Encore Energy Partners 10Q 2011 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 o No o

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

Large accelerated filer o Accelerated filer þ

Non-accelerated filer o Smaller reporting company o

(Do not check if a smaller reporting company)

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 May 9, 2011 45,481,604

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets	1
	Consolidated Statements of Operations	2
	Consolidated Statement of Partners’ Equity and Comprehensive Income (Loss)	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	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	29
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Removed and Reserved	30
Item 5.	Other Information	30
Item 6.	Exhibits	30

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” 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;

·	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) Part II, “Item 1A. Risk Factors” and elsewhere in this report, (2) our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, (3) our reports and registration statements filed from time to time with the SEC and (4) other 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.

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

·	BOE/D. One BOE per day.

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

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

·	DD&A. Depletion, depreciation and amortization.

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

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

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

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

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

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

·	FASB. Financial Accounting Standards Board.

·	FASC. FASB Accounting Standards Codification.

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

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

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

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

·	LIBOR. London Interbank Offered Rate.

·	MBbl. One thousand Bbls.

·	MBOE. One thousand BOE.

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

·	Mcf/D. One Mcf per day.

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

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

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

·	NYMEX. New York Mercantile Exchange.

·	Oil. Crude oil 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 our wells and related equipment and facilities. For a complete definition of production costs, please refer to Regulation S-X, Rule 4-10(a)(20).

·	Production Margin. Wellhead revenues less production costs.

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

Proved Developed Reserves. 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, is acreage that is allocated or assignable to producing wells or wells capable of production. For a complete definition of developed oil and gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(6).

Proved 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 the SEC’s Regulation S-X, Rule 4-10(a)(22).

Proved Undeveloped 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 the SEC’s Regulation S-X, Rule 4-10(a)(31).

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

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

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

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

·	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 natural gas lease that gives the owner the right to drill for and produce hydrocarbons on the leased acreage and requires the owner to pay a share of the production and development costs.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

	March 31,			December 31,
	2011			2010
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	1,488		$	1,380
Accounts receivable - trade		21,985			22,795
Derivatives		416			2,604
Other		2,462			470
Total current assets		26,351			27,249

Properties and equipment, at cost - successful efforts method:
Proved properties, including wells and related equipment		859,230			857,999
Unproved properties		25			17
Accumulated depletion, depreciation, and amortization		(270,868	)		(259,575	)
		588,387			598,441
Other property and equipment		1,531			1,327
Accumulated depreciation		(671	)		(613	)
		860			714

Goodwill		9,290			9,290
Other intangibles, net		2,936			3,012
Derivatives		-			836
Other		-			1,778
Total assets	$	627,824		$	641,320

LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,796		$	2,103
Affiliate		1,571			98
Accrued liabilities:
Lease operating		4,298			4,550
Development capital		1,354			890
Interest		221			298
Production taxes and marketing		12,061			10,109
Derivatives		19,715			3,530
Oil and natural gas revenues payable		1,636			1,730
Credit agreement		224,000			-
Other		1,442			1,278
Total current liabilities		269,094			24,586

Derivatives		53,155			20,681
Future abandonment cost, net of current portion		13,198			13,080
Deferred taxes		82			11
Credit agreement		-			234,000
Total liabilities		335,529			292,358

Commitments and contingencies (see Note 11)

Partners' equity:
Limited partners - public, 24,557,549 and 24,417,542 common units issued
and outstanding, respectively		309,571			340,126
Limited partners - affiliates, 20,924,055 common units issued and outstanding		(15,909	)		10,125
General partner - 504,851 general partner units issued and outstanding		(722	)		(94	)
Accumulated other comprehensive loss		(645	)		(1,195	)
Total partners' equity		292,295			348,962
Total liabilities and partners' equity	$	627,824		$	641,320

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)

	2011			2010
Revenues:
Oil	$	39,020		$	36,010
Natural gas		5,793			8,622
Natural gas liquids		2,339			3,943
Marketing		47			70
Commodity derivative fair value loss - realized		(3,345	)		(707	)
Commodity derivative fair value gain (loss) - unrealized		(48,125	)		6,179
Total revenues		(4,271	)		54,117

Expenses:
Production:
Lease operating		8,010			11,619
Production taxes and marketing		4,322			5,066
Depletion, depreciation, and amortization		11,614			12,851
Exploration		-			21
General and administrative		3,330			3,728
Total expenses		27,276			33,285

Operating income (loss)		(31,547	)		20,832

Other income (expenses):
Interest		(2,170	)		(2,377	)
Interest rate derivative fair value loss - realized		(972	)		(982	)
Interest rate derivative fair value gain (loss) - unrealized		395			(59	)
Other		1			25
Total other expenses		(2,746	)		(3,393	)

Income (loss) before income taxes		(34,293	)		17,439
Income tax provision		(112	)		(26	)

Net income (loss)	$	(34,405	)	$	17,413

Net income (loss) allocation (see Note 8):
Limited partners' interest in net income (loss)	$	(34,027	)	$	17,221
General partner's interest in net income (loss)	$	(378	)	$	192

Net income (loss) per common unit:
Basic	$	(0.75	)	$	0.38
Diluted	$	(0.75	)	$	0.38

Weighted average common units outstanding:
Basic		45,473			45,299
Diluted		45,473			45,324

Cash distributions declared per common unit	$	0.5000		$	0.5375

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

(in thousands, except per unit amounts)

(unaudited)

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

Balance at 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 $7		-		-			-		-			2,225			2,225
Total comprehensive income															34,295
Balance at December 31, 2010		45,342		350,251			505		(94	)		(1,195	)		348,962
Non-cash equity-based compensation		140		178			-		2			-			180
Cash distributions to unitholders ($.50 per unit)		-		(22,740	)		-		(252	)		-			(22,992	)
Components of comprehensive income:
Net loss attributable to unitholders		-		(34,027	)		-		(378	)		-			(34,405	)
Settlement of interest rate cash flow hedges in
comprehensive loss		-		-			-		-			550			550
Total comprehensive loss															(33,855	)
Balance at March 31, 2011		45,482	$	293,662			505	$	(722	)	$	(645	)	$	292,295

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Three months ended
	March 31,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	(34,405	)	$	17,413
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depletion, depreciation, and amortization		11,614			12,851
Deferred taxes		107			(11	)
Non-cash equity-based compensation expense		180			906
Non-cash derivative loss (gain)		52,237			(3,700	)
Other		381			1,366
Changes in operating assets and liabilities:
Accounts receivable		810			6,556
Other current assets		(2,016	)		141
Other assets		1,397			(15	)
Accounts payable - trade		693			(1,153	)
Other current liabilities		3,545			4,167
Net cash provided by operating activities		34,543			38,521

Cash flows from investing activities:
Purchase of other property and equipment		(204	)		-
Acquisition of oil and natural gas properties		-			(292	)
Development of oil and natural gas properties		(1,239	)		(989	)
Net cash used in investing activities		(1,443	)		(1,281	)

Cash flows from financing activities:
Proceeds from credit agreement		10,000			5,000
Payments of credit agreement		(20,000	)		(10,000	)
Cash distributions to unitholders		(22,992	)		(24,612	)
Net cash used in financing activities		(32,992	)		(29,612	)

Increase in cash and cash equivalents		108			7,628
Cash and cash equivalents, beginning of period		1,380			1,754
Cash and cash equivalents, end of period	$	1,488		$	9,382

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 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 March 24, 2011, VNR delivered a formal proposal to the chairman of the Conflicts Committee (the “Conflicts Committee”) of ENP GP to acquire all of the outstanding common units of ENP, for consideration of 0.72 common unit of VNR for each outstanding common unit of ENP in a transaction to be structured as a merger of ENP with VNG. The Conflicts Committee of ENP GP has retained Bracewell & Giuliani as legal advisors and Jefferies & Company as financial advisors to assist in the evaluation of the proposal from VNR. The proposal is subject to customary terms and conditions, including applicable board and special committee approvals and the negotiation of definitive agreements. The Conflicts Committee of ENP GP and its advisors are currently considering the proposal and expect to respond to VNR in due course.

Note 2. Basis of Presentation

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

In 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 March 31, 2011, results of operations for the three months ended March 31, 2011 and 2010, and cash flows for the three months ended March 31, 2011 and 2010. 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 on Form 10-K.

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 (loss) or partners’ equity.

Note 3. Proved Properties

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

	March 31,		December 31,
	2011		2010
	(in thousands)
Proved leasehold costs	$	609,938	$	609,910
Wells and related equipment - completed		249,248		248,017
Wells and related equipment - in process		44		72
Total proved properties	$	859,230	$	857,999

Note 4. Fair Value Measurements

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

	March 31, 2011				December 31, 2010
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	1,488	$	1,488	$	1,380	$	1,380
Accounts receivable - trade		21,985		21,985		22,795		22,795
Commodity derivative contracts		416		416		15,682		15,682
Liabilities:
Accounts payable - trade		2,796		2,796		2,103		2,103
Accounts payable - affiliate		1,571		1,571		98		98
Credit Agreement		224,000		224,000		234,000		232,517
Commodity derivative contracts		71,823		71,823		35,011		35,011
Interest rate swaps		1,047		1,047		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 March 31, 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 lenders underwriting ENP’s Credit Agreement. ENP also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

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

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 Consolidated Statement of Operations. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive income 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

Historically, ENP has managed commodity price risk with swap contracts, put contracts and collars. 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.

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.

The following tables summarize ENP’s open commodity derivative contracts as of March 31, 2011:

	April 1, -December 31, 2011		Year 2012		Year 2013		Year 2014
Gas Positions:
Fixed Price Swaps:
Notional Volume (MMBtu)		2,805,550		3,367,932		2,993,000		—
Fixed Price ($/MMBtu)	$	6.06	$	5.75	$	5.10	$	—
Puts:
Notional Volume (MMBtu)		934,450		328,668		—		—
Fixed Price ($/MMBtu)	$	6.31	$	6.76	$	—	$	—
Total Gas Positions:
Notional Volume (MMBtu)		3,740,000		3,696,600		2,993,000		—
Oil Positions:
Fixed Price Swaps:
Notional Volume (Bbls)		394,625		947,940		1,295,750		1,168,000
Fixed Price ($/Bbl)	$	81.62	$	83.29	$	88.95	$	88.95
Collars:
Notional Volume (Bbls)		517,000		475,800		—		—
Floor Price ($/Bbl)	$	80.00	$	74.23	$	—	$	—
Ceiling Price ($/Bbl)	$	96.49	$	90.98	$	—	$	—
Total Oil Positions:
Notional Volume (Bbls)		911,625		1,423,740		1,295,750		1,168,000

Interest Rate Swaps

ENP uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation, whereby it converts the interest due on certain floating rate debt under the Credit Agreement to a weighted average fixed rate. The following table summarizes ENP’s open interest rate swap as of March 31, 2011, which was entered into with Bank of America, N.A.:

	Notional		Fixed			Floating
Term	Amount		Rate			Rate
	(in thousands)
April 1, 2011 - March 2012	$	50,000		2.4200	%	1-month LIBOR

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) prior to January 1, 2011 ineffectiveness on derivative contracts designated as hedges. 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 March 31,
	Recognized in Income	2011			2010
		(in thousands)
Realized gains (losses):
Premium amortization	Commodity derivative fair value loss - realized	$	(3,953	)	$	(2,420	)
Receipts, net of settlements	Commodity derivative fair value gain - realized		608			1,713
Receipts, net of settlements	Interest rate derivative fair value loss - realized		(972	)		(982	)
		$	(4,317	)	$	(1,689	)
Unrealized gains (losses):
Mark-to-market gain (loss)	Commodity derivative fair value gain (loss) - unrealized	$	(48,125	)	$	6,179
Mark-to-market gain (loss)	Interest rate derivative fair value gain - unrealized		395			-
Ineffectiveness on interest rate swaps	Interest rate derivative fair value loss - unrealized		-			(59	)
		$	(47,730	)	$	6,120
Total gains (losses):
Commodity derivatives		$	(51,470	)	$	5,472
Interest rate derivatives			(577	)		(1,041	)
		$	(52,047	)	$	4,431

Accumulated Other Comprehensive Loss

At March 31, 2011 and December 31, 2010, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $0.6 million and $1.2 million, respectively. During the twelve months ending March 31, 2012, ENP expects to reclassify $0.6 million of deferred 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 deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet 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
	Balance Sheet Location	March 31, 2011		December 31, 2010		Balance Sheet Location	March 31, 2011		December 31, 2010
Derivatives not designated as hedges
Commodity derivative contracts	Derivatives - current	$	13,447	$	10,196	Derivatives - current	$	31,699	$	9,906
Interest rate swaps	Derivatives - current		-		-	Derivatives - current		1,047		-
Commodity derivative contracts	Derivatives - noncurrent		6,187		5,486	Derivatives - noncurrent		59,342		25,105
Total derivatives not designated as hedges		$	19,634	$	15,682		$	92,088	$	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		$	19,634	$	15,682		$	92,088	$	36,453

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

	Accumulated OCI (Effective Portion)
	Three Months Ended March 31,
Derivatives Designated as Hedges	2011			2010
Interest rate swaps	$	(550	)	$	824

	Amount of Loss Recognized
	in Income as Ineffective
	Three Months Ended March 31,
Location of Loss Recognized in Income as Ineffective	2011		2010
Derivative fair value gain (loss)	$	-	$	(59	)

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 and collars. We estimate the fair values of the swaps 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 March 31, 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	$	(64,390	)	$	-	$	(64,390	)	$	-
Oil derivative contracts - floors and caps		(16,355	)		-		(16,355	)		-
Natural gas derivative contracts - swaps		6,888			-		6,888			-
Natural gas derivative contracts - floors		2,450			-		2,450			-
Interest rate swaps		(1,047	)		-		(1,047	)		-
Total	$	(72,454	)	$	-	$	(72,454	)	$	-

The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the three months ended March 31, 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 March 31, 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.

Note 5. Asset Retirement Obligations

Asset retirement obligations relate to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal. The following table summarizes the changes in ENP’s asset retirement obligations for the three months ended March 31, 2011 (in thousands):

Future abandonment liability at January 1, 2011	$	13,838
Accretion of discount		186
Total future abandonment costs at March 31, 2011		14,024
Less: current obligations		(826	)
Long-term future abandonment liability at March 31, 2011	$	13,198

As of March 31, 2011, $13.2 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.8 million were current and included in “Other current liabilities” in the accompanying Consolidated Balance Sheet. Approximately $5.1 million of the long-term future abandonment liability represents the estimated cost for decommissioning the Elk Basin natural gas processing plant.

Note 6. Credit Agreement

ENP is a party to a five-year Credit Agreement dated March 7, 2007 (as amended, the “ENP 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 March 31, 2011. ENP is currently evaluating its options including 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 our 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 million. Availability under the Credit Agreement is subject to a borrowing base of $375.0 million, which is redetermined semi-annually and upon requested special redeterminations. As of March 31, 2011, there were $224 million of outstanding borrowings and $151 million of borrowing capacity under the Credit Agreement. In April 2011, the borrowing base was redetermined. See Note 13. Subsequent Events for further discussion.

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:

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

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

Any outstanding letters of credit reduce the availability under the 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 March 31, 2011, ENP was in compliance with all covenants of the 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 7. Partners’ Equity and Distributions

Distributions

ENP’s partnership agreement requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined in ENP’s partnership agreement) to its unitholders. 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 March 31	4/28/2011	$	0.4900	5/13/2011	(a)	$	22,533	(a)

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 8. 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 and unvested phantom units are considered participating securities. Earnings per unit is calculated by dividing the limited partners’ interest in net income (loss), after deducting the interests of participating securities, by the weighted average common units outstanding.

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

	March 31,
	2011			2010
	(in thousands, except per unit amounts)
Net income (loss) attributable to unitholders	$	(34,405	)	$	17,413

Numerator:
Numerator for basic earnings per unit:
Net income (loss) attributable to unitholders	$	(34,405	)	$	17,413
Less: distributions earned by participating securities		(252	)		(252	)
Plus: cash distributions in excess of
income (loss) allocated to the general partner		630			60
Net income (loss) allocated to limited partners	$	(34,027	)	$	17,221

Denominator:
Denominator for basic earnings per unit:
Weighted average common units outstanding		45,473			45,299
Effect of dilutive phantom units		-			25
Denominator for diluted earnings per unit		45,473			45,324

Net income (loss) per common unit:
Basic	$	(0.75	)	$	0.38
Diluted	$	(0.75	)	$	0.38

Note 9. Unit-Based Compensation Plans

Long-Term Incentive Plan

In September 2007, the board of directors of the General Partner adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”), which provides for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, 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. As of March 31, 2011, there was approximately $2.9 million of unrecognized compensation cost related to non-vested restricted units, which is expected to be recognized over a period of 3.8 years. The Consolidated Statements of Operations reflects non-cash compensation of $0.2 million in “General and administrative expense” for the three months ended March 31, 2011. As of March 31, 2011, there were 934,993 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 Encore Acquisition Company 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 three months ended March 31, 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 March 31, 2011, there were no outstanding phantom units.

Note 10. Comprehensive Income (Loss)

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

	Three months ended
	March 31,
	2011			2010
	(in thousands)
Net income (loss)	$	(34,405	)	$	17,413
Settlement of interest rate cash flow hedges		550			158
Comprehensive income (loss)	$	(33,855	)	$	17,571

Note 11. Commitments and Contingencies

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

Additionally, ENP has contractual obligations related to future plugging and abandonment expenses on oil and natural gas properties and related facilities disposal, 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 on Form 10-K for ENP’s contractual obligations as of March 31, 2011.

Note 12. Related Party Transactions

Administrative Services Agreement

ENP does not have any employees. The employees supporting the operations of ENP were: the employees of Encore Acquisition Company 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, such as 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 are 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, Encore Operating received an administrative fee of $2.02 per BOE of ENP’s production. Effective April 1, 2010, the administrative fee increased to $2.06 per BOE of ENP’s production. ENP also 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 quarter 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.

See Note 13. Subsequent Events for further discussion of change in COPAS Wage Index Adjustment. 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 (including COPAS recovery) paid pursuant to the administrative services agreement are included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations. The reimbursements of actual third-party expenses incurred 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 March 31,
	2011		2010
	(in thousands)
Administrative fees	$	1,588	$	1,642
COPAS recovery	$	805	$	667
Third-party expenses	$	1,855	$	2,762

As of March 31, 2011 and December 31, 2010, ENP had a payable to Vanguard of $1.4 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 February 14, 2011, ENP paid cash distributions of approximately $23 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 13. Subsequent Events

Effective April 1, 2011, the administrative fee to be paid to VNG pursuant to the administration services agreement decreased from $2.06 per BOE of ENP’s production to $2.05 per BOE as the COPAS Wage Index Adjustment decreased 0.7 percent.

On April 14, 2011, the borrowing base under the Credit Agreement was increased from $375 million to $400 million pursuant to the semi-annual redetermination. All other terms of the Credit Agreement remained the same.

On April 28, 2011, the board of directors of the General Partner declared an ENP cash distribution for the first quarter of 2011 to unitholders of record as of the close of business on May 6, 2011 of $0.49 per unit or approximately $22.5 million of which $10.5 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 May 13, 2011.

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

· Overview of Business

· First Quarter 2011 Highlights

· Results of Operations – Comparison of Quarter Ended March 31, 2011 to Quarter Ended March 31, 2010

· Capital Commitments, Capital Resources, and Liquidity

· Non-GAAP Financial Measure

· Critical Accounting Policies and Estimates

Recent Developments

On March 24, 2011, Vanguard Natural Resources, LLC (“Vanguard”) delivered a formal proposal to the chairman of the Conflicts Committee (the “Conflicts Committee”) of the General Partner, to acquire all of the outstanding common units of us, for consideration of 0.72 common unit of Vanguard for each outstanding common unit of us in a transaction to be structured as a merger of us with Vanguard. The Conflicts Committee of ENP GP has retained Bracewell & Giuliani as legal advisors and Jefferies & Company as financial advisors to assist in the evaluation of the proposal from VNR. The proposal of Vanguard is subject to customary terms and conditions, including applicable board and special committee approvals and the negotiation of definitive agreements. The Conflicts Committee of the General Partner is currently considering the proposal and expects to respond to Vanguard in due course.

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.

First Quarter 2011 Highlights

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

·	Our average realized oil price increased eight percent to $79.64 per Bbl as compared to $73.57 per Bbl in the first quarter of 2010. Our average realized natural gas price decreased 26 percent to $4.19 per Mcf as compared to $5.69 per Mcf in the first quarter of 2010.

·	Our oil, natural gas and natural gas liquids revenues decreased three percent to $47.2 million as compared to $48.6 million in the first quarter of 2010. Oil represented approximately 64 percent and 60 percent of our total production in the first quarter of 2011 and 2010, respectively.

Our production margin increased nine percent to $34.8 million as compared to $31.9 million in the first quarter of 2010. Total oil and natural gas wellhead revenues per BOE increased by four percent while total production expenses per BOE decreased by 21 percent. On a per BOE basis, our production margin increased 17 percent to $45.71 per BOE as compared to $39.22 per BOE for the first quarter of 2010.

·	We invested $1.2 million in development and exploitation activities.

·	Our net loss was $34.4 million ($(0.75) per common unit) as compared to a net income of $17.4 million ($0.38 per common unit) for the first quarter of 2010 primarily due to $54.3 million increase in mark-to-market losses on our commodity derivatives contracts.

·	Average daily production volumes decreased six percent on a BOE basis from 9,034 BOE/D to 8,463 BOE/D.

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

Results of Operations

Comparison of Quarter Ended March 31, 2011 to Quarter Ended March 31, 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 March 31,						Increase / (Decrease)
	2011			2010			$
Revenues (in thousands):
Oil	$	39,020		$	36,010		$	3,010		8	%
Natural gas		5,793			8,622			(2,829	)	-33	%
Natural gas liquids		2,339			3,943			(1,604	)	-41	%
Total oil, natural gas and natural gas liquids revenues		47,152			48,575			(1,423	)	-3	%
Marketing		47			70			(23	)	-33	%
Commodity derivatve fair value loss - realized		(3,345	)		(707	)		(2,638	)	-373	%
Commodity derivatve fair value gain (loss) - realized		(48,125	)		6,179			(54,304	)	-879	%
Total revenues	$	(4,271	)	$	54,117		$	(58,388	)	-108	%

Average realized prices:
Oil ($/Bbl)	$	79.64		$	73.57		$	6.07		8	%
Natural gas ($/Mcf)	$	4.19		$	5.69		$	(1.50	)	-26	%
Natural gas liquids ($/Bbl)	$	56.82		$	55.49		$	1.33		2	%
Combined ($/BOE)	$	61.91		$	59.75		$	2.16		4	%

Total production volumes:
Oil (MBbls)		490			489			1		0	%
Natural gas (MMcf)		1,383			1,515			(132	)	-9	%
Natural gas liquids (Bbls)		41			71			(30	)	-42	%
Combined (MBOE)		762			813			(51	)	-6	%

Average daily production volumes:
Oil (Bbls/D)		5,444			5,438			6		0	%
Natural gas (Mcf/D)		15,368			16,834			(1,466	)	-9	%
Natural gas liquids (Bbls/D)		457			790			(333	)	-42	%
Combined (BOE/D)		8,463			9,034			(571	)	-6	%

Average NYMEX prices:
Oil (per Bbl)	$	94.25		$	78.61		$	15.64		20	%
Natural gas (per Mcf)	$	4.11		$	5.36		$	(1.25	)	-23	%

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 March 31,
	2011			2010
Average realized oil price ($/Bbl)	$	79.64		$	73.57
Average NYMEX ($/Bbl)	$	94.25		$	78.61
Differential to NYMEX	$	(14.61	)	$	(5.04	)
Average realized oil price to NYMEX percentage		84	%		94	%


Average realized natural gas price ($/Mcf)	$	4.19		$	5.69
Average NYMEX ($/Mcf)	$	4.11		$	5.36
Differential to NYMEX	$	0.08		$	0.33
Average realized natural gas price to NYMEX percentage		102	%		106	%

Our average realized oil price as a percentage of the average NYMEX price was 84 percent in the first quarter of 2011 as compared to 94 percent in the first quarter of 2010. Our average realized natural gas price as a percentage of the average NYMEX price was 102 percent in the first quarter of 2011 as compared to 106 percent in the first 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 eight percent from $36 million in the first quarter of 2010 to $39 million in the first quarter of 2011 as a result of a $6.07 per Bbl increase in our average realized oil price and a 1 MBbls increase in our oil production volumes. Our higher average realized oil price increased oil revenues by approximately $3 million and was primarily due to a higher average NYMEX price, which increased from $78.61 per Bbl in the first quarter of 2010 to $94.25 per Bbl in the first quarter of 2011. However, we did not reap the entire benefit of the 20 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 $5.04 in first quarter 2010 to $14.61 in the first quarter 2011.

Natural gas revenues decreased 33 percent from $8.6 million in the first quarter of 2010 to $5.8 million in the first quarter of 2011 as a result of a $1.50 per Mcf decrease in our average realized natural gas price and a nine percent decrease in our natural gas production volumes. Our lower average realized natural gas price decreased natural gas revenues by approximately $2.3 million and was primarily due to a lower average NYMEX price, which decreased from $5.36 per Mcf in the first quarter of 2010 to $4.11 per Mcf in the first quarter 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.

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

	Three months ended March 31,						Increase / (Decrease)
	2011			2010			$			%
Expenses (in thousands):
Production:
Lease operating	$	8,010		$	11,619		$	(3,609	)	-31	%
Production taxes and marketing		4,322			5,066			(744	)	-15	%
Total production expenses		12,332			16,685			(4,353	)	-26	%
Other:
Depletion, depreciation, and amortization		11,614			12,851			(1,237	)	-10	%
Exploration		-			21			(21	)	-100	%
General and administrative		3,330			3,728			(398	)	-11	%
Total operating expenses		27,276			33,285			(6,009	)	-18	%
Interest		2,170			2,377			(207	)	-9	%
Interest rate derivative fair value loss - realized		972			982			(10	)	-1	%
Interest rate derivative fair value gain (loss) - unrealized		(395	)		59			(454	)	-769	%
Other		(1	)		(25	)		24		96	%
Income tax provision		112			26			86		331	%
Total expenses	$	30,134		$	36,704		$	(6,570	)	-18	%

Expenses (per BOE):
Production:
Lease operating	$	10.52		$	14.29		$	(3.77	)	-26	%
Production taxes and marketing		5.67			6.23			(0.56	)	-9	%
Total production expenses		16.19			20.52			(4.33	)	-21	%
Other:
Depletion, depreciation, and amortization		15.25			15.81			(0.56	)	-4	%
Exploration		-			0.03			(0.03	)	-100	%
General and administrative		4.37			4.59			(0.22	)	-5	%
Total operating expenses		35.81			40.95			(5.14	)	-13	%
Interest		2.85			2.92			(0.07	)	-2	%
Interest rate derivative fair value loss - realized		1.28			1.21			0.07		6	%
Interest rate derivative fair value gain (loss) - unrealized		(0.52	)		0.07			(0.59	)	-843	%
Other		-			(0.03	)		0.03		-100	%
Income tax provision		0.15			0.03			0.12		400	%
Total expenses	$	39.57		$	45.15		$	(5.58	)	-12	%

Production expenses. LOE decreased $3.6 million from $11.6 million in the first quarter of 2010 to $8.0 million in the first quarter 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 $9.7 million consistent with management’s expectations. This amount was still lower than the prior year 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 taxes and marketing expenses decreased from $5.1 million in the first quarter of 2010 to $4.3 million in the first quarter of 2011. As a percentage of wellhead revenues, production, severance, and ad valorem taxes decreased from 10.9 percent in the first quarter of 2010 to 8.8 percent in the first quarter of 2011.

Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense decreased $1.2 million from $12.9 million in the first quarter of 2010 to $11.6 million in the first quarter of 2011 primarily due to lower production volumes in the first quarter of 2011 compared to the same period in 2010.

General and administrative (“G&A”) expense. G&A expense decreased $0.4 million to $3.3 million in the first quarter of 2011 as compared to $3.7 million in the first quarter of 2010 primarily due to professional fees incurred in the first quarter of 2010 related to the acquisition of properties from Encore Operating.

Interest expense. Interest expense decreased $0.2 million from $2.4 million in the first quarter of 2010 to $2.2 million in the first quarter of 2011 primarily due to lower weighted average outstanding borrowings under our Credit Agreement.

Interest rate derivative fair value gain (loss). Please read Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our derivative contracts.

Capital Commitments, Capital Resources, and Liquidity

Capital commitments

Our primary uses of cash are:

·	Distributions to unitholders;

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

·	Acquisitions of oil and natural gas properties;

·	Funding of working capital; and

·	Contractual obligations.

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

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

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

		Cash Distribution
	Date	Declared per				Total
	Declared	Common Unit		Date Paid		Distribution
2011						(in thousands)
Quarter ended March 31	4/28/2011	$	0.4900	5/13/2011	(a)	$	22,533	(a)

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 March 31,
	2011		2010
	(in thousands)
Development and exploitation	$	1,239	$	531
Exploration		-		20
Total	$	1,239	$	551

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 is expected to increase significantly in 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 $18.3 million and $19.8 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 2011, 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, 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, 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 on Form 10-K. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

Please read “Capital Commitments, Capital Resources, and Liquidity – Capital commitments – Contractual obligations” included in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2010 Annual Report on Form 10-K for additional information regarding our commitments and obligations.

Other contingencies and commitments. Historically, Encore Operating provided administrative services for us, such as 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 constitute 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.

Encore Operating received an administrative fee of $2.02 per BOE of our production for such services from April 1, 2009 to March 31, 2010. Effective April 1, 2010 the administrative fee increased to $2.06 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 quarter 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 our general partner upon the recommendation of its conflicts committee; and

·	otherwise as agreed upon by VNG and our general partner, with the approval of the conflicts committee of the board of directors of our general partner.

Capital resources

Cash flows from operating activities. Cash provided by operating activities decreased $4 million from $38.5 million for the first quarter of 2010 to $34.5 million for the first quarter of 2011, primarily due to decreased settlements received on our commodity derivative contracts of $1.1 million as a result of higher commodity prices in the first quarter of 2011 and 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 $0.1 million from $1.3 million for the first quarter of 2010 to $1.4 million for the first quarter of 2011, primarily due to a $0.2 million increase in amounts paid to develop oil and natural gas properties.

Cash flows from financing activities. Our cash flows from financing activities consist primarily of proceeds from and payments on our 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 quarter of 2011, we used net cash of $33 million in financing activities, including $23 million in distributions to unitholders and net repayments of $10 million under our Credit Agreement. Net repayments decreased the outstanding borrowings under our Credit Agreement from $234 million at December 31, 2010 to $224 million at March 31, 2011.

During the first quarter of 2010, we used net cash of $29.6 million in financing activities, including $24.6 million of distributions to unitholders and net repayments of $5 million under our Credit Agreement. Net repayments decreased the outstanding borrowings in the Credit Agreement from $255 million at December 31, 2009 to $250 million at March 31, 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 $18.3 million and $19.8 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 quarter of 2011, our average realized oil prices increased by eight percent and our natural gas prices decreased by 26 percent, as compared to our average realized prices for each in the first quarter 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 two-thirds of our forecasted oil production through 2014 and natural gas production through 2013, respectively, 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 4 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 March 31, 2011. We are currently evaluating our options which, based on discussions with lenders, include extending the term of the Credit Agreement or refinancing under a new revolving credit facility. We will continue to monitor these options with lenders (and consider other potential solutions) in the coming months. However, the size or term of any extension to the revolving credit facility or replacement of the revolving credit facility may be significantly impacted should we consummate the proposed merger with VNR.

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 our 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 million. Availability under the Credit Agreement was subject to a borrowing base of $375 million and on March 31, 2011, there were $224 million of outstanding borrowings and $151 million of borrowing capacity under the Credit Agreement. The borrowing base is redetermined semi-annually and upon requested special redeterminations. On April 14, 2011, the borrowing base was increased to $400 million pursuant to the semi-annual redetermination. On May 10, 2011, there were $224 million of outstanding borrowings and $176 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:

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

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

Any outstanding letters of credit reduce the availability under the 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 March 31, 2011, we were in compliance with all covenants under the Credit Agreement.

Capitalization. At March 31, 2011, we had total assets of $627.8 million and total capitalization of $516.3 million, of which 57 percent was represented by partners’ equity and 43 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;

•

income taxes;

•

Unit-based compensation expense; 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 March 31, 2011 as compared to the three months ended March 31, 2010, Adjusted EBITDAX increased two percent from $31.8 million to $32.3 million. The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDAX (in thousands):

	Three Months Ended March 31,
	2011			2010
Net income (loss)	$	(34,405	)	$	17,413
Plus:
Net interest expense, including realized losses on interest rate derivative contracts		3,141			3,334
Depletion, depreciation and amortization		11,614			12,851
Exploration expense		-			21
Amortization of premiums paid on derivative contracts		3,953			2,420
Unrealized (gains) losses on commodity and interest rate derivative contracts		47,730			(6,120	)
Income taxes		112			26
Unit-based compensation expense		180			906
Non-cash debt related expense		-			938
Adjusted EBITDAX	$	32,325		$	31,789

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 on Form 10-K, for information regarding our critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The information included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of our 2010 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of our potential exposure to market risks, including commodity price risk and interest rate risk.

Commodity Price Sensitivity

Our commodity derivative contracts are discussed in Note 4 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” As of March 31, 2011, the fair market value of our commodity derivative contracts was a net liability of approximately $71.4 million, of which $18.3 million settles during the next twelve months.

Interest Rate Sensitivity

Our Credit Agreement is discussed in Note 6 of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” At March 31, 2011, we had outstanding borrowings under our Credit Agreement of $224 million, $50 million of which has a fixed interest rate pursuant to an interest rate swap through March 2012 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 $0.04 million of interest expense per year, and if the Eurodollar rate decreased by 10 percent, we would incur $0.04 million less of interest expense per year.

Our interest rate swaps are discussed in Note 4 of Notes to the Consolidated Financial Statements included in “Item 1. Financial Statements.” As of March 31, 2011, the fair market value of our interest rate swaps was a net liability of approximately $1.0 million.

Counterparty Risk

At March 31, 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			BNP Paribas			The Bank of Nova Scotia			Wells Fargo Bank, N.A.			Credit Agricole S.A.			RBC Bank
		(A+)		(AA)			(AA-)			(AA)			(AA-)				(A-)		Total
Current asset	$	-		$	-		$	-		$	-		$	-		$	416		$	416
Current liability		(1,047	)		(8,773	)		(3	)		(4,195	)		(5,697	)		-			(19,715	)
Long-term liability		-			(8,718	)		(4,187	)		(13,807	)		(15,584	)		(10,859	)		(53,155	)
Total amount owed to counterparty	$	(1,047	)	$	(17,491	)	$	(4,190	)	$	(18,002	)	$	(21,281	)	$	(10,443	)	$	(72,454	)

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, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of March 31, 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 46.7% aggregate equity interest in us. Pursuant to the Vanguard Acquisition, the functions of the 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 implementing new processes and modifying existing processes.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating and capital costs and reduced demand for the oil and natural gas we produce.

In December 2009, the U.S. Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. In addition, on November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, beginning in 2012 for emissions occurring in 2011. Also, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits, including drilling permits, before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to our operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition.

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	Form of Amended and Restated Indemnification Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed with the SEC on April 7, 2011).

10.2	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed with the SEC on April 13, 2011).

31.1*

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

31.2*

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

32.1*

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

32.2*

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

____________

*	Filed herewith.

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: May 10, 2011

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	Form of Amended and Restated Indemnification Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed with the SEC on April 7, 2011).

10.2	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed with the SEC on April 13, 2011).

31.1*

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

31.2*

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

32.1*

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

32.2*

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

____________

* Filed herewith.

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Constraining
Legalese
Litigous
Readability	8th grade Avg

Encore Energy Partners Inactive 10-Q2011 Q1 Quarterly report

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