Edgar Filing: Vanguard Natural Resources, LLC

form10-q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)
x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number: 001-33756

Vanguard Natural Resources, LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware		61-1521161
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

5847 San Felipe, Suite 3000 Houston, Texas		77057
(Address of Principal Executive Offices)		(Zip Code)

(832) 327-2255

(Registrant’s Telephone Number, Including Area Code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

x Yes o No

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes x No

Common units outstanding on November 4, 2011: 29,836,019.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS

PART I - FINANCIAL INFORMATION
Item 1.	Unaudited Financial Statements
	Consolidated Statements of Operations	3
	Consolidated Statements of Comprehensive Income	4
	Consolidated Balance Sheets	5
	Consolidated Statements of Members’ Equity	6
	Consolidated Statements of Cash Flows	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	52

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Removed and Reserved	54
Item 5.	Other Information	54
Item 6.	Exhibits	54

GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:

/day	= per day	Mcf	= thousand cubic feet

Bbls	= barrels	Mcfe	= thousand cubic feet of natural gas equivalents

BOE	= barrel of oil equivalent	MMBOE	= million barrels of oil equivalent

Btu	= British thermal unit	MMBtu	= million British thermal units

MBbls	= thousand barrels	MMcf	= million cubic feet

MBOE	= thousand barrels of oil equivalent	NGLs	= natural gas liquids

When we refer to oil, natural gas and NGLs in “equivalents,” we are doing so to compare quantities of NGLs and oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which 42 gallons is equal to one Bbl of oil or one Bbl of NGLs and one Bbl of oil or one Bbl of NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

References in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), Trust Energy Company, LLC (“TEC”), VNR Holdings, LLC (“VNRH”), Ariana Energy, LLC (“Ariana Energy”), Vanguard Permian, LLC (“Vanguard Permian”), VNR Finance Corp. (“VNRF”), Encore Energy Partners GP LLC (“ENP GP”), Encore Energy Partners LP (“ENP”), Encore Energy Partners Operating LLC (“OLLC”), Encore Energy Partners Finance Corporation (“ENPF”), Encore Clear Fork Pipeline LLC (“ECFP”) and (2) “Vanguard Predecessor,” “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

PART I – FINANCIAL INFORMATION

Item 1. Unaudited Financial Statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)

	Three Months Ended September 30,							Nine Months Ended September 30,
	2011			2010				2011			2010
Revenues:
Oil, natural gas and NGLs	$	74,429		$	22,684		$	226,838		$	62,200
Loss on commodity cash flow hedges		(635	)		(568	)		(2,307	)		(2,127	)
Realized gain on other commodity derivative contracts		1,902			6,513			4,474			18,274
Unrealized gain (loss) on other commodity derivative contracts		109,639			(9,388	)		68,625			1,332
Total revenues		185,335			19,241			297,630			79,679

Costs and expenses:
Production:
Lease operating expenses		15,393			4,838			43,960			13,545
Production and other taxes		7,693			1,753			21,319			5,215
Depreciation, depletion, amortization, and accretion		21,419			6,179			62,797			16,130
Selling, general and administrative expenses		5,330			1,104			16,436			3,638
Total costs and expenses		49,835			13,874			144,512			38,528

Income from operations		135,500			5,367			153,118			41,151

Other income (expense):
Interest expense		(7,509	)		(1,708	)		(21,137	)		(4,522	)
Realized loss on interest rate derivative contracts		(664	)		(511	)		(2,208	)		(1,624	)
Gain on interest rate cash flow hedges		—			101			39			216
Unrealized loss on interest rate derivative contracts		(1,939	)		(1,337	)		(1,641	)		(2,021	)
Net gain (loss) on acquisition of oil and natural gas properties		487			—			(383	)		(5,680	)
Other		70			—			76			—
Total other expense		(9,555	)		(3,455	)		(25,254	)		(13,631	)

Net income		125,945			1,912			127,864			27,520
Less:
Net income attributable to non-controlling interest		50,061			—			50,593			—
Net income attributable to Vanguard unitholders	$	75,884		$	1,912		$	77,271		$	27,520

Net income per Common and Class B units – basic	$	2.51		$	0.09		$	2.56		$	1.35

Net income per Common and Class B units – diluted	$	2.50		$	0.09		$	2.55		$	1.34

Weighted average units outstanding:
Common units – basic		29,839			21,671			29,792			20,037
Common units – diluted		29,981			21,710			29,855			20,071
Class B units – basic & diluted		420			420			420			420

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in thousands)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010			2011		2010

Net income	$	125,945	$	1,912	$	127,864	$	27,520

Net gains from derivative contracts:
Reclassification adjustments for settlements		635		467		2,268		1,911
Other comprehensive income		635		467		2,268		1,911

Comprehensive income	$	126,580	$	2,379	$	130,132	$	29,431

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

	September 30, 2011			December 31, 2010
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	3,346		$	1,828
Trade accounts receivable, net		45,311			32,961
Derivative assets		27,919			16,523
Other current assets		4,287			1,474
Total current assets		80,863			52,786

Oil and natural gas properties, at cost		1,518,536			1,312,107
Accumulated depletion		(310,229	)		(248,704	)
Oil and natural gas properties evaluated, net – full cost method		1,208,307			1,063,403

Other assets
Goodwill		420,955			420,955
Other intangible assets, net		8,882			9,017
Derivative assets		19,246			1,479
Deferred financing costs		2,868			5,649
Other assets		2,982			1,903
Total assets	$	1,744,103		$	1,555,192

Liabilities and members’ equity

Current liabilities
Accounts payable:
Trade	$	2,878		$	3,156
Affiliate		1,461			668
Accrued liabilities:
Lease operating		6,227			5,156
Developmental capital		2,899			996
Interest		591			310
Production and other taxes		16,908			11,793
Derivative liabilities		1,813			6,209
Deferred swap premium liability		432			1,739
Oil and natural gas revenue payable		3,767			2,241
Other		5,083			8,202
Current portion, long-term debt		531,000			175,000
Total current liabilities		573,059			215,470

Long-term debt		218,500			410,500
Derivative liabilities		4,423			30,384
Asset retirement obligations, net of current portion		34,364			29,434
Other long-term liabilities		63			11
Total liabilities		830,409			685,799

Commitments and contingencies

Members’ equity
Members’ capital, 29,836,019 common units issued and outstanding at September 30, 2011 and 29,666,039 at December 31, 2010		346,612			318,597
Class B units, 420,000 issued and outstanding at September 30, 2011 and December 31, 2010		4,450			5,166
Accumulated other comprehensive loss		(764	)		(3,032	)
Total VNR members’ equity		350,298			320,731
Non-controlling interest in subsidiary		563,396			548,662
Total members’ equity		913,694			869,393
Total liabilities and members’ equity	$	1,744,103		$	1,555,192

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2011 AND THE YEAR ENDED DECEMBER 31, 2010

(in thousands, except per unit data)

(Unaudited)

	Common Units			Common Units Amount			Class B Units		Class B Units Amount			Accumulated Other Comprehensive Loss			Non-controlling Interest			Total Members’ Equity
Balance at January 1, 2010		18,416		$	59,873			420	$	5,930		$	(5,517	)	$	—		$	60,286
Distributions to members ($0.525 per unit to unitholders of record February 5, 2010 and May 7, 2010 and $0.55 per unit to unitholders of record August 6, 2010 and November 5, 2010, respectively)		—			(45,747	)		—		(903	)		—			—			(46,650	)
Issuance of common units, net of offering costs of $530		8,263			193,541			—		—			—			—			193,541
Issuance of common units in connection with Encore Acquisition		3,137			93,020			—		—			—			—			93,020
Redemption of common units		(150	)		(3,651	)		—		—			—			—			(3,651	)
Unit-based compensation		—			(324	)		—		139			—			—			(185	)
Net income		—			21,885			—		—			—			—			21,885
Settlement of cash flow hedges in other comprehensive income		—			—			—		—			2,485			—			2,485
Non-controlling interest in subsidiary		—			—			—		—			—			548,662			548,662
Balance at December 31, 2010		29,666		$	318,597			420	$	5,166		$	(3,032	)	$	548,662		$	869,393
Distributions to members ($0.56 per unit to unitholders of record February 7, 2011, $0.57 per unit to unitholders of record May 6, 2011, $0.575 per unit to unitholders of record August 5, 2011)		—			(50,821	)		—		(716	)		—			—			(51,537	)
Reduction of equity proceeds for offering costs		—			(126	)		—		—			—			—			(126	)
Unit-based compensation		170			1,691			—		—			—			—			1,691
Net income		—			77,271			—		—			—			50,593			127,864
Settlement of cash flow hedges in other comprehensive income		—			—			—		—			2,268			—			2,268
ENP cash distributions to non-controlling interest		—			—			—		—			—			(35,859	)		(35,859	)
Balance at September 30, 2011		29,836		$	346,612			420	$	4,450		$	(764	)	$	563,396		$	913,694

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(in thousands)

	Nine Months Ended September 30,
	2011			2010
Operating activities
Net income	$	127,864		$	27,520
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion		62,797			16,130
Amortization of deferred financing costs		3,161			962
Deferred taxes		96			—
Unit-based compensation		1,821			656
Non-cash compensation associated with phantom units granted to officers		310			103
Amortization of premiums paid on derivative contracts		9,501			1,479
Amortization of value on derivative contracts acquired		154			1,657
Unrealized (gains) losses on other commodity and interest rate derivative contracts		(66,984	)		689
Net loss on acquisition of oil and natural gas properties		383			5,680
Changes in operating assets and liabilities:
Trade accounts receivable		(12,350	)		(1,224	)
Other receivables		—			354
Payables to affiliates		793			(286	)
Other current assets		(2,116	)		(39	)
Price risk management activities, net		(1,368	)		(217	)
Accounts payable and oil and natural gas revenue payable		1,244			564
Accrued expenses and other current liabilities		3,801			(2,998	)
Other assets		4			(23	)
Net cash provided by operating activities		129,111			51,007

Investing activities
Additions to property and equipment		(650	)		(168	)
Additions to oil and natural gas properties		(23,729	)		(13,220	)
Acquisitions of oil and natural gas properties		(183,659	)		(114,531	)
Deposits and prepayments of oil and natural gas properties		(666	)		(66	)
Proceeds from the sale of oil and natural gas properties		4,975			—
Net cash used in investing activities		(203,729	)		(127,985	)

Financing activities
Proceeds from borrowings		393,000			132,700
Repayment of debt		(229,000	)		(91,600	)
Proceeds from equity offering, net		—			72,984
Distributions to members		(51,537	)		(31,925	)
Financing costs		(380	)		(774	)
Prepaid offering costs		(88	)		(239	)
Purchase of units for issuance as unit-based compensation		—			(1,421	)
ENP distributions to non-controlling interest		(35,859	)		—
Net cash provided by financing activities		76,136			79,725
Net increase in cash and cash equivalents		1,518			2,747
Cash and cash equivalents, beginning of period		1,828			487
Cash and cash equivalents, end of period	$	3,346		$	3,234

Supplemental cash flow information:
Cash paid for interest	$	17,713		$	3,516
Non-cash investing and financing activities:
Asset retirement obligations	$	4,661		$	619
Deferred swap premium	$	9		$	—
Derivatives assumed in acquisition of oil and natural gas properties	$	130		$	—

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Description of the Business:

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. We were formed in October 2006 but effective January 5, 2007, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) was separated into our operating subsidiary and Vinland Energy Eastern, LLC ("Vinland"). We own a 100% controlling interest, through certain of our subsidiaries, in properties and oil and natural gas reserves located in four operating areas:

·	the Permian Basin in West Texas and New Mexico;

·	South Texas;

·	the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee; and

·	Mississippi.

In addition, through our interest in our subsidiary, ENP, we have, indirectly, an approximate 46.6% aggregate controlling interest in ENP’s properties and oil and natural gas reserves located in four operating areas:

·	the Permian Basin in West Texas and New Mexico;

·	the Big Horn Basin in Wyoming and Montana;

·	the Williston Basin in North Dakota and Montana; and

·	the Arkoma Basin in Arkansas and Oklahoma.

On December 31, 2010, we completed an acquisition pursuant to a purchase agreement with Denbury Resources Inc. (“Denbury”), Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Operating, L.P. (collectively, the “Encore Selling Parties” and, together with Denbury, the “Selling Parties”) to acquire (the “Encore Acquisition”) all of the member interests in ENP GP, the general partner of ENP and 20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), which represented a 46.6% aggregate equity interest in ENP at September 30, 2011. As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million.

In connection with closing of the Encore Acquisition, VNG entered into a Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, with ENP, ENP GP, Encore Operating, L.P. (“Encore Operating”), OLLC and Denbury (the “Services Agreement”). The Services Agreement was amended solely to add VNG as a party and provide for VNG to assume the rights and obligations of Encore Operating and Denbury under the previous administrative services agreement going forward.

Pursuant to the Services Agreement, VNG will provide certain general and administrative services to ENP, ENP GP and OLLC (collectively, the “ENP Group”) in exchange for a quarterly fee of $2.06 per BOE of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee is paid by ENP (the “Administrative Fee”). The Administrative Fee is subject to certain index-related adjustments on an annual basis. Effective April 1, 2011, the Administrative Fee decreased from $2.06 per BOE of ENP’s production to $2.05 per BOE as the Council of Petroleum Accountants Societies (“COPAS”) Wage Index Adjustment decreased 0.7 percent. ENP also is obligated to reimburse VNG for all third-party expenses it incurs on behalf of the ENP Group. These terms are identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement.

The fair value of the assets and liabilities we acquired on December 31, 2010 in the Encore Acquisition and cash flows associated with the transaction were included in the consolidated balance sheet as of December 31, 2010. We have consolidated ENP’s accounts since December 31, 2010, the acquisition date. See Note 2. Acquisitions for additional information.

On July 11, 2011, Vanguard and ENP announced the execution of a definitive agreement that would result in a merger whereby ENP would become a wholly-owned subsidiary of VNG through a unit-for-unit exchange. Under the terms of the definitive agreement, ENP’s public unitholders would receive 0.75 Vanguard common units in exchange for each ENP common unit they own at closing. The transaction would 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 members of the Vanguard Conflicts Committee, which is also comprised solely of independent directors, negotiated the terms on behalf of Vanguard and also voted unanimously in favor of the merger. In addition, RBC Capital Markets has issued a fairness opinion to the Vanguard Conflicts Committee stating that they believe the exchange ratio is fair, from a financial point of view, to Vanguard.

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 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, Vanguard and ENP filed a Registration Statement on Form S-4 (the “Form S-4”) with the Securities and Exchange Commission (the “SEC”), which was declared effective on October 31, 2011. The Form S-4 incorporates a joint proxy statement/prospectus which Vanguard and ENP 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, Vanguard and ENP have agreed to customary restrictions in the way they conduct their businesses.

1.	Summary of Significant Accounting Policies

The accompanying financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2010, from the audited financial statements filed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 Annual Report”). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2010 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income, members’ equity or net cash flows.

As of September 30, 2011, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2010 Annual Report.

(a)	Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of September 30, 2011 and December 31, 2010 and for the three and nine months ended September 30, 2011 and 2010 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation.

(b)	Recently Adopted Accounting Pronouncements:

In December 2010, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance which includes amendments that affect any public entity as defined by Accounting Standards Codification (“ASC”) Topic 805 “Business Combinations” (“ASC Topic 805”), that enters into business combinations that are material on an individual or aggregate basis. The amendments in this guidance specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments were effective for us on January 1, 2011. As this guidance provides only disclosure requirements, the adoption of this standard did not impact 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 International Financial Reporting Standards (“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. We have adopted this guidance early. As this guidance provides only presentation requirements, the adoption of this standard did not have any impact on our results of operations, cash flows or financial position.

(c)	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 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 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 ASC 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.

(d)	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.

(e)	Non-controlling Interest:

As of September 30, 2011, Vanguard owned approximately 46.0% of ENP's outstanding common units. Vanguard also owns 100% of ENP GP, which is ENP's general partner, for an aggregate interest of 46.6% at September 30, 2011. Since December 31, 2010, the acquisition date, we consolidated ENP as we have the ability to control the operating and financial decisions and policies of ENP through our ownership of ENP GP and reflected the non-controlling interest as a separate element of members’ equity on our Consolidated Balance Sheet. As presented in the accompanying unaudited Consolidated Balance Sheet as of September 30, 2011, the $563.4 million of “non-controlling interest” represents third-party ownership interests other than Vanguard's in ENP. As presented in the accompanying unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2011, “net income attributable to non-controlling interest” of $50.1 million and $50.6 million, respectively, represents ENP's results of operations attributable to third-party owners other than Vanguard.

2.	Acquisitions

On April 30, 2010, we entered into a definitive purchase agreement with a private seller for the acquisition of certain oil and natural gas properties located in Mississippi, Texas and New Mexico. We refer to this acquisition as the “Parker Creek Acquisition.” The purchase price for the assets was $113.1 million with an effective date of May 1, 2010. We completed this acquisition on May 20, 2010. The adjusted purchase price of $114.3 million considered final purchase price adjustments of approximately $1.2 million. The purchase price was funded by the approximate $71.5 million in net proceeds from our May 2010 equity offering and with borrowings under our existing reserve-based credit facility. In conjunction with the acquisition, we entered into crude oil hedges covering approximately 56% of the estimated production from proved producing reserves through 2013 at a weighted average price of $91.70 per barrel. In accordance with the guidance contained within ASC Topic 805 “Business Combinations”, the measurement of the fair value at acquisition date of the assets acquired in the Parker Creek Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $5.7 million, which was immediately impaired and recorded as a loss. The loss resulted from a decrease in oil prices used to value the reserves.

On November 16, 2010, we entered into a purchase agreement with the Selling Parties to acquire all of the member interests in ENP GP, the general partner of ENP and 20,924,055 common units representing limited partnership interests in ENP, representing a 46.7% aggregate equity interest in ENP. As consideration for the purchase, we paid $300.0 million in cash and paid $80.0 million in stock by issuing 3,137,255 VNR common units, at an agreed upon price of $25.50 per unit. The 3,137,255 VNR common units issued were valued at the closing price of $29.65 at December 31, 2010. We completed this acquisition on December 31, 2010. The acquisition was accounted for under the acquisition method of accounting in accordance with ASC Topic 805, which requires the assets and liabilities acquired be recorded at their fair values at the date of acquisition. The estimate of fair values resulted in goodwill of $421.0 million, which was recorded in the accompanying Consolidated Balance Sheet at December 31, 2010.

On April 28, 2011, we entered into a purchase and sale agreement with a private seller, for the acquisition of certain oil and natural gas properties located in Texas and New Mexico. We refer to this acquisition as the “Newfield Acquisition.” The purchase price for the assets was $9.1 million with an effective date of April 1, 2011. We completed this acquisition on May 12, 2011 for an adjusted purchase price of $9.2 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with borrowings under our existing reserve-based credit facility. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Newfield Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $0.9 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 June 22, 2011, pursuant to two purchase and sale agreements, we and ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. We and ENP 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. We refer to this acquisition as the “Permian Basin Acquisition I.” The effective date of this acquisition is May 1, 2011. This acquisition was completed on July 29, 2011 for an aggregate adjusted purchase price of $81.4 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our reserve-based credit facility and the ENP Credit Agreement (defined below). In accordance with the guidance contained within ASC 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 $0.7 million, subject to a 53.4% non-controlling interest 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, ENP 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 the ENP 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, ENP 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. ENP 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 the ENP 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, ENP 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 the ENP 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 2010 show the effect on our consolidated results of operations as if all of our and ENP’s acquisitions 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) the assumption of asset retirement obligations and accretion expense for the properties acquired, (2) the conversion of ENP’s method of accounting for oil and natural gas properties from the successful efforts method of accounting to the full cost method of accounting, (3) depletion expense applied to the adjusted basis of the properties acquired, (4) interest expense on additional borrowings necessary to finance the acquisitions, (5) the impact of additional common units issued in connection with our 2010 equity offering completed at the time of the Parker Creek Acquisition, (6) the impact of additional common units issued in connection with the Encore Acquisition and (7) the allocation of ENP’s pro forma net income to the non-controlling interest of ENP. The net gain (loss) 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	$	191,713	$	66,238	$	326,857	$	271,162
Net income	$	127,887	$	2,631	$	137,766	$	78,294
Net income attributable to non-controlling interest	$	51,695	$	182	$	55,163	$	20,739
Net income attributable to VNR	$	76,191	$	2,449	$	82,603	$	57,554
Net income per unit:
Common & Class B units – basic	$	2.52	$	0.10	$	2.73	$	2.28
Common & Class B units – diluted	$	2.51	$	0.10	$	2.73	$	2. 28

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for all of our acquisitions 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,				Nine Months Ended September 30,
	2011		2010			2011		2010
Parker Creek Acquisition
Revenues	$	4,591	$	4,712	$	14,442	$	6,750
Excess of revenues over direct operating expenses	$	4,061	$	3,961	$	12,779	$	5,670
Newfield Acquisition
Revenues	$	424	$	—	$	733	$	—
Excess of revenues over direct operating expenses	$	90	$	—	$	351	$	—
Permian Basin Acquisition I
Revenues	$	1,277	$	—	$	1,277	$	—
Excess of revenues over direct operating expenses	$	438	$	—	$	438	$	—

The amount of revenues and earnings included in our 2011 Consolidated Statements of Operations for the Encore Acquisition, including ENP’s acquisitions completed during 2011, are shown in the table that follows (in thousands).

	Three Months Ended		Nine Months Ended
	September 30, 2011			September 30, 2011
ENP
Revenues	$	131,401		$	203,628
Net income	$	93,738		$	94,735

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for ENP’s acquisitions completed during 2011, including 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

Debt

Our financing arrangements consisted of the following:

			Amount Outstanding
Description	Interest Rate	Maturity Date	September 30, 2011			December 31, 2010
			(in thousands)
Senior secured reserve-based credit facility	Variable (1)	October 1, 2012	$	218,500		$	176,500
Term Loan	Variable (2)	December 31, 2011		175,000			175,000
ENP’s credit agreement	Variable (3)	March 7, 2012		356,000			234,000
Total debt				749,500			585,500
Less: current obligations				(531,000	)		(175,000	)
Total long term debt			$	218,500		$	410,500

(1)	Variable interest rate was 2.98% and 3.00% at September 30, 2011 and December 31, 2010, respectively.

(2)	Variable interest rate was 5.74% and 5.77% at September 30, 2011 and December 31, 2010, respectively.

(3)	Weighted average interest rate was 2.82% and 2.80% at September 30, 2011 and December 31, 2010, respectively.

Senior Secured Reserve-Based Credit Facility

On January 3, 2007, we entered into a reserve-based credit facility under which our initial borrowing base was set at $115.5 million. In November 2010, our borrowing base under the reserve-based credit facility was reduced from $240.0 million to $225.0 million pursuant to our semi-annual redetermination. Also in November 2010, in connection with the Encore Acquisition, we entered into the Third Amendment to the Second Amended and Restated Credit Agreement to provide for certain amendments and modifications to allow us to incur indebtedness under, and grant the related security interests for the Term Loan discussed below. Such amendments and modifications included the granting of a second priority lien on VNG’s interests in ENP GP and the ENP Units. In addition to the existing first priority liens on the assets of VNG and its subsidiaries, amounts outstanding under the reserve-based credit facility will also be secured by a second priority lien on VNG’s interest in ENP GP and the ENP Units. In December 2010, we entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (as amended, the “Existing Facility”), which contains certain amendments necessary to exclude ENP GP’s pledge of the general partners interests issued by ENP that it owns as collateral securing the loans and other extensions of credit made to VNG pursuant to the Second Amended and Restated Credit Agreement. Additionally, the Existing Facility clarifies the amounts guaranteed by subsidiaries of VNG pursuant to guaranty agreements previously delivered by such subsidiaries. On July 28, 2011, the borrowing base under our reserve-based credit facility was increased from $235.0 million to $265.0 million pursuant to our request for an interim redetermination in connection with the Permian Basin Acquisition I. All other terms of the reserve-based credit facility remained the same. At September 30, 2011, the applicable margins and other fees will increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans Margin	2.25%	2.50%	2.75%	3.00%
ABR Loans Margin	1.25%	1.50%	1.75%	2.00%
Commitment Fee Rate	0.50%	0.50%	0.50%	0.50%
Letter of Credit Fee	2.25%	2.50%	2.75%	3.00%

Our reserve-based credit facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets, or make distributions to our unitholders when our outstanding borrowings exceed 90% of our borrowing base. The reserve-based credit facility limits the amount of outstanding debt to be hedged to no greater than 85% of the actual outstanding balance. At September 30, 2011, we were in compliance with all of our debt covenants.

On September 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amends and restates the Company’s 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 the Company and ENP. Additionally, as a condition precedent to the effectiveness of the Amended Credit Agreement, Vanguard is required to repay all outstanding debt under the Term Loan and to terminate and extinguish the corresponding Term Loan credit facility (discussed below) by the effective date of Amended Credit Agreement. The Amended Credit Agreement provides for an initial borrowing base of $765 million and a maturity of October 31, 2016. The borrowing base under the Amended Credit Agreement will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the oil and natural gas prices at such time. Our obligations under the Amended Credit Agreement are secured by mortgages on our oil and natural gas properties. Additionally, the obligations under the Amended Credit Agreement are guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries. Under the Amended Credit Agreement, we have agreed that a portion of the proceeds of the credit facility created by this Amended Credit Agreement will be used to repay amounts outstanding under the ENP Credit Agreement.

The Amended Credit Agreement contains various covenants, substantially similar to the Existing Facility, that limit our ability to incur indebtedness, enter into commodity and interest rate swaps, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. The Amended Credit Agreement also contains covenants, substantially similar to the Existing Facility, that require us to maintain specified financial ratios. Under the Amended Credit Agreement the debt-to-EBITDA covenant was increased to 4.0x from 3.5x under the Existing Facility. The Amended Credit Agreement also increased the percentage of production that can be hedged into the future, eliminated the required interest coverage ratio, eliminated the ten percent liquidity requirement to pay distributions to unitholders and allowed for unsecured debt. The other terms and conditions of the Amended Credit Agreement are substantially similar to the Existing Facility.

Under the Amended Credit Agreement, the applicable margins and other fees based on the utilization of the borrowing base are as follows:

Borrowing Base Utilization Percentage	<25%	>25% <50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans	1.50%	1.75%	2.00%	2.25%	2.50%
ABR Loans and Letter of Credit Fee Rate	0.50%	0.75%	1.00%	1.25%	1.50%
Commitment Fee Rate	0.50%	0.50%	0.375%	0.375%	0.375%

Our reserve-based credit facility required us to enter into a commodity price hedge position establishing certain minimum fixed prices for anticipated future production. See Note 4. Price and Interest Rate Risk Management Activities for further discussion.

Term Loan

Concurrent with the Encore Acquisition, VNG entered into a $175.0 million Term Loan with BNP Paribas to fund a portion of the consideration for the acquisition.

Borrowings under the Term Loan are comprised entirely of ABR Loans or Eurodollar Loans as VNG may request. Interest on ABR Borrowings under the Term Loan is payable quarterly on the last day of each March, June, September and December and accrues at a rate per annum equal to 6.50% plus the greater of (a) the prime rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1%, or (c) the Adjusted LIBOR Rate in effect on such day plus 2%. Interest on Eurodollar Borrowings is payable on the last day of the interest period applicable to such borrowing, and in the case of a Eurodollar Borrowing with an interest period of more than six months' duration, each day prior to the last day of such interest period that occurs at intervals of six months' duration after the first day of such interest period and accrues at a rate per annum of 5.50% plus the Adjusted LIBOR Rate for the interest period in effect for such borrowings. Amounts outstanding under the Term Loan may be prepaid prior to maturity, together with all accrued and unpaid interest relating to the amount prepaid, without prepayment penalty. The Term Loan contains various covenants, including restrictions on liens, restrictions on incurring other indebtedness without the lenders’ consent and restrictions on entering into certain transactions. The Term Loan matures the earlier of (a) the first anniversary of the effective date (December 31, 2011) or (b) the date following both (i) the completion of any acquisition by Vanguard of the remainder of ENP and (ii) VNG’s execution and delivery of a new or amended and restated revolving credit facility replacing VNG’s current reserve-based credit facility. As previously indicated, as a condition precedent to the effectiveness of the Amended Credit Agreement referred to above, Vanguard is required to repay all outstanding debt under the Term Loan and to terminate and extinguish the corresponding Term Loan credit facility by the effective date of Amended Credit Agreement.

Amounts outstanding under the Term Loan are secured by a second priority lien on all assets of VNG and its subsidiaries securing VNG's current reserve-based credit facility (other than VNG’s interest in ENP GP and the ENP Units) and a first priority lien on VNG’s interest in ENP GP and the ENP Units.

Our Term Loan contains a number of customary covenants that among other things require us to maintain certain financial ratios. At September 30, 2011, we were in compliance with the covenants under our Term Loan.

ENP’s Credit Agreement

ENP entered into a five-year credit agreement dated March 7, 2007 (as amended, the “ENP Credit Agreement”). The ENP Credit Agreement matures on March 7, 2012; therefore, all outstanding borrowings under the ENP Credit Agreement are reflected as a current liability at September 30, 2011. On September 30, 2011, Vanguard entered into the Amended Credit Agreement that would retire all of the outstanding debt of ENP upon the consummation of a merger with Vanguard as discussed above.

The ENP 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 ENP Credit Agreement is $475.0 million. Availability under the ENP 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 ENP Credit Agreement.

ENP incurs a quarterly commitment fee at a rate of 0.5% per year on the unused portion of the ENP Credit Agreement. Obligations under the ENP 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 ENP and its restricted subsidiaries. In addition, obligations under the ENP Credit Agreement are guaranteed by us and ENP’s restricted subsidiaries. Obligations under the ENP Credit Agreement are non-recourse to Vanguard.

Loans under the ENP 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. Such loans bear interest at the applicable rate plus the applicable margin indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans Margin	2.25%	2.50%	2.75%	3.00%
ABR Loans Margin	1.25%	1.50%	1.75%	2.00%

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%; 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%.

The ENP Credit Agreement contains a number of customary covenants that requires ENP to maintain certain financial ratios, limits ENP’s ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate and engage in certain asset dispositions, including a sale of all or substantially all of the ENP’s assets. As of September 30, 2011, ENP was in compliance with all covenants of the ENP Credit Agreement.

4.	Price and Interest Rate Risk Management Activities

We have entered into derivative contracts with counterparties that are lenders under our financing arrangements to hedge price risk associated with a portion of our oil and natural gas production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Under fixed-priced commodity swap agreements, we receive a fixed price on a notional quantity in exchange for paying a variable price based on a market index. In addition, we sell calls, purchase puts or provide options to counterparties under swaption agreements to extend the swaps into subsequent years. Under put option agreements, we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. At settlement date, we receive the excess, if any, of the fixed floor over floating rate. We also enter into basis swap contracts which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. Under collar contracts, we pay the counterparty if the market price is above the ceiling price and the counterparty pays us if the market price is below the floor price on a notional quantity. Put options for natural gas are settled based on the NYMEX price for natural gas at Henry Hub, and collars are settled based on a market index selected by us at inception of the contract. We also may enter into three-way collar contracts which 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 price 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. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.

Under ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”), all derivative instruments are recorded on the accompanying Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the Consolidated Balance Sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles. The realized and unrealized gains (losses) on derivative contracts that do not qualify for hedge accounting treatment are recorded as gains (losses) on other commodity derivative contracts or gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations.

We have elected not to designate our current portfolio of derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included as unrealized gains (losses) on other commodity derivative contracts or gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations.

As of September 30, 2011, we had open commodity derivative contracts covering our anticipated future production as follows:

Swap Agreements

	Gas			Oil
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average Fixed Price
VNG
October 1, 2011 – December 31, 2011	724,426	$	7.83	128,500	$	90.23
January 1, 2012 – December 31, 2012	1,281,000	$	5.45	420,900	$	92.42
January 1, 2013 – December 31, 2013	2,190,000	$	5.62	—	$	—
January 1, 2014 – December 31, 2014	—	$	—	209,875	$	94.37
ENP
October 1, 2011 – December 31, 2011	1,168,584	$	5.81	141,220	$	83.15
January 1, 2012 – December 31, 2012	4,648,932	$	5.52	1,021,140	$	84.49
January 1, 2013 – December 31, 2013	4,270,500	$	5.05	1,332,250	$	89.11
January 1, 2014 – December 31, 2014	452,500	$	4.80	1,204,500	$	89.14
Consolidated
October 1, 2011 – December 31, 2011	1,893,010	$	6.58	269,720	$	86.52
January 1, 2012 – December 31, 2012	5,929,932	$	5.51	1,442,040	$	86.80
January 1, 2013 – December 31, 2013	6,460,500	$	5.24	1,332,250	$	89.11
January 1, 2014 – December 31, 2014	452,500	$	4.80	1,414,375	$	89.91

Swaptions

Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:

	Gas			Oil
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average Fixed Price
VNG
January 1, 2012 – December 31, 2012	—	$	—	91,500	$	95.20
January 1, 2013 – December 31, 2013	—	$	—	68,600	$	99.44
January 1, 2014 – December 31, 2014	1,277,500	$	5.77	127,750	$	95.00
January 1, 2015 – December 31, 2015	—	$	—	292,000	$	95.63
ENP
January 1, 2013 – December 31, 2013	—	$	—	36,500	$	105.00
January 1, 2014 – December 31, 2014	365,000	$	5.40	—	$	—
January 1, 2015 – December 31, 2015	—	$	—	36,500	$	95.00
Consolidated
January 1, 2012 – December 31, 2012	—	$	—	91,500	$	95.20
January 1, 2013 – December 31, 2013	—	$	—	105,100	$	101.37
January 1, 2014 – December 31, 2014	1,642,500	$	5.69	127,750	$	95.00
January 1, 2015 – December 31, 2015	—	$	—	328,500	$	95.56

Basis Swaps

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

	Gas			Oil
Contract Period	MMBtu	Weighted Avg. Basis Differential (1)		Bbls	Weighted Avg. Basis Differential (2)
ENP
October 1, 2011 – December 31, 2011	230,000	$	(0.32)	21,000	$	19.10
January 1, 2012 – December 31, 2012	915,000	$	(0.32)	84,000	$	15.15
January 1, 2013 – December 31, 2013	912,500	$	(0.32)	84,000	$	9.60
January 1, 2014 – December 31, 2014	452,500	$	(0.32)	—	$	—

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

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

Collars

	Gas						Oil
	MMBtu		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period
VNG
October 1, 2011 – December 31, 2011		579,600	$	7.50	$	8.66		9,200	$	100.00	$	116.20
January 1, 2012 – December 31, 2012		—	$	—	$	—		118,950	$	90.77	$	106.62
January 1, 2013 – December 31, 2013		—	$	—	$	—		82,125	$	88.89	$	107.34
January 1, 2014 – December 31, 2014		—	$	—	$	—		12,000	$	100.00	$	116.20
ENP
October 1, 2011 – December 31, 2011		—	$	—	$	—		172,960	$	80.00	$	96.49
January 1, 2012 – December 31, 2012		—	$	—	$	—		475,800	$	74.23	$	90.98
Consolidated
October 1, 2011 – December 31, 2011		579,600	$	7.50	$	8.66		182,160	$	81.01	$	97.48
January 1, 2012 – December 31, 2012		—	$	—	$	—		594,750	$	77.54	$	94.11
January 1, 2013 – December 31, 2013		—	$	—	$	—		82,125	$	88.89	$	107.34
January 1, 2014 – December 31, 2014		—	$	—	$	—		12,000	$	100.00	$	116.20

Three-Way Collars

	Oil
	Bbls		Floor		Ceiling		Put Sold
Production Period
VNG
October 1, 2011 – December 31, 2011		20,700	$	90.00	$	102.06	$	70.00
January 1, 2012 – December 31, 2012		82,350	$	90.00	$	111.22	$	70.00
January 1, 2013 – December 31, 2013		387,525	$	90.21	$	102.38	$	62.12
ENP
October 1, 2011 – December 31, 2011		48,300	$	90.00	$	102.56	$	70.00
January 1, 2012 – December 31, 2012		192,150	$	90.00	$	106.76	$	70.00
January 1, 2013 – December 31, 2013		191,625	$	90.00	$	106.76	$	70.00
January 1, 2014 – December 31, 2014		54,750	$	90.00	$	105.00	$	70.00
Consolidated
October 1, 2011 – December 31, 2011		69,000	$	90.00	$	102.41	$	70.00
January 1, 2012 – December 31, 2012		274,500	$	90.00	$	108.10	$	70.00
January 1, 2013 – December 31, 2013		579,150	$	90.14	$	103.83	$	64.73
January 1, 2014 – December 31, 2014		54,750	$	90.00	$	105.00	$	70.00

Puts

	Gas
Contract Period	MMBtu	Weighted Average Fixed Price
ENP
October 1, 2011 – December 31, 2011	312,616	$	6.31
January 1, 2012 – December 31, 2012	328,668	$	6.76

Interest Rate Swaps

We enter into interest rate swap agreements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate exposures to fixed interest rates.

As of September 30, 2011, we had open interest rate derivative contracts as follows (in thousands):

	Notional Amount		Fixed Libor Rates
Period:
VNG
October 1, 2011 to December 10, 2014	$	20,000		2.60	%
October 1, 2011 to January 31, 2015	$	40,000		1.75	%
October 1, 2011 to January 31, 2015	$	20,000		1.89	%
October 1, 2011 to September 23, 2016	$	75,000		1.15	%
August 6, 2012 to August 6, 2014	$	25,000		2.09	%
August 6, 2012 to August 5, 2015 (1)	$	30,000		2.25	%
ENP
October 1, 2011 to March 7, 2016 (2)	$	75,000		1.08	%

	(1)	The counterparty has the option to extend the termination date of this contract to August 5, 2018.
	(2)	ENP entered into this interest rate swap on September 21, 2011, and the terms became effective on October 7, 2011.

Balance Sheet Presentation

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 (in thousands):

	September 30, 2011			December 31, 2010
Assets:
Commodity derivatives	$	71,518		$	33,435
Interest rate swaps		881			97
	$	72,399		$	33,532
Liabilities:
Commodity derivatives	$	(24,952	)	$	(48,008	)
Interest rate swaps		(6,518	)		(4,115	)
	$	(31,470	)	$	(52,123	)

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our reserve-based credit facility (See Note 3. Debt for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $72.4 million at September 30, 2011.

We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments only with counterparties that are also lenders in our reserve-based credit facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives, and therefore the risk of such loss is somewhat mitigated as of September 30, 2011.

Gain (Loss) on Derivatives

Gains and losses on derivatives that are not accounted for as cash flow hedges are reported on the accompanying Consolidated Statements of Operations in “realized or unrealized gain (loss) on other commodity derivative contracts” and “realized or unrealized gain (loss) on interest rate derivative contracts.” Realized gains (losses) represent amounts related to the settlement of derivative instruments. Unrealized gains (losses) represent the change in fair value of the derivative instruments to be settled in the future and are non-cash items which fluctuate in value as commodity prices and interest rates change.

The following presents our reported gains and losses on derivative instruments (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Realized gains (losses):
Other commodity derivatives	$	1,902		$	6,513		$	4,474		$	18,274
Interest rate swaps		(664	)		(511	)		(2,208	)		(1,624	)
	$	1,238		$	6,002		$	2,266		$	16,650
Unrealized gains (losses):
Other commodity derivatives	$	109,639		$	(9,388	)	$	68,625		$	1,332
Interest rate swaps		(1,939	)		(1,337	)		(1,641	)		(2,021	)
	$	107,700		$	(10,725	)	$	66,984		$	(689	)
Total gains (losses):
Other commodity derivatives	$	111,541		$	(2,875	)	$	73,099		$	19,606
Interest rate swaps		(2,603	)		(1,848	)		(3,849	)		(3,645	)
	$	108,938		$	(4,723	)	$	69,250		$	15,961

5.	Fair Value Measurements

We adopted ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”) for financial assets and financial liabilities as of January 1, 2008 and for non-financial assets and liabilities as of January 1, 2009. ASC Topic 820 does not expand the use of fair value measurements, but rather, provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets carried at fair value subsequent to an impairment write-down. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental fair value information about financial instruments not carried at fair value.

The estimated fair values of our financial instruments closely approximate the carrying amounts as discussed below:

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, payables to affiliates, phantom unit compensation accrual, accrued ad valorem taxes and accrued expenses. The carrying amounts approximate fair value due to the short maturity of these instruments.

Debt. The carrying amount of our financing arrangements approximates fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings.

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis. This includes natural gas, oil and interest rate derivatives contracts. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. These assumptions include certain factors not consistently provided for previously by those companies utilizing fair value measurement; examples of such factors would include our own credit standing (when valuing liabilities) and the buyer’s risk premium. In adopting ASC Topic 820, we determined that the impact of these additional assumptions on fair value measurements did not have a material effect on our financial position or results of operations.

ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process.

The standard describes three levels of inputs that may be used to measure fair value:


Level 1		Quoted prices for identical instruments in active markets.

Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.

Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

As required by ASC 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 swaps, options 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.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):

	September 30, 2011
	Fair Value Measurements Using							Assets/Liabilities
	Level 1		Level 2			Level 3		at Fair value
Assets:
Commodity price derivative contracts	$	—	$	47,165		$	—	$	47,165
Interest rate derivative contracts		—		—			—		—
Total derivative instruments	$	—	$	47,165		$	—	$	47,165

Liabilities:
Commodity price derivative contracts	$	—	$	(599	)	$	—	$	(599	)
Interest rate derivative contracts		—		(5,637	)		—		(5,637	)
Total derivative instruments	$	—	$	(6,236	)	$	—	$	(6,236	)

	December 31, 2010
	Fair Value Measurements Using							Assets/Liabilities
	Level 1		Level 2			Level 3		at Fair value
Assets:
Commodity price derivative contracts	$	—	$	17,359		$	—	$	17,359
Interest rate derivative contracts		—		643			—		643
Total derivative instruments	$	—	$	18,002		$	—	$	18,002

Liabilities:
Commodity price derivative contracts	$	—	$	(31,931	)	$	—	$	(31,931	)
Interest rate derivative contracts		—		(4,662	)		—		(4,662	)
Total derivative instruments	$	—	$	(36,593	)	$	—	$	(36,593	)

On January 1, 2009, we adopted the previously-deferred provisions of ASC Topic 820 for nonfinancial assets and liabilities, which are comprised primarily of asset retirement costs and obligations initially measured at fair value in accordance with ASC Topic 410 Subtopic 20 “Asset Retirement Obligations” (“ASC Topic 410-20”). These assets and liabilities are recorded at fair value when incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6. Asset Retirement Obligations in accordance with ASC Topic 410-20. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate (5.0% to 7.0%); (4) the ten year average inflation factor (2.3%) and (5) the estimated cost for decommissioning the Elk Basin natural gas processing plant near Powell, Wyoming. The adoption of ASC Topic 820 on January 1, 2009, as it relates to nonfinancial assets and nonfinancial liabilities, did not have a material impact on our financial position, results of operations or cash flows.

6.	Asset Retirement Obligations

The asset retirement obligations as of September 30 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, were as follows (in thousands):

	2011			2010
Asset retirement obligations at January 1,	$	30,202		$	4,420
Liabilities added during the current period		4,661			619
Accretion expense		609			121
Retirements		(90	)		—
Total asset retirement obligations at September 30,		35,382			5,160
Less: current obligations		(1,018	)		—
Long-term asset retirement obligation at September 30,	$	34,364		$	5,160

7.	Related Party Transactions

In Appalachia, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas. We reimburse Vinland $60 per well per month (in addition to normal third party operating costs) for operating our current oil and natural gas properties in Appalachia under a Management Services Agreement (“MSA”), which costs are reflected in our lease operating expenses. Under a Gathering and Compression Agreement (“GCA”), Vinland receives a $0.25 per Mcf transportation fee on existing wells drilled at December 31, 2006 and $0.55 per Mcf transportation fee on any new wells drilled after December 31, 2006 within the area of mutual interest or “AMI.” In June 2010, we began discussions with Vinland regarding an amendment to the GCA to go into effect beginning on July 1, 2010. The amended agreement would provide gathering and compression services based upon actual costs plus a margin of $.055 per mcf. We and Vinland agreed in principle to this change effective July 1, 2010, and we have jointly operated on this basis since then, however, no formal agreement between us and Vinland has been signed. We are currently negotiating other agreements with Vinland concerning our joint operations, and our intent is to have all our operations governed under a single set of agreements, including this amendment to the GCA. In the event no agreement is reached between us and Vinland, all the terms of the agreements will revert back to the original agreements effective July 1, 2010. Under the GCA, the transportation fee that we pay to Vinland only encompasses transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets would apply. These transportation fees are outlined in the GCA and are reflected in our lease operating expenses. Costs incurred under the MSA were $0.5 million for each of the three months ended September 30, 2011 and 2010 and $1.4 million and $1.5 million for the nine months ended September 30, 2011 and 2010, respectively. Costs incurred under the GCA were $0.5 million and $0.4 million for the three months ended September 30, 2011 and 2010, respectively, and $1.4 million and $1.1 million for the nine months ended September 30, 2011 and 2010, respectively. A payable of $1.3 million and $0.6 million, respectively, is reflected on our September 30, 2011 and December 31, 2010 Consolidated Balance Sheets in connection with these agreements and direct expenses incurred by Vinland related to the drilling of new wells and operations of all of our existing wells in Appalachia.

In connection with closing of the Encore Acquisition, VNG entered into a Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, with ENP, ENP GP, Encore Operating, L.P., OLLC and Denbury (the “Services Agreement”). The Services Agreement was amended solely to add VNG as a party and provide for VNG to assume the rights and obligations of Encore Operating and Denbury under the previous administrative services agreement going forward.

Pursuant to the Services Agreement, VNG provides certain general and administrative services to the ENP Group in exchange for a quarterly fee of $2.05 per BOE of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee is paid by ENP (the “Administrative Fee”). The Administrative Fee is subject to certain index-related adjustments on an annual basis. The Administrative Fee was $2.06 per BOE through March 31, 2011 and effective April 1, 2011 was decreased to $2.05 per BOE. ENP also is obligated to reimburse VNG for all third-party expenses it incurs on behalf of the ENP Group. These terms are identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement. During the three months ended September 30, 2011, VNG received administrative fees amounting to $1.7 million, COPAS recovery amounting to $1.6 million and received reimbursements of third-party expenses amounting to $2.0 million. During the nine months ended September 30, 2011, VNG received administrative fees amounting to $4.8 million, COPAS recovery amounting to $3.5 million and reimbursements of third-party expenses amounting to $5.3 million.

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 ENP GP upon the recommendation of its conflicts committee; and

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

8.	Commitments and Contingencies

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or government proceedings against us, or contemplated to be brought against us, under the various environmental statutes to which we are subject.

Additionally, the following pending litigation is outstanding related to the proposed merger with ENP. 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 ENP 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 ENP, 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.

9.	Common Units and Net Income per Unit

Basic earnings per unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income attributable to Vanguard unitholders by the weighted average number of units outstanding during the period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. As of September 30, 2011, we had two classes of units outstanding: (i) units representing limited liability company interests (“common units”) listed on the NYSE under the symbol VNR and (ii) Class B units, issued to management and an employee as discussed in Note 10. Unit-Based Compensation. The Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic earnings per unit.

For the three and nine months ended September 30, 2011, the 175,000 options granted to officers under the long-term incentive plan have been included in the computation of diluted earnings per unit as 57,269 and 62,894, respectively, additional common units that would have been issued and outstanding under the treasury stock method assuming the options had been exercised at the beginning of the period. For the three and nine months ended September 30, 2010, these options were included in the computation of diluted earnings per unit as 38,654 and 33,657, respectively, additional common units that would have been issued and outstanding under the treasury stock method assuming the options had been exercised at the beginning of the period, respectively. The 85,000 phantom units granted to officers during 2010 and 2011 under our long-term incentive plan have also been included in the computation of earnings per unit for the three months ended September 30, 2011 as they had a dilutive effect and excluded for the nine months ended September 30, 2011 as they had no dilutive effect. The 42,500 phantom units granted to officers during 2010 under our long-term incentive plan did not have a dilutive effect on earnings per unit for the three and nine months ended September 30, 2010; therefore, they have been excluded in the computation of diluted earnings per unit.

In accordance with ASC Topic 260, dual presentation of basic and diluted earnings per unit has been presented in the Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010 including each class of units issued and outstanding during the respective periods: common units and Class B units. Net income per unit is allocated to the common units and the Class B units on an equal basis.

10.	Unit-Based Compensation

In April 2007, the sole member at that time reserved 460,000 restricted Class B units in VNR for issuance to employees. Certain members of management were granted 365,000 restricted VNR Class B units in April 2007, which vested in April 2009, two years from the date of grant. In addition, another 55,000 restricted VNR Class B units were issued in August 2007 to two other employees that were hired in April and May of 2007, which vested in April and May 2010, three years after the date of grant. The remaining 40,000 restricted VNR Class B units were not granted and are not expected to be granted in the future.

In October 2007, two officers were granted options to purchase an aggregate of 175,000 units under our long-term incentive plan with an exercise price equal to the initial public offering price of $19.00, which vested immediately upon being granted and had a fair value of $0.1 million on the date of grant. The grant date fair value for these option awards was calculated in accordance with ASC Topic 718 “Compensation-Stock Compensation” (“ASC Topic 718”), by calculating the Black-Scholes value of each option, using a volatility rate of 12.18%, an expected dividend yield of 8.95% and a discount rate of 5.12%, and multiplying the Black-Scholes value by the number of options awarded. In determining a volatility rate of 12.18%, we, due to a lack of historical data regarding our common units, used the historical volatility of the Citigroup MLP Index over the 365 day period prior to the date of grant.

In February 2010, we and VNRH entered into second amended and restated Executive Employment Agreements (the “February Amended Agreements”) with two executives. The Amended Agreements were effective January 1, 2010 and will continue until January 1, 2013, with subsequent one year renewals in the event that neither we, VNRH nor the executives have given notice to the other parties that the agreements should not be extended. Also in June 2010, we and VNRH entered into a second amended and restated Executive Employment Agreement (the “June Amended Agreement,” together with the February Amended Agreements, the “Amended Agreements”) with one executive. The June Amended Agreement was effective May 15, 2010 and will continue until May 15, 2013, with subsequent one year renewals in the event that neither we, VNRH nor the executive have given notice to the other parties that the agreement should not be extended. The Amended Agreements provide for an annual base salary and include an annual bonus structure for the executives. The annual bonus will be calculated based upon two company performance elements, absolute target distribution growth and relative unit performance to peer group, as well as a third discretionary element to be determined by our board of directors for the February Amended Agreements and by the Chief Executive Officer for the June Amended Agreement. Each of the three components will be weighted equally in calculating the respective executive officer’s annual bonus. The annual bonus does not require a minimum payout, although the maximum payout may not exceed two times the respective executive’s annual base salary.

The February Amended Agreements also provide for each executive to receive 15,000 restricted units granted pursuant to the Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) and the June Amended Agreement provides for the executive to receive an annual grant of 12,500 restricted units granted pursuant to the VNR LTIP. During the nine months ended September 30, 2011, executives were granted restricted common units amounting to 62,500 units. The restricted units are subject to a vesting period of three years. One-third of the aggregate number of the restricted units will vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with us. In the event the executives are terminated without “Cause,” or the executive resigns for “Good Reason” (as each term is defined in the Amended Agreements), or the executive is terminated due to his death or “Disability” (as such term is defined in the Amended Agreement), all unvested outstanding restricted units shall receive accelerated vesting. Where the executive is terminated for “Cause,” all restricted units, whether vested or unvested, will be forfeited. Upon the occurrence of a “Change of Control,” (as defined in the VNR LTIP), all unvested outstanding restricted units shall vest.

In addition, the February Amended Agreements provide for each executive to receive an annual grant of 15,000 phantom units granted pursuant to the VNR LTIP and the June Amended Agreement provides for the executive to receive an annual grant of 12,500 phantom units granted pursuant to the VNR LTIP. The phantom units are also subject to a three-year vesting period, although the vesting is not pro-rata, but a one-time event which shall occur on the three-year anniversary of the date of grant so long as the executive remains continuously employed with us during such time. The phantom units are accompanied by dividend equivalent rights, which entitle the executives to receive the value of any distributions made by us on our units generally with respect to the number of phantom shares that executive received pursuant to this grant. In the event the executive is terminated for “Cause” (as such term is defined in the Amended Agreements), all phantom units, whether vested or unvested, will be forfeited. The phantom units, once vested, shall be settled upon the earlier to occur of (a) the occurrence of a “Change of Control,” (as defined in the VNR LTIP), or (b) the executive’s separation from service. The amount to be paid in connection with these phantom units, can be paid in cash or in units at the election of the officers and will be equal to the appreciation in value of the units from the date of the grant until the determination date (December 31, 2013). As of September 30, 2011, an accrued liability of $0.5 million has been recorded and non-cash unit-based compensation expense of $0.1 million and $0.06 million has been recognized in the selling, general and administrative expenses line item in the Consolidated Statements of Operations related to these phantom units for the three months ended September 30, 2011 and 2010, respectively, and $0.3 million and $0.1 million for the nine months ended September 30, 2011 and 2010, respectively.

During the first nine months of 2011, VNR employees were granted a total of 119,459 common units which will vest equally over a four year period. In May 2011, four board members were granted 11,884 common units which will vest one year from the date of grant. All of these grants have distribution equivalent rights that provide the grantee with a payment equal to the distribution on unvested units. In July 2011, one board member was granted 2,228 common units which vested immediately upon being granted.

These common units, Class B units, options and phantom 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 ASC 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 December 31, 2010		66,719		$	22.18
Granted		196,071		$	28.80
Forfeited		(18,656	)	$	(29.40	)
Vested		(29,947	)	$	(23.03	)
Non-vested units at September 30, 2011		214,187		$	27.49

At September 30, 2011, there was approximately $4.7 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 2.5 years. Our accompanying Consolidated Statements of Operations reflect non-cash compensation of $0.5 million and $0.3 million in the selling, general and administrative expenses line item for the three months ended September 30, 2011 and 2010, respectively, and $1.2 million and $0.8 million for the nine months ended September 30, 2011 and 2010, respectively.

In September 2007, the board of directors of ENP GP adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP 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 ENP GP and its affiliates who perform services for or on behalf of ENP and its subsidiaries are eligible to be granted awards under the ENP LTIP. The ENP LTIP is administered by the board of directors of ENP GP or a committee thereof, referred to as the plan administrator. To satisfy common unit awards under the ENP LTIP, ENP may acquire common units in the open market, use common units owned by ENP GP, or use common units acquired by ENP GP from ENP or from any other person.

The total number of common units reserved for issuance pursuant to the ENP 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 weighted average grant date fair value of these units was $22.21 per unit and the total fair value was approximately $3.1 million on the date of grant.

In February 2011, ENP issued 7,980 units under the ENP LTIP to three of the members of the Board of Directors 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 ASC 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 December 31, 2010		—		$	—
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 ENP’s non-vested restricted units, which is expected to be recognized over a period of approximately 2.3 years. The accompanying Consolidated Statements of Operations reflects non-cash compensation of $0.2 million and $0.7 million in the selling general and administrative expenses line item 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 ENP LTIP.

11.	Shelf Registration Statements

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. The shelf registration statement does not provide assurance that ENP will or could sell any such securities. ENP’s ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase ENP securities at acceptable prices. 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. 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. As a result of these offerings, as of September 30, 2011, ENP has approximately $822.1 million remaining available under its shelf registration statement.

During the third quarter 2009, we filed a registration statement with the SEC which registered offerings of up to $300.0 million of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the 2009 shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In August 2009, we completed an offering of 3.9 million of our common units. The common units were offered to the public at a price of $14.25 per common unit. We received net proceeds of approximately $53.2 million from the offering, after deducting underwriting discounts of $2.4 million and offering costs of $0.5 million. In December 2009, we completed an offering of 2.6 million of our common units. The common units were offered to the public at a price of $18.00 per common unit. We received net proceeds of approximately $44.4 million from the offering, after deducting underwriting discounts of $2.0 million and offering costs of $0.1 million. We paid $4.3 million of the proceeds from this offering to redeem 250,000 common units from our founding unitholder.

In May 2010, we completed an offering of 3.3 million of our common units. The common units were offered to the public at a price of $23.00 per common unit. We received proceeds of approximately $71.5 million from the offering, after deducting underwriting discounts of $3.2 million and offering costs of $0.1 million.

In July 2010, we filed a registration statement with the SEC which registered offerings of up to $800.0 million of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of the offering of securities issued under the 2010 shelf registration statement will be determined at the time of the offerings. The shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In August 2010, we entered into an equity distribution agreement relating to our common units representing limited liability company interests having an aggregate offering price of up to $60.0 million. In accordance with the terms of the equity distribution agreement we may offer and sell up to the maximum dollar amount of our common units from time to time through our sales agent. Sales of the common units, if any, may be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, (the “NYSE”), at market prices. Our sales agent will receive from us a commission of 1.25% based on the gross sales price per common unit for any common units sold through it as agent under the equity distribution agreement. During September through December 2010, we received net proceeds of approximately $6.3 million from the sales of 240,111 common units, after commissions.

On September 9, 2011, we entered into an amended and restated equity distribution agreement which extended, for an additional three years, the existing agreement with our sales agent to act as our exclusive distribution agent with respect to the issuance and sale of our common units up to an aggregate gross sales price of $200 million. Of the $200 million of the common units under the amended and restated equity distribution agreement, $115.0 million of the common units may be issued pursuant to our existing shelf registration statement on Form S-3. The additional $85 million of the common units may be issued pursuant to a new shelf registration statement on Form S-3 to be filed when the existing shelf registration statement expires.

In October 2010, we completed an offering of 4.8 million of our common units. The common units were offered to the public at a price of $25.40 per common unit. We received net proceeds of approximately $115.8 million from the offering, after deducting underwriting discounts of $5.1 million and offering costs of $0.3 million. We paid $3.7 million of the proceeds of this offering to redeem 150,000 common units from our founding unitholder. The net proceeds of $112.1 million were used to pay down outstanding borrowings under our reserve-based credit facility.

As a result of these offerings, as of September 30, 2011, we had approximately $62.6 million and $678.8 million remaining available under our 2009 and 2010 shelf registration statements, respectively.

12.	Subsequent Events

On October 27, 2011, the board of directors declared a cash distribution attributable to the third quarter of 2011 of $0.5775 per common unit expected to be paid on November 14, 2011 to Vanguard unitholders of record as of the close of business on November 7, 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, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes presented in Item 1 of this Quarterly Report on Form 10-Q and information disclosed in our 2010 Annual Report.

Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Statements included in this Quarterly Report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in the Risk Factor section of the 2010 Annual Report, our Quarterly Reports on Forms 10-Q for the periods ended March 31, 2011 and June 30, 2011 and this Quarterly Report on Form 10-Q, and those set forth from time to time in our filings with the SEC, which are available on our website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and Retrieval System at www.sec.gov.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

Overview

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows to allow us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions through the acquisition of new oil and natural gas reserves. We own a 100% controlling interest, through certain of our subsidiaries, in properties and oil and natural gas reserves located in four operating areas:

·	the Permian Basin in West Texas and New Mexico;

·	South Texas;

·	the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee; and

·	Mississippi.

·	the Permian Basin in West Texas and New Mexico;

·	the Big Horn Basin in Wyoming and Montana;

·	the Williston Basin in North Dakota and Montana; and

·	the Arkoma Basin in Arkansas and Oklahoma.

At September 30, 2011, we owned working interests in 5,321 gross (2,600 net) productive wells, including those wells acquired in the Encore Acquisition, which are subject to a 53.4% non-controlling interest. Our average net production per day for the year ended December 31, 2010 and for the nine months ended September 30, 2011 was 4,721 BOE per day and 13,310 BOE per day, respectively. Our average net production for the year ended December 31, 2010 did not include any production from properties acquired in connection with the Encore Acquisition. Our average net production for the nine months ended September 30, 2011 includes production from the properties acquired in connection with the Encore Acquisition and are subject to a 53.4% non-controlling interest in ENP. In addition to these productive wells, we own leasehold acreage allowing us to drill new wells. As of September 30, 2011, we had a 40% working interest in approximately 109,291 gross undeveloped acres surrounding or adjacent to our existing wells located in the Appalachian Basin. In South Texas and the Permian Basin, VNR owns working interests ranging from 30-100% in approximately 15,890 undeveloped acres surrounding our existing wells. Additionally, ENP owns working interests ranging from 8-77% in approximately 15,912 undeveloped acres surrounding their existing wells in the Permian Basin, Big Horn Basin, Williston Basin and Arkoma Basin. As of September 30, 2011, based on internal reserve estimates, approximately 16% or 12.6 MMBOE of our estimated proved reserves were attributable to our working interests in undeveloped acreage. The proved undeveloped reserves that we acquired in connection with the Encore Acquisition (as described below) are subject to a 53.4% non-controlling interest in ENP held by unrelated third parties.

Recent Developments

Encore Acquisition

On December 31, 2010, we completed an acquisition pursuant to a purchase agreement with Denbury Resources Inc. (“Denbury”), Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Operating, L.P. (collectively, the “Encore Selling Parties” and, together with Denbury, the “Selling Parties”) to acquire (the “Encore Acquisition”) all of the member interests in ENP GP, the general partner of ENP, and 20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), which represented a 46.6% aggregate equity interest in ENP at September 30, 2011. As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million.

Pursuant to the Services Agreement, VNG provides certain general and administrative services to ENP, ENP GP and the OLLC (collectively, the “ENP Group”) in exchange for a quarterly fee of $2.05 per BOE of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee is paid by ENP (the “Administrative Fee”). The Administrative Fee is subject to certain index-related adjustments on an annual basis. The Administrative Fee was $2.06 per BOE through March 31, 2011 and effective April 1, 2011 was decreased to $2.05 per BOE. ENP also is obligated to reimburse VNG for all third-party expenses it incurs on behalf of the ENP Group. These terms are identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement.

The fair value of the assets and liabilities we acquired on December 31, 2010 in the Encore Acquisition and cash flows associated with the transaction were included in the Consolidated Balance Sheet as of December 31, 2010. We have consolidated ENP’s accounts since December 31, 2010, the acquisition date.

On July 11, 2011, Vanguard and ENP announced the execution of a definitive agreement that would result in a merger whereby ENP would become a wholly-owned subsidiary of VNG, through a unit-for-unit exchange. Under the terms of the definitive agreement, ENP’s public unitholders would receive 0.75 Vanguard common units in exchange for each ENP common unit they own at closing. The transaction would 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 members of the Vanguard Conflicts Committee, which is also comprised solely of independent directors, negotiated the terms on behalf of Vanguard and also voted unanimously in favor of the merger. In addition, RBC Capital Markets has issued a fairness opinion to the Vanguard Conflicts Committee stating that they believe the exchange ratio is fair, from a financial point of view, to Vanguard.

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 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, Vanguard and ENP 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 Vanguard and ENP 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, Vanguard and ENP have agreed to customary restrictions in the way they conduct their businesses.

Acquisitions of Oil and Natural Gas Properties

Parker Creek Acquisition

On April 30, 2010, we entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Mississippi, Texas and New Mexico. We refer to this acquisition as the “Parker Creek Acquisition.” The purchase price for the assets was $113.1 million with an effective date of May 1, 2010. We completed this acquisition on May 20, 2010. The adjusted purchase price of $114.3 million considered final purchase price adjustments of approximately $1.2 million. The purchase price was funded from the approximate $71.5 million in net proceeds from our May 2010 equity offering and with borrowings under the Company’s existing reserve-based credit facility. In conjunction with the acquisition, we entered into crude oil hedges covering approximately 56% of the estimated production from proved producing reserves through 2013 at a weighted average price of $91.70 per barrel. As of September 30, 2011, based on internal reserve estimates, these acquired properties have estimated proved reserves of 3.4 MMBOE, 97% of which is oil and 68% is proved developed.

Newfield Acquisition

On April 28, 2011, we entered into a Purchase and Sale Agreement with a private seller, for the acquisition of certain oil and natural gas properties located in Texas and New Mexico. We refer to this acquisition as the “Newfield Acquisition.” The purchase price for the assets was $9.1 million with an effective date of April 1, 2011. We completed this acquisition on May 12, 2011 for an adjusted purchase price of $9.2 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with borrowings under the Company’s existing reserve-based credit facility.

Permian Basin Acquisition I

On June 22, 2011, pursuant to two Purchase and Sale Agreements, we and ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. We refer to this acquisition as the “Permian Basin Acquisition I.” We and ENP 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. This acquisition was completed on July 29, 2011 for an aggregate adjusted purchase price of $81.4 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under our reserve-based credit facility and the ENP Credit Agreement. As of September 30, 2011, the interests acquired, including the proved reserves attributable to the approximate 53.4% non-controlling interest in ENP, have estimated total net proved reserves of 5.3 MMBOE, of which approximately 70% are oil and NGLs reserves and are 100% proved developed.

Permian Basin Acquisition II

On August 8, 2011, ENP 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 the ENP Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 1.02 MMBOE, of which approximately 87% are oil and are 50% proved developed.

Wyoming Acquisition

On August 15, 2011, ENP 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. ENP 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 the ENP Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 3.91 MMBOE, of which approximately 65% are natural gas reserves and are 100% proved developed producing.

Gulf Coast Acquisition

On August 31, 2011, ENP 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 the ENP Credit Agreement. As of September 30, 2011, based on internal reserve estimates, the interests acquired by ENP have estimated total net proved reserves of 2.13 MMBOE, of which approximately 83% are oil and NGLs reserves and are 100% proved developed.

Our Relationship with Vinland

On April 18, 2007 but effective as of January 5, 2007, we entered into various agreements with Vinland, under which we rely on Vinland to operate our existing producing wells in Appalachia and coordinate our development drilling program in Appalachia. We expect to benefit from the substantial development and operational expertise of Vinland management in the Appalachian Basin. Under the MSA, Vinland advises and consults with us regarding all aspects of our production and development operations in Appalachia and provides us with administrative support services as necessary for the operation of our business. Under the GCA that we entered into with Vinland Energy Gathering, LLC (“VEG”), VEG gathers, compresses, delivers, and provides the services necessary for us to market our natural gas production in the AMI. VEG delivers our natural gas production to certain designated interconnects with third-party transporters.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Oil, natural gas and NGLs prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce, our access to capital and our ability to pay cash distributions to our unitholders. We have mitigated the volatility on our cash flows with oil and natural gas price derivative contracts through 2014. These hedges are placed on a portion of our proved producing and a portion of our total anticipated production during this time frame. As oil, natural gas and NGLs prices fluctuate, we will recognize non-cash, unrealized gains and losses in our Consolidated Statements of Operations related to the change in fair value of our commodity derivative contracts.

We face the challenge of oil and natural gas production declines. As a given well’s initial reservoir pressures are depleted, oil, natural gas and NGLs production decreases, thus reducing our total reserves. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. During the nine months ended September 30, 2011, we drilled seven gross (5.9 net) operated wells and completed two gross (1.2 net) operated wells. Also, during the nine months ended September 30, 2011, we drilled eight gross (3.0 net) non-operated wells and completed seven gross (2.9 net) non-operated wells. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. In accordance with our business plan, we intend to invest the capital necessary to maintain our cash flow at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue our debt or equity securities on favorable terms, or at all, and we may be unable to refinance our borrowings when our credit facilities expire. Additionally, in the event of significant declines in commodity prices, our borrowing base under our reserve-based credit facility and the ENP Credit Agreement may be redetermined such that they will not provide for the working capital necessary to fund our capital spending program and could affect our ability to make distributions.

Results of Operations

The following table sets forth selected financial and operating data for the periods indicated (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011(a)			2010(c)			2011(a)			2010(b)(c)
Revenues:
Oil sales	$	54,493		$	14,116		$	172,815		$	34,804
Natural gas sales		13,805			6,399			37,020			20,302
NGLs sales		6,131			2,169			17,003			7,094
Oil, natural gas and NGLs sales		74,429			22,684			226,838			62,200
Loss on commodity cash flow hedges		(635	)		(568	)		(2,307	)		(2,127	)
Realized gain on other commodity derivative contracts		1,902			6,513			4,474			18,274
Unrealized gain (loss) on other commodity derivative contracts		109,639			(9,388	)		68,625			1,332
Total revenues	$	185,335		$	19,241		$	297,630		$	79,679
Costs and expenses:
Production:
Lease operating expenses	$	15,393		$	4,838		$	43,960		$	13,545
Production taxes and marketing		7,693			1,753			21,319			5,215
Depreciation, depletion, amortization, and accretion		21,419			6,179			62,797			16,130
Selling, general and administrative expenses		5,330			1,104			16,436			3,638
Total costs and expenses	$	49,835		$	13,874		$	144,512		$	38,528
Other income (expense):
Interest expense	$	(7,509	)	$	(1,708	)	$	(21,137	)	$	(4,522	)
Realized loss on interest rate derivative contracts	$	(664	)	$	(511	)	$	(2,208	)	$	(1,624	)
Gain on interest rate cash flow hedges	$	—		$	101		$	39		$	216
Unrealized loss on interest rate derivative contracts	$	(1,939	)	$	(1,337	)	$	(1,641	)	$	(2,021	)
Net gain (loss) on acquisition of oil and natural gas properties	$	487		$	—		$	(383	)	$	(5,680	)
Other	$	70		$	—		$	76		$	—

	(a)	During 2011, we and ENP acquired certain oil and natural gas properties and related assets in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast area. The operating results of these properties are included with ours from the date of acquisition forward.
	(b)	The Parker Creek Acquisition closed on May 20, 2010 and, as such, only four months and eleven days of operations are included in the nine month period ended September 30, 2010.
	(c)	The Encore Acquisition closed on December 31, 2010 and, as such, no operations are included in the three or nine month periods ended September 30, 2010.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Revenues

Oil, natural gas and NGLs sales increased $51.7 million to $74.4 million during the three months ended September 30, 2011 as compared to the same period in 2010. The key oil, natural gas and NGLs revenue measurements were as follows:

	Three Months Ended September 30,						Percentage Increase (Decrease)
	2011(a)			2010(b)			Percentage Increase (Decrease)
Net Natural Gas Production:
Appalachian gas (MMcf)		665			762			(13)	%
Permian gas (MMcf)		150			100			50	%
South Texas gas (MMcf)		214			427			(50)	%
ENP gas (MMcf)		1,556			—			—
Total natural gas production (MMcf)		2,585			1,289			101	%

Average Appalachian daily gas production (Mcf/day)		7,231			8,276			(13)	%
Average Permian daily gas production (Mcf/day)		1,628			1,087			50	%
Average South Texas daily gas production (Mcf/day)		2,328			4,646			(50)	%
Average ENP daily gas production (Mcf/day)		16,912			—			—
Average daily gas production (Mcf/day)		28,099			14,009			101	%

Average Natural Gas Sales Price per Mcf:
Net realized gas price, including hedges		$8.00	(c)		$9.56	(c)		(16)	%
Net realized gas price, excluding hedges		$5.34			$4.97			7	%

Net Oil Production:
Appalachian oil (Bbls)		21,829			27,971			(22)	%
Permian oil (Bbls)		104,670			103,327			1	%
South Texas oil (Bbls)		5,878			5,341			10	%
Mississippi oil (Bbls)		51,883			63,650			(18)	%
ENP oil (Bbls)		511,046			—			—
Total oil production (Bbls)		695,306			200,289			247	%

Average Appalachian daily oil production (Bbls/day)		237			304			(22)	%
Average Permian daily oil production (Bbls/day)		1,137			1,123			1	%
Average South Texas daily oil production (Bbls/day)		63			58			10	%
Average Mississippi daily oil production (Bbls/day)		564			692			(18)	%
Average ENP daily oil production (Bbls/day)		5,555			—			—
Average daily oil production (Bbls/day)		7,556			2,177			247	%

Average Oil Sales Price per Bbl:
Net realized oil price, including hedges		$76.89	(c)		$75.46	(c)		2	%
Net realized oil price, excluding hedges		$78.19			$70.48			11	%

Net NGLs Production:
Permian NGLs (Bbls)		25,516			9,466			170	%
South Texas NGLs (Bbls)		21,682			42,778			(49)	%
ENP NGLs (Bbls)		56,791			—			—
Total NGLs production (Bbls)		103,989			52,244			99	%

Average Permian daily NGLs production (Bbls/day)		278			103			170	%
Average South Texas daily NGLs production (Bbls/day)		236			465			(49)	%
Average ENP daily NGLs production (Bbls/day)		617			—			—
Average daily NGLs production (Bbls/day)		1,131			568			99	%

Average Net Realized NGLs Sales Price per Bbl		$58.96			$41.58			42	%

	(a)	During 2011, we and ENP acquired certain oil and natural gas properties and related assets in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast area. The operating results of these properties are included with ours from the date of acquisition forward..
	(b)	The Encore Acquisition closed on December 31, 2010 and, as such, no operations are included in the three month period ended September 30, 2010.
	(c)	Excludes amortization of premiums paid and amortization of value on derivative contracts acquired.

The increase in oil, natural gas and NGLs sales during the three months ended September 30, 2011 compared to the same period in 2010 was due primarily to the increases in production from our acquisitions. We experienced an 11% increase in the average realized oil price, excluding hedges, and a 7% increase in the average realized natural gas sales price received, excluding hedges. Oil revenues increased 286% from $14.1 million during the three months ended September 30, 2010 to $54.5 million during the same period in 2011 as a result of a $7.71 per Bbl increase in our average realized oil price, excluding hedges, and a 495.0 MBbls increase in our oil production volumes. Our higher average realized oil price was primarily due to a higher average NYMEX price, which increased from $76.10 per Bbl in the third quarter of 2010 to $89.59 per Bbl in the third quarter of 2011. However, we did not reap the entire benefit of the 18% increase in the NYMEX oil price due to significant widening of the basis differential received on our oil primarily as a result of the closure of Exxon's pipelines in Wyoming due to leaks which affected production from ENP’s Elk Basin field where we had to settle for a lower price per barrel of oil produced during the closure. Natural gas revenues increased 116% from $6.4 million during the three months ended September 30, 2010 to $13.8 million during the same period in 2011 as a result of a $0.37 per Mcf increase in our average realized natural gas price, excluding hedges, and a 101% increase in our natural gas production volumes from the wells acquired in the Encore Acquisition. Additionally, our total production increased by 163% on a BOE basis. The increase in production for the three months ended September 30, 2011 over the comparable period in 2010 was primarily attributable to the impact from the Encore Acquisition completed in December 2010 and all of ENP’s acquisition completed during the third quarter 2011. On a BOE basis, crude oil, natural gas, and NGLs accounted for 57%, 35% and 8%, respectively, of our production during the three months ended September 30, 2011 compared to crude oil, natural gas, and NGLs of 43%, 46% and 11%, respectively, during the same period in 2010.

Hedging and Price Risk Management Activities

During the three months ended September 30, 2011, we recognized a $1.9 million realized gain on other commodity derivative contracts related to the settlements recognized during the period and a $109.6 million gain related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting. These realized and unrealized gains resulted from the changes in commodity prices and the effect of these price changes is discussed in the paragraph below. During the three months ended September 30, 2011 and 2010, we recognized $0.6 million in losses in each period on commodity cash flow hedges that previously met the criteria for cash flow hedge accounting. These amounts relate to derivative contracts that we entered into in order to mitigate commodity price exposure on a portion of our expected production and designated as cash flow hedges. They were later de-designated as cash flow hedges and the losses for the three months ended September 30, 2011 and 2010 relate to amounts that settled in the respective periods which have been reclassified to earnings from accumulated other comprehensive loss.

The purpose of our hedging program is to mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and by us paying the counterparty when commodity prices are above the hedged price. In either case, the impact on our operating cash flow is approximately the same. However, because the majority of our hedges are not designated as cash flow hedges, there can be a significant amount of volatility in our earnings when we record the change in the fair value of all of our derivative contracts. As commodity prices fluctuate, the fair value of those contracts will fluctuate and the impact is reflected as a non-cash, unrealized gain or loss in our Consolidated Statements of Operations. However, these fair value changes that are reflected in the Consolidated Statements of Operations only reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged.

Costs and Expenses

Lease operating expenses increased by $10.6 million to $15.4 million for the three months ended September 30, 2011 as compared to the three months ended September 30, 2010, of which $10.5 million related primarily to the Encore Acquisition and to increased lease operating expenses for oil and natural gas properties acquired by ENP during the third quarter 2011.

Production and other taxes include severance, ad valorem and other taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. Production and other taxes increased by $5.9 million for the three months ended September 30, 2011 as compared to the same period in 2010. Severance taxes increased by $5.0 million as a result of increased oil, natural gas and NGLs sales due to the Encore Acquisition. Ad valorem taxes increased by $0.7 million primarily due to the taxes on oil and natural gas properties acquired in the Encore Acquisition.

Depreciation, depletion, amortization and accretion increased by approximately $15.2 million to $21.4 million for the three months ended September 30, 2011 from approximately $6.2 million for the three months ended September 30, 2010 due primarily to approximately $15.8 million additional depletion recorded on oil and natural gas properties acquired in the Encore Acquisition and oil and natural gas properties acquired by ENP during the third quarter 2011, offset by lower depletion for oil and natural gas properties owned by Vanguard due to lower depletion rate.

Selling, general and administrative expenses include the costs of our administrative employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the three months ended September 30, 2011 increased $4.2 million as compared to the three months ended September 30, 2010 principally due to approximately $2.8 million in incremental costs related to ENP, a $0.8 million increase in Vanguard’s expenses related to the hiring of additional personnel and expanding operations in connection with the Encore Acquisition, a $0.1 million increase in compensation related expenses, a $0.3 million increase in non-cash compensation charges related to the grant of units to employees and the grant of phantom units to officers and a $0.2 million increase in professional fees related to the integration of the ENP operations.

Other Income and Expense

Interest expense increased to $7.5 million for the three months ended September 30, 2011 as compared to $1.7 million for the three months ended September 30, 2010 primarily due to approximately $2.6 million of interest expense on the Term Loan borrowed in connection with the Encore Acquisition, $2.6 million of interest expense incurred for the ENP Credit Agreement and higher average outstanding debt under our reserve-based credit facility during the three months ended September 30, 2011.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Revenues

Oil, natural gas and NGLs sales increased $164.6 million to $226.8 million during the nine months ended September 30, 2011 as compared to the same period in 2010. The key oil, natural gas and NGLs revenue measurements were as follows:

	Nine Months Ended September 30,						Percentage Increase (Decrease)
	2011(a)			2010(b)(c)			Percentage Increase (Decrease)
Net Natural Gas Production:
Appalachian gas (MMcf)		1,980			2,198			(10)	%
Permian gas (MMcf)		341			279			22	%
South Texas gas (MMcf)		1,080			1,287			(16)	%
ENP gas (MMcf)		4,394			—			—
Total natural gas production (MMcf)		7,795			3,764			107	%

Average Appalachian daily gas production (Mcf/day)		7,253			8,050			(10)	%
Average Permian daily gas production (Mcf/day)		1,248			1,023			22	%
Average South Texas daily gas production (Mcf/day)		3,957			4,715			(16)	%
Average ENP daily gas production (Mcf/day)		16,094			—			—
Average daily gas production (Mcf/day)		28,552			13,788			107	%

Average Natural Gas Sales Price per Mcf:
Net realized gas price, including hedges		$7.43	(d)		$ 9.92	(d)		(25)	%
Net realized gas price, excluding hedges		$4.75			$ 5.39			(12)	%

Net Oil Production:
Appalachian oil (Bbls)		70,302			89,301			(21)	%
Permian oil (Bbls)		315,676			291,565			8	%
South Texas oil (Bbls)		16,870			15,793			7	%
Mississippi oil (Bbls)		151,613			90,486			68	%
ENP oil (Bbls)		1,496,432			—			—
Total oil production (Bbls)		2,050,893			487,145			321	%

Average Appalachian daily oil production (Bbls/day)		258			327			(21)	%
Average Permian daily oil production (Bbls/day)		1,157			1,068			8	%
Average South Texas daily oil production (Bbls/day)		62			58			7	%
Average Mississippi daily oil production (Bbls/day)		555			331			68	%
Average ENP daily oil production (Bbls/day)		5,481			—			—
Average daily oil production (Bbls/day)		7,513			1,784			321	%

Average Oil Sales Price per Bbl:
Net realized oil price, including hedges		$79.75	(d)		$ 76.09	(d)		5	%
Net realized oil price, excluding hedges		$84.16			$ 71.44			18	%

Net NGLs Production:
Permian NGLs (Bbls)		45,342			25,763			76	%
South Texas NGLs (Bbls)		101,611			133,881			(24)	%
ENP NGLs (Bbls)		136,722			—			—
Total NGLsproduction (Bbls)		283,675			159,644			78	%

Average Permian daily NGLs production (Bbls/day)		166			94			76	%
Average South Texas daily NGLs production (Bbls/day)		373			490			(24)	%
Average ENP daily NGLs production (Bbls/day)		501			—			—
Average daily NGLs production (Bbls/day)		1,040			584			78	%

Average Net Realized NGLs Sales Price per Bbl		$59.94			$44.52			35	%

	(a)	During 2011, we and ENP acquired certain oil and natural gas properties and related assets in the Permian Basin, Wyoming and the Texas and Louisiana Gulf Coast area. The operating results of these properties are included with ours from the date of acquisition forward.
	(b)	The Parker Creek Acquisition closed on May 20, 2010 and, as such, only four months and eleven days of operations are included in the nine month period ended September 30, 2010.
	(c)	The Encore Acquisition closed on December 31, 2010 and, as such, no operations are included in the nine month period ended September 30, 2010.
	(d)	Excludes amortization of premiums paid and amortization of value on derivative contracts acquired.

The increase in oil, natural gas and NGLs sales during the nine months ended September 30, 2011 compared to the same period in 2010 was due primarily to the increases in production from our acquisitions. We experienced an 18% increase in the average realized oil price, excluding hedges, and a 12% decrease in the average realized natural gas sales price received, excluding hedges. Oil revenues increased 397% from $34.8 million during the nine months ended September 30, 2010 to $172.8 million during the same period in 2011 as a result of a $12.72 per Bbl increase in our average realized oil price, excluding hedges, and a 1,563.7 MBbls increase in our oil production volumes. Our higher average realized oil price was primarily due to a higher average NYMEX price, which increased from $77.60 per Bbl in the first nine months of 2010 to $95.31 per Bbl in the first nine months of 2011. However, we did not reap the entire benefit of the 23% increase in the NYMEX oil price due to significant widening of the basis differential received on our oil primarily as a result of the closure of Exxon's pipelines in Wyoming due to leaks which affected production from ENP’s Elk Basin field where we had to settle for a lower price per barrel of oil produced during the closure. Natural gas revenues increased 82% from $20.3 million during the nine months ended September 30, 2010 to $37.0 million during the same period in 2011 as a result of a 107% increase in our natural gas production volumes from the wells acquired in the Encore Acquisition. The impact of the increase in our natural gas production volumes was offset by a $0.64 per Mcf decrease in our average realized natural gas price, excluding hedges, primarily due to a lower average NYMEX price, which decreased from $4.54 per Mcf in the first nine months of 2010 to $4.19 per Mcf in the first nine months of 2011. Additionally, our total production increased by 185% on a BOE basis. The increase in production for the nine months ended September 30, 2011 over the comparable period in 2010 was primarily attributable to the impact from the Encore Acquisition completed in December 2010 and all of ENP’s acquisition completed during the third quarter 2011. On a BOE basis, crude oil, natural gas and NGLs accounted for 56%, 36% and 8%, respectively, of our production during the nine months ended September 30, 2011 compared to crude oil, natural gas, and NGLs of 38%, 49% and 13%, respectively, during the same period in 2010.

Hedging and Price Risk Management Activities

During the nine months ended September 30, 2011, we recognized a $4.5 million realized gain on other commodity derivative contracts related to the settlements recognized during the period and a $68.6 million gain related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting. These realized and unrealized gains and losses resulted from the changes in commodity prices, and the effect of these price changes is discussed in the paragraph below. During the nine months ended September 30, 2011 and 2010, we recognized $2.3 million and $2.1 million in losses on commodity cash flow hedges that previously met the criteria for cash flow hedge accounting, respectively. These amounts relate to derivative contracts that we entered into in order to mitigate commodity price exposure on a portion of our expected production and designated as cash flow hedges. They were later de-designated as cash flow hedges and the losses for the nine months ended September 30, 2011 and 2010 relate to amounts that settled in the respective periods which have been reclassified to earnings from accumulated other comprehensive loss.

The purpose of our hedging program is to help mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and by us paying the counterparty when commodity prices are above the hedged price. In either case, the impact on our operating cash flow is approximately the same. However, because the majority of our hedges are not designated as cash flow hedges, there can be a significant amount of volatility in our earnings when we record the change in the fair value of all of our derivative contracts. As commodity prices fluctuate, the fair value of those contracts will fluctuate and the impact is reflected as a non-cash, unrealized gain or loss in our Consolidated Statements of Operations. However, these fair value changes that are reflected in the Consolidated Statements of Operations only reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged.

Costs and Expenses

Lease operating expenses increased by $30.4 million to $44.0 million for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010, of which $29.2 million related primarily to the Encore Acquisition and to increased lease operating expenses for oil and natural gas properties acquired by ENP during the third quarter 2011. Additionally, contributing to this increase were higher lease operating expenses for wells acquired in the Parker Creek Acquisition and the Permian Basin I acquisition.

Production and other taxes include severance, ad valorem and other taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. Production taxes increased by $16.1 million for the nine months ended September 30, 2011 as compared to the same period in 2010. Severance taxes increased by $13.9 million as a result of increased oil, natural gas and NGLs due to the Encore Acquisition. Ad valorem taxes increased by $1.8 million primarily due to the taxes on oil and natural gas properties acquired in the Encore Acquisition.

Depreciation, depletion, amortization and accretion increased to approximately $62.8 million for the nine months ended September 30, 2011 from approximately $16.1 million for the nine months ended September 30, 2010 due primarily to approximately $46.1 million additional depletion recorded on oil and natural gas properties acquired in the Encore Acquisition and oil and natural gas properties acquired by ENP during the third quarter 2011.

Selling, general and administrative expenses include the costs of our administrative employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the nine months ended September 30, 2011 increased $12.8 million as compared to the nine months ended September 30, 2010 principally due to approximately $7.9 million in incremental costs related to ENP, a $0.7 million increase in non-cash compensation charges related to the grant of units to employees and the grant of phantom units to officers, a $1.1 million increase in compensation related expenses and a $3.1 million increase in Vanguard’s expenses related to the hiring of additional personnel and expanding operations in connection with the Encore Acquisition.

Other Income and Expense

Interest expense increased to $21.1 million for the nine months ended September 30, 2011 as compared to $4.5 million for the nine months ended September 30, 2010 primarily due to approximately $7.6 million of interest expense on the Term Loan borrowed in connection with the Encore Acquisition, $7.0 million of interest expense incurred for the ENP Credit Agreement and higher average outstanding debt under our reserve-based credit facility during the nine months ended September 30, 2011.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to select and apply accounting policies that best provide the framework to report its results of operations and financial position. The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of September 30, 2011, our critical accounting policies were consistent with those discussed in our 2010 Annual Report.

Use of Estimates

Liquidity and Capital Resources

Overview

We have utilized private equity, proceeds from bank borrowings, cash flow from operations and more recently the public equity markets for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties; however, we expect to distribute to unitholders a significant portion of our free cash flow. As we execute our business strategy, we will continually monitor the capital resources available to us to meet future financial obligations, planned capital expenditures, acquisition capital and distributions to our unitholders. Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for and acquiring additional reserves. We expect to fund our drilling capital expenditures and distributions to unitholders with cash flow from operations, while funding any acquisition capital expenditures that we might incur with borrowings under VNR’s reserve-based credit facility or the ENP Credit Agreement and publicly offered equity or debt, depending on market conditions. As of November 7, 2011, we had $51.0 million and $54.0 million available to be borrowed under Vanguard’s reserve-based credit facility and under ENP’s Credit Agreement, respectively.

The borrowing bases are subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the bank’s petroleum engineers utilizing the bank’s internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. If commodity prices decline in the future and banks lower their internal projections of oil, natural gas and NGLs prices, it is possible that we will be subject to further decreases in our borrowing base availability in the future. If our outstanding borrowings under VNR’s reserve-based credit facility exceed 90% of the borrowing base, we would be required to suspend distributions to our unitholders until we have reduced our borrowings to below the 90% threshold.

Our Consolidated Balance Sheets include the $175.0 million one year Term Loan used to finance the Encore Acquisition and all of the outstanding debt of ENP as current liabilities. The ENP Credit Agreement matures on March 7, 2012; therefore, all outstanding borrowings under the ENP Credit Agreement are reflected as a current liability on the balance sheet. On September 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amends and restates the Company’s Second Amended and Restated Credit Agreement (the “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 the Company 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, VNR agrees that a portion of the proceeds of the credit facility created by the Amended Credit Agreement be used to repay amounts outstanding under the ENP Credit Agreement. In addition, VNR has agreed that upon the effectiveness of the Amended Agreement, all outstanding debt under the Term Loan shall have been repaid in full and the corresponding Term Loan credit facility will be terminated and extinguished. 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 ENP revolving credit facility, refinancing the Term Loan or refinancing both obligations under new revolving credit facilities.

Absent accretive acquisitions, to the extent available after unitholder distributions, debt service and capital expenditures, it is our intention to utilize our excess cash flow to reduce our borrowings under our reserve-based credit facilities. Based upon current expectations, we believe existing liquidity and capital resources will be sufficient to conduct our business and operations for the foreseeable future.

Cash Flow from Operations

Net cash provided by operating activities was $129.1 million during the nine months ended September 30, 2011, as compared to $51.0 million during the nine months ended September 30, 2010. The increase in cash provided by operating activities during the nine months ended September 30, 2011 as compared to the same period in 2010 was substantially generated from increased production volumes related to the Encore Acquisition and the acquisitions of oil and natural gas properties completed by Vanguard and ENP during the nine months ended September 30, 2011. Changes in working capital decreased total cash flows by $10.0 million in 2011 as compared to $3.9 million in 2010. Contributing to the decrease in working capital during 2011 was a $12.4 million increase in accounts receivable resulting from the timing of collections offset by a $5.0 million increase in accounts payable, oil and natural gas revenue payable and accrued expenses that resulted primarily from the timing effects of payments for transaction costs related to the Encore Acquisition and compensation related amounts and the timing of payment for invoices. Unrealized derivative gains and losses are non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the nine months ended September 30, 2011 or 2010.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and NGLs. Oil, natural gas and NGLs prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather, and other factors beyond our control. Future cash flow from operations will depend on our ability to maintain and increase production through our drilling program and acquisitions, as well as the prices received for production. We enter into derivative contracts to reduce the impact of commodity price volatility on operations. Currently, we use a combination of fixed-price swaps, basis swaps, puts, swaptions, NYMEX collars and three-way collars to reduce our exposure to the volatility in oil, natural gas and NGLs prices. See Note 4 in Notes to Consolidated Financial Statements and Part 1—Item 3—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk, for details about derivatives in place through 2014 for oil and natural gas.

Cash Flow from Investing Activities

Cash used in investing activities was approximately $203.7 million for the nine months ended September 30, 2011, as compared to $128.0 million during the same period in 2010. Cash used in investing activities during the first nine months of 2011 was primarily attributable to $23.7 million for the drilling and development of oil and natural gas properties, $183.7 million for the acquisitions of oil and natural gas properties and $0.7 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties, offset by $5.0 million in proceeds from the divestiture of certain oil and natural gas properties in the Permian Basin. Cash used in investing activities during the first nine months of 2010 included $114.5 million for the acquisition of oil and natural gas properties in the Parker Creek Acquisition, $13.2 million for the drilling and development of oil and natural gas properties and $0.07 million for prepayments for the drilling and development of oil and natural gas properties.

Cash Flow from Financing Activities

Cash provided by financing activities was approximately $76.1 million for the nine months ended September 30, 2011, as compared to $79.7 million for the nine months ended September 30, 2010. During the nine months ended September 30, 2011, total net proceeds from borrowings under our financing arrangements were $164.0 million. Additionally, cash of $51.5 million was used in distributions to unitholders and $35.9 million in ENP’s distributions to non-controlling interest. Cash provided by financing activities during the nine months ended September 30, 2010 included $41.1 million in net borrowings under our reserve-based credit facility and proceeds from our public equity offerings of $73.0 million, net of offering costs of $0.2 million. Offsetting the cash provided by financing activities during the nine months ended September 30, 2010 was cash used of $31.9 million for distributions to unitholders.

Reserve-Based Credit Facility

On January 3, 2007, we entered into a reserve-based credit facility under which our initial borrowing base was set at $115.5 million. In June 2010, we entered into the Second Amendment to Second Amended and Restated Credit Agreement, which (1) increased the borrowing base to $240.0 million, (2) allows us to enter into commodity price hedges with respect to the acquired production upon signing a purchase and sale agreement, (3) added a new lender, Credit Agricole Corporate and Investment Bank, and (4) allows us to hedge up to 85% of the projected oil and gas production from total proved reserves. Previously, our hedging was limited to 95% of the projected oil and gas production from proved developed producing reserves. The other terms and conditions of the reserve-based credit facility remained substantially the same. In November 2010, our borrowing base under the reserve-based credit facility was reduced from $240.0 million to $225.0 million pursuant to our semi-annual redetermination. Also in November 2010, in connection with the Encore Acquisition, we entered into the Third Amendment to the Second Amended and Restated Credit Agreement to provide for certain amendments and modifications to allow us to incur indebtedness under, and grant the related security interests for the Term Loan discussed below. Such amendments and modifications included the granting of a second priority lien on VNG’s interests in ENP GP and the ENP Units. In addition to the existing first priority liens on the assets of VNG and its subsidiaries, amounts outstanding under the reserve-based credit facility will also be secured by a second priority lien on VNG’s interest in ENP GP and the ENP Units. In December 2010, we entered into the Fourth Amendment to Second Amended and Restated Credit Agreement, which contains certain amendments necessary to exclude ENP GP’s pledge of the general partners interests issued by ENP that it owns as collateral securing the loans and other extensions of credit made to VNG pursuant to the Second Amended and Restated Credit Agreement. Additionally, the Fourth Amendment clarifies the amounts guaranteed by subsidiaries of VNG pursuant to guaranty agreements previously delivered by such subsidiaries. On July 28, 2011, the borrowing base under our reserve-based credit facility was increased from $235.0 million to $265.0 million pursuant to our request for an interim redetermination in connection with the Permian Basin Acquisition I. All other terms of the reserve-based credit facility remained the same. At September 30, 2011, the applicable margins and other fees will increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans Margin	2.25%	2.50%	2.75%	3.00%
ABR Loans Margin	1.25%	1.50%	1.75%	2.00%
Commitment Fee Rate	0.50%	0.50%	0.50%	0.50%
Letter of Credit Fee	2.25%	2.50%	2.75%	3.00%

The borrowing base is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the bank’s petroleum engineers utilizing the bank’s internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. If commodity prices decline in the future and banks lower their internal projections of oil, natural gas and NGLs prices, it is possible that we will be subject to further decreases in our borrowing base availability in the future. If our outstanding borrowings under the reserve-based credit facility exceed 90% of the borrowing base, we would be required to suspend distributions to our unitholders until we have reduced our borrowings to below the 90% threshold. As a result, absent accretive acquisitions, it is our current intention to utilize our excess cash flow during the remainder of 2011 to reduce our borrowings under our reserve-based credit facility. As of November 7, 2011, we had $51.0 million available to be borrowed under our reserve-based credit facility.

Borrowings under the reserve-based credit facility are available for the development and acquisition of oil and natural gas properties, working capital, and general limited liability company purposes. Our obligations under the reserve-based credit facility are secured by substantially all of our assets.

At our election, interest is determined by reference to:

the London interbank offered rate, or LIBOR, plus an applicable margin between 2.25% and 3.00% per annum; or

a domestic bank rate plus an applicable margin between 1.25% and 2.00% per annum.

As of September 30, 2011, we had elected for interest to be determined by reference to the LIBOR method described above. Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans, but not less frequently than quarterly.

The reserve-based credit facility contains various covenants that limit our ability to:

incur indebtedness;

grant certain liens;

make certain loans, acquisitions, capital expenditures and investments;

make distributions;

merge or consolidate; or

engage in certain asset dispositions, including a sale of all or substantially all of our assets.

The reserve-based credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income (which is equal to our Adjusted EBITDA), and giving pro forma effect to any acquisitions or capital expenditures, to interest expense of not less than 2.5 to 1.0;

consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC Topic 815, which includes the current portion of derivative contracts; and

consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 3.5 to 1.0.

We have the ability to borrow under the reserve-based credit facility to pay distributions to unitholders as long as there has not been a default or event of default and if the amount of borrowings outstanding under our reserve-based credit facility is less than 90% of the borrowing base.

As of September 30, 2011, we were in compliance with all covenants under our reserve-based credit facility. If an event of default exists under the reserve-based credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Among others, each of the following will be an event of default:

failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

a representation or warranty is proven to be incorrect when made;

failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

default by us on the payment of any other indebtedness in excess of $2.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

bankruptcy or insolvency events involving us or our subsidiaries;

the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any year; and

a change of control, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the SEC) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests other than by Majeed S. Nami or his affiliates, or (2) the replacement of a majority of our directors by persons not approved by our board of directors.

On September 30, 2011, we entered into the Amended Credit Agreement which amends and restates the Company’s 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 the Company and ENP. Additionally, as a condition precedent to the effectiveness of the Amended Credit Agreement, Vanguard is required to repay all outstanding debt under the Term Loan and to terminate and extinguish the corresponding Term Loan credit facility by the effective date of Amended Credit Agreement. The Amended Credit Agreement provides for an initial borrowing base of $765 million and a maturity of October 31, 2016. The borrowing base under the Amended Credit Agreement will be redetermined semi-annually by the lenders in their sole discretion, based on, among other things, reserve reports as prepared by reserve engineers taking into account the oil and natural gas prices at such time. The Company’s obligations under the Amended Credit Agreement are secured by mortgages on its oil and natural gas properties. Additionally, the obligations under the Amended Credit Agreement are guaranteed by all of the Company’s operating subsidiaries and may be guaranteed by any future subsidiaries. Under the Amended Credit Agreement, we have agreed that a portion of the proceeds of the credit facility created by this Amended Credit Agreement be used to repay amounts outstanding under the ENP Credit Agreement.

The Amended Credit Agreement contains various covenants, substantially similar to the Existing Facility, that limit the Company’s ability to incur indebtedness, enter into commodity and interest rate swaps, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. The Amended Credit Agreement also contains covenants, substantially similar to the Existing Facility, that require the Company to maintain specified financial ratios. Under the Amended Credit Agreement the debt-to-EBITDA covenant was increased to 4.0x from 3.5x under the Existing Facility. The Amended Credit Agreement also increased the percentage of production that can be hedged into the future, eliminated the required interest coverage ratio, eliminated the ten percent liquidity requirement to pay distributions to unitholders, and allowed for unsecured debt. The other terms and conditions of the Amended Credit Agreement are substantially similar to the Existing Facility.

Under the Amended Credit Agreement, the applicable margins and other fees based on the utilization of the borrowing base are as follows:

Borrowing Base Utilization Percentage	<25%	>25% <50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans	1.50%	1.75%	2.00%	2.25%	2.50%
ABR Loans and Letter of Credit Fee Rate	0.50%	0.75%	1.00%	1.25%	1.50%
Commitment Fee Rate	0.50%	0.50%	0.375%	0.375%	0.375%

Term Loan

Concurrent with the Encore Acquisition, VNG entered into a $175.0 million Term Loan with BNP Paribas to fund a portion of the consideration for the acquisition.

Borrowings under the Term Loan are comprised entirely of ABR Loans or Eurodollar Loans as VNG may request. Interest on ABR Borrowings under the Term Loan is payable quarterly on the last day of each March, June, September and December and accrues at a rate per annum equal to 6.50% plus the greater of (a) the prime rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1%, and (c) the Adjusted LIBOR Rate in effect on such day plus 2%. Interest on Eurodollar Borrowings is payable on the last day of the interest period applicable to such borrowing, and in the case of a Eurodollar Borrowing with an interest period of more than six months' duration, each day prior to the last day of such interest period that occurs at intervals of six months' duration after the first day of such interest period and accrues at a rate per annum of 5.50% plus the Adjusted LIBOR Rate for the interest period in effect for such borrowing. Amounts outstanding under the Term Loan may be prepaid prior to maturity, together with all accrued and unpaid interest relating to the amount prepaid, without prepayment penalty. The Term Loan contains various covenants, including restrictions on liens, restrictions on incurring other indebtedness without the lenders’ consent and restrictions on entering into certain transactions. The Term Loan matures the earlier of the first anniversary of the effective date (December 31, 2011) or the date following both the completion of any acquisition by Vanguard of the remainder of ENP and VNG’s execution and delivery of a new or amended and restated revolving credit facility replacing VNG’s current reserve-based credit facility. As previously indicated, as a condition precedent to the effectiveness of the Amended Credit Agreement referred to above, Vanguard is required to repay all outstanding debt under the Term Loan and to terminate and extinguish the corresponding Term Loan credit facility by the effective date of Amended Credit Agreement.

On December 31, 2010, VNG entered into the First Amendment to Term Loan Agreement, which contains certain amendments necessary to exclude ENP GP’s pledge of the general partner’s interests issued by ENP that it owns as collateral securing the loans and other extensions of credit made to VNG pursuant to the Term Loan Agreement.

The Term Loan also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income (which is equal to our Adjusted EBITDA), and giving pro forma effect to cash distributions by ENP and ENP GP with respect to ENP Interests (annualized) less the aggregate amount of cash used to purchase equity interests of VNR, to interest expense of not less than 2.5 to 1.0;

As of September 30, 2011, we were in compliance with all covenants under the Term Loan.

ENP’s Credit Agreement

The syndicate of lenders underwriting ENP’s credit agreement includes 15 banking and other financial institutions. None of the lenders are underwriting more than 8% of the total commitments. We believe the number of lenders and the small percentage participation of each, provides adequate diversity and flexibility should further consolidation occur within the financial services industry.

ENP entered into a credit agreement dated March 7, 2007 (as amended, the “ENP Credit Agreement”). The ENP Credit Agreement matures on March 7, 2012; therefore all outstanding borrowings under the ENP Credit Agreement are reflected as a current liability at September 30, 2011. On September 30, 2011, Vanguard entered into an Amended Credit Agreement that would retire all of the outstanding debt of ENP upon the consummation of a merger with Vanguard as discussed above.

The ENP 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 ENP Credit Agreement is $475.0 million. Availability under the ENP Credit Agreement was subject to a borrowing base of $400.0 million, which is redetermined semi-annually and upon requested special redeterminations. As of September 30, 2011, there were $356.0 million of outstanding borrowings and $44.0 million of borrowing capacity under the ENP Credit Agreement. As of November 7, 2011, there were $346.0 million of outstanding borrowings and $54.0 million of borrowing capacity under the ENP Credit Agreement.

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

Ratio of Outstanding Borrowings to Borrowing Base	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans Margin	2.25%	2.50%	2.75%	3.00%
ABR Loans Margin	1.25%	1.50%	1.75%	2.00%

The “Eurodollar rate” for any interest period (either one, two, six, or six months, as selected by us) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the Federal Funds Effective Rate plus 0.5%; 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%.

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

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

a prohibition against incurring debt, subject to permitted exceptions;

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

a restriction on creating liens on our assets and the assets of ENP and its 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% 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 ENP 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, as defined in the ENP 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 EBITDAX, as defined in the ENP Credit Agreement, of not more than 3.5 to 1.0.

The ENP 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 ENP Credit Agreement to be immediately due and payable. As of September 30, 2011, we were in compliance with all covenants under the ENP Credit Agreement.

Off-Balance Sheet Arrangements

At September 30, 2011, we did not have any off-balance sheet arrangements that have, or are reasonably likely to have, an effect on our financial position or results of operations.

Contingencies

We regularly analyze current information and accrue for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. As of September 30, 2011, there were no loss contingencies. Please read Note 8 of the Notes to the Consolidated Financial Statements included in Item 1. Unaudited Financial Statements for additional information regarding pending litigation related to the proposed merger with ENP.

Commitments and Contractual Obligations

A summary of our contractual obligations as of September 30, 2011 is provided in the following table (in thousands):

	Payments Due by Year (in thousands)
	2011		2012		2013		2014		2015		After 2015		Total
Management base salaries	$	261	$	1,045	$	116	$	—	$	—	$	—	$	1,422
Asset retirement obligations (1)		260		997		1,291		653		502		31,679		35,382
Derivative liabilities (2)		773		9,216		8,444		5,305		7,716		16		31,470
Financing arrangements (3)		175,000		574,500		—		—		—		—		749,500
Operating leases		265		932		251		—		—		—		1,448
Development commitments (4)		890		—		—		—		—		—		890
Total	$	177,449	$	586,690	$	10,102	$	5,958	$	8,218	$	31,695	$	820,112

	(1)	Represents the discounted future plugging and abandonment costs of oil and natural gas wells and the decommissioning of ENP’s Elk Basin gas plant. Please read Note 6 of the Notes to the Consolidated Financial Statements included in Item 1. Unaudited Financial Statements for additional information regarding our asset retirement obligations.
	(2)	Represents liabilities for commodity and interest rate derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 3—Quantitative and Qualitative Disclosures About Market Risk” and Note 4 of the Notes to the Consolidated Financial Statements included in Item 1. Unaudited Financial Statements for additional information regarding our commodity and interest rate derivative contracts.
	(3)	This table does not include interest to be paid on the principal balances shown as the interest rates on our financing arrangements are variable. Please read Note 3 of the Notes to the Consolidated Financial Statements included in Item 1. Unaudited Financial Statements for additional information regarding our long-term debt.
	(4)	Represents authorized purchases for work in process.

Non-GAAP Financial Measure

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income attributable to Vanguard unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income attributable to Vanguard unitholders plus net income attributable to the non-controlling interest. The result is net income which includes the non-controlling interest. From this we add or subtract the following:

•

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

•

Depreciation, depletion, and amortization (including accretion of asset retirement obligations);

•

Amortization of premiums paid on derivative contracts;

•

Amortization of value on derivative contracts acquired;

•

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

•

Net gains and losses on acquisition of oil and natural gas properties;

•

Deferred taxes;

•

Unit-based compensation expense;

•

Unrealized fair value of phantom units granted to officers;

•

Material transaction costs incurred on acquisitions and mergers;

•

Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard unitholders; and

•

Administrative services fees charged to ENP, excluding the non-controlling interest, which are eliminated in consolidation.

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

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

For the three months ended September 30, 2011 as compared to the three months ended September 30, 2010, Adjusted EBITDA attributable to Vanguard unitholders increased 67%, from $22.2 million to $37.0 million. For the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010, Adjusted EBITDA attributable to Vanguard unitholders increased 86%, from $59.8 million to $111.1 million. The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDA (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011			2010		2011			2010
Net income attributable to Vanguard unitholders	$	75,884		$	1,912	$	77,271		$	27,520
Net income attributable to non-controlling interest		50,061			—		50,593			—
Net income		125,945			1,912		127,864			27,520
Plus:
Interest expense, including realized losses on interest rate derivative contracts and gain on interest rate cash flow hedges		8,173			2,118		23,306			5,930
Depreciation, depletion, amortization and accretion		21,419			6,179		62,797			16,130
Amortization of premiums paid on derivative contracts		4,663			481		9,501			1,479
Amortization of value on derivative contracts acquired		36			489		154			1,657
Unrealized (gains) losses on other commodity and interest rate derivative contracts		(107,700	)		10,725		(66,984	)		689
Net (gain) loss on acquisition of oil and natural gas properties		(487	)		—		383			5,680
Deferred taxes		220			12		415			(37	)
Unit-based compensation expense		675			190		1,821			656
Unrealized fair value of phantom units granted to officers		77			55		310			103
Material transaction costs incurred on acquisitions and mergers		1,182			—		1,745			—
Adjusted EBITDA before non-controlling interest		54,203			22,161		161,312			59,807
Non-controlling interest attributable to adjustments above		(17,957	)		—		(52,457	)		—
Administrative services fees eliminated in consolidation		782			—		2,250			—
Adjusted EBITDA attributable to Vanguard unitholders	$	37,028		$	22,161	$	111,105		$	59,807

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGLs prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Conditions sometimes arise where actual production is less than estimated, which has, and could result in overhedged volumes.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, natural gas and NGLs production. Realized pricing is primarily driven by the Columbia Gas Appalachian Index (“TECO Index”), Henry Hub, Houston Ship Channel, West Texas (“Waha Index”), El Paso Natural Gas Company (Permian Basin) and Colorado Interstate Gas Company (Rocky Mountains) prices for natural gas production and the West Texas Intermediate (“WTI”) Light Sweet price for oil production. Pricing for oil, natural gas and NGLs production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control. In addition, the potential exists that if commodity prices decline to a certain level, the borrowing base can be decreased at the borrowing base redetermination date to an amount lower than the amount of debt currently outstanding and, because it would be uneconomical, production could decline to levels below our hedged volumes.

Furthermore, the risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, write downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if estimated future development costs increase.

We enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that mitigate the volatility of future prices received. These transactions may include price swaps whereby we will receive a fixed-price for our production and pay a variable market price to the contract counterparty. Additionally, we may acquire put options for which we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. As each monthly contract settles, we receive the excess, if any, of the fixed floor over the floating rate. We also enter into basis swap contracts which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. Furthermore, we may enter into collars where we pay the counterparty if the market price is above the ceiling price and the counterparty pays us if the market price is below the floor on a notional quantity. We also may enter into three-way collar contracts which 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 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. We also enter into swaption agreements, under which we provide options to counterparties to extend swap contracts into subsequent years. In deciding which type of derivative instrument to use, our management considers the relative benefit of each type against any cost that would be incurred, prevailing commodity market conditions and management’s view on future commodity pricing. The amount of oil and natural gas production which is hedged is determined by applying a percentage to the expected amount of production in our most current reserve report in a given year. Typically, management intends to hedge 75% to 85% of projected production up to a four year period. These activities are intended to support our realized commodity prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Management will consider liquidating a derivative contract if they believe that they can take advantage of an unusual market condition allowing them to realize a current gain and then have the ability to enter into a new derivative contract in the future at or above the commodity price of the contract that was liquidated.

At September 30, 2011, the fair value of commodity derivative contracts was an asset of approximately $46.6 million, of which $27.8 million settles during the next twelve months.

The following table summarizes commodity derivative contracts in place at September 30, 2011:

	October 1, -
	December 31,		Year		Year		Year
	2011		2012		2013		2014
Gas Positions:
Fixed Price Swaps:
VNG
Notional Volume (MMBtu)		724,426		1,281,000		2,190,000		—
Fixed Price ($/MMBtu)	$	7.83	$	5.45	$	5.62	$	—
ENP
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
Consolidated
Notional Volume (MMBtu)		1,893,010		5,929,932		6,460,500		452,500
Fixed Price ($/MMBtu)	$	6.58	$	5.51	$	5.24	$	4.80
Collars:
VNG
Notional Volume (MMBtu)		579,600		—		—		—
Floor Price ($/MMBtu)	$	7.50	$	—	$	—	$	—
Ceiling Price ($/MMBtu)	$	8.66	$	—	$	—	$	—
Puts:
ENP
Notional Volume (MMBtu)		312,616		328,668		—		—
Fixed Price ($/MMBtu)	$	6.31	$	6.76	$	—	$	—
Total Gas Positions:
VNG
Notional Volume (MMBtu)		1,304,026		1,281,000		2,190,000		—
Fixed Price ($/MMBtu)	$	7.68	$	5.45	$	5.62	$	—
ENP
Notional Volume (MMBtu)		1,481,200		4,977,600		4,270,500		452,500
Fixed Price ($/MMBtu)	$	5.92	$	5.61	$	5.05	$	4.80
Consolidated
Notional Volume (MMBtu)		2,785,226		6,258,600		6,460,500		452,500
Fixed Price ($/MMBtu)	$	6.74	$	5.57	$	5.24	$	4.80

	October 1, -
	December 31,		Year		Year		Year
	2011		2012		2013		2014
Oil Positions:
Fixed Price Swaps:
VNG
Notional Volume (Bbls)		128,500		420,900		—		209,875
Fixed Price ($/Bbl)	$	90.23	$	92.42	$	—	$	94.37
ENP
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
Consolidated
Notional Volume (Bbls)		269,720		1,442,040		1,332,250		1,414,375
Fixed Price ($/Bbl)	$	86.52	$	86.80	$	89.11	$	89.91
Collars:
VNG
Notional Volume (Bbls)		9,200		118,950		82,125		12,000
Floor Price ($/Bbl)	$	100.00	$	90.77	$	88.89	$	100.00
Ceiling Price ($/Bbl)	$	116.20	$	106.62	$	107.34	$	116.20
ENP
Notional Volume (Bbls)		172,960		475,800		—		—
Floor Price ($/Bbl)	$	80.00	$	74.23	$	—	$	—
Ceiling Price ($/Bbl)	$	96.49	$	90.98	$	—	$	—
Consolidated
Notional Volume (Bbls)		182,160		594,750		82,125		12,000
Floor Price ($/Bbl)	$	81.01	$	77.54	$	88.89	$	100.00
Ceiling Price ($/Bbl)	$	97.48	$	94.11	$	107.34	$	116.20
Three Way Collars:
VNG
Notional Volume (Bbls)		20,700		82,350		387,525		—
Floor Price ($/Bbl)	$	90.00	$	90.00	$	90.21	$	—
Ceiling Price ($/Bbl)	$	102.06	$	111.22	$	102.38	$	—
Put Sold ($/Bbl)	$	70.00	$	70.00	$	62.12	$	—
ENP
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
Consolidated
Notional Volume (Bbls)		69,000		274,500		579,150		54,750
Floor Price ($/Bbl)	$	90.00	$	90.00	$	90.14	$	90.00
Ceiling Price ($/Bbl)	$	102.41	$	108.10	$	103.83	$	105.00
Put Sold ($/Bbl)	$	70.00	$	70.00	$	64.73	$	70.00
Total Oil Positions:
VNG
Notional Volume (Bbls)		158,400		622,200		469,650		221,875
Fixed Price ($/Bbl)	$	90.77	$	91.78	$	89.98	$	94.68
ENP
Notional Volume (Bbls)		362,480		1,689,090		1,523,875		1,259,250
Fixed Price ($/Bbl)	$	82.56	$	82.23	$	89.23	$	89.17
Consolidated
Notional Volume (Bbls)		520,880		2,311,290		1,993,525		1,481,125
Fixed Price ($/Bbl)	$	85.05	$	84.80	$	89.40	$	90.00

As of September 30, 2011, the Company 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 ($/Bbl) (2)	$	19.10		$	15.15		$	9.60		$	—

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

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

Calls were sold or options provided to counterparties under swaption agreements to extend the swaps into subsequent years as follows:

	Year 2012		Year 2013		Year 2014		Year 2015
Gas Positions:
Swaptions:
VNG
Notional Volume (MMBtu)		—		—		1,277,500		—
Weighted Average Fixed Price ($/MMBtu)	$	—	$	—	$	5.77	$	—
ENP
Notional Volume (MMBtu)		—		—		365,000		—
Weighted Average Fixed Price ($/MMBtu)	$	—	$	—	$	5.40	$	—
Consolidated
Notional Volume (MMBtu)		—		—		1,642,500		—
Weighted Average Fixed Price ($/MMBtu)	$	—	$	—	$	5.69	$	—

Oil Positions:
Swaptions:
VNG
Notional Volume (Bbls)		91,500		68,600		127,750		292,000
Weighted Average Fixed Price ($/Bbl)	$	95.20	$	99.44	$	95.00	$	95.63
ENP
Notional Volume (Bbls)		—		36,500		—		36,500
Weighted Average Fixed Price ($/Bbl)	$	—	$	105.00	$	—	$	95.00
Consolidated
Notional Volume (Bbls)		91,500		105,100		127,750		328,500
Weighted Average Fixed Price ($/Bbl)	$	95.20	$	101.37	$	95.00	$	95.56

Interest Rate Risks

At September 30, 2011, we had debt outstanding of $749.5 million. The amount outstanding under our reserve-based credit facility at September 30, 2011 of $218.5 million is subject to interest at floating rates based on LIBOR. If the debt remains the same, a 10% increase in LIBOR would result in an estimated two thousand dollar increase in annual interest expense after consideration of the interest rate swaps discussed below. There was no interest rate derivatives hedging the interest rates associated with the amount outstanding under our Term Loan at September 30, 2011 of $175.0 million. At September 30, 2011, we had outstanding borrowings under the ENP Credit Agreement of $356.0 million, $75.0 million of which has a fixed interest rate pursuant to an interest rate swap through March 2016, and the remainder of which is subject to floating market rates of interest that are linked to the Eurodollar rate. At this level of floating rate debt, if the Eurodollar rate increased 10%, we would incur an additional $0.06 million of interest expense per year.

We enter into interest rate swaps, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The Company records changes in the fair value of its interest rate derivatives in current earnings under unrealized gains (losses) on interest rate derivative contracts. During 2008, VNR chose to de-designate its interest rate swaps as cash flow hedges as the terms of new contracts entered into in August 2008 no longer matched the terms of the original contracts, thus causing the interest rate hedges to be ineffective. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive income and is being reclassified to earnings in the month in which the transactions settle.

The following summarizes information concerning our positions in open interest rate derivative contracts at September 30, 2011 (in thousands):

	Notional Amount		Fixed Libor Rates
Period:
VNG
October 1, 2011 to December 10, 2014	$	20,000		2.60	%
October 1, 2011 to January 31, 2015	$	40,000		1.75	%
October 1, 2011 to January 31, 2015	$	20,000		1.89	%
October 1, 2011 to September 23, 2016	$	75,000		1.15	%
August 6, 2012 to August 6, 2014	$	25,000		2.09	%
August 6, 2012 to August 5, 2015 (1)	$	30,000		2.25	%
ENP
October 1, 2011 to March 7, 2016 (2)	$	75,000		1.08	%

	(1)	The counterparty has the option to extend the termination date of this contract to August 5, 2018.
	(2)	ENP entered into this interest rate swap on September 21, 2011, and the terms became effective on October 7, 2011.

Counterparty Risk

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

	Current Assets		Long-Term Assets		Current Liabilities			Long-Term Liabilities			Total Amount Due From/(Owed To) Counterparty at September 30, 2011
Citibank, N.A. (A+)	$	2,047	$	682	$	—		$	—		$	2,729
Wells Fargo Bank N.A./Wachovia Bank, N.A. (AA)		368		2,797		(141	)		—			3,024
BNP Paribas (AA)		9,553		3,213		(1,184	)		(2,533	)		9,049
The Bank of Nova Scotia (AA-)		4,191		4,335		(199	)		(1,289	)		7,038
BBVA Compass (A)		30		277		—			—			307
Credit Agricole (A+)		7,570		3,743		(223	)		(360	)		10,730
Royal Bank of Canada (AA-)		3,148		4,199		—			—			7,347
Natixis (A+)		1,012		—		—			(11	)		1,001
Bank of America (A+)		—		—		(66	)		(230	)		(296	)
Total	$	27,919	$	19,246	$	(1,813	)	$	(4,423	)	$	40,929

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with our counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us 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 our credit exposure to a given counterparty in the event of close-out.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

On December 31, 2010, we completed the acquisition of all of the member interest in ENP GP and 20,924,055 common units representing limited partnership interests in ENP, which represented a 46.6% aggregate equity interest in ENP at September 30, 2011. Pursuant to this acquisition, the functions of the ENP accounting department were transitioned to Houston and integrated with VNG’s, and ENP’s books and records were converted to a new accounting software. Additionally, the books and records of Vanguard and its subsidiaries were converted to the same accounting software, and Vanguard Permian’s production accounting functions, that had been previously outsourced to a third party, were brought in-house. As a result, our management is continuing to implement new processes and modify existing processes.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Form 10-Q or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our common units, please refer to Part I-Item 1A-Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (the “2010 Annual Report”) and to Part II-Item 1A-Risk Factors in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011 and June 30, 2011. There have been no material changes to the risk factors set forth in our 2010 Annual Report and Part II-Item 1A-Risk Factors in our Quarterly Reports on Form 10-Q for the periods ended March 31, 2011 and June 30, 2011.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Removed and Reserved

Item 5. Other Information

None.

Item 6. Exhibits

EXHIBIT INDEX

Each exhibit identified below is filed as a part of this Report.

Exhibit No.	Exhibit Title	Incorporated by Reference to the Following
3.1	Certificate of Formation of Vanguard Natural Resources, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
3.2	Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC (including specimen unit certificate for the units)	Form 8-K, filed November 2, 2007 (File No. 001-33756)
10.1	Agreement and Plan of Merger, dated July 10, 2011 among Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Vanguard Acquisition Company, LLC, Encore Energy Partners L.P. and Encore Energy Partners GP LLC	Form 8-K, filed July 11, 2011 (File No. 001-33756)
10.2	Third Amended and Restated Credit Agreement dated September 30, 2011, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Form 8-K, filed October 5, 2011 (File No. 001-33756)
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

SIGNATURES

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

	VANGUARD NATURAL RESOURCES, LLC
	(Registrant)

Date: November 8, 2011
	/s/ Richard A. Robert
	Richard A. Robert
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)