Vanguard Natural Resources, Inc. - FORM 8-K/A - EX-99.3

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-99.1 - Vanguard Natural Resources, Inc.	exhibit99-1.htm
EX-99.4 - Vanguard Natural Resources, Inc.	exhibit99-4.htm

Exhibit 99.3

ENCORE ENERGY PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit amounts)

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

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

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

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

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

Commitments and contingencies (see Note 12)

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

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

(unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2011			2010			2011			2010
Revenues:
Oil	$	38,814		$	33,765		$	122,869		$	105,732
Natural gas		8,811			6,497			20,872			21,407
Natural gas liquids		3,554			2,521			8,978			9,001
Marketing		126			60			207			207
Commodity derivative fair value gain (loss) - realized		(2,818	)		1,342			(7,616	)		1,959
Commodity derivative fair value gain (loss) - unrealized		82,914			(8,922	)		58,318			12,521
Total revenues		131,401			35,263			203,628			150,827

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

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

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

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

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

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

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

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

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENT OF PARTNERS’ EQUITY AND COMPREHENSIVE INCOME

(in thousands, except per unit amounts)

(unaudited)

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

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

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

ENCORE ENERGY PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Nine months ended
	September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	103,217		$	46,318
Adjustments to reconcile net income to net cash provided
by operating activities:
Depletion, depreciation, amortization and accretion		35,568			38,472
Deferred taxes		127			(55	)
Non-cash equity-based compensation expense		667			1,043
Non-cash derivative gain		(50,424	)		(5,046	)
Gain on acquisitions of oil and natural gas properties		(815	)		-
Other		1,143			2,182
Changes in operating assets and liabilities:
Accounts receivable		(12,616	)		13,169
Other current assets		(514	)		(36	)
Other assets		-			(15	)
Accounts payable		2,461			(583	)
Other current liabilities		7,135			2,981
Net cash provided by operating activities		85,949			98,430

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

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

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

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

ENCORE ENERGY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1. Description of Business

Encore Energy Partners LP (together with its subsidiaries, “ENP”) is engaged in the acquisition, exploitation, and development of oil and natural gas reserves from onshore fields in the United States. Encore Energy Partners GP LLC (the “General Partner” or “ENP GP”), a Delaware limited liability company which is a wholly-owned subsidiary of Vanguard Natural Resources, LLC (together with its subsidiaries, “Vanguard” or “VNR”), a publicly traded Delaware limited liability company, serves as ENP’s general partner and Encore Energy Partners Operating LLC (“OLLC”), a Delaware limited liability company and wholly-owned subsidiary of ENP, owns and operates ENP’s properties. ENP’s properties and oil and natural gas reserves are located in four operating areas:

·	the Big Horn Basin in Wyoming and Montana;

·	the Permian Basin in West Texas and New Mexico;

·	the Williston Basin in North Dakota and Montana; and

·	the Arkoma Basin in Arkansas and Oklahoma.

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

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

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

Note 2. Summary of Significant Accounting Policies

(a)	Basis of Presentation

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

In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments necessary to present fairly, in all material respects, ENP’s financial position as of September 30, 2011, results of operations for the three and nine months ended September 30, 2011 and 2010, respectively, and cash flows for the nine months ended September 30, 2011 and 2010, respectively. All adjustments are of a normal recurring nature. These interim results are not necessarily indicative of results for an entire year.

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

(b)	New Pronouncements Issued But Not Yet Adopted

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

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

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

(c)	Use of Estimates

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

Reclassifications

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

Note 3. Acquisitions

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

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

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

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

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

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

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

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

Note 4. Proved Properties

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

	September 30,		December 31,
	2011		2010
	(in thousands)
Proved leasehold costs	$	741,421	$	609,910
Wells and related equipment - completed		261,386		248,017
Wells and related equipment - in process		44		72
Total proved properties	$	1,002,851	$	857,999

Note 5. Fair Value Measurements

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

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

The book values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term nature of these instruments. The book value of ENP’s five-year credit agreement (as amended, the “Credit Agreement”) approximates fair value as the interest rate is variable; however, ENP adjusted the estimated fair value for estimated nonperformance risk of approximately $1.5 million at December 31, 2010. The nonperformance risk was determined using industry credit default swaps. No adjustment for nonperformance risk was made at September 30, 2011 as the Credit Agreement matures within one year and any adjustment would be considered insignificant. Commodity derivative contracts and interest rate swaps are marked-to-market each period and are thus stated at fair value in the accompanying Consolidated Balance Sheets.

Derivative Policy

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

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

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

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

Commodity Derivative Contracts

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

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

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

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

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

Basis Swaps

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

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

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

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

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

Swaptions

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

Interest Rate Swaps

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

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

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

Current Period Impact

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

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

Accumulated Other Comprehensive Loss

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

Tabular Disclosures of Fair Value Measurements

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

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

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

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

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

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

Fair Value Hierarchy

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

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

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

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

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

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

The following table sets forth ENP’s assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011:

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

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

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

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

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

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

Note 6. Asset Retirement Obligations

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

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

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

Note 7. Credit Agreement

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Note 8. Partners’ Equity and Distributions

Distributions

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

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

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

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

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

Note 9. Earnings Per Unit

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

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

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

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

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

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

Note 10. Unit-Based Compensation Plans

Long-Term Incentive Plan

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

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

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

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

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

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

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

Note 11. Comprehensive Income

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

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

Note 12. Commitments and Contingencies

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

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

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

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

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

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

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

Note 13. Related Party Transactions

Administrative Services Agreement

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

From April 1, 2009 to March 31, 2010, the administrative fee was $2.02 per BOE of ENP’s production, and from April 1, 2010 through March 31, 2011, the fee was increased to $2.06 per BOE. Effective April 1, 2011, the administrative fee decreased to $2.05 per BOE of ENP’s production. ENP also reimbursed Encore Operating for actual third-party expenses incurred on ENP’s behalf. In addition, Encore Operating was entitled to retain any COPAS overhead charges associated with drilling and operating wells that would otherwise be paid by non-operating interest owners to the operator. Pursuant to the Vanguard Acquisition, VNG received the same fees and reimbursements for services performed during the first nine months of 2011 as previously received by Encore Operating.

The administrative fee will increase in the following circumstances:

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

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

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

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

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

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

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

Distributions

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

Note 14. Subsequent Events

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

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

Vanguard Natural Resources, Inc. - FORM 8-K/A - EX-99.3 - January 9, 2012

Attached files

Vanguard Natural Resources, Inc. Reports