Vanguard Natural Resources, Inc. - FORM 8-K/A - EX-99.1

Attached files

file	filename
8-K/A - Vanguard Natural Resources, Inc.	form8-ka.htm
EX-23.1 - Vanguard Natural Resources, Inc.	exhibit23-1.htm
EX-99.2 - Vanguard Natural Resources, Inc.	exhibit99-2.htm
EX-99.3 - Vanguard Natural Resources, Inc.	exhibit99-3.htm
EX-99.4 - Vanguard Natural Resources, Inc.	exhibit99-4.htm

Exhibit 99.1

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

	December 31,
	2010			2009
ASSETS

Current assets:
Cash and cash equivalents	$	1,380		$	1,754
Accounts receivable:
Trade		22,795			24,543
Affiliate		-			8,213
Derivatives		10,196			12,881
Other		470			857
Total current assets		34,841			48,248

Properties and equipment, at cost - successful efforts method:
Proved properties, including wells and related equipment		857,999			851,833
Unproved properties		17			55
Accumulated depletion, depreciation, and amortization		(259,575	)		(210,417	)
		598,441			641,471
Other property and equipment		1,327			863
Accumulated depreciation		(613	)		(419	)
		714			444

Goodwill		9,290			9,290
Other intangibles, net		3,012			3,316
Derivatives		5,486			13,423
Other		1,778			3,459
Total assets	$	653,562		$	719,651

LIABILITIES AND PARTNERS' EQUITY

Current liabilities:
Accounts payable:
Trade	$	2,103		$	577
Affiliate		98			2,780
Accrued liabilities:
Lease operating		4,550			4,157
Development capital		890			1,484
Interest		298			429
Production taxes and marketing		10,109			10,218
Derivatives		11,122			9,815
Oil and natural gas revenues payable		1,730			1,598
Other		1,278			1,632
Total current liabilities		32,178			32,690

Derivatives		25,331			13,401
Future abandonment cost, net of current portion		13,080			12,556
Long-term debt		234,000			255,000
Deferred taxes		11			-
Total liabilities		304,600			313,647

Commitments and contingencies (see Note 4)

Partners' equity:
Limited partners - 45,341,597 and 45,285,347 common units issued and
outstanding, respectively		350,251			409,777
General partner - 504,851 general partner units issued and outstanding		(94	)		(353	)
Accumulated other comprehensive loss		(1,195	)		(3,420	)
Total partners' equity		348,962			406,004
Total liabilities and partners' equity	$	653,562		$	719,651

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

	Year Ended December 31,
	2010			2009			2008
Revenues:
Oil	$	155,367		$	128,404		$	227,559
Natural gas		28,109			21,635			53,864
Marketing		269			478			5,324
Total revenues		183,745			150,517			286,747

Expenses:
Production:
Lease operating		43,021			43,451			46,766
Production taxes and marketing		18,221			16,452			33,591
Depletion, depreciation, and amortization		50,580			57,481			58,076
Exploration		194			3,132			196
General and administrative		12,398			12,040			16,606
Derivative fair value loss (gain)		14,146			47,464			(96,880	)
Total expenses		138,560			180,020			58,355

Operating income (loss)		45,185			(29,503	)		228,392

Other income (expenses):
Interest		(13,171	)		(10,974	)		(6,969	)
Other		56			162			95
Total other expenses		(13,115	)		(10,812	)		(6,874	)

Income (loss) before income taxes		32,070			(40,315	)		221,518
Income tax benefit (provision)		-			(14	)		(762	)

Net income (loss)	$	32,070		$	(40,329	)	$	220,756

Net income (loss) allocation (see Note 8):
Limited partners' interest in net income (loss)	$	31,722		$	(39,913	)	$	163,070
General partner's interest in net income (loss)	$	348		$	(592	)	$	2,648

Net income (loss) per common unit:
Basic	$	0.70		$	(1.01	)	$	5.33
Diluted	$	0.70		$	(1.01	)	$	5.21

Weighted average common units outstanding:
Basic		45,331			39,366			30,568
Diluted		45,337			39,366			31,938

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

ENCORE ENERGY PARTNERS LP

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

(in thousands, except per unit amounts)

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

Balance at December 31, 2007		24,187	$	630,852			505	$	9,214		$	-		$	640,066
Net distributions to owner		-		(47,629	)		-		(1,166	)		(1	)		(48,796	)
Deemed distributions in connection with common control acquisition of assets		6,885		(122,083	)		-		(2,944	)		-			(125,027	)
Issuance of common units in exchange for net profits interest in certain
Crockett County properties		284		5,748			-		-			-			5,748
Non-cash equity-based compensation		-		5,180			-		83			-			5,263
Cash distributions to unitholders ($2.3111 per unit)		-		(73,234	)		-		(1,167	)		-			(74,401	)
Vesting of phantom units		7		-			-		-			-			-
Conversion of management incentive units		1,715		-			-		-			-			-
Components of comprehensive income:
Net income attributable to owner related to pre-partnership
operations of common control acquisition of assets		-		50,420			-		1,220			-			51,640
Net income attributable to unitholders		-		166,822			-		2,294			-			169,116
Change in deferred hedge loss on interest rate swaps, net of tax of $12		-		-			-		-			(4,258	)		(4,258	)
Total comprehensive income															216,498
Balance at December 31, 2008		33,078		616,076			505		7,534			(4,259	)		619,351
Net distributions to owner		-		(11,137	)		-		(272	)		-			(11,409	)
Deemed distributions in connection with common control acquisition of assets		-		(245,334	)		-		(5,913	)		-			(251,247	)
Proceeds from issuance of common units, net of offering costs		12,190		170,000			-		(114	)		-			169,886
Non-cash equity-based compensation		-		560			-		5			-			565
Cash distributions to unitholders ($2.05 per unit)		-		(80,617	)		-		(1,035	)		-			(81,652	)
Vesting of phantom units and conversion of management incentive units		17		-			-		-			-			-
Components of comprehensive loss:
Net income attributable to owner related to pre-partnership
operations of common control acquisition of assets		-		172			-		4			-			176
Net loss attributable to unitholders		-		(39,943	)		-		(562	)		-			(40,505	)
Change in deferred hedge loss on interest rate swaps, net of tax of $2		-		-			-		-			839			839
Total comprehensive loss															(39,490	)
Balance at December 31, 2009		45,285		409,777			505		(353	)		(3,420	)		406,004
Net contributions from owner		-		(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

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2010			2009			2008
Cash flows from operating activities:
Net income (loss)	$	32,070		$	(40,329	)	$	220,756
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depletion, depreciation, and amortization		50,580			57,481			58,076
Deferred taxes		(70	)		(286	)		322
Non-cash equity-based compensation expense		1,331			565			5,232
Non-cash derivative loss (gain)		26,092			117,685			(92,286	)
Other		2,450			4,483			486
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable		9,921			(10,591	)		12,437
Current derivatives		-			(2,020	)		(9,586	)
Other current assets		177			(221	)		(176	)
Long-term derivatives		-			(9,072	)		(6,881	)
Other assets		33			(3	)		578
Accounts payable		(1,157	)		(2,555	)		(1,748	)
Other current liabilities		(76	)		(167	)		2,025
Net cash provided by operating activities		121,351			114,970			189,235

Cash flows from investing activities:
Purchases of other property and equipment		(464	)		(88	)		(315	)
Acquisition of oil and natural gas properties		(280	)		(31,960	)		(215	)
Development of oil and natural gas properties		(6,375	)		(9,037	)		(41,803	)
Net cash used in investing activities		(7,119	)		(41,085	)		(42,333	)

Cash flows from financing activities:
Proceeds from issuance of common units, net of issuance costs		-			170,089			-
Proceeds from long-term debt, net of issuance costs		15,000			227,061			243,310
Payments on long-term debt		(36,000	)		(125,000	)		(141,000	)
Deemed distributions in connection with common control acquisition of assets		-			(251,247	)		(125,027	)
Cash distributions to unitholders		(93,382	)		(81,652	)		(74,401	)
Other		(224	)		(12,001	)		(49,168	)
Net cash used in financing activities		(114,606	)		(72,750	)		(146,286	)

Increase (decrease) in cash and cash equivalents		(374	)		1,135			616
Cash and cash equivalents, beginning of period		1,754			619			3
Cash and cash equivalents, end of period	$	1,380		$	1,754		$	619

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

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Description of Business

Encore Energy Partners LP (together with its subsidiaries, “ENP”), a Delaware limited partnership formed in February of 2007 by Encore Acquisition Company (“EAC”), is engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States. Encore Energy Partners GP LLC (the “General Partner”), a Delaware limited liability company and indirect wholly owned subsidiary of Vanguard Natural Resources, LLC (together with its subsidiaries, “Vanguard”), 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 core areas:

·	the Big Horn Basin in Wyoming and Montana;

·	the Permian Basin in West Texas and New Mexico;

·	the Williston Basin in North Dakota and Montana; and

·	the Arkoma Basin in Arkansas and Oklahoma.

On March 9, 2010, EAC, a former parent of the General Partner, was merged with and into Denbury (the “Merger”), with Denbury Resources Inc. (together with its subsidiaries, “Denbury”), a publicly traded Delaware corporation, surviving the Merger. As part of the Merger, Denbury became the then owner of the General Partner and approximately 46.1 percent of ENP’s outstanding common units. The Merger did not impact the accompanying Consolidated Financial Statements.

On November 17, 2010, Denbury announced that it had entered into an agreement to sell its ownership interests in ENP to Vanguard Natural Gas ( “VNG”), a wholly-owned subsidiary of Vanguard and the parent of the General Partner, for $300 million in cash and approximately 3.14 million Vanguard common units (the “Vanguard Acquisition”). The transaction closed on December 31, 2010. Denbury sold its interest in 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. The Vanguard Acquisition did not impact the accompanying Consolidated Financial Statements.

Note 2. Summary of Significant Accounting Policies

Principles of Consolidation

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

Use of Estimates

Preparing financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make certain estimations and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities in the consolidated financial statements. Actual results could differ materially from those estimates.

Estimates made in preparing these consolidated financial statements include, among other things, estimates of the proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; operating costs accrued; volumes and prices for revenues accrued; estimates of the fair value of unit-based compensation awards; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Changes in the assumptions used could have a significant impact on reported results in future periods.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis and considering legal right of offset, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is included in “Other” in the “Financing activities” section of ENP’s Consolidated Statements of Cash Flows.

The following table sets forth supplemental disclosures of cash flow information for the periods indicated:

	Year ended December 31,
	2010		2009		2008
	(In thousands)
Cash paid during the period for:
Interest	$	9,253	$	9,761	$	6,614
Income taxes		178		297		-
Non-cash investing and financing activities:
Issuance of common units in connection with acquisition of
net profits interest in certain Crockett County properties (a)		-		-		5,748
Issuance of common units in connection with acquisition of the
Permian and Williston Basin Assets (a)		-		-		125,027

______________

(a)	Please read “Note 3. Acquisitions” for additional discussion.

Accounts Receivable

Trade accounts receivable, which are primarily from oil and natural gas sales, are recorded at the invoiced amount and do not bear interest. ENP routinely reviews outstanding accounts receivable balances and assesses the financial strength of its customers and records a reserve for amounts not expected to be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2010 and 2009, ENP had no allowance for doubtful accounts.

Properties and Equipment

Oil and Natural Gas Properties. ENP uses the successful efforts method of accounting for its oil and natural gas properties. ENP applies the provisions of the “Financial Accounting and Reporting by Oil and Gas Producing Companies” topic of the Financial Accounting Standards Board Accounting Standards Codification (the “FASC”). Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with drilling exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.

If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs would be expensed in ENP’s Consolidated Statements of Operations and shown as an adjustment to net income (loss) in the “Operating activities” section of ENP’s Consolidated Statements of Cash Flows in the period in which the determination was made. If an exploratory well finds reserves but they cannot be classified as proved, ENP continues to capitalize the associated cost as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and ENP is making sufficient progress in assessing the reserves and the operating viability of the project. If subsequently it is determined that these conditions do not continue to exist, all previously capitalized costs associated with the exploratory well would be expensed and shown as an adjustment to net income (loss) in the “Operating activities” section of ENP’s Consolidated Statements of Cash Flows in the period in which the determination was made. Re-drilling or directional drilling in a previously abandoned well is classified as development or exploratory based on whether it is in a proved or unproved reservoir. Costs for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Costs to recomplete a well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is unsuccessful, the costs would be charged to expense. All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of ENP’s Consolidated Statements of Cash Flows.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Costs to construct facilities or increase the productive capacity from existing reservoirs are capitalized. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or total proved reserves, as applicable. Natural gas volumes are converted to barrels of oil equivalent (“BOE”) at the rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas.

The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to accumulated DD&A.

Independent petroleum engineers estimate ENP’s reserves annually on December 31. This results in a new DD&A rate which ENP uses for the preceding fourth quarter after adjusting for fourth quarter production. ENP internally estimates reserve additions and reclassifications of reserves from proved undeveloped to proved developed at the end of the first, second, and third quarters for use in determining a DD&A rate for the respective quarter.

ENP applies the provisions of the “Accounting for the Impairment or Disposal of Long-Lived Assets” topic of the FASC, which requires us to assess the need for an impairment of long-lived assets to be held and used, including proved oil and natural gas properties, whenever events and circumstances indicate that the carrying value of the asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then an impairment charge is recognized to the extent the asset’s carrying value exceeds its fair value. Expected future net cash flows are based on existing proved reserves (and appropriately risk-adjusted probable reserves), forecasted production information, and management’s outlook of future commodity prices. Any impairment charge incurred is expensed and reduces the net basis in the asset. Management aggregates proved property for impairment testing the same way as for calculating DD&A. The price assumptions used to calculate undiscounted cash flows is based on judgment. ENP uses prices consistent with the prices it believes a market participant would use in bidding on acquisitions and/or assessing capital projects. These price assumptions are critical to the impairment analysis as lower prices could trigger impairment.

Unproved properties, the majority of which relate to the acquisition of leasehold interests, are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs which ENP believes will not be transferred to proved properties over the remaining life of the lease.

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:

	December 31,
	2010		2009
	(in thousands)
Proved leasehold costs	$	609,910	$	609,692
Wells and related equipment - Completed		248,017		241,953
Wells and related equipment - In process		72		188
Total proved properties	$	857,999	$	851,833

Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is expensed on a straight-line basis over estimated useful lives, which range from three to seven years. Gains or losses from the disposal of other property and equipment are recognized in the period realized and included in “Other” in the accompanying Consolidated Statements of Operations.

Goodwill and Other Intangible Assets

ENP accounts for goodwill and other intangible assets under the provisions of the “Goodwill and Other Intangible Assets” topic of the FASC. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is tested for impairment annually on December 31 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. ENP has determined that it has only one reporting unit, which is oil and natural gas production in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.

ENP utilizes both a market capitalization and an income approach to determine the fair value of its reporting unit. The primary component of the income approach is the estimated discounted future net cash flows expected to be recovered from the reporting unit’s oil and natural gas properties. ENP’s analysis concluded that there was no impairment of goodwill as of December 31, 2010. Significant decreases in the prices of oil and natural gas or significant negative reserve adjustments from the December 31, 2010 assessment could change ENP’s estimates of the fair value of its reporting units and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. ENP evaluates the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

ENP is a party to a contract allowing it to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2010, the gross carrying value of this contact was $4.2 million and accumulated amortization was $1.2 million. During each of the years ended December 31, 2010, 2009, and 2008 ENP recorded approximately $0.3 million of amortization expense related to this contract. The net carrying value is shown as “Other intangibles, net” on the accompanying Consolidated Balance Sheets and is being amortized on a straight-line basis through November 2020. ENP expects to recognize $0.3 million of amortization expense during each of the next five years related to this contract.

Asset Retirement Obligations

ENP applies the provisions of the “Accounting for Asset Retirement Obligation” topic of the FASC, which requires it to recognize the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which the property is acquired or a new well is drilled. An amount equal to and offsetting the liability is capitalized as part of the carrying amount of ENP’s oil and natural gas properties. The liability is recorded at its discounted risk adjusted fair value and then accreted each period until it is settled or the asset is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining field life based on reserve estimates. Please read “Note 5. Asset Retirement Obligations” for additional information.

Unit-Based Compensation

ENP does not have any employees. However, the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “LTIP”) allows for the grant of unit awards and unit-based awards for employees, consultants, and directors of Vanguard, the General Partner, and any of their affiliates that perform services for ENP. ENP accounts for unit-based compensation according to the provisions of the “Share-Based Payment” topic of the FASC, which requires the recognition of compensation expense for unit-based awards over the requisite service period in an amount equal to the grant date fair value of the awards. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of ENP’s unit-based compensation plans.

Segment Reporting

ENP operates in only one industry: the oil and natural gas exploration and production industry in the United States. All revenues are derived from customers located in the United States.

Major Customers / Concentration of Credit Risk

The following purchasers accounted for 10 percent or greater of the sales of production for the period indicated:


	Percentage of Total Sales of Production for the Year Ended December 31,
Purchaser	2010			2009			2008
Marathon Oil Corporation		30	%		43	%		19	%
ConocoPhillips	(a)			(a)				17	%
Tesoro Refining & Marketing Co		10	%	(a)				15	%

(a)	Less than 10 percent for the period indicated.

Income Taxes

ENP is treated as a partnership for federal and state income tax purposes with each partner being separately taxed on his share of ENP’s taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying consolidated financial statements. However, the portion of ENP’s operations that is located in Texas is subject to an entity-level tax, the Texas margin tax, at an effective rate of up to 0.7 percent of income that is apportioned to Texas. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective Texas margin tax bases. Such amounts are immaterial to ENP.

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as ENP does not have access to information about each unitholder’s tax attributes in ENP.

ENP performs a periodic evaluation of tax positions to review the appropriate recognition threshold for each tax position recognized in its consolidated financial statements. As of December 31, 2010 and 2009, all of ENP’s tax positions met the “more-likely-than-not” threshold. As a result, no additional tax expense, interest, or penalties have been accrued.

Oil and Natural Gas Revenue Recognition

Oil and natural gas revenues are recognized as oil and natural gas is produced and sold, net of royalties. Royalties and severance taxes are incurred based upon the actual price received from the sales. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable – trade” in the accompanying Consolidated Balance Sheets. Natural gas revenues are reduced by any processing and other fees incurred except for transportation costs paid to third parties, which are recorded as “Production taxes and marketing” in the accompanying Consolidated Statements of Operations. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized based on actual sales of natural gas rather than ENP’s proportionate share of natural gas production. If ENP’s overproduced imbalance position (i.e., ENP has cumulatively been over-allocated production) is greater than ENP’s share of remaining reserves, a liability is recorded for the excess at period-end prices unless a different price is specified in the contract in which case that price is used. Revenue is not recognized for the production in tanks, oil marketed on behalf of joint owners in ENP’s properties, or oil in pipelines that has not been delivered to the purchaser.

Natural gas imbalances at December 31, 2010 and 2009 were 28,370 million British thermal units (“MMBtu”) and 15,139 MMBtu, respectively, over-delivered to ENP, the value of which was approximately $0.1 million and $0.1 million, respectively.

Marketing Revenues and Expenses

In March 2007, ENP acquired a crude oil pipeline and a natural gas pipeline as part of the Big Horn Basin acquisition. Natural gas volumes are purchased from numerous gas producers at the inlet of the pipeline and resold downstream to various local and off-system markets. In addition, pipeline tariffs are collected for transportation through the crude oil pipeline.

Marketing revenues includes the sales of oil and natural gas purchased from third parties, as well as pipeline tariffs charged for transportation volumes through ENP’s pipelines. Marketing revenues derived from sales of oil or natural gas purchased from third parties are recognized when persuasive evidence of a sales arrangement exists, delivery has occurred, the sales price is fixed or determinable, and collectibility is reasonably assured. As ENP takes title to the oil and natural gas and has risks and rewards of ownership, these transactions are presented gross in the accompanying Consolidated Statements of Operations, unless they meet the criteria for netting as outlined in the “Accounting for Purchases and Sales of Inventory with the Same Counterparty” topic of the FASC.

Shipping Costs

Shipping costs in the form of pipeline fees and trucking costs paid to third parties are incurred to transport oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in “Production taxes and marketing,” in the accompanying Consolidated Statements of Operations.

Derivatives

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 revolving credit facility. ENP also uses derivative instruments in the form of interest rate swaps, which hedge risk related to interest rate fluctuation.

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

ENP elected to designate its outstanding interest rate swaps as cash flow hedges through December 31, 2010. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized in earnings and included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations. Effective January 1, 2011, ENP elected to de-designate its outstanding interest rate swaps as cash flow hedges and therefore, will begin to recognize changes in the fair market value of its interest rate swaps in the Consolidated Statement of Operations beginning in 2011.

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

Earnings Per Unit

ENP’s net income (loss) is allocated to partners equity accounts in accordance with the provisions of the partnership agreement. For purposes of calculating earnings per unit, ENP allocates net income (loss) to its limited partners and participating securities, including general partner units, each quarter under the provisions of the “Earnings Per Share” topic of the FASC, which requires earnings per unit to be calculated using the two-class method. Under the two-class method of calculating earnings per unit, earnings are allocated to participating securities as if all the earnings for the period had been distributed. A participating security is any security that may participate in distributions with common units. For purposes of calculating earnings per unit, general partner units, unvested phantom units, and unvested management incentive units are considered participating securities. Net income (loss) per common 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. Please read “Note 8. Earnings Per Unit” for additional discussion.

Comprehensive Income (Loss)

ENP has elected to show comprehensive income (loss) as part of its Consolidated Statements of Partners’ Equity and Comprehensive Income (Loss) rather than in its Consolidated Statements of Operations or in a separate statement.

Reclassifications

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

New Accounting Pronouncements

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

In December 2008, the United States Securities and Exchange Commission (the “SEC”) issued Release 33-8995, which amends oil and natural gas reporting requirements under Regulations S-K and S-X. Release 33-8995 also adds a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which is being phased out. Release 33-8995 permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Release 33-8995 will also allow companies to disclose their probable and possible reserves to investors at the company’s option. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than a year-end price, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. Release 33-8995 was prospectively effective for financial statements issued for fiscal years ending on or after December 31, 2009.

Note 3. Acquisitions

Rockies and Permian Basin Assets

In August 2009, ENP acquired certain oil and natural gas properties and related assets in the Big Horn Basin in Wyoming, the Permian Basin in West Texas and New Mexico, and the Williston Basin in Montana and North Dakota (the “Rockies and Permian Basin Assets”) from Encore Operating, L.P. (“Encore Operating”), at the time a wholly owned subsidiary of EAC, for approximately $179.6 million in cash, which was financed through borrowings under ENP’s revolving credit facility and proceeds from the issuance of ENP common units to the public.

Williston Basin Assets

In June 2009, ENP acquired certain oil and natural gas properties and related assets in the Williston Basin in North Dakota and Montana (the “Williston Basin Assets”) from Encore Operating for approximately $25.2 million in cash, which was financed through borrowings under ENP’s revolving credit facility and proceeds from the issuance of ENP common units to the public.

Vinegarone Assets

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

Arkoma Basin Assets

In January 2009, ENP acquired certain oil and natural gas properties and related assets in the Arkoma Basin in Arkansas and royalty interest properties primarily in Oklahoma, as well as 10,300 unleased mineral acres (the “Arkoma Basin Assets”) from Encore Operating for approximately $46.4 million in cash, which was financed through borrowings under ENP’s revolving credit facility.

Permian and Williston Basin Assets

In February 2008, ENP acquired certain oil and natural gas properties and related assets in the Permian Basin in West Texas and in the Williston Basin in North Dakota (the “Permian and Williston Basin Assets”) from Encore Operating for approximately $125.0 million in cash and 6,884,776 ENP common units, which were valued at approximately $125.0 million at the time of the acquisition. However, no accounting value was ascribed to the common units as the cash consideration exceeded Encore Operating’s carrying value of the properties. The cash portion of the purchase price was financed through borrowings under ENP’s revolving credit facility.

In May 2008, ENP acquired an existing net profits interest in certain of its properties in the Permian Basin in West Texas from an independent energy company for 283,700 ENP common units, which were valued at approximately $5.8 million at the time of the acquisition.

Note 4. Commitments and Contingencies

Litigation

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 position, results of operations, liquidity, or ability to pay distributions.

Leases

ENP leases equipment that have non-cancelable lease terms in excess of one year. The following table summarizes by year the remaining non-cancelable future payments under these operating leases as of December 31, 2010 (in thousands):

2011	$	687
2012		515
2013		-
2014		-
2015		-
Thereafter		-
	$	1,202

ENP’s operating lease rental expense was approximately $1.3 million, $1.1 million, and $1.0 million during the years ended December 31, 2010, 2009, and 2008, respectively.

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 periods indicated:

	Year Ended December 31,
	2010			2009
	(in thousands)
Future abandonment liability at January 1	$	13,130		$	12,376
Acquisition of properties		-			67
Wells drilled		-			22
Accretion of discount		736			709
Plugging and abandonment costs incurred		(254	)		(164	)
Revision of previous estimates		226			120
Future abandonment liability at December 31	$	13,838		$	13,130

As of December 31, 2010, $13.1 million of ENP’s asset retirement obligations were long-term and recorded in “Future abandonment cost, net of current portion” and $0.7 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. Long-Term Debt

Revolving Credit Facility

ENP is a party to a five-year credit agreement dated March 7, 2007 (as amended, the “Credit Agreement”). The Credit Agreement matures on March 7, 2012. Any outstanding borrowings under the Credit Agreement will become a current liability in March 2011. ENP is currently evaluating our options including letting any outstanding borrowings under the Credit Agreement if a merger with Vanguard is imminent, extending the term of the Credit Agreement, or refinancing under a new revolving credit facility. Based on discussions with banks, all options are currently viable.

In November 2009, ENP amended the Credit Agreement, which amendment was effective upon the closing of the Merger, to, among other things, permit the consummation of the Merger not being treated as a “Change of Control” under the Credit Agreement. Denbury paid a fee of approximately $0.9 million for this bank waiver and did not seek reimbursement from ENP for this payment. As such, the $0.9 million paid by Denbury is reflected as a capital contribution to ENP by Denbury in its then capacity as the parent of the General Partner and is included in “General and administrative expense” in the accompanying Consolidated Statement of Operations for the year ended December 31, 2010 as a non-cash expense.

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 triggers upon (1) the failure of Vanguard to continue to control the General Partner, (2) the acquisition by any person or group, directly or indirectly, of equity interests representing more than 35% of the total voting power in Vanguard, or (3) the occupation of a majority of the seats on the board of managers of Vanguard by persons who were neither (x) nominated by the board of managers of Vanguard nor (y) appointed by managers 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 million, which is redetermined semi-annually and upon requested special redeterminations. On December 31, 2010, there were $234 million of outstanding borrowings and $141 million of borrowing capacity under the Credit Agreement.

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

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

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 under the Credit Agreement bear interest at the Eurodollar rate plus the applicable margin indicated in the following table, and base rate loans under the Credit Agreement bear interest at the base rate plus the applicable margin indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	Applicable Margin for	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 London Interbank Offered Rate (“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 covenants including, among others, the following:

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

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

·	a restriction on creating liens on ENP’s assets and the assets of 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 of not less than 1.0 to 1.0;

·	a requirement that ENP maintain a ratio of consolidated EBITDA, as defined in the Credit Agreement, to the sum of consolidated net interest expense plus letter of credit fees of not less than 2.5 to 1.0; and

·	a requirement that ENP maintain a ratio of consolidated funded debt to consolidated adjusted EBITDA, as defined in the Credit Agreement, of not more than 3.5 to 1.0.

As of December 31, 2010, ENP were 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 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.

Long-Term Debt Maturities

The following table shows ENP’s long-term debt maturities as of December 31, 2010:

	Payments Due by Period
	Total		2011		2012		2013		2014		2015		Thereafter
	(in thousands)
Credit Agreement	$	234,000	$	-	$	234,000	$	-	$	-	$	-	$	-

During the years ended December 31, 2010, 2009, and 2008, the weighted average interest rate for total indebtedness was 5.3 percent, 5.0 percent, and 4.8 percent, respectively.

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 provides information regarding ENP’s distributions of available cash for the periods indicated:

		Cash Distribution
	Date	Declared per			Total
	Declared	Common Unit		Date Paid	Distribution
2010					(in thousands)
Quarter ended December 31	1/27/2011	$	0.5000	2/14/2011	$	22,923
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
2009
Quarter ended December 31	1/25/2010	$	0.5375	2/12/2010		24,642
Quarter ended September 30	10/26/2009	$	0.5375	11/13/2009		24,642
Quarter ended June 30	7/27/2009	$	0.5125	8/14/2009		23,481
Quarter ended March 31	4/27/2009	$	0.5000	5/15/2009		16,813
2008
Quarter ended December 31	1/26/2009	$	0.5000	2/13/2009		16,813
Quarter ended September 30	11/7/2008	$	0.6600	11/14/2008		22,191
Quarter ended June 30	8/11/2008	$	0.6881	8/14/2008		23,119
Quarter ended March 31	5/9/2008	$	0.5755	5/15/2008		19,316
2007
Quarter ended December 31	2/6/2008	$	0.3875	2/14/2008		9,843

Shelf Registration Statement on Form S-3

In November 2008, ENP’s “shelf” registration statement on Form S-3 was declared effective by the SEC. Under the shelf registration statement, ENP may offer common units, senior debt, or subordinated debt in one or more offerings with a total initial offering price of up to $1 billion.

Public Offerings of Common Units

In July 2009, ENP issued 9,430,000 common units under its shelf registration statement at a price to the public of $14.30 per common unit. ENP used the net proceeds of approximately $129.2 million, after deducting the underwriters’ discounts and commissions of $5.4 million, in the aggregate, and offering costs of approximately $0.2 million, to fund a portion of the purchase price of the Rockies and Permian Basin Assets.

In May 2009, ENP issued 2,760,000 common units under its shelf registration statement at a price to the public of $15.60 per common unit. ENP used the net proceeds of approximately $40.9 million, after deducting the underwriters’ discounts and commissions of $1.9 million, in the aggregate, and offering costs of approximately $0.2 million, to fund the purchase price of the Vinegarone Assets and a portion of the purchase price of the Williston Basin Assets.

Note 8. Earnings Per Unit

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

	Year Ended December 31,
	2010			2009			2008
	(in thousands, except per unit amounts)
Net income (loss)	$	32,070		$	(40,329	)	$	220,756
Less: net income for pre-partnership operations of
assets acquired from affiliates		-			(176	)		(51,640	)
Net income (loss) attributable to unitholders	$	32,070		$	(40,505	)	$	169,116

Numerator:
Numerator for basic earnings per unit:
Net income (loss) attributable to unitholders	$	32,070		$	(40,505	)	$	169,116
Less: distributions earned by participating securities		(1,010	)		(1,054	)		(4,498	)
Plus: cash distributions in excess of (less than) income allocated
to the general partner		662			1,646			(1,548	)
Net income (loss) allocated to limited partners		31,722			(39,913	)		163,070
Plus: income allocated to dilutive participating securities		-			-			3,398
Net income (loss) allocated to limited partners	$	31,722		$	(39,913	)	$	166,468

Denominator:
Denominator for basic earnings per unit:
Weighted average common units outstanding		45,331			39,366			30,568
Effect of dilutive management incentive units		-			-			1,367
Effect of dilutive phantom units (a)		6			-			3
Denominator for diluted earnings per unit		45,337			39,366			31,938

Net income (loss) per common unit:
Basic	$	0.70		$	(1.01	)	$	5.33
Diluted	$	0.70		$	(1.01	)	$	5.21

_________

(a)	For the year ended December 31, 2009, 56,250 phantom units were outstanding but were excluded from the diluted earnings per unit calculations because their effect would have been antidilutive. Please read “Note 9. Unit-Based Compensation Plans” for additional discussion of phantom units.

Note 9. Unit-Based Compensation Plans

Management Incentive Units

In May 2007, the board of directors of the General Partner issued 550,000 management incentive units to certain executive officers of the General Partner. During 2008, the management incentive units became convertible into ENP common units, at the option of the holder, at a ratio of one management incentive unit to approximately 3.1186 ENP common units, and all 550,000 management incentive units were converted into 1,715,205 ENP common units.

The fair value of the management incentive units was estimated on the date of grant using a discounted dividend model. During 2008, ENP recognized non-cash unit-based compensation expense for the management incentive units of approximately $4.8 million, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. There have been no additional issuances of management incentive units.

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. As of December 31, 2010, there were 1,075,000 common units available for issuance under the LTIP.

Phantom Units. As a result of the change of control of the General Partner in conjunction with the Merger of EAC with and into Denbury, 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 during March 2010. The fair value of these phantom units was approximately $1.2 million on the date of the Merger. During the year ended December 31, 2010, 2009, and 2008, ENP recognized non-cash unit-based compensation expense related to phantom units of approximately $0.7 million (upon closing of the Merger on March 9, 2010), $0.4 million, and $0.3 million, respectively, which is included in “General and administrative expense” in the accompanying Consolidated Statements of Operations. As of December 31, 2010, there were no outstanding phantom units.

During 2009 and 2008, ENP issued 25,000 and 30,000, respectively, phantom units to members of the General Partner’s board of directors, the vesting of which is dependent only on the passage of time and continuation as a board member. During 2009 and 2008, there were 12,500 and 6,250, respectively, phantom units that vested, the total fair value of which was $0.2 million and $0.1 million, respectively.

Note 10. Fair Value Measurements

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

	December 31,
	2010				2009
	Book		Fair		Book		Fair
	Value		Value		Value		Value
	(in thousands)
Assets:
Cash and cash equivalents	$	1,380	$	1,380	$	1,754	$	1,754
Accounts receivable - trade		22,795		22,795		24,543		24,543
Accounts receivable - affiliate		-		-		8,213		8,213
Commodity derivative contracts		15,682		15,682		26,304		26,304
Liabilities:
Accounts payable - trade		2,103		2,103		577		577
Accounts payable - affiliate		98		98		2,780		2,780
Credit Agreement		234,000		232,517		255,000		252,047
Commodity derivative contracts		35,011		35,011		19,547		19,547
Interest rate swaps		1,442		1,442		3,669		3,669

The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of the Credit Agreement approximates fair value as the interest rate is variable; however, ENP adjusted the estimated fair value for its estimated nonperformance risk of approximately $1.5 million and $3.0 million at December 31, 2010 and 2009, respectively. The nonperformance risk was determined using industry credit default swaps. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

Commodity Derivative Contracts

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

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

The following tables summarize ENP’s open commodity derivative contracts as of December 31, 2010:

Oil Derivative Contracts

	Average		Weighted		Average		Weighted		Average		Weighted
	Daily		Average		Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Cap		Cap		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Volume		Price		Value
	(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(Bbl)		(per Bbl)		(in thousands)
2011													$	(8,343	)
		1,880	$	80.00		1,440	$	95.41		425	$	87.10
		1,000		70.00		-		-		760		78.46
		760		65.00		-		-		250		69.65
2012														(13,806	)
		750		70.00		500		82.05		1,290		87.60
		1,510		65.00		250		79.25		1,300		76.54
2013														(4,944	)
		-		-		-		-		3,550		88.95
2014														(3,813	)
		-		-		-		-		3,200		88.95
													$	(30,906	)

Natural Gas Derivative Contracts

	Average		Weighted		Average		Weighted		Asset
	Daily		Average		Daily		Average		(Liability)
	Floor		Floor		Swap		Swap		Fair Market
Period	Volume		Price		Volume		Price		Value
	(Mcf)		(per Mcf)		(Mcf)		(per Mcf)		(in thousands)
2011									$	8,633
		3,398	$	6.31		7,952	$	6.36
		-		-		550		5.86
		-		-		1,700		4.71
2012										3,600
		898		6.76		5,452		6.26
		-		-		2,050		5.26
		-		-		1,700		4.71
2013										(656	)
		-		-		6,500		5.21
		-		-		1,700		4.71
									$	11,577

Counterparty Risk. At December 31, 2010, ENP had committed 10 percent or greater (in terms of fair market value) of either its oil or natural gas derivative contracts in asset positions to the following counterparties:

	Fair Market Value of		Fair Market Value of
	Oil Derivative		Natural Gas Derivative
	Contracts		Contracts
Counterparty	Committed		Committed
	(in thousands)
BNP Paribas	$	1,166	$	2,552
Calyon		986		6,466
Royal Bank of Canada		1,079		3,605

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. ENP’s accounting policy is to not offset fair value amounts for derivative instruments in the accompanying Consolidated Balance Sheets.

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 swaps as of December 31, 2010, all of which were entered into with Bank of America, N.A.:

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

During the years ended December 31, 2010, 2009, and 2008, settlements of interest rate swaps increased ENP’s interest expense by approximately $3.9 million, $3.8 million, and $0.2 million, respectively.

Current Period Impact

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

	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Ineffectiveness on interest rate swaps	$	5		$	2		$	372
Mark-to-market loss (gain)		16,271			94,438			(101,595	)
Premium amortization		9,816			23,245			8,936
Receipts, net of settlements		(11,946	)		(70,221	)		(4,593	)
Total derivative fair value loss (gain)	$	14,146		$	47,464		$	(96,880	)

Effective January 1, 2011, ENP elected to de-designate its outstanding interest rate swaps as cash flow hedges and therefore, will begin to recognize changes in the fair market value of its interest rate swaps in the Consolidated Statement of Operations beginning in 2011.

Accumulated Other Comprehensive Loss

At December 31, 2010 and 2009, “Accumulated other comprehensive loss” on the accompanying Consolidated Balance Sheets consisted entirely of deferred losses, net of tax, on ENP’s interest rate swaps of $1.2 million and $3.4 million, respectively. During the twelve months ended December 31, 2011, ENP expects to reclassify $1.2 million of deferred losses associated with its interest rate swaps from accumulated other comprehensive loss to interest expense. The actual gains or losses ENP will realize from its interest rate swaps may vary significantly from the deferred losses recorded in “Accumulated other comprehensive loss” in the accompanying Consolidated Balance Sheet due to the fluctuation of interest rates.

Tabular Disclosures of Fair Value Measurements

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

	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet	December 31,		December 31,		Balance Sheet	December 31,		December 31,
	Location	2010		2009		Location	2010		2009
Derivatives not designated as hedges
Commodity derivative contracts	Derivatives - current	$	10,196	$	12,881	Derivatives - current	$	9,906	$	6,393
Commodity derivative contracts	Derivatives - noncurrent		5,486		13,423	Derivatives - noncurrent		25,105		13,154
Total derivatives not designated as hedges		$	15,682	$	26,304		$	35,011	$	19,547

Derivatives designated as hedges
Interest rate swaps	Derivatives - current	$	-	$	-	Derivatives - current	$	1,216	$	3,421
Interest rate swaps	Derivatives - noncurrent		-		-	Derivatives - noncurrent		226		248
Total derivatives designated as hedges		$	-	$	-		$	1,442	$	3,669
Total derivatives		$	15,682	$	26,304		$	36,453	$	23,216

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

		Amount of Loss (Gain) Recognized In Income
	Location of Loss (Gain)	Year ended December 31,
Derivatives Not Designated as Hedges	Recognized In Income	2010		2009		2008
Commodity derivative contracts	Derivative fair value loss (gain)	$	14,141	$	47,462	$	(97,252	)

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

	Amount of Loss Recognized in
	Accumulated OCI (Effective Portion)
	Year ended December 31,
Derivatives Designated as Hedges	2010		2009		2008
Interest rate swaps	$	1,693	$	2,946	$	4,505

	Amount of Loss Reclassified from Accumulated
	OCI into Income (Effective Portion)
Location of Loss Reclassified from Accumulated	Year ended December 31,
OCI into Income (Effective Portion)	2010		2009		2008
Interest expense	$	3,918	$	3,785	$	246

	Amount of Loss Recognized
	In Income as Ineffective
	Year ended December 31,
Location of Loss Recognized in Income as Ineffective	2010		2009		2008
Derivative fair value loss (gain)	$	5	$	2	$	372

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.

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

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

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

ENP adjusts the valuations from the valuation model for nonperformance risk, using management’s estimate of the counterparty’s credit quality for asset positions and ENP’s credit quality for liability positions. ENP uses multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2010:

				Fair Value Measurements at Reporting Date Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable Inputs			Unobservable Inputs
Description	Asset (Liability)			(Level 1)		(Level 2)			(Level 3)
	(in thousands)
Oil derivative contracts - swaps	$	(27,240	)	$	-	$	(27,240	)	$	-
Oil derivative contracts - floors and caps		(3,666	)		-		-			(3,666	)
Natural gas derivative contracts - swaps		8,510			-		8,510			-
Natural gas derivative contracts - floors and caps		3,067			-		-			3,067
Interest rate swaps		(1,442	)		-		(1,442	)		-
Total	$	(20,771	)	$	-	$	(20,172	)	$	(599	)

The following table summarizes the changes in the fair value of ENP’s Level 3 assets and liabilities for the year ended December 31, 2010:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Oil Derivative			Natural Gas
	Contracts -			Derivative Contracts -
	Floors and Caps			Floors and Caps			Total
	(in thousands)
Balance at January 1, 2010	$	8,585		$	8,528		$	17,113
Total gains (losses):
Included in earnings		(12,654	)		4,859			(7,795	)
Settlements		403			(10,320	)		(9,917	)
Balance at December 31, 2010	$	(3,666	)	$	3,067		$	(599	)

The amount of total gains (losses) for the period included in
earnings attributable to the change in unrealized gains (losses)
relating to assets still held at the reporting date	$	(12,654	)	$	4,859		$	(7,795	)

Since ENP does not use hedge accounting for its commodity derivative contracts, all gains and losses on its Level 3 assets and liabilities are included in “Derivative fair value loss (gain)” in the accompanying Consolidated Statements of Operations.

All fair values have been adjusted for nonperformance risk resulting in a decrease of the net commodity derivative asset of approximately $0.1 million as of December 31, 2010. For commodity derivative contracts which are in an asset position, ENP uses the counterparty’s credit default swap rating. For commodity derivative contracts which are in a liability position, ENP uses the average credit default swap rating of its peer companies as ENP does not have its own credit default swap rating.

Note 11. Related Party Transactions

Administrative Services Agreement

ENP does not have any employees. The employees supporting the operations of ENP were: the employees of EAC prior to March 2010, the employees of Denbury from March 2010 to December 31, 2010, and became the employees of VNG pursuant to the Vanguard Acquisition on December 31, 2010. During 2010, Encore Operating 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 constitute gross negligence or willful misconduct. On December 31, 2010, duties under the administrative services agreement were assigned to VNG pursuant to the Vanguard Acquisition.

Encore Operating initially received an administrative fee of $1.75 per BOE of ENP’s production for such services. From April 1, 2008 to March 31, 2009, the administrative fee was $1.88 per BOE of ENP’s production. From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production. Effective April 1, 2010, the administrative fee increased to $2.06 per BOE of ENP’s production. ENP also 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 will receive the fees and reimbursements for services performed in 2011.

The administrative fee will increase in the following circumstances:

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

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

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

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

Administrative fees (including COPAS recovery) paid to Encore Operating pursuant to the administrative services agreement are included in “General and administrative expenses” in the accompanying Consolidated Statement of Operations. The reimbursements of actual third-party expenses incurred by Encore Operating on ENP’s behalf are included in “Lease operating expense” or “General and administrative expenses” in the accompanying Consolidated Statements of Operations based on the nature of the expense. The following table illustrates amounts paid by ENP to Encore Operating pursuant to the administrative service agreement for the periods indicated:

	Year Ended December 31,
	2010		2009		2008
	(in thousands)
Administrative fees (including COPAS recovery)	$	9,954	$	5,693	$	6,600
Third-party expenses		2,734		5,352		8,269

As of December 31, 2010, ENP had a payable to Vanguard of $0.1 million which is reflected as “Accounts payable – affiliate” in the accompanying Consolidated Balance Sheets. As of December 31, 2009, ENP had a payable to EAC of $2.8 million which is reflected as “Accounts payable – affiliate” in the accompanying Consolidated Balance Sheets, and a receivable from EAC of $8.2 million which is reflected as “Accounts receivable – affiliate” in the accompanying Consolidated Balance Sheets.

Acquisitions

As previously discussed, ENP acquired from Encore Operating (1) the Permian and Williston Basin Assets in February 2008 for approximately $125.0 million in cash and the issuance of 6,884,776 ENP common units to Encore Operating, (2) the Arkoma Basin Assets in January 2009 for approximately $46.4 million in cash, (3) the Williston Basin Assets in June 2009 for approximately $25.2 million in cash, and (4) the Rockies and Permian Basin Assets in August 2009 for approximately $179.6 million in cash. Prior to acquisition by ENP, these properties were owned by EAC and were not separate legal entities.

In addition to payroll-related expenses, EAC incurred general and administrative expenses related to leasing office space and other corporate overhead expenses during the period these properties were owned by EAC. A portion of EAC’s consolidated general and administrative expenses was allocated to ENP and included in the accompanying Consolidated Statements of Operations based on the respective percentage of BOE produced by the properties in relation to the total BOE produced by EAC on a consolidated basis for the years ended December 31, 2009 and 2008. A portion of EAC’s consolidated indirect lease operating overhead expenses was allocated to ENP included in the accompanying Consolidated Statements of Operations based on its share of EAC’s direct lease operating expense for the years ended December 31, 2009 and 2008.

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. During the years ended December 31, 2010, 2009, and 2008, ENP distributed $93.4 million, $81.7 million, and $74.5, million, of which $43.7 million, $43.9 million, and $46.9 million, respectively, was paid to the General Partner and its affiliates.

Note 12. Subsequent Events

On January 27, 2011, the board of directors of the General Partner declared an ENP cash distribution for the fourth quarter of 2010 to unitholders of record as of the close of business on February 7, 2011 of $0.50 per unit or approximately $22.9 million of which $10.7 million is expected to be paid to the General Partner and its affiliates. The distribution is expected to be paid to unitholders on or about February 14, 2011.

In January 2011, ENP issued 140,007 restricted units under the LTIP to Vanguard field employees performing services on ENP’s properties (grant was equal to one-year salary for each employee who received a grant). 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.

Attached files

Vanguard Natural Resources, Inc. Reports

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