phantom unit vesting in conjunction with the merger of EAC with and into Denbury resulted in the recognition of unit-based compensation expense of approximately $0.7 million of during the nine months ended September 30, 2010.

Interest expense. Interest expense remained constant at $7.0 million during the first nine months of 2011 and 2010 as higher weighted average outstanding borrowings under our Credit Agreement were offset by lower weighted average interest rates during the first nine months of 2011 as compared to the same period in 2010.

Capital Commitments, Capital Resources, and Liquidity

Capital commitments

Our primary uses of cash are:

·	Distributions to unitholders;

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

·	Funding of working capital; and

·	Contractual obligations.

Distributions to unitholders. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement). Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs.

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

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

		Cash Distribution
	Date	Declared per				Total
	Declared	Common Unit		Date Paid		Distribution
2011						(in thousands)
Quarter ended September 30	10/27/2011	$	0.4700	11/14/2011	(a)	$	21,615	(a)
Quarter ended June 30	7/26/2011	$	0.4700	8/12/2011		$	21,617
Quarter ended March 31	4/28/2011	$	0.4900	5/13/2011		$	22,537

2010
Quarter ended December 31	1/27/2011	$	0.5000	2/14/2011		$	22,992
Quarter ended September 30	10/28/2010	$	0.5000	11/12/2010		$	22,923
Quarter ended June 30	7/29/2010	$	0.5000	8/13/2010		$	22,923
Quarter ended March 31	4/30/2010	$	0.5000	5/14/2010		$	22,923

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

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

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
	(in thousands)
Development and exploitation	$	7,139	$	1,996	$	9,852	$	4,236
Exploration		-		105		-		171
Total	$	7,139	$	2,101	$	9,852	$	4,407

Our development and exploitation expenditures primarily relate to drilling development and infill wells, workovers of existing wells, and field related facilities. Under Vanguard, our development capital has increased during 2011 in an attempt to reduce the impact of declines in our production as seen in 2010. Our capital budget for the remainder of 2011 is expected to be between $3.5 million and $4.3 million, dependent on our maintenance capital requirements and excluding proved property acquisitions. This expected increase in capital expenditures will reduce the amount of cash available for distribution in the near-term and may require a further reduction of the quarterly cash distribution to unitholders in the near-term.

Funding of working capital. Through the next twelve months, we expect our operating cash flows will be sufficient to fund our working capital and capital expenditures. We anticipate cash reserves to be close to zero because we intend to distribute available cash to unitholders and reduce outstanding borrowings and related interest expense under our Credit Agreement. However, through March 7, 2012, we have availability under our Credit Agreement to fund our obligations as they become due. Our production volumes, commodity prices, differentials for oil and natural gas and interest rates will be the largest variables affecting our working capital.

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

Contractual obligations. We have contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, the Credit Agreement, derivative contracts, operating leases, and development commitments. Neither the amounts nor the terms of any other commitments or contingent obligations have changed significantly from the year-end amounts reflected in our 2010 Annual Report. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Please read “Capital Commitments, Capital Resources, and Liquidity – Capital commitments – Contractual obligations” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2010 Annual Report for additional information regarding our commitments and obligations.

Other contingencies and commitments . Historically, Encore Operating provided administrative services for us, including accounting, corporate development, finance, land, legal, and engineering, pursuant to an administrative services agreement. In addition, Encore Operating provided all personnel and any facilities, goods, and equipment necessary to perform these services and not otherwise provided by us. Encore Operating was not liable to us for its performance of, or failure to perform, services under the administrative services agreement unless its acts or omissions constituted gross negligence or willful misconduct. On December 31, 2010, Encore Operating’s duties under the administrative services agreement were assigned to VNG pursuant to the Vanguard Acquisition.

The administrative fee was $2.02 per BOE of our production for such services from April 1, 2009 to March 31, 2010 and $2.06 per BOE from April 1, 2010 through March 31, 2011. Effective April 1, 2011 the administrative fee decreased to $2.05 per BOE of our production as a result of the COPAS Wage Index Adjustment. We also reimbursed Encore Operating for actual third-party expenses incurred on our behalf. In addition, Encore Operating was 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. Pursuant to the Vanguard Acquisition, VNG received the same fees and reimbursements for services performed during the first nine months of 2011 as previously received by Encore Operating.

The administrative fee will increase in the following circumstances:

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

if we acquire any additional assets, VNG may propose an increase in its administrative fee that covers the provision of services for such additional assets; however, such proposal must be approved by the board of directors of the General Partner upon the recommendation of its conflicts committee; and

·	otherwise as agreed upon by VNG and the General Partner, with the approval of the conflicts committee of the board of directors of the General Partner.

Capital resources

Cash flows from operating activities . Cash provided by operating activities decreased $12.5 million from $98.4 million during the first nine months of 2010 to $85.9 million during the first nine months of 2011, primarily due to decreased settlements received on our commodity derivative contracts of $8.8 million as a result of higher commodity prices during 2011 and a decrease in the level of cash provided by accounts receivable, primarily from the timing effect of cash collections, partially offset by an increase in our production margin.

Cash flows from investing activities . Cash used in investing activities increased $137.3 million from $4.2 million during the first nine months of 2010 to $141.5 million during the first nine months of 2011. The increase was primarily due to $130.9 million in amounts paid for the acquisitions of oil and natural gas properties in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast during the first nine months of 2011 and an increase of $6.0 million in amounts paid for the development of oil and natural gas properties during the first nine months of 2011 as compared to the same period in 2010.

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

During the first nine months of 2011, net cash of $54.9 million was provided by financing activities, including $122.0 million in net borrowings under our Credit Agreement, offset by $67.1 million in distributions to unitholders. Proceeds from borrowings increased the outstanding borrowings under our Credit Agreement from $234.0 million at December 31, 2010 to $356.0 million at September 30, 2011 and were used to fund the acquisitions of oil and natural gas properties in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast.

During the first nine months of 2010, we used net cash of $85.7 million in financing activities, including $70.5 million in distributions to unitholders and net repayments of $15.0 million under our Credit Agreement. Net repayments decreased the outstanding borrowings in the Credit Agreement from $255.0 million at December 31, 2009 to $240.0 million at September 30, 2010.

Liquidity

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

Our capital budget for the remainder of 2011 is expected to be between $3.5 million and $4.3 million, dependent on our maintenance capital requirements and excluding proved property acquisitions. The level of these and other future expenditures are largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects, and market conditions. We plan to finance our ongoing normal expenditures using internally generated cash flow and availability under our Credit Agreement.

Internally generated cash flows. Our internally generated cash flows, results of operations, and financing for our operations are largely dependent on oil and natural gas prices. During the first nine months of 2011, our average realized oil prices increased by 18 percent and our natural gas prices decreased by 2 percent, as compared to our average realized prices for each in the first nine months of 2010. Realized oil and natural gas prices fluctuate widely in response to changing market forces. If oil and natural gas prices decline or we experience a significant widening of our differentials, then our earnings, cash flows from operations, borrowing base under our Credit Agreement, and ability to pay distributions may be adversely impacted. Prolonged periods of lower oil and natural gas prices or sustained wider differentials could cause us to not be in compliance with financial covenants under our Credit Agreement and thereby affect our liquidity. However, we have protected approximately 60 percent of our forecasted oil and natural gas production through 2014 against declining commodity prices to certain levels using commodity derivative contracts. On the other hand, if there is an increase in commodity prices above the ceiling prices in our commodity derivative contracts, those contracts would prevent us from realizing the benefits of those price increases. Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Sensitivity” and Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our commodity derivative contracts.

Credit Agreement. We entered into a five-year credit agreement dated March 7, 2007 (as amended, the “Credit Agreement”). The syndicate of lenders underwriting our Credit Agreement includes 15 banking and other financial institutions. None of the lenders are underwriting more than eight percent of the total commitment. We believe the number of lenders and the small percentage participation of each, provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

Certain of the lenders underwriting our Credit Agreement are also counterparties to our derivative contracts. Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion.

The Credit Agreement matures on March 7, 2012; therefore, all outstanding borrowings under the Credit Agreement are reflected as a current liability at September 30, 2011. In July 2011, Vanguard began the syndication of a new credit facility that would retire all of the outstanding debt of ENP upon the consummation of the proposed merger with Vanguard. On September 30, 2011, Vanguard entered into a Third Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amends and restates its existing facility. The execution of the Amended Credit Agreement will only be effective upon the satisfaction of certain conditions including, but not limited to, the successful consummation of the previously announced merger between Vanguard and ENP. The Amended Credit Agreement provides for an initial borrowing base of $765 million and a maturity of October 31, 2016. Under the terms of the Amended Credit Agreement, Vanguard has agreed that a portion of the proceeds of the credit facility created by this Amended Credit Agreement be used to repay amounts outstanding under ENP’s Credit Agreement. In the event that the merger is not consummated, we will continue to evaluate our options which, based on discussions with lenders, include extending the term of the Credit Agreement or refinancing under a new revolving credit facility.

In December 2010, we amended the Credit Agreement to, among other things, amend the definition of “Change of Control” to eliminate references to the “Selling Parties” and include change of control covenants that require the acceleration of payments upon (1) the failure of Vanguard to continue to control the General Partner, (2) the acquisition by any person or group, directly or indirectly, of equity interests representing more than 35% of the total voting power in Vanguard, or (3) the occupation of a majority of the seats on the board of directors of Vanguard by persons who were neither (x) nominated by the board of directors of Vanguard nor (y) appointed by directors so nominated. This amendment also modifies the covenant governing transactions with affiliates to eliminate all references to the “Selling Parties” and instead reference transactions with Vanguard, VNG, and their subsidiaries.

The Credit Agreement provides for revolving credit loans to be made to us from time to time and letters of credit to be issued from time to time for our account or any of our restricted subsidiaries. The aggregate amount of the commitments of the lenders under the Credit Agreement is $475.0 million. Availability under the Credit Agreement was subject to a borrowing base of $400.0 million, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2011, there were $356.0 million of outstanding borrowings and $44.0 million of borrowing capacity under the Credit Agreement. On November 7, 2011, there were $346.0 million of outstanding borrowings and $54.0 million of borrowing capacity under the Credit Agreement.

We incur a quarterly commitment fee at a rate of 0.5 percent per year on the unused portion of the Credit Agreement. Obligations under the Credit Agreement are secured by a first-priority security interest in substantially all of our proved oil and natural gas reserves and in the equity interests of or restricted subsidiaries. In addition, obligations under the Credit Agreement are guaranteed by us and our restricted subsidiaries. Obligations under the Credit Agreement are non-recourse to Vanguard.

Loans under the Credit Agreement are subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans bear interest at the base rate plus the applicable margin indicated in the following table:

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

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

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

The Credit Agreement contains several restrictive covenants including, among others, the following:

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

·	a prohibition against purchasing or redeeming partnership units, or prepaying indebtedness, subject to permitted exceptions;

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

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

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

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

·	a requirement that we maintain a ratio of consolidated current assets to consolidated current liabilities, as defined in the Credit Agreement which excludes the current portion of long term debt, of not less than 1.0 to 1.0;

·	a requirement that we maintain a ratio of consolidated EBITDAX to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

·	a requirement that we maintain a ratio of consolidated funded debt to consolidated adjusted EBITDAX of not more than 3.5 to 1.0.

The Credit Agreement contains customary events of default, which would permit the lenders to accelerate the debt if not cured within applicable grace periods. If an event of default occurs and is continuing, lenders with a majority of the aggregate commitments may require Bank of America, N.A. to declare all amounts outstanding under the Credit Agreement to be immediately due and payable. As of September 30, 2011, we were in compliance with all covenants under the Credit Agreement.

Capitalization. At September 30, 2011, we had total assets of $790.1 million and total capitalization of $742.6 million, of which 52 percent was represented by partners’ equity and 48 percent by our Credit Agreement. At December 31, 2010, we had total assets of $641.3 million and total capitalization of $583.0 million, of which 60 percent was represented by partners’ equity and 40 percent by our Credit Agreement. The percentages of our capitalization represented by partners’ equity and our Credit Agreement could vary in the future if debt or equity is used to finance capital projects or acquisitions.

Non-GAAP Financial Measure

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) plus:

•

Net interest expense, including write-off of deferred financing fees and realized gains and losses on interest rate derivative contracts;

•

Depletion, depreciation and amortization (including accretion of asset retirement obligations);

•

Exploration expense;

•

Amortization of premiums paid on derivative contracts;

•

Unrealized gains and losses on commodity and interest rate derivative contracts;

•

Net gain on acquisition of oil and natural gas properties;

•

Income taxes;

•

Unit-based compensation expense;

•

Material transaction costs incurred on acquisitions and mergers; and

•

Non-cash debt related expense.

Adjusted EBITDAX is a significant performance metric used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors, debt service and capital expenditures) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDAX is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts, and others to assess the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Our Adjusted EBITDAX should not be considered as an alternative to net income, operating income, cash flow from operating activities, or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDAX excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDAX may not be comparable to similarly titled measures of other companies.

For the three months ended September 30, 2011 as compared to the three months ended September 30, 2010, Adjusted EBITDAX increased 13 percent from $29.8 million to $33.6 million. For the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010, Adjusted EBITDAX increased seven percent from $91.7 million to $98.2 million. The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDAX (in thousands):

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Net income	$	96,449		$	2,441		$	103,217		$	46,318
Plus:
Net interest expense, including realized losses on interest rate derivative contracts		3,092			3,268			8,887			9,865
Depletion, depreciation and amortization		12,500			12,782			35,568			38,472
Exploration expense		-			53			-			129
Amortization of premiums paid on derivative contracts		4,210			2,474			8,163			7,342
Unrealized (gains) losses on commodity and interest rate derivative contracts		(83,437	)		8,951			(59,464	)		(12,388	)
Net gain on acquisition of oil and natural gas properties		(815	)		-			(815	)		-
Income taxes		220			(147	)		415			(36	)
Unit-based compensation expense		222			2			667			1,043
Material transaction costs incurred on acquisitions and mergers		1,182			-			1,589			-
Non-cash debt related expense		-			-			-			938
Adjusted EBITDAX	$	33,623		$	29,824		$	98,227		$	91,683

Critical Accounting Policies and Estimates

Please read “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” of our 2010 Annual Report, for information regarding our critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The information included in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of our 2010 Annual Report is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

Commodity Price Sensitivity

Our commodity derivative contracts are discussed in Note 5 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of September 30, 2011, the fair market value of our commodity derivative contracts was a net asset of approximately $30.7 million, of which $14.8 million settles during the next twelve months.

Interest Rate Sensitivity

Our Credit Agreement is discussed in Note 7 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At September 30, 2011, we had outstanding borrowings under our Credit Agreement of $356.0 million, $75.0 million of which has a fixed interest rate pursuant to an interest rate swap through March 2016, and the remainder is subject to floating market rates of interest that are linked to the Eurodollar rate. At this level of floating rate debt, if the Eurodollar rate increased by 10 percent, we would incur an additional $0.06 million of interest expense per year, and if the Eurodollar rate decreased by 10 percent, we would incur $0.06 million less of interest expense per year.

Our interest rate swaps are discussed in Note 5 of Notes to the Consolidated Financial Statements included in “Item 1. Financial Statements.” As of September 30, 2011, the fair market value of our interest rate swaps was a net liability of approximately $0.3 million.

Counterparty Risk

At September 30, 2011, based upon all of our open derivative contracts shown above and their respective mark to market values, we had the following current and long-term derivative assets and liabilities shown by counterparty with their current S&P financial strength rating in parentheses (in thousands):

	Bank of America			Credit Agricole S.A.		BNP Paribas		The Bank of Nova Scotia		Wells Fargo Bank, N.A.		RBC Bank		Natixis S. A.
		(A+)			(A+)	(AA)		(AA-)		(AA)		(BBB)			(A+)		Total
Current asset	$	-		$	6,280	$	3,502	$	503	$	368	$	3,148	$	1,012		$	14,813
Long-term asset		-			3,693		3,214		1,998		2,780		4,199		-			15,884
Current liability		(66	)		-		-		-		-		-		-			(66	)
Long-term liability		(230	)		-		-		-		-		-		(11	)		(241	)
Total amount owed to counterparty	$	(296	)	$	9,973	$	6,716	$	2,501	$	3,148	$	7,347	$	1,001		$	30,390

In order to mitigate the credit risk of financial instruments, ENP enters into master netting agreements with certain counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and ENP. Instead of treating each financial transaction between the counterparty and ENP separately, the master netting agreement enables the counterparty and ENP to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit ENP in two ways: (1) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (2) netting of settlement amounts reduces ENP’s credit exposure to a given counterparty in the event of close-out.

Item 4. Controls and Procedures

As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) was evaluated by our management, with the participation of the Chief Executive Officer and our Chief Financial Officer of the General Partner, in accordance with rules of the Securities Exchange Act of 1934, as amended. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer of the General Partner have concluded that our disclosure controls and procedures were effective as of September 30, 2011 to provide reasonable assurance that information required to be disclosed by us in our reports that we file or submit under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management, including the principal executive and principal financial officer, as appropriate to allow timely decisions regarding required disclosure and recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

On December 31, 2010, Vanguard completed the acquisition of all of the member interest in the General Partner and 20,924,055 common units representing limited partnership interests in us, representing a 46.6% aggregate equity interest in us at September 30, 2011. Pursuant to the Vanguard Acquisition, the functions of the ENP accounting department were transitioned to Houston and integrated with VNG’s, and our books and records were converted to a new accounting software. As a result, our management is continuing to implement new processes and modify existing processes.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the factors discussed in “Item 1A. Risk Factors” and elsewhere in our 2010 Annual Report and to Part II-Item 1A-Risk Factors in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011 and June 30, 2011, which could materially affect our business, financial condition, results of operations, or ability to pay distributions. The risks described in our 2010 Annual Report and in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011 and June 30, 2011 are not the only risks we face. Unknown risks and uncertainties or risks and uncertainties that we currently believe to be immaterial may also have a material adverse effect on our business, financial condition, results of operations, or ability to pay distributions.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Removed and Reserved

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit No. Description

3.1	Certificate of Limited Partnership of Encore Energy Partners LP (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142847), filed with the SEC on May 11, 2007).

3.2	Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of September 17, 2007 (incorporated by reference to Exhibit 3.1 of our 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 our Current Report on Form 8-K, filed with the SEC on April 18, 2008).

10.1

Agreement and Plan of Merger, dated July 10, 2011 among Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Vanguard Acquisition Company, LLC, Encore Energy Partners L.P. and Encore Energy Partners GP LLC (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K, filed with the SEC on July 11, 2011).

31.1*

Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer of the General Partner).

31.2*

Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer of the General Partner).

32.1*

Section 1350 Certification (Principal Executive Officer of the General Partner).

32.2*

Section 1350 Certification (Principal Financial Officer of the General Partner).

____________

*	Filed herewith.

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)

SIGNATURES

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

ENCORE ENERGY PARTNERS LP

By: Encore Energy Partners GP LLC, its General Partner

/s/ Richard A. Robert

Richard A. Robert

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)

Date: November 8, 2011

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued

(unaudited)

EXHIBIT INDEX

Exhibit No. Description

3.1	Certificate of Limited Partnership of Encore Energy Partners LP (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142847), filed with the SEC on May 11, 2007).

3.2	Second Amended and Restated Agreement of Limited Partnership of Encore Energy Partners LP, dated as of September 17, 2007 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed with the SEC on September 21, 2007).

3.2.1

10.1

31.1*

Rule 13a-14(a)/15d-14(a) Certification (Principal Executive Officer of the General Partner).

31.2*

Rule 13a-14(a)/15d-14(a) Certification (Principal Financial Officer of the General Partner).

32.1*

Section 1350 Certification (Principal Executive Officer of the General Partner).

32.2*

Section 1350 Certification (Principal Financial Officer of the General Partner).

____________

* Filed herewith.

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