Vanguard Natural Resources, Inc. - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.	exhibit31-1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.	exhibit31-2.htm
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.	exhibit32-2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.	exhibit32-1.htm
EX-10.3 - EXHIBIT 10.3 - Vanguard Natural Resources, Inc.	exhibit10-3.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, 2009
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.)

7700 San Felipe, Suite 485 Houston, Texas		77063
(Address of Principal Executive Offices)		(Zip Code)

Telephone Number: (832) 327-2255

Internet Website: www.vnrllc.com

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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).

Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See 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). Yes o No x

Common units outstanding on November 4, 2009: 16,078,673.

VANGUARD NATURAL RESOURCES, LLC

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS

PART I - FINANCIAL INFORMATION
Item 1.	Unaudited Financial Statements
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Members’ Equity	5
	Consolidated Statements of Cash Flows	6
	Consolidated Statements of Comprehensive Loss	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	40

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults Upon Senior Securities	43
Item 4.	Submission of Matters to a Vote of Securities Holders	43
Item 5.	Other Information	43
Item 6.	Exhibits	44

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
Bcfe	=	billion cubic feet of natural gas equivalents	MMBtu	=	million British thermal units
Btu	=	British thermal unit	MMcf	=	million cubic feet
Gal	=	gallons	NGL	=	natural gas liquids

When we refer to natural gas, natural gas liquids and oil in “equivalents,” we are doing so to compare quantities of natural gas liquids 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 and one Bbl of oil 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, Trust Energy Company, LLC (“TEC”), VNR Holdings, Inc. (“VNRH”), Ariana Energy, LLC (“Ariana Energy”), Vanguard Permian, LLC (“Vanguard Permian”) and VNR Finance Corp. (“VNRF”) and (2) “Vanguard Predecessor,” “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

PART I – FINANCIAL INFORMATION

Item 1. 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,
	2009			2008			2009			2008
Revenues:
Natural gas, natural gas liquids and oil sales	$	11,324		$	20,839		$	29,930		$	55,693
Gain (loss) on commodity cash flow hedges		(463	)		45			(1,737	)		616
Gain (loss) on other commodity derivative contracts		(4,210	)		63,364			7,302			(16,453	)
Total revenues		6,651			84,248			35,495			39,856

Costs and expenses:
Lease operating expenses		3,322			3,485			9,233			7,800
Depreciation, depletion, amortization, and accretion		3,272			4,187			9,700			10,341
Impairment of natural gas and oil properties		—			—			63,818			—
Selling, general and administrative expenses		2,137			1,560			8,230			4,843
Production and other taxes		974			1,263			2,537			3,658
Total costs and expenses		9,705			10,495			93,518			26,642

Income (loss) from operations		(3,054	)		73,753			(58,023	)		13,214

Other income and (expense):
Interest income		—			4			—			16
Interest expense		(1,042	)		(1,489	)		(3,034	)		(3,863	)
Gain on acquisition of natural gas and oil properties		5,878			—			5,878			—
Loss on interest rate derivative contracts		(1,081	)		(459	)		(853	)		(510	)
Total other income (expense)		3,755			(1,944	)		1,991			(4,357	)

Net income (loss)	$	701		$	71,809		$	(56,032	)	$	8,857

Net income (loss) per unit:
Common & Class B units – basic	$	0.05		$	5.90		$	(4.24	)	$	0.77

Common & Class B units – diluted	$	0.05		$	5.90		$	(4.24	)	$	0.77

Weighted average units outstanding:
Common units – basic & diluted		14,027,186			11,749,421			12,779,869			11,115,463
Class B units – basic & diluted		420,000			420,000			420,000			420,000

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30, 2009			December 31, 2008
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	2,046		$	3
Trade accounts receivable, net		5,410			6,083
Derivative assets		19,516			22,184
Other receivables		2,912			2,763
Other current assets		766			845
Total current assets		30,650			31,878


Natural gas and oil properties, at cost		341,898			284,447
Accumulated depletion		(175,493	)		(102,178	)
Natural gas and oil properties evaluated, net – full cost method		166,405			182,269

Other assets
Derivative assets		6,850			15,749
Deferred financing costs		3,301			882
Other assets		1,627			1,784
Total assets	$	208,833		$	232,562

Liabilities and members’ equity

Current liabilities
Accounts payable – trade	$	611		$	2,148
Accounts payable – natural gas and oil		1,525			1,327
Payables to affiliates		866			2,555
Deferred swap liability		997			—
Derivative liabilities		29			486
Phantom unit compensation accrual		3,034			—
Accrued ad valorem taxes		1,591			34
Accrued expenses		344			1,214
Total current liabilities		8,997			7,764

Long-term debt		123,500			135,000
Derivative liabilities		2,801			2,313
Deferred swap liability		2,075			—
Asset retirement obligations		4,133			2,134
Total liabilities		141,506			147,211

Commitments and contingencies

Members’ equity
Members’ capital, 16,078,673 common units issued and outstanding at September 30, 2009 and 12,145,873 at December 31, 2008		67,409			88,550
Class B units, 420,000 issued and outstanding at September 30, 2009 and December 31, 2008		6,045			4,606
Accumulated other comprehensive loss		(6,127	)		(7,805	)
Total members’ equity		67,327			85,351
Total liabilities and members’ equity	$	208,833		$	232,562

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, 2009 AND THE YEAR ENDED DECEMBER 31, 2008

(in thousands, except unit data)

(Unaudited)

	Common Units	Common Units Amount			Class B Units	Class B Units Amount			Accumulated Other Comprehensive Loss			Total Members’ Equity
Balance, January 1, 2008	10,795,000	$	90,258		420,000	$	2,132		$	(10,059	)	$	82,331
Distributions to members ($0.291, $0.445, $0.445 and $0.50 per unit to unitholders of record February 7, 2008, April 30, 2008, July 31, 2008 and October 31, 2008, respectively)	—		(19,423	)	—		(706	)		—			(20,129	)
Issuance of common units for acquisition of natural gas and oil properties, net of offering costs of $54	1,350,873		21,306		—		—			—			21,306
Unit-based compensation	—		161		— —		3,180			—			3,341
Net loss	—		(3,752	)	—		—			—			(3,752	)
Settlement of cash flow hedges in other comprehensive income	—		—		—		—			2,254			2,254
Balance at December 31, 2008	12,145,873	$	88,550		420,000	$	4,606		$	(7,805	)	$	85,351
Distributions to members ($0.50 per unit to unitholders of record January 31, 2009, April 30, 2009 and July 31, 2009, respectively)	—		(18,219	)	—		(630	)		—			(18,849	)
Issuance of common units, net of offering costs of $491	3,932,800		53,192		—		—			—			53,192
Unit-based compensation	—		(82	)	—		2,069			—			1,987
Net loss	—		(56,032	)	—		—			—			(56,032	)
Settlement of cash flow hedges in other comprehensive income	—		—		—		—			1,678			1,678
Balance at September 30, 2009	16,078,673	$	67,409		420,000	$	6,045		$	(6,127	)	$	67,327

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,
	2009			2008
Operating activities
Net income (loss)	$	(56,032	)	$	8,857
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion		9,700			10,341
Impairment of natural gas and oil properties		63,818			—
Amortization of deferred financing costs		363			264
Unit-based compensation		2,311			2,708
Unrealized fair value of phantom units granted to officers		3,034			—
Amortization of premiums paid and non-cash settlements on derivative contracts		4,383			3,982
Unrealized losses on other commodity and interest rate derivative contracts		16,105			6,463
Gain on acquisition of natural gas and oil properties		(5,878	)		—
Changes in operating assets and liabilities:
Trade accounts receivable		673			(6,730	)
Other receivables		(149	)		—
Payables to affiliates		(1,689	)		662
Other current assets		11			(435	)
Price risk management activities, net		(13	)		(452	)
Accounts payable		(1,339	)		673
Accrued expenses		687			2,300
Other assets		(27	)		—
Net cash provided by operating activities		35,958			28,633

Investing activities
Additions to property and equipment		(9	)		(70	)
Additions to natural gas and oil properties		(2,981	)		(13,360	)
Acquisitions of natural gas and oil properties		(49,964	)		(99,815	)
Deposits and prepayments of natural gas and oil properties		(699	)		(901	)
Net cash used in investing activities		(53,653	)		(114,146	)

Financing activities
Proceeds from borrowings		16,800			112,900
Repayment of debt		(28,300	)		(15,800	)
Distributions to members		(18,849	)		(13,846	)
Proceeds from equity offering		53,192			—
Financing costs		(2,781	)		(274	)
Purchase of units for issuance as unit-based compensation		(324	)		(236	)
Net cash provided by financing activities		19,738			82,744

Net increase (decrease) in cash and cash equivalents		2,043			(2,769	)

Cash and cash equivalents, beginning of period		3			3,110
Cash and cash equivalents, end of period	$	2,046		$	341

Supplemental cash flow information:
Cash paid for interest	$	2,964		$	3,342
Non-cash financing and investing activities:
Asset retirement obligations	$	1,913		$	2,155
Derivatives assumed in acquisition of natural gas and oil properties	$	4,128		$	2,468
Deferred swap liability	$	3,072		$	—
Non-monetary exchange of natural gas and oil properties	$	2,660		$	—
Issuance of common units for acquisition of natural gas and oil properties	$	—		$	21,360
Transfer of deposit for natural gas and oil properties	$	—		$	7,830

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(in thousands)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009			2008

Net income (loss)	$	701	$	71,809	$	(56,032	)	$	8,857

Net gains (losses) from derivative contracts:
Unrealized mark-to-market gains arising during the period		—		—		—			2,747
Reclassification adjustments for settlements		434		7		1,678			(564	)
Other comprehensive income		434		7		1,678			2,183

Comprehensive income (loss)	$	1,135	$	71,816	$	(54,354	)	$	11,040

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Description of the Business:

Vanguard Natural Resources, LLC is a publicly-traded limited liability company focused on the acquisition and development of mature, long-lived natural gas and oil properties in the United States. Through our operating subsidiaries, we own properties in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee, in the Permian Basin, primarily in west Texas and southeastern New Mexico, and in South Texas.

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"). As part of the separation, we retained all of our Predecessor’s proved producing wells and associated reserves. We also retained 40% of our Predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres and a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing gas and oil wells. In the separation, Vinland was conveyed the remaining 60% of our Predecessor’s working interest in the known producing horizons in this acreage, 100% of our Predecessor’s working interest in depths above and 100 feet below our known producing horizons, all of our gathering and compression assets, and all employees other than our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer. Vinland operates all of our existing wells in Appalachia and all of the wells that we drill in Appalachia. We refer to these events as the "Restructuring."

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, 2008, from the audited financial statements filed in our 2008 Annual Report on Form 10-K. 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 2008 Annual Report on Form 10-K, 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 loss, members’ equity, or net cash flows.

As of September 30, 2009, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2008 Annual Report on Form 10-K, except for those under Recently Adopted Accounting Pronouncements.

(a)	Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of September 30, 2009 and December 31, 2008 and for the three and nine months ended September 30, 2009 and 2008 include our accounts and those of our wholly-owned 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:

Effective July 1, 2009, the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) became the single official source of authoritative, nongovernmental GAAP in the United States. The historical GAAP hierarchy was eliminated, and the ASC became the only level of authoritative GAAP, other than guidance issued by the Securities and Exchange Commission (“SEC”). Our accounting policies were not affected by the conversion to ASC. However, references to specific accounting standards in the footnotes to our consolidated financial statements have been changed to refer to the appropriate section of ASC.

In September 2006, the FASB issued guidance which defines fair value, establishes the framework for measuring fair value and expands disclosures about fair value measurements. This guidance is contained in ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”). In February 2008, the FASB deferred the effective date applicable to us to January 1, 2009 for all nonfinancial assets and liabilities, except for those that are recognized or disclosed at fair value on a recurring basis (that is, at least annually). On January 1, 2008, we adopted the provisions of ASC Topic 820, as it relates to financial assets and financial liabilities and we determined that the impact of the additional assumptions on fair value measurements did not have a material effect on our financial position or results of operations. We adopted the deferred provisions of ASC Topic 820 on January 1, 2009, as it relates to nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our financial position or results of operations. See Note 5. Fair Value Measurements for further discussion.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In April 2009, the FASB issued additional guidance for estimating fair value in accordance with ASC Topic 820. The additional guidance addresses determining fair value when the volume and level of activity for an asset or liability have significantly decreased and identifying transactions that are not orderly. We adopted the provisions of this guidance on June 30, 2009 and the adoption did not have a material impact on our consolidated financial statements.

In December 2007, the FASB issued guidance which established principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. This guidance is contained in ASC Topic 805, “Business Combinations” (“ASC Topic 805”). This guidance also established disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. Effective January 1, 2009, we adopted the provisions of ASC Topic 805 and applied the provisions to our acquisitions completed in the third quarter 2009. See Note 2. Acquisitions for further discussion.

In April 2009, the FASB issued additional guidance which amended the provisions related to the initial recognition and measurement, subsequent measurement and disclosure of assets and liabilities arising from contingencies in a business combination under ASC Topic 805. The requirements of ASC Topic 805 were carried forward for acquired contingencies, which would require that such contingencies be recognized at fair value on the acquisition date if fair value can be reasonably estimated during the allocation period. Otherwise, companies would typically account for the acquired contingencies in accordance with ASC Topic 450, “Contingencies.” The adoption of the provisions in this additional guidance did not affect our consolidated financial statements.

In March 2008, the FASB issued guidance intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. This guidance is contained in ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”). The guidance achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk-related. Finally, it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. Effective January 1, 2009, we adopted the provisions of ASC Topic 815, and the adoption did not have a material impact on our consolidated financial statements. See Note 4. Price Risk Management Activities for further discussion.

In April 2009, the FASB issued guidance which amends disclosures about fair values of financial instruments and interim financial reporting to require disclosures about fair value of financial instruments in interim financial statements. This guidance is contained in ASC Topic 825, “Financial Instruments” (“ASC Topic 825”). We adopted the provisions of ASC Topic 825 on June 30, 2009 and the adoption did not have a material impact on our consolidated financial statements.

In May 2009, the FASB issued general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This guidance is contained in ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). In particular, this guidance sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. In accordance with this guidance, an entity should apply the requirements to interim or annual financial periods ending after June 15, 2009. We adopted the provisions of ASC Topic 855 effective June 30, 2009 and the adoption did not have a material impact on our financial statements. The date through which subsequent events have been evaluated is November 4, 2009, the date on which the financial statements were issued. See Note 11. Subsequent Event for further discussion.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(c)	New Pronouncements Issued But Not Yet Adopted:

In December 2008, the SEC published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect future impairment and depletion calculations. The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We have not yet determined the impact of this Final Rule, which will vary depending on changes in commodity prices, on our disclosures, financial position, or results of operations.

In June 2009, the FASB issued guidance to change financial reporting by enterprises involved with variable interest entities (“VIEs”). The standard replaces the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a VIE with an approach focused on identifying which enterprise has the power to direct the activities of a VIE and the obligation to absorb losses of the entity or the right to receive the entity’s residual returns. This standard will be effective for us on January 1, 2010. We do not have any interests in variable interest entities; therefore, we do not anticipate that this standard will have any impact on our consolidated financial statements.

In August 2009, the FASB issued Accounting Standards Update No. 2009-05 (“ASC Update 2009-05”), an update to ASC Topic 820. This update provides amendments to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. Among other provisions, this update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the valuation techniques described in ASC Update 2009-05. ASC Update 2009-05 will become effective for our annual financial statements for the year ended December 31, 2009. We have not determined the impact that this update may have on our financial statements.

(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 natural gas, natural gas liquids and oil reserves and related cash flow estimates used in impairment tests and fair value calculations of natural gas and oil properties, the fair value of derivative contracts and asset retirement obligations, accrued natural gas, natural gas liquids and oil revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization, and accretion. Actual results could differ from those estimates.

2.	Acquisitions

On December 21, 2007, we entered into a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of west Texas and southeastern New Mexico. We refer to this acquisition as the Permian Basin acquisition. The purchase price for said assets was $78.3 million with an effective date of October 1, 2007. We completed this acquisition on January 31, 2008 for an adjusted purchase price of $73.4 million, subject to customary post closing adjustments. The post closing adjustments reduced the final purchase price to $71.5 million and included a purchase price adjustment of $6.8 million for the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the final settlement date. As part of this acquisition, we assumed fixed-price oil swaps covering approximately 90% of the estimated proved developed producing oil reserves through 2011 at a weighted average price of $87.29. The fair value of these fixed-price oil swaps was a liability of $1.1 million at January 31, 2008. This acquisition was funded with borrowings under our existing reserve-based credit facility.

On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd. (“Segundo”), a wholly- owned subsidiary of the Lewis Energy Group, for the acquisition of certain natural gas and oil properties located in the Dos Hermanos Field in Webb County, Texas. We refer to this acquisition as the South Texas acquisition. The purchase price for said assets was $53.4 million with an effective date of June 1, 2008. We completed this acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with $30.0 million of borrowings under our reserve-based credit facility and through the issuance of 1,350,873 common units of the Company valued at $21.4 million. Upon closing this transaction, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from existing producing wells in the acquired properties for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following unaudited pro-forma results for the three and nine months ended September 30, 2008 show the effect on our consolidated results of operations as if the Permian Basin acquisition and the South Texas acquisition had occurred on January 1, 2008. The pro-forma results for the 2008 periods presented are the results of combining our statement of operations with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (1) assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, (3) interest expense on additional borrowings necessary to finance the acquisition, and (4) the impact of common units issued to partially finance the July 2008 acquisition. 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) (unaudited)
	Three Months Ended September 30, 2008		Nine Months Ended September 30, 2008
Total revenues	$	85,166	$	48,181
Net income	$	72,138	$	11,840
Net income per unit:
Common & Class B units – basic	$	5.74	$	0.94
Common & Class B units – diluted	$	5.74	$	0.94

On July 17, 2009, we entered into a Purchase and Sale Agreement with Segundo for the acquisition of certain natural gas and oil properties located in the Sun TSH Field in La Salle County, Texas. We refer to this acquisition as the Sun TSH acquisition. The purchase price for said assets was $52.3 million with an effective date of July 1, 2009. We completed this acquisition on August 17, 2009 for an adjusted purchase price of $50.5 million, subject to customary post-closing adjustments to be determined. The adjusted purchase price was $50.5 million after consideration of preliminary purchase price adjustments of approximately $1.8 million, which included the settlement of a derivative contract for the latter part of August 2009 in the amount of $0.3 million. This acquisition was funded with borrowings under our reserve-based credit facility and proceeds from the Company’s public equity offering of 3.5 million common units completed on August 17, 2009. Upon closing this transaction, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August 2009 through December 2010, which had a fair value of $4.1 million on the closing date. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $5.9 million, calculated in the following table. The gain resulted from the changes in natural gas and oil prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the consolidated statement of operations.

	(in thousands)
Fair value of assets and liabilities acquired:
Natural gas and oil properties	$	54,942
Derivative assets		4,128
Other currents assets		187
Accrued expenses		(298	)
Asset retirement obligations		(2,254	)
Total fair value of assets and liabilities acquired		56,705

Fair value of consideration transferred		50,827

Gain on acquisition of natural gas and oil properties	$	5,878

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following unaudited pro-forma results for the three and nine months ended September 30, 2009 and September 30, 2008 show the effect on our consolidated results of operations as if this acquisition had occurred on January 1, 2009 and on January 1, 2008, respectively. The pro-forma results for the 2009 and 2008 periods presented are the results of combining our statement of operations with the revenues and direct operating expenses of the oil and gas properties acquired adjusted for (1) assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the purchase method of accounting, and (3) interest expense on additional borrowings necessary to finance the acquisition. 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) (unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009			2008
Total revenues	$	8,156	$	91,959	$	41,880		$	62,852
Net income (loss)	$	1,858	$	77,997	$	(53,002	)	$	26,814
Net income (loss) per unit:
Common & Class B units – basic	$	0.11	$	4.73	$	(3.21	)	$	1.63
Common & Class B units – diluted	$	0.11	$	4.73	$	(3.21	)	$	1.63

3.	Credit Facility and Long-Term Debt

Our credit facility and long-term debt consisted of the following:

Amount Outstanding

(in thousands)

Description

Interest Rate

Maturity Date

September 30,

2009

December 31,

2008

Senior secured reserve-based credit facility

Variable (1)

October 1, 2012

123,500

135,000

(1) Variable interest rate was 2.7% and 3.8% at September 30, 2009 and December 31, 2008, respectively.

Senior Secured Reserve-Based Credit Facility

In January 2007, we entered into a four-year revolving credit facility (“reserve-based credit facility”) with Citibank, N.A. and BNP Paribas. All of our Predecessor’s outstanding debt was repaid with borrowings under this reserve-based credit facility. The available credit line (“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 (as determined by independent petroleum engineers) of estimated future net cash flows from certain of our proved natural gas, natural gas liquids and oil reserves. The reserve-based credit facility is secured by a first lien security interest in all of our natural gas and oil properties. Additional borrowings were made in January 2008 pursuant to the acquisition of natural gas and oil properties in the Permian Basin. In February 2008, our reserve-based credit facility was amended and restated to extend the maturity from January 3, 2011 to March 31, 2011, increase the facility amount from $200.0 million to $400.0 million, increase our borrowing base from $110.5 million to $150.0 million and add two additional financial institutions as lenders, Wachovia Bank, N.A. and The Bank of Nova Scotia. In May 2008, our reserved-based credit facility was amended in response to a potential acquisition that, ultimately, did not occur. As a result, none of the provisions included in this amendment went into effect. In October 2008, we amended our reserve-based credit facility, which set our borrowing base under the facility at $175.0 million pursuant to our semi-annual redetermination and added a new lender, BBVA Compass Bank. In February 2009, our reserve-based credit facility was amended to allow us to repurchase up to $5.0 million of our own units. In May 2009, our borrowing base was set at $154.0 million pursuant to our semi-annual redetermination. In June 2009, a fourth amendment to our reserve-based credit facility was entered into which temporarily increased the percentage of outstanding indebtedness for which interest rate derivatives could be used. The percentage was increased from 75% to 85% but was to revert back to 75% in one year at June 2010. In August 2009, our reserve-based credit facility was amended and restated to (1) extend the maturity from March 31, 2011 to October 1, 2012, (2) increase our borrowing base from $154.0 million to $175.0 million, (3) increase our borrowing costs, (4) permanently allow 85% of our outstanding indebtedness to be covered under interest rate derivatives, and (5) add two financial institutions as lenders, Comerica Bank and Royal Bank of Canada. Our indebtedness under the reserve-based credit facility totaled $123.5 million at September 30, 2009. In October 2009, our reserve-based credit facility was amended, See Note 10. Subsequent Event for further discussion.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Interest rates under the reserve-based credit facility are based on Eurodollar (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At September 30, 2009 the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans	2.25%	2.50%	2.75%	3.00%
ABR Loans	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. At September 30, 2009, we were in compliance with our debt covenants.

4.	Price Risk Management Activities

We have entered into derivative contracts with counterparties that are also lenders under our reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova Scotia, and Wells Fargo Bank, N.A. (also under the name of Wachovia Bank, N.A.), to hedge price risk associated with a portion of our natural gas and oil 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, such as the Columbia Gas Appalachian Index (“TECO Index”), Henry Hub, or Houston Ship Channel for natural gas production and the West Texas Intermediate Light Sweet for oil production. 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. 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. The collars and put options for natural gas are settled based on the NYMEX price for natural gas at Henry Hub or Houston Ship Channel.

Under ASC Topic 815 “Derivatives and Hedging,” all derivative instruments are recorded on the 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 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 consolidated statements of operations.

In February 2008, as part of the Permian Basin acquisition, we assumed fixed-price oil swaps covering approximately 90% of the estimated proved developed producing oil production through 2011 at a weighted average price of $87.29. Also, in February 2008, we sold calls (or set a ceiling price) which effectively collared 2,000,000 MMBtu of gas production in 2008 through 2009 which was previously only subject to a put (or price floor), we reset the price on 2,387,640 MMBtu of natural gas swaps settling in 2010 from $7.53 to $8.76 per MMBtu, and we entered into a 2012 fixed-price oil swap at $80.00 for 87% of our estimated proved developed production. In April 2008, we reset the price on 800,000 MMBtu of natural gas puts settling from May 1, 2008 to December 31, 2008 from $7.50 to $9.00 per MMBtu at a cost to us of $0.3 million which was funded with cash on hand. In July 2008, in connection with the South Texas acquisition, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from our existing producing wells for the period beginning July 2008 through December 2011.

In February 2009, we liquidated our 2012 oil swap and entered into new 2010 and 2011 natural gas swap and collar transactions. Specifically, a fixed price NYMEX natural gas swap for January through September 2010 and April through September 2011 at $8.04 and $7.85, respectively, was executed for 2,000 MMBtu/day. In addition, a 2,000 MMBtu/day NYMEX natural gas collar with a floor price of $7.50 and a ceiling price of $9.00 for October 2010 through March 2011 and October 2011 through December 2011 was executed. These natural gas derivatives were obtained at prices above the then current market by using the proceeds of the liquidation of the 2012 oil swap.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In August 2009, in connection with the Sun TSH acquisition, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August of 2009 through December 2010. In addition, concurrent with the execution of the purchase and sale agreement, the Company entered into a collar for certain volumes in 2010 and a series of collars for a substantial portion of the expected gas production for 2011 at prices above the then current market with a total cost to the Company of $3.1 million, which was financed through deferred premiums.

As of September 30, 2009, we have open commodity derivative contracts covering our anticipated future production as follows:

Swap Agreements

	Gas			Oil
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	WTI Price
October 1, 2009 - December 31, 2009	864,806	$	9.34	44,000	$	87.23
January 1, 2010 - December 31, 2010	4,731,040	$	8.66	164,250	$	85.65
January 1, 2011 - December 31, 2011	3,328,312	$	7.83	151,250	$	85.50

Put Option Contracts

Contract Period	Volume in MMBtu		Purchased NYMEX Price Floor
October 1, 2009 - December 31, 2009	651,446		$	7.85

Collars

	Gas						Oil
	MMBtu		Floor		Ceiling		Bbls		Floor		Ceiling
Production Period:
October 1, 2009 - December 31, 2009		249,999	$	7.50	$	9.00		9,200	$	100.00	$	127.00
January 1, 2010 - December 31, 2010		1,607,500	$	7.73	$	8.92		—	$	—	$	—
January 1, 2011 - December 31, 2011		1,933,500	$	7.34	$	8.44		—	$	—	$	—

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.

From December 2007 through March 2008, we entered into interest rate swap agreements which effectively fixed the LIBOR rate at 2.66 % to 3.88% on $60.0 million of borrowings. In August 2008, we entered into two interest rate basis swaps which changed the reset option from three month LIBOR to one month LIBOR on the total $60.0 million of outstanding interest rate swaps. By doing so, we reduced our borrowing cost based on three month LIBOR by 14 basis points on $20.0 million of borrowings for a one year period starting September 10, 2008 and 12 basis points on $40.0 million of borrowings for a one year period starting October 31, 2008. As a result of these two basis swaps, we chose to de-designate the interest rate swaps as cash flow hedges as the terms of the new contracts no longer matched the terms of the original contracts, thus causing the interest rate hedges to be ineffective. Beginning in the third quarter of 2008, we recorded changes in the fair value of our interest rate derivatives in current earnings under gains (losses) on interest rate derivative contracts. The net unrealized gain at June 30, 2008 related to the de-designated cash flow hedges is reported in accumulated other comprehensive income and later reclassified to earnings in the month in which the transactions settle. In December 2008, we amended three existing interest rate swap agreements and entered into one new agreement which fixed the LIBOR rate at 1.85% on $10.0 million of borrowings through December 2010. The first amended agreement reduced the fixed LIBOR rate from 3.88% to 3.35% on $20.0 million and the maturity was extended two additional years to December 10, 2012. In addition, the second amended agreement reset the notional amount on the March 31, 2011 swap from $10.0 million to $20.0 million and also reduced the rate from 2.66% to 2.08%. The third amended agreement reset the notional amount on the January 31, 2011 swap from $10.0 million to $20.0 million, reduced the rate from 3.00% to 2.38% and also extended the maturity two additional years to 2013.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As of September 30, 2009, we have open interest rate derivative contracts as follows:

	Notional Amount (in thousands)		Fixed Libor Rates
Period:
October 1, 2009 to December 18, 2010	$	10,000	1.50	%
October 1, 2009 to December 20, 2010	$	10,000	1.85	%
October 1, 2009 to January 31, 2011	$	20,000	3.00	%
October 1, 2009 to March 31, 2011	$	20,000	2.08	%
October 1, 2009 to December 10, 2012	$	20,000	3.35	%
October 1, 2009 to January 31, 2013	$	20,000	2.38	%
October 1, 2009 to October 31, 2009 (Basis Swap)	$	40,000	LIBOR 1M vs. LIBOR 3M

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.

	September 30, 2009			December 31, 2008
	(in thousands)
Assets:
Commodity derivatives	$	30,734			$	39,875
Interest rate swaps		—				—
	$	30,734			$	39,875
Liabilities:
Commodity derivatives	$	(4,739	)		$	(1,942	)
Interest rate swaps		(2,459	)			(2,799	)
	$	(7,198	)		$	(4,741	)

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. Credit Facilities and Long-Term Debt for further discussion) which is secured by our natural gas and oil 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 $30.7 million at September 30, 2009.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, 2009.

Gain (Loss) on Derivatives

Gains and losses on derivatives are reported on the consolidated statement of operations in “gain (loss) on other commodity derivative contracts” and “loss on interest rate derivative contracts” and include realized and unrealized gains (losses). 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 that will settle in the future and are non-cash items.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Realized gains (losses):
Other commodity derivatives	$	8,010		$	(2,989	)	$	23,794		$	(10,410	)
Interest rate swaps		(506	)		(39	)		(1,240	)		(90	)
	$	7,504		$	(3,028	)	$	22,554		$	(10,500	)
Unrealized gains (losses):
Other commodity derivatives	$	(12,220	)	$	66,353		$	(16,492	)	$	(6,043	)
Interest rate swaps		(575	)		(420	)		387			(420	)
	$	(12,795	)	$	65,933		$	(16,105	)	$	(6,463	)
Total gains (losses):
Other commodity derivatives	$	(4,210	)	$	63,364		$	7,302		$	(16,453	)
Interest rate swaps		(1,081	)		(459	)		(853	)		(510	)
	$	(5,291	)	$	62,905		$	6,449		$	(16,963	)

5.	Fair Value Measurements

As discussed in Note 1. Summary of Significant Accounting Policies (b), we adopted 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 sheet, 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, deferred swap liability, 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.

Long-term debt. The carrying amount of our reserve-based credit facility approximates fair value because our current borrowing rate does 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.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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

	September 30, 2009 (in thousands)
	Fair Value Measurements Using							Assets/Liabilities
	Level 1		Level 2			Level 3		at Fair value
Assets:
Commodity price derivative contracts	$	—	$	26,366		$	—	$	26,366
Total derivative instruments	$	—	$	26,366		$	—	$	26,366

Liabilities:
Commodity price derivative contracts	$	—	$	(371	)	$	—	$	(371	)
Interest rate derivative contracts		—		(2,459	)		—		(2,459	)
Total derivative instruments	$	—	$	(2,830	)	$	—	$	(2,830	)

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, in accordance with ASC Topic 410-20. During the nine months ended September 30, 2009, in connection with natural gas and oil properties acquired in the Sun TSH acquisition, we incurred and recorded asset retirement obligations totaling $2.3 million at fair value. 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 abandon 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 (2.4%); and (4) the ten year average inflation factor (2.4%). 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 or results of operations.

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:

	2009			2008
	(in thousands)
Asset retirement obligations at January 1,	$	2,134		$	190
Liabilities added during the current period		2,254			2,155
Accretion expense		86			59
Revisions of estimates		(341	)		—
Asset retirement obligation at September 30,	$	4,133		$	2,404

7.	Related Party Transactions

In Appalachia, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas. Pursuant to amended agreements effective March 1, 2009, we reimburse Vinland $95 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our lease operating expenses. Also, pursuant to amended agreements effective March 1, 2009, Vinland receives a fee based upon the actual costs incurred by Vinland to provide gathering and transportation services plus a $0.05 per Mcf margin. This transportation fee 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 under a Gathering and Compression Agreement (“GCA”) with Vinland and are reflected in our lease operating expenses. Costs incurred under the MSA were $0.5 million and $0.1 million for the three months ended September 30, 2009 and 2008 and $1.2 million and $0.4 million for the nine months ended September 30, 2009 and 2008, respectively. Costs incurred under the GCA were $0.4 million and $0.2 million for the three months ended September 30, 2009 and 2008 and $0.9 million and $0.8 million for the nine months ended September 30, 2009 and 2008, respectively. A payable of $0.9 million and $2.6 million, respectively, is reflected on our September 30, 2009 and December 31, 2008 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.

On April 1, 2009, we and our wholly-owned subsidiary, TEC, exchanged several wells and lease interests (the “Asset Exchange”) with Vinland, Appalachian Royalty Trust, LLC, and Nami Resources Company, L.L.C. (collectively, the “Nami Companies”). Each of the Nami Companies is beneficially owned by Majeed S. Nami, who, as of September 30, 2009, beneficially owned 19.5% of our common units representing limited liability company interests. In the Asset Exchange, we assigned well, strata and leasehold interests with internal estimated future cash flows of approximately $2.7 million discounted at ten percent, and received well, strata, and leasehold interests with an approximately equal value; therefore no gain or loss was recognized.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

8.	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 (loss) attributable to 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, 2009, we have two classes of units outstanding: (i) units representing limited liability company interests (“common units”) listed on NYSE under the symbol VNR and (ii) Class B units, issued to management and an employee as discussed in Note 9. Unit-Based Compensation. The Class B units participate in distributions and no forfeiture is expected; therefore, all Class B units were considered in the computation of basic earnings per unit. The 175,000 options granted to officers under our long-term incentive plan had no dilutive effect as the exercise price was higher than the market price at September 30, 2009; therefore, they have been excluded from the computation of diluted earnings per unit. In addition, the phantom units granted to officers under our long-term incentive plan will have no dilutive effect unless there is a liability at December 31, 2009 and if the officers elect to have the liability satisfied in units; therefore, they have been excluded from 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, 2009 and 2008 including each class of units issued and outstanding at that date: common units and Class B units. Net income (loss) per unit is allocated to the common units and the Class B units on an equal basis.

9.	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 Class B units in VNR in April 2007, which vested 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 will vest after three years. The remaining 40,000 restricted Class B units are available to be awarded to new employees or members of our board of directors as they are retained.

In October 2007, one board member was granted 5,000 common units and in February 2008, three board members were granted 5,000 common units each of which vested after one year. Additionally, 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.

On January 1, 2009, in accordance with their previously negotiated employment agreements, phantom units were granted to two officers in amounts equal to 1% of our units outstanding at January 1, 2009. The amount will be paid in either cash or at the officer’s election, units and will equal the appreciation in value of the units, if any, from the date of the grant until the determination date (December 31, 2009), plus cash distributions paid on the units, less an 8% hurdle rate. As of September 30, 2009, an accrued liability and non-cash compensation expense totaling $3.0 million has been recognized for the unrealized fair value of these phantom units.

On January 7, 2009, four board members were granted 5,000 common units each of which will vest after one year and on February 27, 2009, employees were granted 17,950 units that will vest after one year.

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, 2009 is presented below:

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

	Number of Non-vested Units			Weighted Average Grant Date Fair Value

Non-vested units at December 31, 2008		440,000		$	18.10
Granted		37,950		$	8.07
Vested		(385,000	)	$	(17.97	)
Non-vested units at September 30, 2009		92,950		$	14.54

At September 30, 2009, there was approximately $0.3 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 0.5 years. Our consolidated statement of operations reflects non-cash unit-based compensation of $1.3 million and $5.3 million in the selling, general and administrative line item, of which $0.8 million and $3.0 million relates to the unrealized fair value of phantom units granted to officers for the three and nine months ended September 30, 2009, respectively. Non-cash unit-based compensation was $0.8 million and $2.7 million for the three and nine months ended September 30, 2008, respectively. There was no expense related to the fair value of phantom units granted to officers in the three or nine month period ended September 30, 2008.

10.	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 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 shares of its common units. The units were offered to the public at a price of $14.25 per 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. As a result of the offering, we have approximately $244.0 million remaining available under our 2009 shelf registration statement as of September 30, 2009.

11.	Subsequent Event

On October 1, 2009, we entered into the First Amendment to our Second Amended and Restated Credit Agreement, which reduced our borrowing base under the reserve-based credit facility from $175.0 million to $170.0 million pursuant to our semi-annual redetermination and changed the definition of majority lenders from 75% to 66.67%. All other terms under the reserve-based credit facility remained the same.

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 2008 Annual Report on Form 10-K.

Forward-Looking Statements

This report contains “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. 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 2008 Annual Report on Form 10-K 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 (“EDGAR”) at http://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 natural gas and oil properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions through the acquisition of new natural gas and oil properties. Our properties are located in the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee, the Permian Basin, primarily in west Texas and southeastern New Mexico, and in South Texas.

We owned working interests in 1,587 gross (1,132 net) productive wells at September 30, 2009, and our average net production for the twelve months ended December 31, 2008 and for the nine months ended September 30, 2009 was 16,206 Mcfe per day and 18,623 Mcfe per day, respectively. In addition to these productive wells, we own leasehold acreage allowing us to drill new wells. We have an approximate 40% working interest in the known producing horizons in approximately 96,800 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. Furthermore, in South Texas, we own working interest ranging from 45-50% in approximately 13,303 undeveloped acres surrounding our existing wells. Based on internal reserve estimates at September 30, 2009, approximately 28%, or 35.9 Bcfe, of our estimated proved reserves were attributable to our working interests in undeveloped acreage.

Disruption to Functioning of Capital Markets

During the first nine months of 2009, our unit price increased from a closing low of $6.35 on January 2, 2009 to a closing high of $16.44 on September 30, 2009. Also, during the nine months ended September 30, 2009, we did not drill any wells on our operated properties and there was limited drilling on non-operated properties. We intend to move forward with our development drilling program when market conditions allow for an adequate return on the drilling investment and only when we have sufficient liquidity to do so. Maintaining adequate liquidity may involve the issuance of debt and equity at less attractive terms, could involve the sale of non-core assets, and could require reductions in our capital spending. In the near-term we will focus on maximizing returns on existing assets by managing our costs and selectively deploying capital to improve existing conditions.

Permian Basin Acquisition

On December 21, 2007, we entered in to a Purchase and Sale Agreement with the Apache Corporation for the purchase of certain oil and natural gas properties located in ten separate fields in the Permian Basin of west Texas and southeastern New Mexico. The purchase price for said assets was $78.3 million with an effective date of October 1, 2007. We completed this acquisition on January 31, 2008 for an adjusted purchase price of $73.4 million, subject to customary post closing adjustments. The post closing adjustments reduced the final purchase price to $71.5 million and included a purchase price adjustment of $6.8 million for the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the final settlement date. This acquisition was funded with borrowings under our reserve-based credit facility. Through this acquisition, we acquired working interests in 390 gross wells (67 net wells), 49 of which we operate. We manage the operations of these assets from two district offices, one in Lovington, New Mexico and the other in Christoval, Texas. Our operating focus has been on maximizing existing production and looking for complementary acquisitions that we can add to this operating platform. At September 30, 2009, based on internal reserve estimates, we own 3.5 million barrels of oil equivalent, 87% of which is oil and 88% of which is proved developed producing.

South Texas Acquisition

On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd. (“Segundo”), a wholly- owned subsidiary of the Lewis Energy Group, L. P. (“Lewis”) for the acquisition of certain natural gas and oil properties located in the Dos Hermanos Field in Webb County, Texas. The purchase price for said assets was $53.4 million with an effective date of June 1, 2008. We completed this acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with $30.0 million of borrowings under our reserve-based credit facility and through the issuance of 1,350,873 common units of the Company. In this purchase, we acquired an average of a 98% working interest in 91 producing wells and an average 47.5% working interest in approximately 4,705 gross acres with 41 identified proved undeveloped locations. An affiliate of Lewis operates all the properties and is contractually obligated to drill seven wells each year from 2009 through 2013 unless we mutually agree not to do so. Upon closing this transaction, we assumed natural gas swaps and collars based on Houston Ship Channel pricing for approximately 85% of the estimated gas production from existing producing wells in the acquired properties for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008. At September 30, 2009, based on internal reserve estimates, we own 20.0 Bcfe of proved reserves, 100% of which is natural gas and natural gas liquids and 56% of which is proved developed producing.

Sun TSH Acquisition

On July 17, 2009, we entered into a Purchase and Sale Agreement to acquire certain natural gas and oil properties located in the Sun TSH Field in La Salle County, Texas for $52.3 million with Segundo. Lewis will operate all of the wells acquired in this transaction. Based on the current net daily production of approximately 6,100 Mcfe, the properties have a reserve to production ratio of approximately 16 years. The acquisition had a July 1, 2009 effective date, was completed on August 17, 2009 for an adjusted purchase price of $50.5 million, and is subject to customary post-closing adjustments to be determined. The properties acquired have total estimated proved reserves of 34.9 Bcfe as of September 30, 2009, of which 96% is natural gas and natural gas liquids and 67% is proved developed producing. This acquisition was funded with borrowings under our reserve-based credit facility and proceeds from the Company’s public equity offering of 3.5 million common units completed on August 17, 2009.

At closing, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August of 2009 through December of 2010, which had a fair value of $4.1 million on the closing date. In addition, concurrent with the execution of the Purchase and Sale Agreement, we entered into a collar for certain volumes in 2010 and a series of collars for a substantial portion of the expected gas production for 2011 at prices above the then current market with a total cost to the Company of $3.1 million which was financed through deferred premiums. Inclusive of the hedges added, approximately 90% of the estimated gas production from existing producing wells in the acquired properties is hedged through 2011. A schedule of the hedges assumed and added is shown below:

Contract Period	Volume (MMBtu)		Price
Put and Swap Agreements Assumed:
August – December 2009		765,000	$	8.00
January – December 2010		949,000	$	7.50
Collars Added:
January – December 2010		693,500	$	7.50 - $8.50
January – December 2011		1,569,500	$	7.31 - $8.31	(1)

(1)

Price is calculated based on weighted average pricing.

Reserve-Based Credit Facility

On January 3, 2007, we entered into a reserve-based credit facility which is available for our general limited liability company purposes, including, without limitation, capital expenditures and acquisitions. Our obligations under the reserve-based credit facility are secured by substantially all of our assets. Our initial borrowing base under the reserve-based credit facility was set at $115.5 million. However, the borrowing base was subject to $1.0 million reductions per month starting on July 1, 2007 through November 1, 2007, which resulted in a borrowing base of $110.5 million as reaffirmed in November 2007 pursuant to a semi-annual borrowing base redetermination. We applied $80.0 million of the net proceeds from our IPO in October 2007 to reduce our indebtedness under the reserve-based credit facility. In February 2008, our reserve-based credit facility was amended and restated to extend the maturity from January 3, 2011 to March 31, 2011, increase the facility amount from $200.0 million to $400.0 million, increase our borrowing base from $110.5 million to $150.0 million and add two additional financial institutions as lenders, Wachovia bank, N.A., and The Bank of Nova Scotia. Additional borrowings were made in January 2008 pursuant to the acquisition of natural gas and oil properties in the Permian Basin, and in July 2008 an additional $30.0 million was borrowed to fund a portion of the cash consideration paid in the South Texas acquisition. In May 2008, our reserve-based credit facility was amended in response to a potential acquisition that ultimately did not occur. As a result, none of the provisions included in this amendment went into effect. In October 2008, we amended our reserve-based credit facility which set our borrowing base under the facility at $175.0 million pursuant to our semi-annual redetermination and added a new lender, BBVA Compass Bank. In February 2009, a third amendment was entered into which amended covenants to allow us to repurchase up to $5.0 million of our own units. In May 2009, our borrowing base was set at $154.0 million pursuant to our semi-annual redetermination. In June 2009, a fourth amendment to our reserve-based credit facility was entered into which temporarily increased the percentage of outstanding indebtedness for which interest rate derivatives could be used. The percentage was increased from 75% to 85% but was to revert back to 75% in one year at June 2010. In August 2009, our reserve-based credit facility was amended and restated to (1) extend the maturity from March 31, 2011 to October 1, 2012, (2) increase our borrowing base from $154.0 million to $175.0 million, (3) increase our borrowing costs, (4) permanently allow 85% of our outstanding indebtedness to be covered under interest rate derivatives, and (5) add two financial institutions as lenders, Comerica Bank and Royal Bank of Canada. Indebtedness under the reserve-based credit facility totaled $123.5 million at September 30, 2009, and the applicable margins and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans	2.25%	2.50%	2.75%	3.00%
ABR Loans	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%

In October 2009, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which reduced our borrowing base under the reserve-based credit facility from $175.0 million to $170.0 million pursuant to our semi-annual redetermination and changed the definition of majority lenders from 75% to 66.67%. All other terms under the reserve-based credit facility remained the same.

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. Multiple events during 2008 and 2009 involving numerous financial institutions effectively restricted liquidity within the capital markets throughout the United States and around the world. While capital markets remain volatile, efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector appears to have improved the situation. As evidenced by our recent successful equity offering, successful amendment of our reserve-based credit facility and recent successful equity and debt offerings by our peers, we believe that our access to capital has improved and we have been successful in improving our financial position to date.

Natural gas, natural gas liquids and oil prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas, natural gas liquids and oil reserves that we can economically produce and our access to capital. We have mitigated the volatility on our cash flows through 2011 by implementing a hedging program on a portion of our proved producing and a portion of our total anticipated production during this time frame. As natural gas, natural gas liquids and oil prices fluctuate, we will recognize non-cash, unrealized gains and losses in our consolidated statement of operations related to the change in fair value of our commodity derivative contracts.

We face the challenge of natural gas, natural gas liquids and oil production declines. As a given well’s initial reservoir pressures are depleted, natural gas, natural gas liquids and oil 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, 2009, we did not drill any wells on our operated properties and there was limited drilling on non-operated properties. 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 production 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 equity securities on favorable terms, or at all, and we may be unable to refinance our reserve-based credit facility when it expires. Additionally, due to the significant decline in commodity prices, our borrowing base under our reserve-based credit facility may be redetermined such that it will not provide for the working capital necessary to fund our capital spending program and could affect our ability to make distributions. The next scheduled redetermination of our borrowing base is April 2010.

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,
	2009(c)			2008(b)			2009(c)			2008(a)(b)
Revenues:
Natural gas sales	$	4,742		$	12,708		$	15,500		$	34,812
Natural gas liquids sales		1,136			601			1,811			824
Oil sales		5,446			7,530			12,619			20,057
Natural gas, natural gas liquids and oil sales		11,324			20,839			29,930			55,693
Realized gain (loss) on commodity cash flow hedges		(463	)		45			(1,737	)		616
Realized gain (loss) on other commodity derivative contracts		8,010			(2,989	)		23,794			(10,410	)
Unrealized gain (loss) on other commodity derivative contracts		(12,220	)		66,353			(16,492	)		(6,043	)
Total revenues	$	6,651		$	84,248		$	35,495		$	39,856
Costs and expenses:
Lease operating expenses	$	3,322		$	3,485		$	9,233		$	7,800
Depreciation, depletion, amortization, and accretion		3,272			4,187			9,700			10,341
Impairment of natural gas and oil properties		—			—			63,818			—
Selling, general and administrative expenses		2,137			1,560			8,230			4,843
Production and other taxes		974			1,263			2,537			3,658
Total costs and expenses	$	9,705		$	10,495		$	93,518		$	26,642
Other income and (expense):
Interest expense, net	$	(1,042	)	$	(1,485	)	$	(3,034	)	$	(3,847	)
Gain on acquisition of natural gas and oil properties		5,878			—			5,878			—
Realized loss on interest rate derivative contracts	$	(506	)	$	(39	)	$	(1,240	)	$	(90	)
Unrealized gain (loss) on interest rate derivative contracts	$	(575	)	$	(420	)	$	387		$	(420	)

	(a)	The Permian Basin acquisition closed on January 31, 2008 and, as such, only eight months of operations are included in the nine month period ended September 30, 2008.
	(b)	The South Texas acquisition closed on July 28, 2008 and, as such, only two months of operations are included in the three month and nine month period ended September 30, 2008.
	(c)	The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately one and a half months of operations are included in the three month and nine month period ended September 30, 2009.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues

Natural gas, natural gas liquids and oil sales decreased $9.5 million to $11.3 million during the three months ended September 30, 2009 as compared to the same period in 2008. The key revenue measurements were as follows:

	Three Months Ended September 30,					Percentage Increase (Decrease)
	2009			2008		Percentage Increase (Decrease)
Net Natural Gas Production:
Appalachian gas (MMcf)		773		923		(16)	%
Permian gas (MMcf)		57		—		N/A
South Texas gas (MMcf)		196		160	(a)	23	%
Sun TSH gas (MMcf)		139	(b)	—		N/A
Total natural gas production (MMcf)		1,165		1,083		8	%

Average Appalachian daily gas production (Mcf/day)		8,403		10,031		(16)	%
Average Permian daily gas production (Mcf/day)		617		—		N/A
Average South Texas daily gas production (Mcf/day)		2,136		2,463	(a)	(13)	%
Average Sun TSH daily gas production (Mcf/day)		3, 088	(b)	—		N/A
Average Vanguard daily gas production (Mcf/day)		14,244		12,494

Average Natural Gas Sales Price per Mcf:
Net realized gas price, including hedges	$	11.12	(c)	$10.84	(c)	3	%
Net realized gas price, excluding hedges	$	4.07		$10.94		(63)	%

Net Oil Production:
Appalachian oil (Bbls)		25,451		11,122		129	%
Permian oil (Bbls)		57,525		54,924		5	%
Sun TSH oil (Bbls)		2,425	(b)	—		N/A
Total oil production (Bbls)		85,401		66,046		29	%

Average Appalachian daily oil production (Bbls/day)		277		121		129	%
Average Permian daily oil production (Bbls/day)		625		597		5	%
Average Sun TSH daily oil production (Bbls/day)		54	(b)	—		N/A
Average Vanguard daily oil production (Bbls/day)		956		718

Average Oil Sales Price per Bbl:
Net realized oil price, including hedges	$	77.15	(c)	$93.26	(c)	(17)	%
Net realized oil price, excluding hedges	$	63.76		$114.01		(44)	%

Net Natural Gas Liquids Production:
Permian natural gas liquids (Gal)		105,336		128,171		(18)	%
South Texas natural gas liquids (Gal)		436,922		421,680	(a)	4	%
Sun TSH natural gas liquids (Gal)		848,954	(b)	—		N/A
Total natural gas liquids production (Gal)		1,391,212		549,851		153	%

Average Permian daily natural gas liquids production (Gal/day)		1,145		1,393		(18)	%
Average South Texas daily natural gas liquids production (Gal/day)		4,749		6,487	(a)	(27)	%
Average Sun TSH daily natural gas liquids production (Gal/day)		18,866	(b)	—		N/A
Average Vanguard daily natural gas liquids production (Gal/day)		24,760		7,880

Average Natural Gas Liquids Sales Price per Gal:
Net realized natural gas liquids price, including hedges	$	0.82	(c)	$1.09	(c)	(25)	%
Net realized natural gas liquids price, excluding hedges	$	0.82		$1.09		(25)	%

	(a)	The South Texas acquisition closed on July 28, 2008 and, as such, only two months of operations are included in the three month period ended September 30, 2008.
	(b)	The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately one and a half months of operations are included in the three month period ended September 30, 2009.
	(c)	Excludes amortization of premiums paid and non-cash settlements on derivative contracts.

The decrease in natural gas, natural gas liquids and oil sales during the three months ended September 30, 2009 compared to the same period in 2008 was due primarily to the decreases in commodity prices. In Appalachia, we experienced a 16% decrease in natural gas production which was partially offset by a 129% increase in oil production during the three months ended September 30, 2009 compared to the same period in 2008 for a net production decline of 6% on a Mcfe basis, which is largely attributable to our decision to not drill wells in 2009 due to low natural gas prices. The 129% increase in Appalachian oil production was primarily due to our focus on completing to oil zones as oil prices increased during the first three quarters of 2008 and recompleting to oil zones on existing natural gas wells in 2009, which also adversely affected the amount of natural gas produced in 2009. We experienced a 63% decrease in the average realized natural gas sales price received (excluding hedges) and a 44% decrease in the average realized oil price (excluding hedges). The decrease in commodity prices was partially offset by a 20% increase in our total production on a Mcfe basis. The increase in production for the three months ended September 30, 2009 over the comparable period in 2008 was primarily attributable to the impact from the South Texas and Sun TSH acquisitions completed in July 2008 and August 2009, respectively.

Hedging and Price Risk Management Activities

During the three months ended September 30, 2009, we recognized $0.5 million related to losses on commodity cash flow hedges. These hedges were entered into in order to mitigate commodity price exposure on a portion of our expected production and were designated as cash flow hedges. The loss on commodity cash flow hedges for the three months ended September 30, 2009 relates to the amount that settled in 2009 and has been reclassified to earnings from accumulated other comprehensive loss.

During the three months ended September 30, 2009, we recognized $4.2 million related to losses on other commodity derivative contracts compared to gains of $63.4 million during the same period in 2008. The losses on other commodity derivative contracts for the three months ended September 30, 2009 includes a $12.2 million unrealized loss related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting and a $8.0 million realized gain related to the settlements recognized during the period. The gain on other commodity derivative contracts for the three months ended September 30, 2008 includes a $66.4 million unrealized gain related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting and a $3.0 million realized loss related to the settlements recognized during the period. The increase in unrealized losses on other commodity derivative contracts during the three months ended September 30, 2009 compared to the same period in 2008 resulted primarily from an increase in market oil prices during the same respective periods. The increase in realized gains on other commodity derivative contracts during the three months ended September 30, 2009 compared to the same period in 2008 resulted primarily from the decrease in market natural gas prices during the third quarter 2009, which increased the dollar amount of settlements received during that period.

The purpose of our hedging program is to mitigate the volatility in our 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 we pay the counterparty when commodity prices are above the hedged price. In either case, the impact on our 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 statement of operations. However, these fair value changes that are reflected in the consolidated statement 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 cash flow when the contract settles and the commodity is sold in the market will be approximately the same.

Costs and Expenses

Lease operating expenses include third-party transportation costs, gathering and compression fees, field personnel and other customary charges. Lease operating expenses in Appalachia also historically included a $60 per well per month administrative charge pursuant to a management services agreement with Vinland. This fee was increased to $95 per well per month beginning March 1, 2009 through December 31, 2009 pursuant to an agreement whereunder Vinland has agreed to provide well-tending services on Vanguard owned wells under a turnkey pricing contract. In addition, we historically have paid a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for production from wells drilled pre and post January 1, 2007, respectively, to Vinland pursuant to a gathering and compression agreement with Vinland. This gathering and compression agreement has been amended for the period beginning March 1, 2009 through December 31, 2009 to provide for a fee based upon the actual costs incurred by Vinland to provide gathering and transportation services plus a $0.05 per Mcf margin. Lease operating expenses decreased by $0.2 million to $3.3 million for the three months ended September 30, 2009 as compared to the three months ended September 30, 2008 September due to an effort to constrain costs during the three months ended September 30, 2009.

Depreciation, depletion, amortization and accretion decreased to approximately $3.3 million for the three months ended September 30, 2009 from approximately $4.2 million for the three months ended September 30, 2008 due primarily to a lower unamortized cost of natural gas and oil properties as a result of the impairment of these properties recorded during the fourth quarter of 2008 and the first three months of 2009.

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, 2009 increased $0.6 million as compared to the three months ended September 30, 2008 principally due to an increase in non-cash charges. For the three months ended September 30, 2009 and 2008, non-cash compensation charges amounted to $1.3 million and $0.8 million, respectively, related to the grant of restricted Class B units to officers and an employee, the grant of unit options to management, the grant of phantom units to officers and the grant of common units to board members and employees during 2007 through 2009.

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 decreased by $0.3 million for the three months ended September 30, 2009 as compared to the same period in 2008 as a result of decreased natural gas and oil revenues.

Interest expense declined to $1.0 million for the three months ended September 30, 2009 compared to $1.5 million for the three months ended September 30, 2008 primarily due to lower interest rates and lower average outstanding debt during the three months ended September 30, 2009.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues

Natural gas, natural gas liquids and oil sales decreased $25.8 million to $29.9 million during the nine months ended September 30, 2009 as compared to the same period in 2008. The key revenue measurements were as follows:

	Nine Months Ended September 30,					Percentage Increase (Decrease)
	2009			2008		Percentage Increase (Decrease)
Net Natural Gas Production:
Appalachian gas (MMcf)		2,372		2,693		(12)	%
Permian gas (MMcf)		153		132	(a)	16	%
South Texas gas (MMcf)		624		179	(b)	249	%
Sun TSH gas (MMcf)		139	(c)	—		N/A
Total natural gas production (MMcf)		3,288		3,004		9	%

Average Appalachian daily gas production (Mcf/day)		8,691		9,827		(12)	%
Average Permian daily gas production (Mcf/day)		560		543	(a)	3	%
Average South Texas daily gas production (Mcf/day)		2,286		2,757	(b)	(17)	%
Average Sun TSH daily gas production (Mcf/day)		3,088	(c)	—		N/A
Average Vanguard daily gas production (Mcf/day)		14,625		13,127

Average Natural Gas Sales Price per Mcf:
Net realized gas price, including hedges	$	11.13	(d)	$10.52	(d)	6	%
Net realized gas price, excluding hedges	$	4.71		$11.29		(58)	%

Net Oil Production:
Appalachian oil (Bbls)		63,148		32,543		94	%
Permian oil (Bbls)		175,175		157,463	(a)	11	%
Sun TSH oil (Bbls)		2,425	(c)	—		N/A
Total oil production (Bbls)		240,748		190,006		27	%

Average Appalachian daily oil production (Bbls/day)		231		119		94	%
Average Permian daily oil production (Bbls/day)		642		648	(a)	(1)	%
Average Sun TSH daily oil production (Bbls/day)		54	(c)	—		N/A
Average Vanguard daily oil production (Bbls/day)		927		767

Average Oil Sales Price per Bbl:
Net realized oil price, including hedges	$	74.64	(d)	$87.61	(d)	(15)	%
Net realized oil price, excluding hedges	$	52.42		$105.56		(50)	%

Net Natural Gas Liquids Production:
Permian natural gas liquids (Gal)		340,536		128,171	(a)	166	%
South Texas natural gas liquids (Gal)		1,268,161		421,680	(b)	201	%
Sun TSH natural gas liquids (Gal)		848,954	(c)	—		N/A
Total natural gas liquids production (Gal)		2,457,651		549,851		347	%

Average Permian daily natural gas liquids production (Gal/day)		1,247		527	(a)	137	%
Average South Texas daily natural gas liquids production (Gal/day)		4,645		6,487	(b)	(28)	%
Average Sun TSH daily natural gas liquids production (Gal/day)		18,866	(c)	—		N/A
Average Vanguard daily natural gas liquids production (Gal/day)		24,758		7,014

Average Natural Gas Liquids Sales Price per Gal:
Net realized natural gas liquids price, including hedges	$	0.74	(d)	$1.50	(d)	(51)	%
Net realized natural gas liquids price, excluding hedges	$	0.74		$1.50		(51)	%

	(a)	The Permian Basin acquisition closed on January 31, 2008 and, as such, only eight months of operations are included in the nine month period ended September 30, 2008.
	(b)	The South Texas acquisition closed on July 28, 2008 and, as such, only two months of operations are included in the nine month period ended September 30, 2008.
	(c)	The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately one and a half months of operations are included in the nine month period ended September 30, 2009.
	(d)	Excludes amortization of premiums paid and non-cash settlements on derivative contracts.

The decrease in natural gas, natural gas liquids and oil sales during the nine months ended September 30, 2009 compared to the same period in 2008 was due primarily to the decreases in commodity prices. In Appalachia, we experienced a 12% decrease in natural gas production which was partially offset by a 94% increase in oil production during the nine months ended September 30, 2009 compared to the same period in 2008 for a net production decline of 5% on a Mcfe basis, which is largely attributable to our decision to not drill wells in 2009 due to low natural gas prices. The 94% increase in Appalachian oil production was primarily due to our focus on completing to oil zones as oil prices increased during the first three quarters of 2008 and recompleting to oil zones on existing natural gas wells in 2009, which also adversely affected the amount of natural gas produced in 2009. We experienced a 58% decrease in the average realized natural gas sales price received (excluding hedges) and a 50% decrease in the average realized oil price (excluding hedges). The decrease in commodity prices was partially offset by a 20% increase in our total production on a Mcfe basis. The increase in production for the nine months ended September 30, 2009 over the comparable period in 2008 was primarily attributable to the impact from the Permian Basin, South Texas and Sun TSH acquisitions completed in January 2008, July 2008 and August 2009, respectively.

Hedging and Price Risk Management Activities

During the nine months ended September 30, 2009, we recognized $1.7 million related to losses on commodity cash flow hedges compared to gains of $0.6 million during the same period in 2008. 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. The loss on commodity cash flow hedges for the nine months ended September 30, 2009 relates to the amount that settled in 2009 and has been reclassified to earnings from accumulated other comprehensive loss.

During the nine months ended September 30, 2009, we recognized $7.3 million related to gains on other commodity derivative contracts compared to losses of $16.4 million during the same period in 2008. The gains on other commodity derivative contracts for the nine months ended September 30, 2009 includes a $16.5 million unrealized loss related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting and a $23.8 million realized gain related to the settlements recognized during the period. The loss on other commodity derivative contracts for the nine months ended September 30, 2008 includes a $6.0 million unrealized loss related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting and a $10.4 million realized loss related to the settlements recognized during the period. The increase in unrealized losses on other commodity derivative contracts during the nine months ended September 30, 2009 compared to the same period in 2008 resulted primarily from the increase in market oil prices during the same respective periods. The increase in realized gains on other commodity derivative contracts during the nine months ended September 30, 2009 compared to the same period in 2008 resulted from the decrease in commodity prices during the nine months ended September 30, 2009, which increased the dollar amount of settlements received that period.

Costs and Expenses

Lease operating expenses include third-party transportation costs, gathering and compression fees, field personnel and other customary charges. Lease operating expenses in Appalachia also historically included a $60 per well per month administrative charge pursuant to a management services agreement with Vinland. This fee was increased to $95 per well per month beginning March 1, 2009 through December 31, 2009 pursuant to an agreement whereunder Vinland has agreed to provide well-tending services on Vanguard owned wells under a turnkey pricing contract. In addition, we historically have paid a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for production from wells drilled pre and post January 1, 2007, respectively, to Vinland pursuant to a gathering and compression agreement with Vinland. This gathering and compression agreement has been amended for the period beginning March 1, 2009 through December 31, 2009 to provide for a fee based upon the actual costs incurred by Vinland to provide gathering and transportation services plus a $0.05 per Mcf margin. Lease operating expenses increased by $1.4 million to $9.2 million for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008, of which $1.1 million of the increase was related to the inclusion of the Permian and South Texas wells acquired in 2008 for the entire nine months in 2009 and the acquisition of the Sun TSH wells in August 2009.

Depreciation, depletion, amortization, and accretion decreased to approximately $9.7 million for the nine months ended September 30, 2009 from approximately $10.3 million for the nine months ended September 30, 2008 due primarily to a lower unamortized cost of natural gas and oil properties as a result of the impairments of these properties recorded during the fourth quarter of 2008 and the first three months of 2009, offset by additional depletion recorded on natural gas and oil properties acquired in the Permian Basin, South Texas and Sun TSH acquisitions.

An impairment of natural gas and oil properties in the amount of $63.8 million was recognized during the nine months ended September 30, 2009 as the unamortized cost of natural gas and oil properties exceeded the sum of the estimated future net revenues from proved properties using period-end prices, discounted at 10% and the lower of cost or fair value of unproved properties as a result of a decline in natural gas prices at the measurement date, March 31, 2009. The impairment calculation did not consider the positive impact of our commodity derivative positions as GAAP only allows the inclusion of derivatives designated as cash flow hedges.

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, 2009 increased $3.4 million as compared to the nine months ended September 30, 2008 principally due to an increase in non-cash charges. For the nine months ended September 30, 2009 and 2008, non-cash compensation charges amounted to $5.3 million and $2.7 million, respectively, related to the grant of restricted Class B units to officers and an employee, the grant of unit options to management, the grant of phantom units to officers and the grant of common units to board members and employees during 2007 through 2009. All other cash selling, general and administrative expenses increased $0.8 million during the nine months ended September 30, 2009 as compared to the same period in 2008 principally due to incremental costs associated with the company’s growth and acquisitions.

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 decreased by $1.1 million for the nine months ended September 30, 2009 as compared to the same period in 2008 as a result of decreased natural gas and oil revenues.

Interest expense declined to $3.0 million for the nine months ended September 30, 2009 compared to $3.9 million for the nine months ended September 30, 2008 primarily due to lower interest rates and lower average outstanding debt during the nine months ended September 30, 2009.

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, 2009, our critical accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2008.

Recently Adopted Accounting Pronouncements

In September 2006, the FASB issued guidance which defines fair value, establishes the framework for measuring fair value and expands disclosures about fair value measurements. This guidance is contained in ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”). In February 2008, the FASB deferred the effective date for us to January 1, 2009 for all nonfinancial assets and liabilities, except for those that are recognized or disclosed at fair value on a recurring basis (that is, at least annually). On January 1, 2008, we adopted the provisions of ASC Topic 820, as it relates to financial assets and financial liabilities and we determined that the impact of the additional assumptions on fair value measurements did not have a material effect on our financial position or results of operations. We adopted the deferred provisions of ASC Topic 820 on January 1, 2009, as it relates to nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact on our financial position or results of operations. See Note 5 on Part 1—Item 1—Notes to Consolidated Financial Statements for further discussion.

In March 2008, the FASB issued guidance intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. This guidance is contained in ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”). The guidance achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk-related. Finally, it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. Effective January 1, 2009, we adopted the provisions of ASC Topic 815, and the adoption did not have a material impact on our consolidated financial statements. See Note 4 on Part 1—Item 1—Notes to Consolidated Financial Statements for further discussion.

New Pronouncements Issued But Not Yet Adopted

Use of Estimates

Liquidity and Capital Resources

Disruption to Functioning of Capital Markets

Multiple events during 2008 and 2009 involving numerous financial institutions effectively restricted liquidity within the capital markets throughout the United States and around the world. While capital markets remain volatile, efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector appears to have improved the situation. As evidenced by our recent successful equity offering, successful amendment of our reserve-based credit facility and recent successful equity and debt offerings by our peers, we believe that our access to capital has improved and we have been successful in improving our financial position to date. During the nine months ended September 30, 2009, we did not drill any wells on our operated properties and there was limited drilling on non-operated properties. We intend to move forward with our development drilling program when market conditions allow for an adequate return on the drilling investment and only when we have sufficient liquidity to do so.

Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, the NYMEX crude oil spot price per barrel for the period between January 1, 2009 and September 30, 2009 ranged from a high of $73.68 to a low of $34.03 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2009 to September 30, 2009 ranged from a high of $6.07 to a low of $2.51. As of October 27, 2009, the NYMEX crude oil spot price per barrel was $79.45 and the NYMEX natural gas spot price per MMBtu was $4.56.

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 natural gas and oil 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 our reserve-based credit facility and publicly offered equity, depending on market conditions. As of October 31, 2009, we have $52.0 million available to be borrowed under our reserve-based credit facility.

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 (as determined by independent petroleum engineers) of estimated future net cash flows (utilizing the bank’s internal projection of future natural gas, natural gas liquids and oil prices) from our proved natural gas, natural gas liquids and oil reserves. Based on the current commodity price environment, banks have lowered their internal projections of future natural gas, natural gas liquids and oil prices which has decreased the borrowing base and thus decreased the amount available to be borrowed under our reserve-based credit facility. In October 2009, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which reduced our borrowing base under the reserve-based credit facility from $175.0 million to $170.0 million pursuant to our semi-annual redetermination and changed the definition of majority lenders from 75% to 66.67%. All other terms under the reserve-based credit facility remained the same. If commodity prices continue to decline and banks continue to lower their internal projections of natural gas, natural gas liquids and oil prices, it is possible that we will be subject to additional 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, to the extent available after unitholder distributions, debt service, and capital expenditures, it is our current intention to utilize our excess cash flow during the remainder of 2009 to reduce our borrowings under our reserve-based credit facility. Based upon current expectations, we believe existing liquidity and capital resources will be sufficient for the conduct of our business and operations for the foreseeable future.

Cash Flow from Operations

Net cash provided by operating activities was $36.0 million during the nine months ended September 30, 2009, compared to $28.6 million during the nine months ended September 30, 2008. The increase in cash provided by operating activities during the nine months ended September 30, 2009 as compared to the same period in 2008 was substantially generated from increased production revenue related to the Permian Basin, South Texas and Sun TSH acquisitions. Changes in working capital decreased total cash flows by $1.8 million in 2009 compared to decreasing total cash flows by $4.0 million in 2008.

Cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas, natural gas liquids and oil prices. Natural gas, natural gas liquids and oil 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 our cash flows. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes, and as such, we classify these cash flows as operating activities. Currently, we use a combination of fixed-price swaps and NYMEX collars and put options to reduce our exposure to the volatility in natural gas, natural gas liquids and oil 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 2011.

Cash Flow from Investing Activities

Cash used in investing activities was approximately $53.7 million for the nine months ended September 30, 2009, compared to $114.1 million for the nine months ended September 30, 2008. The decrease in cash used in investing activities was primarily attributable to $99.8 million used for the acquisition of natural gas and oil properties in the Permian Basin and South Texas during the nine months ended September 30, 2008 compared to $50.0 million used for the Sun TSH acquisition during the nine months ended September 30, 2009. In addition, the total for the nine months ended September 30, 2009 includes $3.0 million for the drilling and development of natural gas and oil properties as compared to $13.4 million for the nine months ended September 30, 2008 as a result of our decision to not drill wells in 2009 due to low natural gas prices.

Cash Flow from Financing Activities

Cash provided by financing activities was approximately $19.7 million for the nine months ended September 30, 2009, compared to $82.7 million for the nine months September 30, 2008. During the nine months ended September 30, 2009, total net repayments under our reserve-based credit facility were $11.5 million and $18.8 million was used for distributions to unitholders compared to $13.8 million in distribution to unitholders in the comparable period in 2008. Proceeds from the equity offering of 3.9 million common units completed in August 2009 provided financing cash flows totaling $53.2 million, net of offering costs of $0.5 million, during the nine months ended September 30, 2009. During the nine months ended September 30, 2008, total proceeds from borrowings under our reserve-based credit facility were $112.9 million, which were principally used to fund the Permian Basin and South Texas acquisitions.

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. Our reserve-based credit facility was amended and restated in February 2008 to extend the maturity date from January 2011 to March 2011, increase the maximum facility amount from $200.0 million to $400.0 million, increase our borrowing base from $110.5 million to $150.0 million and add two additional financial institutions as lenders, Wachovia Bank, N.A. and the Bank of Nova Scotia. The increase in the borrowing base was principally the result of inclusion of the reserves related to the Permian Basin acquisition in January 2008. In May 2008, our reserve-based credit facility was amended in response to a potential acquisition that ultimately did not occur. As a result, none of the provisions included in this amendment went into effect. As of October 22, 2008, our reserve-based credit facility was amended to increase the borrowing base to $175.0 million and add one lender, BBVA Compass Bank. The increase in the borrowing base was principally the result of inclusion of the reserves related to the South Texas acquisition in July 2008. In February 2009, a third amendment was entered into which amended covenants to allow the company to repurchase up to $5.0 million of our own units. In May 2009, our borrowing base was set at $154.0 million pursuant to our semi-annual redetermination. In June 2009, a fourth amendment to our reserve-based credit facility was entered into which temporarily increased the percentage of outstanding indebtedness for which interest rate derivatives could be used. The percentage was increased from 75% to 85% but was to revert back to 75% in one year at June 2010. In August 2009, our reserve-based credit facility was amended and restated to (1) extend the maturity from March 31, 2011 to October 1, 2012, (2) increase our borrowing base from $154.0 million to $175.0 million, (3) increase our borrowing costs, (4) permanently allow 85% of our outstanding indebtedness to be covered under interest rate derivatives, and (5) add two financial institutions as lenders, Comerica Bank and Royal Bank of Canada. At September 30, 2009, we had $123.5 million outstanding under our reserve-based credit facility and as of October 31, 2009, we have $52.0 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 natural gas and oil 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, 2009, we have 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, 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. Also, distributions can only be made to unitholders if the amount of borrowings outstanding under our reserve-based credit facility is less than 90% of the borrowing base.

We believe that we are in compliance with the terms of 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 Securities Exchange Commission) 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.

Off-Balance Sheet Arrangements

At September 30, 2009, 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, 2009, there were no loss contingencies.

Commitments and Contractual Obligations

A summary of our contractual obligations as of September 30, 2009 is provided in the following table:

	Payments Due by Year (in thousands)
	2009		2010		2011		2012		2013		After 2013		Total
Management compensation	$	169	$	112	$	—	$	—	$	—	$	—	$	281
Asset retirement obligations		—		118		186		72		94		3,663		4,133
Derivative liabilities		38		3,541		2,459		889		271		—		7,198
Long-term debt (1)		—		—		—		123,500		—		—		123,500
Operating leases		31		31		—		—		—		—		62
Total	$	238	$	3,802	$	2,645	$	124,461	$	365	$	3,663	$	135,174

(1)

This table does not include interest to be paid on the principal balances shown as the interest rates on the reserve-based credit facility are variable.

Non-GAAP Financial Measure

Adjusted EBITDA

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

•

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

•

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

•

Impairment of natural gas and oil properties;

•

Amortization of premiums paid and non-cash settlement on derivative contracts;

•

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

•

Gains and losses on acquisitions of natural gas and oil properties;

•

Deferred taxes;

•

Unit-based compensation expense; and

•

Unrealized fair value of phantom units granted to officers.

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, 2009 as compared to the three months ended September 30, 2008, Adjusted EBITDA increased 13%, from $13.8 million to $15.6 million. For the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008, Adjusted EBITDA increased 15%, from $36.2 million to $41.5 million. The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDA:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008

Net income (loss)	$	701		$	71,809		$	(56,032	)	$	8,857
Plus:
Interest expense, including realized losses on interest rate derivative contracts		1,548			1,489			4,274			3,863
Depreciation, depletion, amortization, and accretion		3,272			4,187			9,700			10,341
Impairment of natural gas and oil properties		-			-			63,818			-
Amortization of premiums paid and non-cash settlements on derivative contracts		1,811			1,451			4,383			3,982
Unrealized (gains) losses on other commodity and interest rate derivative contracts		12,795			(65,933	)		16,105			6,463
Gain on acquisition of natural gas and oil properties		(5,878	)		-			(5,878	)		-
Deferred taxes		(3	)		-			(204	)		-
Unit-based compensation expense		548			812			2,311			2,708
Unrealized fair value of phantom units granted to officers		782			-			3,034			-
Less:
Interest income		-			4			-			16
Adjusted EBITDA	$	15,576		$	13,811		$	41,511		$	36,198

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 natural gas, natural gas liquids and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. 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 natural gas, natural gas liquids and oil production. Realized pricing is primarily driven by the Columbia Gas Appalachian Index (“TECO Index”), Henry Hub, and Houston Ship Channel for natural gas production and the West Texas Intermediate Light Sweet for oil production. Pricing for natural gas 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 to drill new wells, production could decline to levels below our hedged volumes.

Furthermore, the risk that we will be required to writedown the carrying value of our natural gas and oil properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves, or if estimated future development costs increase. For example, natural gas prices declined throughout the first three months of 2009. We recorded a non-cash ceiling test impairment of natural gas and oil properties for the three months ended March 31, 2009 of $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and $49.64 per barrel of crude oil. No ceiling test impairment was necessary for the three months ended June 30, 2009 or September 30, 2009.

We enter into derivative contracts with respect to a portion of our projected natural gas and oil 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. 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. 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 natural gas and oil 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 95% of projected production for a three year period. These activities are intended to support our realized commodity prices at targeted levels and to manage our exposure to natural gas and oil 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, 2009, the fair value of commodity derivative contracts was an asset of approximately $26.0 million, of which $19.5 million settles during the next twelve months.

The following table summarizes commodity derivative contracts in place at September 30, 2009:

	October 1, - December 31, 2009		Year 2010		Year 2011
Gas Positions:
Fixed Price Swaps:
Notional Volume (MMBtu)		864,806		4,731,040		3,328,312
Fixed Price ($/MMBtu)	$	9.34	$	8.66	$	7.83
Puts:
Notional Volume (MMBtu)		651,446		—		—
Floor Price ($/MMBtu)	$	7.85	$	—	$	—
Collars:
Notional Volume (MMBtu)		249,999		1,607,500		1,933,500
Floor Price ($/MMBtu)	$	7.50	$	7.73	$	7.34
Ceiling Price ($/MMBtu)	$	9.00	$	8.92	$	8.44
Total:
Notional Volume (MMBtu)		1,766,251		6,320,540		5,261,812

Oil Positions:
Fixed Price Swaps:
Notional Volume (Bbls)		44,000		164,250		151,250
Fixed Price ($/Bbl)	$	87.23	$	85.65	$	85.50
Collars:
Notional Volume (Bbls)		9,200		—		—
Floor Price ($/Bbl)	$	100.00	$	—	$	—
Ceiling Price ($/Bbl)	$	127.00	$	—	$	—
Total:
Notional Volume (Bbls)		53,200		164,250		151,250

Interest Rate Risks

At September 30, 2009, we had debt outstanding of $123.5 million, which incurred interest at floating rates based on LIBOR in accordance with our reserve-based credit facility and, if the debt remains the same, a 1% increase in LIBOR would result in an estimated $0.2 million increase in annual interest expense after consideration of the interest rate swaps discussed below. We entered into interest rate swaps, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate exposures to fixed interest rates.

In August 2008, we entered into two interest rate basis swaps which changed the reset option from three month LIBOR to one month LIBOR on the total $60.0 million of outstanding interest rate swaps. By doing so, we reduced our borrowing cost based on three month LIBOR by 14 basis points on $20.0 million of borrowings for a one year period starting September 10, 2008 and 12 basis points on $40.0 million of borrowings for a one year period starting October 31, 2008. As a result of these two basis swaps, we chose to de-designate the interest rate swaps as cash flow hedges as the terms of the new contracts no longer matched the terms of the original contracts, thus causing the interest rate hedges to be ineffective. Beginning in the third quarter of 2008, we recorded changes in the fair value of our interest rate derivatives in current earnings under unrealized gains (losses) on interest rate derivative contracts. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive income and later reclassified to earnings in the month in which the transactions settle. In December 2008, we amended three existing interest rate swap agreements and entered into one new agreement which fixed the LIBOR rate at 1.85% on $10.0 million of borrowings through December 2010. The first amended agreement reduced the fixed LIBOR rate from 3.88% to 3.35% on $20.0 million and the maturity was extended two additional years to December 10, 2012. In addition, the second amended agreement reset the notional amount on the March 31, 2011 swap from $10.0 million to $20.0 million and also reduced the rate from 2.66% to 2.08%. The third amended agreement reset the notional amount on the January 31, 2011 swap from $10.0 million to $20.0 million, reduced the rate from 3.00% to 2.38%, and also extended the maturity two additional years to 2013.

The following summarizes information concerning our positions in open interest rate derivative contracts at September 30, 2009:

	Notional Amount (in thousands)		Fixed Libor Rates
Period:
October 1, 2009 to December 18, 2010	$	10,000	1.50	%
October 1, 2009 to December 20, 2010	$	10,000	1.85	%
October 1, 2009 to January 31, 2011	$	20,000	3.00	%
October 1, 2009 to March 31, 2011	$	20,000	2.08	%
October 1, 2009 to December 10, 2012	$	20,000	3.35	%
October 1, 2009 to January 31, 2013	$	20,000	2.38	%
October 1, 2009 to October 31, 2009 (Basis Swap)	$	40,000	LIBOR 1M vs. LIBOR 3M

Counterparty Risk

At September 30, 2009, based upon all of our open commodity and interest rate 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):

	Citibank, N.A. (A+)			BNP Paribas (AA)			The Bank of Nova Scotia (AA-)			Wells Fargo Bank N.A./ Wachovia Bank, N.A. (AA)			Total
Current Asset, net	$	2,393		$	14,418		$	194		$	2,511		$	19,516
Current Liability, net		—			—			—			(29	)		(29	)
Long-Term Asset, net		582			6,068			—			200			6,850
Long-Term Liability, net		(92	)		(1,160	)		(1,163	)		(386	)		(2,801	)
Total Amount Due from Counterparty/(Owed to Counterparty) at September 30, 2009	$	2,883		$	19,326		$	(969	)	$	2,296		$	23,536

We net derivative assets and liabilities for counterparties where we have a legal right of offset. Our counterparties are participants in our reserve-based credit facility.

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, 2009 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management 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 August 17, 2009, we completed the acquisition of certain natural gas and oil properties in South Texas. Pursuant to this transaction, we have outsourced our production accounting for these properties to the same third party that handles the production accounting for the Permian Basin and our other South Texas properties. As a result, there were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed below or elsewhere 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 units, please refer to the section entitled “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008 as supplemented by the risk factors set forth below. There has been no material change in the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2008 other than those set forth below. For further information, see Part I—Item 1A—Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008.

Natural gas, natural gas liquids and oil prices are volatile. A decline in natural gas, natural gas liquids and oil prices could adversely affect our credit availability, financial position, financial results, cash flow, access to capital and ability to grow.

Our future borrowing base under our reserve-based credit facility, financial condition, revenues, results of operations, rate of growth and the carrying value of our natural gas and oil properties depend primarily upon the prices we receive for our natural gas, natural gas liquids and oil production and the prices prevailing from time to time for natural gas, natural gas liquids and oil. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our reserve-based credit facility and through the capital markets. The amount available for borrowing under our reserve-based credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. The decline in natural gas, natural gas liquids and oil prices has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. In August 2009, we entered into the Second Amended and Restated Credit Agreement which provided for an initial borrowing base of $175 million and a maturity of October 1, 2012. 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 natural gas, natural gas liquids and oil prices at such time. In October 2009, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which reduced our borrowing base under the reserve-based credit facility from $175.0 million to $170.0 million pursuant to our semi-annual redetermination. It is possible that we will be subject to a further reduction in our borrowing base at our next scheduled redetermination in April 2010. If our outstanding borrowings under the reserve-based credit facility exceed 90% of our borrowing base, we would be required to cease paying distributions to our unitholders until we reduce our borrowings below the 90% threshold.

·	the level of consumer demand for natural gas and oil;

·	the domestic and foreign supply of natural gas and oil;

·	commodity processing, gathering and transportation availability, and the availability of refining capacity;

·	the price and level of imports of foreign crude natural gas and oil;

·	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and to enforce crude oil price and production controls;

·	domestic and foreign governmental regulations and taxes;

·	the price and availability of alternative fuel sources;

·	weather conditions;

·	political conditions or hostilities in oil and gas producing regions, including the Middle East, Africa and South America;

·	technological advances affecting energy consumption; and

·	worldwide economic conditions.

Declines in natural gas and oil prices would not only reduce our revenue, but could reduce the amount of natural gas and oil that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, and reserves. We use the full cost method of accounting for natural gas and oil properties which requires us to perform a ceiling test quarterly that is impacted by declining prices. Significant price declines could cause us to take quarterly writedowns related to the results of such “ceiling tests”, which would be reflected as non-cash charges against current earnings. We recorded a non-cash ceiling test impairment of natural gas and oil properties for the three months ended March 31, 2009 of $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. No ceiling test impairment was necessary for the three months ended June 30, 2009 or September 30, 2009. If the gas and oil industry experiences significant price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, pay distributions to our unitholders, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can affect the value of our units.

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

During the three months ended September 30, 2009, one of our wholly-owned subsidiaries purchased 2,400 of our common units on the open market at the prevailing market price. The following table summarizes the unit purchases that occurred during the three months ended September 30, 2009:

Period	Number of common units repurchased		Average price paid per common unit
July 1, 2009 to July 31, 2009		—	$	N/A
August 1, 2009 to August 31, 2009		2,400		13.65
September 1, 2009 to September 30, 2009		—		N/A
Total common units purchased		2,400	$	13.65

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

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	Underwriting Agreement dated August 12, 2009, by and among Vanguard Natural Resources, LLC and Citigroup Global Markets Inc., Wells Fargo Securities, LLC and RBC Capital Markets Corporation, as representatives of the several underwriters named therein	Form 8-K, filed August 12, 2009 (File No. 001-33756)
10.2	Second Amended and Restated Credit Agreement dated August 31, 2009, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Form 8-K, filed September 1, 2009 (File No. 001-33756)
10.3	First Amendment to Second Amended and Restated Credit Agreement dated October 14, 2009, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Filed herewith
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

SIGNATURE

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

	VANGUARD NATURAL RESOURCES, LLC
	(Registrant)

Date: November 4, 2009
	/s/ Richard A. Robert
	Richard A. Robert
	Executive Vice President and
	Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

Vanguard Natural Resources, Inc. - FORM 10-Q - November 4, 2009

Attached files

Vanguard Natural Resources, Inc. Reports