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VANGUARD NATURAL RESOURCES, LLC

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Cash Flows	5
	Consolidated Statements of Comprehensive Income (Loss)	6
	Notes to Consolidated Financial Statements (Unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	24
Item 4.	Controls and Procedures	25
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 3.	Default in Senior Securities	27
Item 4.	Submission of Matters to a Vote of Securities Holders	27
Item 5.	Other Information	27
Item 6.	Exhibits	27
SIGNATURE		28

 

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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
Btu		= British thermal unit		MMBtu		= million British thermal units
				MMcf		= million cubic feet

 

When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of 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 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”) and Vanguard Permian, LLC, (“Vanguard Permian”) and (2) “Vanguard Predecessor”, “Predecessor”, “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC. 

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PART I – FINANCIAL INFORMATION

 

		Three Months Ended March 31,
		2008			2007
Revenues:
Natural gas and oil sales		$	14,000,097		$	8,961,616
Realized losses on derivative contracts			(1,150,472	)		(747,808	)
Total revenues			12,849,625			8,213,808
Costs and expenses:
Lease operating expenses			2,015,677			1,146,379
Depreciation, depletion and amortization			2,823,978			2,028,863
Selling, general and administrative expenses			1,645,791			434,288
Bad debt expense			—			1,007,461
Taxes other than income			966,113			510,882
Total costs and expenses			7,451,559			5,127,873
Income from operations			5,398,066			3,085,935
Other income and (expense):
Interest income			7,614			12,967
Interest expense			(1,129,660	)		(2,223,123	)
Loss on extinguishment of debt			—			(2,501,528	)
Total other expense, net			(1,122,046	)		(4,711,684	)
Net income (loss)		$	4,276,020		$	(1,625,749	)
Net income (loss) per unit:
Common & Class B units – basic		$	0.38		$	(0.29	)
Common & Class B units – diluted		$	0.38		$	(0.29	)
Weighted average units outstanding:
Common units – basic & diluted			10,795,000			5,540,000
Class B units – basic & diluted			420,000			—

 

See accompanying notes to consolidated financial statements

3

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

		March 31, 2008			December 31, 2007
		(unaudited)
Assets
Current assets
Cash and cash equivalents		$	757,408		$	3,109,563
Trade accounts receivable, net			9,987,429			4,372,731
Derivative assets			—			4,017,085
Other currents assets			741,969			453,198
Total current assets			11,486,806			11,952,577
Property and equipment
Furniture and fixtures			79,847			72,893
Machinery and equipment			163,765			138,719
Less: accumulated depreciation			(56,150	)		(45,157	)
Total property and equipment			187,462			166,455
Natural gas and oil properties, net – full cost method			183,346,598			106,983,349
Other assets
Derivative assets			203,945			1,329,511
Deferred financing costs			1,035,187			941,833
Non-current deposits			45,963			8,285,883
Other assets			569,142			1,519,577
Total assets		$	196,875,103		$	131,179,185
Liabilities and members’ equity
Current liabilities
Accounts payable – trade		$	849,410		$	1,056,627
Accounts payable – natural gas and oil			717,618			257,073
Payables to affiliates			3,278,376			3,838,328
Derivative liabilities			8,894,489			—
Accrued expenses			5,791,912			203,159
Total current liabilities			19,531,805			5,355,187
Long-term debt			102,500,000			37,400,000
Derivative liabilities			13,246,161			5,903,384
Asset retirement obligations			1,463,924			189,711
Total liabilities			136,741,890			48,848,282
Commitments and contingencies
Members’ equity
Members’ capital, 10,795,000 common units issued and outstanding at March 31, 2008 and December 31, 2007			86,321,263			90,257,856
Class B units, 420,000 issued and outstanding at March 31, 2008 and December 31, 2007			3,004,932			2,131,995
Other comprehensive loss			(29,192,982	)		(10,058,948	)
Total members’ equity			60,133,213			82,330,903
Total liabilities and members’ equity		$	196,875,103		$	131,179,185

 

See accompanying notes to consolidated financial statements

4

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		Three Months Ended March 31,
		2008			2007
Operating activities
Net income (loss)		$	4,276,020		$	(1,625,748	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			2,823,978			2,028,863
Amortization of deferred financing costs			84,410			62,838
Bad debt expense			—			1,007,461
Unit-based compensation			914,564			—
Amortization of premiums prepaid on derivative contracts			1,300,609			—
Changes in operating assets and liabilities:
Trade accounts receivable			(5,614,698	)		(1,618,379	)
Payables to affiliates			(107,452	)		(11,874,522	)
Other current assets			(304,888	)		(1,334,387	)
Price risk management activities, net			(182,840	)		(8,475,675	)
Other non-current assets			—			(3,384	)
Accounts payable			253,328			2,757,409
Accrued expenses			598,078			(223,810	)
Net cash provided by (used in) operating activities			4,041,109			(19,299,334	)
Investing activities
Additions to property and equipment			(32,000	)		—
Additions to natural gas and oil properties			(1,238,379	)		(1,723,031	)
Acquisitions of natural gas and oil properties			(65,661,575	)		—
Deposits and prepayments of natural gas and oil properties			(1,119,981	)		—
Net cash used in investing activities			(68,051,935	)		(1,723,031	)
Financing activities
Proceeds from borrowings			71,400,000			114,600,000
Repayment of debt			(6,300,000	)		(94,067,500	)
Contributions from members			—			1,000
Distribution to members			(3,263,565	)		—
Financing costs			(177,764	)		(1,139,311	)
Net cash provided by financing activities			61,658,671			19,394,189
Net decrease in cash and cash equivalents			(2,352,155	)		(1,628,176	)
Cash and cash equivalents, beginning of period			3,109,563			1,730,956
Cash and cash equivalents, end of period		$	757,408		$	102,780
Supplemental cash flow information:
Cash paid for interest		$	1,105,980		$	1,230,654
Non-cash financing and investing activities:
Asset retirement obligations		$	1,260,544		$	150,628
Accrued dividends declared		$	4,990,675			—
Assumption of fixed-price oil swaps		$	1,128,114			—
Initial contribution of assets		$	—		$	3,289,055

See accompanying notes to consolidated financial statements

5

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

		Three Months Ended March 31,
		2008			2007
Net income (loss)		$	4,276,020		$	(1,625,748	)
Net gains (losses) from cash flow hedging activities:
Unrealized mark-to-market losses arising during the period			(20,102,103	)		(11,664,967	)
Reclassification adjustments for changes in initial value to settlement date			968,069			(404,147	)
Other comprehensive loss			(19,134,034	)		(12,069,114	)
Comprehensive loss		$	(14,858,014	)	$	(13,694,862	)

 

See accompanying notes to consolidated financial statements

6

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 

(Unaudited)

1.    Basis of Presentation and Significant Accounting Policies

Basis of Presentation

 

Vanguard Natural Resources, LLC is a publicly-traded limited liability company focused on the acquisition, development and exploitation 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 and the Permian Basin, primarily in West Texas and Southeastern New Mexico.

 

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”) and Vanguard Permian, LLC, (“Vanguard Permian”) and (2) “Vanguard Predecessor”, “Predecessor”, “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

 

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 acts as the operator of our existing wells and all of the wells that we drill in Appalachia. We refer to these events as the "Restructuring."

 

In October 2007, we completed our initial public offering (“IPO”) of 5.25 million units representing limited liability interests in VNR at $19.00 per unit for net proceeds of $92.8 million after deducting underwriting discounts and fees of $7.0 million. The proceeds were used to reduce indebtedness under our Credit Facility by $80.0 million and the balance was used for the payment of accrued distributions to pre-IPO unitholders and the payment of a deferred swap obligation.

 

VNG was formed in Kentucky on December 15, 2004 and its principal business is to hold interests in TEC, VNRH, Ariana Energy and Vanguard Permian. TEC was formed in Kentucky on December 15, 2004 and its principal business consists of natural gas and oil development and exploitation of mature, long-lived natural gas and oil properties in the Appalachian region of eastern Kentucky. VNRH was formed in Delaware on March 28, 2007 and its principal business was to provide general employment related services, including payroll and employment administration, as well as information technology and communication services to VNR. However, as of January 1, 2008, it no longer provides these services as they have been outsourced to a third party and has limited operating activity. Ariana Energy was formed in Tennessee on April 26, 2002 and its principal business consists of natural gas and oil development and exploitation of mature, long-lived natural gas and oil properties in Tennessee. Vanguard Permian was formed in Delaware on December 21, 2007 and its principal business consists of natural gas and oil development and exploitation of mature long-lived natural gas and oil properties in West Texas and Southeastern New Mexico.

 

The consolidated financial statements as of and for the three months ended March 31, 2008 include the accounts of VNR, VNG, TEC, VNRH, Ariana Energy and Vanguard Permian.

 

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (“SEC”). 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. You should read this Quarterly Report on Form 10-Q along with our 2007 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. The financial statements as of March 31, 2008, and for the three months ended March 31, 2008 and 2007, are unaudited. We derived the consolidated balance sheet as of December 31, 2007, from the audited balance sheet filed in our 2007 Annual Report on Form 10-K. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of our operating results for the entire year. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity. Furthermore, all intercompany accounts and transactions have been eliminated in the consolidated financial statements. 

7

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (CONTINUED)

(Unaudited)

 Summary of Significant Accounting Policies

As of March 31, 2008, the Company’s significant accounting policies are consistent with those discussed in Note 1 of the Company’s consolidated financial statements contained in the Company’s 2007 Annual Report on Form 10-K.

 

Recently Adopted Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 introduces a framework for measuring fair value and expands required disclosure about fair value measurements of assets and liabilities. On February 6, 2008, the FASB issued a final FASB Staff Position (“FSP”) No. FAS 157-b, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In addition, the FSP removes certain leasing transactions from the scope of SFAS 157. The effective date of SFAS 157 for non-financial assets and non-financial liabilities has been delayed by one year to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. SFAS 157 for financial assets and liabilities is effective for fiscal years beginning after November 15, 2007, and the Company prospectively adopted the standard for those assets and liabilities as of January 1, 2008. See Note 6. Fair Value Disclosures. 

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”), which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of SFAS 159 is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of SFAS 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Effective January 1, 2008, the Company adopted SFAS 159 and the adoption did not have a material impact on its consolidated financial statements.

New Pronouncements Issued But Not Yet Adopted

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes 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. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be our fiscal year 2009. The impact, if any, on the consolidated financial statements will depend on the nature and size of business combinations that we consummate after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon the March 31, 2008 balance sheet, SFAS 160 would have no impact on the consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is 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. SFAS 161 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. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are currently evaluating the impact of adopting SFAS 161 on our consolidated financial statements.

8

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (CONTINUED)

(Unaudited)

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the Unites States of America 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 and oil reserves and related cash flow estimates used in impairment tests of natural gas and oil properties, the fair value of derivative contracts and asset retirement obligations, natural gas and oil revenues and expenses, as well as estimates of expenses related to depreciation, depletion and amortization. Actual results could differ from those estimates.

2.     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 adjusted purchase price included a preliminary purchase price adjustment of $4.9 million which represents the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the closing date, January 31, 2008. The purchase price includes a payment of $7.8 million paid by us to the seller in December 2007 and this amount is reported in non-current deposits in our consolidated balance sheet at December 31, 2007. In this acquisition, based on internal reserve forecasts, we acquired approximately 4.4 million barrels of oil equivalent, 83% of which are oil and 90% are proved developed producing. The current net production attributable to this purchase is estimated to be approximately 800 barrels of oil equivalent per day and the reserves-to-production ratio is 15 years. 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 $1,128,114 at January 31, 2008. This acquisition was funded with borrowings under our existing Credit Facility.

3.     Accounts Receivable and Allowance for Doubtful Accounts

We established an approximate $1 million provision for a loss on the entire amount due from a customer which filed for protection under Chapter 11 of the Bankruptcy Code in May 2007. The account receivable was due from oil sales through December 2006 at which time we ceased selling oil to the customer. As the amount of any potential recovery is uncertain, we elected to reserve the entire balance and it is reflected as bad debt expense on our consolidated statement of operations for the three months ended March 31, 2007. We began selling our oil production to a new customer beginning in March 2007.

 

4.    Credit Facilities and Long-Term Debt

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

 

Amount Outstanding

Description

Interest Rate

Maturity Date

March 31, 2008

December 31, 2007

$400 million Senior Secured Revolver

Variable

March 31, 2011

102,500,000

37,400,000

Total

$

102,500,000

$

37,400,000

$400 Million Senior Secured Revolver

 

In January 2007, the Company entered into a four-year $200 million revolving credit facility (“Credit Facility”) with two banks. All of our Predecessor’s outstanding debt was repaid with borrowings under this Credit Facility, including an early prepayment penalty of $2.5 million. 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 proved natural gas and oil reserves of the Company. The initial Borrowing Base was set at $115.5 million and is secured by a first lien security interest in all of the Company’s natural gas and oil properties. However, the borrowing base was subject to $1 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 the 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 Credit Facility. In February 2008, our 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 financial institutions as lenders. Additional borrowings were made pursuant to the acquisition of natural gas and oil properties in the Permian Basin and indebtedness under the Credit Facility totaled $102.5 million at March 31, 2008.

9

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VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (CONTINUED)

(Unaudited)

 

Interest rates under the Credit Facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. At March 31, 2008, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage	<25%	>25%<50%	>50%<75%	>75%
Eurodollar Loans	1.000%	1.250%	1.500%	1.750%
ABR Loans	0.000%	0.250%	0.500%	0.750%
Commitment Fee Rate	0.250%	0.300%	0.375%	0.375%
Letter of Credit Fee	1.000%	1.250%	1.500%	1.750%

 

The Credit Agreement contains a number of customary covenants that require the Company to maintain certain financial ratios, limit the Company’s ability to incur additional debt, sell assets, create liens, or make certain distributions. At March 31, 2008, we were in compliance with our debt covenants.

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 2007 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 2007 Annual Report on Form 10-K, 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, development and exploitation 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 and the Permian Basin, primarily in West Texas and Southeastern New Mexico.

 

We owned working interests in 1,357 gross (902 net) productive wells at March 31, 2008 and our average net production for the twelve months ended December 31, 2007 and for the three months ended March 31, 2008 was 11,610 Mcfe per day and 13,393 Mcfe per day, respectively. We also have a 40% working interest in the known producing horizons in approximately 104,000 gross undeveloped acres surrounding or adjacent to our existing wells located in southeast Kentucky and northeast Tennessee. Vinland Energy Operations, LLC (“Vinland”) acts as the operator of our existing wells in Appalachia and all of the wells that we will drill in this area.

 

Initial Public Offering

 

In October 2007, we completed our initial public offering (“IPO”) of 5.25 million units representing limited liability interests in VNR at $19.00 per unit for net proceeds of $92.8 million after deducting underwriting discounts and fees of $7.0 million. The proceeds were used to reduce indebtedness under our reserve-based credit facility by $80.0 million and the balance was used for the payment of accrued distributions to pre-IPO unitholders and the payment of a deferred swap obligation.

 

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 adjusted purchase price included a preliminary purchase price adjustment of $4.9 million which represents the cash flow from the acquired properties for the period between the effective date, October 1, 2007, and the closing date, January 31, 2008. This acquisition was funded with borrowings under our reserve-based credit facility. In this purchase, we acquired working interests in 390 gross wells (67 net wells), 49 of which we operate. With respect to operations, we have established two district offices, one in Lovington, New Mexico and the other in Christoval, Texas to manage these assets. Our operating focus will be on maximizing existing production and looking for complementary acquisitions that we can add to this operating platform. With this acquisition, based on internal reserve estimates, we acquired 4.4 million barrels of oil equivalent, 83% of which is oil and 90% of which is proved developed producing. The current net production attributable to this purchase is approximately 800 barrels of oil equivalent per day and the reserves-to-production ratio is 15 years. With the closing of this acquisition, our daily production and total reserves increased approximately 40%.

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Our Relationship with Vinland

 

On April 18, 2007 but effective as of January 5, 2007, we entered into various agreements with Vinland, under which we rely on Vinland to operate our existing producing wells in Appalachia and coordinate our development drilling program in this area. We expect to benefit from the substantial development and operational expertise of Vinland management in the Appalachian Basin. Under a management services agreement, Vinland advises and consults with us regarding all aspects of our production and development operations in Appalachia and provides us with administrative support services as necessary for the operation of our business. In addition, Vinland may, but does not have any obligation to, provide us with acquisition services under the management services agreement. While Vinland is not obligated to provide us with acquisition services, we expect that due to significant common ownership Vinland has an incentive to grow our business by helping us to identify, evaluate and complete acquisitions that will be accretive to our distributable cash. In addition, under a gathering and compression agreement that we entered into with Vinland Energy Gathering, LLC (“VEG”), VEG gathers, compresses, delivers and provides the services necessary for us to market our natural gas production in the area of mutual interest, or AMI. VEG delivers our natural gas production to certain designated interconnects with third-party transporters. Since the various agreements were executed on April 18, 2007 but were effective as of January 5, 2007, Vinland reimbursed us for the drilling costs and expenses that we incurred on their behalf associated with their interest in the wells drilled between January 5, 2007 and April 18, 2007. In addition, Vinland reimbursed us for selling, general and administrative expenses that we incurred on their behalf between January 5, 2007 and April 18, 2007. We reimbursed Vinland for certain transaction costs and expenses relating to entering into these agreements.

 

 

Prior to the separation, our Predecessor owned all of the assets that are currently owned by us and Vinland in Appalachia. As part of the separation of our operating company and Vinland, effective January 5, 2007, we conveyed to Vinland 60% of our Predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres in the AMI, 100% of our Predecessor’s interest in an additional 125,000 undeveloped acres and certain coalbed methane rights located in the Appalachian Basin, the rights to any natural gas and oil located on our acreage at 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. 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 in the AMI and a contract right to receive approximately 99% of the net proceeds, after deducting royalties paid to other parties, severance taxes, third-party transportation costs, costs incurred in the operation of wells and overhead costs, from the sale of production from certain producing natural gas and oil wells, which accounted for approximately 4.5% of our estimated proved reserves as of December 31, 2007. In addition, we changed the name of our operating company from Nami Holding Company, LLC to Vanguard Natural Gas, LLC. Collectively, we refer to these events as the “Restructuring.”

 

 

In April 2007, we completed a private equity offering pursuant to which we issued 2,290,000 units to certain private investors, which we collectively refer to as the Private Investors, for $41.2 million. We used the net proceeds of this private equity offering to make a distribution to Majeed S. Nami, VNR’s largest unitholder, who used a portion of these funds to capitalize Vinland and also paid us $3.9 million to reduce outstanding accounts receivable from Vinland. We then used the $3.9 million to repay borrowings and interest under our reserve-based credit facility, and for general limited liability company purposes. Under the terms of the private offering, all outstanding units accrued distributions at $1.75 annually from the closing of the private offering to September 30, 2007 and then distributions payable to the Private Investors only increased to $2.40 until the completion of the initial public offering at which time all accrued distributions totaling $5.6 million were paid.

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On January 3, 2007, our operating company 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 extended 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 financial institutions as lenders. Additional borrowings were made pursuant to the acquisition of natural gas and oil properties in the Permian Basin and indebtedness under the reserve-based credit facility totaled $102.5 million at March 31, 2008. At March 31, 2008, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

 

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage	<25%	>25%<50%	>50%<75%	>75%
Eurodollar Loans	1.000%	1.250%	1.500%	1.750%
ABR Loans	0.000%	0.250%	0.500%	0.750%
Commitment Fee Rate	0.250%	0.300%	0.375%	0.375%
Letter of Credit Fee	1.000%	1.250%	1.500%	1.750%

 

 

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments, competition from other sources of energy, and access to capital. Natural gas 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 and oil reserves that we can economically produce and our access to capital. As required by our reserve-based credit facility, we have mitigated this volatility for the years 2007 through 2011 by implementing a hedging program on our proved producing and total anticipated production during this time frame.

 

We face the challenge of natural gas and oil production declines. As a given well’s initial reservoir pressures are depleted, natural gas 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. 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. 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.

 

Results of Operations

 

The following table sets forth selected financial and operating data for the periods ended March 31:

		Three Months Ended March 31,
		2008(a)			2007
Revenues:
Natural gas and oil sales		$	14,000,097		$	8,961,616
Realized losses on derivative contracts			(1,150,472	)		(747,808	)
Total revenues			12,849,625		$	8,213,808
Costs and expenses:
Lease operating expenses		$	2,015,677		$	1,146,379
Depreciation, depletion and amortization			2,823,978			2,028,863
Selling, general and administrative expenses			1,645,791			434,288
Bad debt expense			—			1,007,461
Taxes other than income			966,113			510,882
Total costs and expenses		$	7,451,559		$	5,127,873
Other income and (expense):
Interest expense, net		$	(1,122,046	)	$	(2,210,156	)
Loss on extinguishment of debt		$	—		$	(2,501,528	)

 

(a)  The Permian acquisition closed on January 31, 2008 and as such only two months of operations are included in the three month period ending March 31, 2008.

 

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Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

 

Revenues

 

Natural gas and oil sales increased $5.0 million to $14.0 million during the three months ended March 31, 2008 as compared to the same period in 2007. The key revenue measurements were as follows:

		Three Months Ended March 31,						Percentage Increase (Decrease)
		2008			2007
Net Natural Gas Production:
Appalachian gas (MMcf)			867			1,068			(19)	%
Permian gas (MMcf)			42	(a)		—			N/A
Total natural gas production (MMcf)			909			1,068			(15)	%
Average Appalachian daily gas production (Mcf/day)			9,527			11,868			(20)	%
Average Permian daily gas production (Mcf/day)			693	(a)		—			N/A
Average Natural Gas Sales Price per Mcf:
Net realized gas price, including hedges			$10.47	(b)		$7.69			36	%
Net realized gas price, excluding hedges			$9.93			$8.39			18	%
Net Oil Production:
Appalachian oil (Bbls)			10,991			—			N/A
Permian oil (Bbls)			40,722	(a)		—			N/A
Total oil (Bbls)			51,713			—			N/A
Average Appalachian daily oil production (Bbls/day)			121			—			N/A
Average Permian daily oil production (Bbls/day)			679	(a)		—			N/A
Average Oil Sales Price per Bbls:
Net realized oil price, including hedges			$89.65			—			N/A
Net realized oil price, excluding hedges			$96.33			—			N/A

 

(a)

The Permian acquisition closed on January 31, 2008 and as such only two months of operations are included in the three month period ending March 31, 2008.

(b)

Excludes amortization of premiums prepaid on derivative contracts.

 

The increase in natural gas and oil sales was due primarily to the impact of the Permian Basin acquisition completed on January 31, 2008. Two months of production from this recently completed acquisition contributed $4.3 million of natural gas and oil sales for the three month period ended March 31, 2008. In Appalachia, a decline in natural gas production was partially offset by an increase in oil production for a net production decline of 13% on an Mcfe basis. However, the negative impact of the production decline was offset by an 18% increase in the average realized natural gas sales price received (excluding hedges).

 

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Hedging Activities

 

During the three months ended March 31, 2008, we had hedges in place for approximately 98% of our total production, which resulted in reported revenues that were $1.2 million lower than we would have achieved at unhedged prices. However, the actual cash impact of the hedges increased realizations by $0.2 million for the three months ended March 31, 2008 after excluding the amortization of premiums prepaid on derivative contracts. During the three months ended March 31, 2007, we hedged approximately 58% of our total production and in January 2007, we terminated existing natural gas swaps at a cost of approximately $2.8 million which resulted in an additional loss on derivative contracts of approximately $0.8 million.

 

Costs and Expenses

 

Production costs consist of the lease operating expenses and taxes other than income taxes (severance and ad valorem taxes). Lease operating expenses include third-party transportation costs, gathering and compression fees, field personnel and other customary charges. Lease operating expenses in Appalachia also include a $60 per month per well administrative charge pursuant to a management services agreement with Vinland, 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, paid to Vinland pursuant to a gathering and compression agreement with Vinland. Lease operating expenses increased by $0.9 million to $2.0 million for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007 of which $0.6 million related to the recently closed Permian Basin acquisition. 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. Taxes other than income increased by $0.5 million for the three months ended March 31, 2008 as compared to the same period in 2007 of which $0.3 million related to the recently closed Permian Basin acquisition.

 

Depreciation, depletion and amortization increased to approximately $2.8 million for the three months ended March 31, 2008 from approximately $2.0 million for the three months ended March 31, 2007 due entirely to the additional depletion recorded on the recently completed Permian Basin acquisition.

 

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 March 31, 2008 increased $1.2 million as compared to the three months ended March 31, 2007 primarily resulting from a $0.9 million non-cash compensation charge related to the grant of restricted Class B units to management and an employee, the grant of unit options to management and the grant of common units to board members during 2007 and 2008. Excluding the impact of the non-cash compensation, selling, general and administrative expenses were $0.7 million for the three months ended March 31, 2008 representing a $0.3 million increase from the same period in 2007 principally due to costs associated with additional employees.

 

Interest expense declined to $1.1 million for the three months ended March 31, 2008 compared to $2.2 million for the three months ended March 31, 2007 primarily due to a reduction in the weighted average outstanding borrowings and lower interest rates. All of our Predecessor’s outstanding debt was repaid with borrowings under our reserve-based credit facility in January 2007, including an early prepayment penalty of $2.5 million.

 

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 March 31, 2008, the Company’s critical accounting policies are consistent with those discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.   

 

Recently Adopted Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 introduces a framework for measuring fair value and expands required disclosure about fair value measurements of assets and liabilities. On February 6, 2008, the FASB issued a final FASB Staff Position (“FSP”) No. FAS 157-b, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In addition, the FSP removes certain leasing  transactions from the scope of SFAS 157. The effective date of SFAS 157 for non-financial assets and non-financial liabilities has been delayed by one year to fiscal years beginning after November 15, 2008 and interim periods within those fiscal years. SFAS 157 for financial assets and liabilities is effective for fiscal years beginning after November 15, 2007, and the Company prospectively adopted the standard for those assets and liabilities as of January 1, 2008. See Note 6 in Notes to Consolidated Financial Statements and Part 1—Item 1—Fair Value Disclosures.

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In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (“SFAS 159”), which permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The objective of SFAS 159 is to reduce volatility in preparer reporting that may be caused as a result of measuring related financial assets and liabilities differently and to expand the use of fair value measurements. The provisions of SFAS 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. Additional disclosures are also required for instruments for which the fair value option is elected. SFAS 159 is effective for fiscal years beginning after November 15, 2007. No retrospective application is allowed, except for companies that choose to adopt early. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. Effective January 1, 2008, the Company adopted SFAS 159 and the adoption did not have a material impact on its consolidated financial statements.

New Pronouncements Issued But Not Yet Adopted

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes 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. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be our fiscal year 2009. The impact, if any, on the consolidated financial statements will depend on the nature and size of business combinations that we consummate after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial statements—an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon the March 31, 2008 balance sheet, SFAS 160 would have no impact on the consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is 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. SFAS 161 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. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are evaluating the impact of SFAS 161 on our consolidated financial statements and do not expect the impact of implementation to be material.

 

Liquidity and Capital Resources

We have utilized private equity, proceeds from bank borrowings, cash flow from operations and, with our recent IPO, 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, as a result of our IPO, 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 or acquiring additional reserves. We expect to fund our maintenance 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 May 13, 2008, we have $47.5 million available to be borrowed 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.

 

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Cash Flow from Operations

 

Net cash provided by operating activities for the three months ended March 31, 2008 was $4.0 million, compared to cash used in operating activities of $19.3 million for the three months ended March 31, 2007. The increase in cash provided by operating activities during the three months ended March 31, 2008 was substantially due to increased income, a reduction in payables to affiliates and a decrease in cash used in price risk management activities. The cash used in operating activities in the first quarter 2007 included the termination of existing natural gas swaps at a cost of approximately $2.8 million, cash paid on early extinguishment of debt of approximately $2.5 million and the payment of $6.5 million for put option derivative contracts.

 

Cash flow from operations is subject to many variables, the most significant of which is the volatility of natural gas and oil prices. Natural gas 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 arrangements to reduce the impact of commodity price volatility on operations. 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 and oil prices. See Note 5 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 2012.

 

Cash Flow from Investing Activities

Cash used in investing activities was approximately $68.1 million for the three months ended March 31, 2008, compared to $1.7 million for the three months ended March 31, 2007. The increase in cash used in investing activities was primarily attributable to $65.6 million used for the acquisition of natural gas and oil properties in the Permian Basin. In addition, the total for the three months ended March 31, 2008 includes $1.2 million for the drilling and development of natural gas and oil properties as compared to $1.7 million for the three months ended March 31, 2007.

 

 Cash Flow from Financing Activities

Cash provided by financing activities was approximately $61.6 million for the three months ended March 31, 2008, compared to $19.4 million for the three months ended March 31, 2007. During the three months ended March 31, 2008, total proceeds from borrowings under our reserve-based credit facility were $71.4 million which were principally used to fund the Permian Basin acquisition. During the three months ended March 31, 2007, total proceeds from borrowings under our reserve-based credit facility were $114.6 million, which was principally used to pay off our Predecessor’s outstanding borrowings.

 

Reserve-Based Credit Facility

On January 3, 2007, our operating company, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC), 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 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 financial institutions as lenders. The increase in the borrowing base was principally the result of inclusion of the reserves related to the Permian Basin acquisition. As a result, as of March 31, 2008, we had $102.5 million outstanding under our reserve-based credit facility and as of May 13, 2008, we have $47.5 million available to be borrowed. Borrowings under the reserve-based credit facility are available for development, exploitation 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 1.00% and 1.75% per annum; or

·

a domestic bank rate plus an applicable margin between 0.00% and 0.75% per annum.

 

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;

 

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·

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, 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 SFAS No. 133, which includes the current portion of derivative contracts;

 

·

consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, 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 4.0 to 1.0.

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

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. 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

 

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·

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 March 31, 2008, the Company did not have any off-balance sheet arrangements that have, or are reasonably likely to have, a material effect on our financial position or results of operations.

 

Contingencies

 

The Company regularly analyzes current information and accrues 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 March 31, 2008, there were no loss contingencies.

 

Commitments and Contractual Obligations

 

A summary of our contractual obligations as of March 31, 2008 is provided in the following table:

 

		Payments Due by Year (in thousands)
		2008			2009			2010			2011			2012			After 2012			Total
Management compensation		$	450		$	600		$	100		$	—		$	—		$	—		$	1,150
Long-term debt			—			—			—			102,500			—			—			102,500
Operating leases			30			41			10			—			—			—			81
Total		$	480		$	641		$	110		$	102,500		$	—		$	—		$	103,731

 

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);

•

Loss on extinguishment of debt;

•

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

•

Bad debt expenses;

•

Amortization of premiums prepaid on derivative contracts;

•

Change in fair value of derivative contracts;

•

Unit-based compensation expense; and

•

Realized (gain) loss on cancelled derivatives.

 

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Adjusted EBITDA is a significant performance metric used by our management to measure (prior to the establishment of any cash reserves by our board of directors) 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 a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies.

 

Our 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 March 31, 2008 as compared to the three months ended March 31, 2007, Adjusted EBITDA increased 51%, from $6.9 million to $10.4 million. The following table presents a reconciliation of consolidated net income to adjusted EBITDA:

 

		Three Months Ended March 31,
		2008			2007
Net income (loss)		$	4,276,020		$	(1,625,749	)
Plus:
Interest expense			1,129,660			2,223,123
Loss on extinguishment of debt			—			2,501,528
Depreciation, depletion and amortization			2,823,978			2,028,863
Bad debt expense			—			1,007,461
Amortization of premiums prepaid on derivative contracts			1,300,609			—
Non-cash compensation expense			915,346			—
Realized loss on cancelled derivatives			—			776,633
Less:
Interest income			7,614			12,967
Adjusted EBITDA		$	10,437,999		$	6,898,892

 

There have been no material changes to our risk factors as disclosed in our 2007 Annual Report on Form 10-K .

 

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

 

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

 

None.

Item 5.  Other Information

 

None.

 

EXHIBIT INDEX

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

 

Exhibit
Number	Description
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith