Unassociated Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q/A

(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2008
OR
 
¨
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
 
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 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 o 
 
Non-accelerated filer x
  
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 August 12, 2008: 12,145,873 
 
 
EXPLANATORY NOTE

On November 10, 2008, in connection with preparing its quarterly report for third quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, management of the Company and the Audit Committee of its Board of Directors concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”).  The primary reasons for this determination were that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient.  Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas which made them ineffective.
 
Under SFAS No. 133, the fair value of derivative contracts is recognized in the Consolidated Balance Sheets as an asset or liability, and the amounts received or paid under the contracts are reflected in earnings during the period in which the underlying production occurs.  If the derivative contracts qualify for hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income”, and changes in the fair value do not affect net income in the period.  If the derivative contract does not qualify for hedge accounting treatment, the change in the fair value of the contract is reflected in earnings during the period as unrealized gain or loss on commodity derivatives.  Under the cash flow hedge accounting treatment used by the Company previously, the fair values of the hedge contracts were recognized in the consolidated balance sheets with the resulting unrealized gain or loss recorded initially in accumulated other comprehensive income and later reclassified through earnings when the hedged production affected earnings.  As a result of the determination that the documentation failed to meet cash flow hedge accounting treatment, the unrealized gain or loss should have been recorded in the consolidated statements of operations as a component of earnings in 2008. In addition, the net derivative loss at December 31, 2007 related to the de-designated natural gas derivative contracts entered into in 2007 will continue to be reported in accumulated other comprehensive income until the month in which the transactions settle.
 
The Company has restated its consolidated unaudited quarterly financial statements for March 31, 2008 and June 30, 2008 to reflect the inability to qualify for hedge accounting treatment. The effect of the restatement is to recognize a non-cash mark to market unrealized loss on commodity derivatives of $20.2 million in the first quarter of 2008 and a non-cash mark to market unrealized loss on commodity derivatives of $52.2 in the second quarter of 2008.  The restatement does not impact the economics of the hedge transactions nor does it affect the Company’s cash flow, liquidity, total assets, total liabilities, or members’ equity in any historical or future period.  The restatement did not have any impact on any of the Company’s financial covenants under its reserve-based credit facility. Details of the restatement are indicated in Note 1 to the Consolidated Financial Statements.
 
 
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 Cash Flows
  
5
 
Consolidated Statements of Comprehensive Income (Loss)
  
6
 
Notes to Consolidated Financial Statements
  
7
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  
17
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
  
30
Item 4.
Controls and Procedures
  
31
       
PART II - OTHER INFORMATION
    
Item 1.
Legal Proceedings
  
32
Item 1A.
Risk Factors
  
32
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
  
35
Item 3.
Default in Senior Securities
  
35
Item 4.
Submission of Matters to a Vote of Securities Holders
  
35
Item 5.
Other Information
  
36
Item 6.
Exhibits
  
36

 
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
 
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. 

 
PART I - FINANCIAL INFORMATION
 
Item 1. Financial Statements
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
   
Three Months Ended
June 30,
    
Six Months Ended
June 30,
  
   
2008
    
2007
    
2008
    
2007
  
Revenues:
  
Restated
          
Restated
        
Natural gas and oil sales
   $ 20,852,386     $ 10,106,737     $ 34,853,984     $ 19,068,353  
Realized losses on commodity cash flow hedges
     —       (918,044 )     —       (1,665,852 )
Total revenues
     20,852,386       9,188,693       34,853,984       17,402,501  
                                 
Costs and expenses:
                                
Lease operating expenses
     2,300,076       1,314,041       4,315,753       2,460,420  
Depreciation, depletion, amortization and accretion
     3,330,024       2,291,426       6,154,002       4,320,289  
Selling, general and administrative expenses
     1,636,675       781,198       3,282,466       1,215,489  
Bad debt expense
     —       —       —       1,007,458  
Taxes other than income taxes
     1,428,965       380,110       2,395,078       890,992  
Total costs and expenses
     8,695,740       4,766,775       16,147,299       9,894,648  
                                 
Income from operations
     12,156,646       4,421,918       18,706,685       7,507,853  
                                 
Other income and (expense):
                                
Interest income
     4,394       14,679       12,008       27,646  
Interest expense
     (1,244,450 )     (2,196,691 )     (2,374,110 )     (4,419,814 )
Realized loss on commodity derivative contracts
     (5,703,498 )     —       (6,849,114 )     —  
Unrealized loss on commodity derivative contracts
     (52,186,386 )     —       (72,396,143 )     —  
Realized loss on interest rate derivative contracts
     (46,450 )     —       (51,306 )     —  
Loss on extinguishment of debt
     —       —       —       (2,501,528 )
Total other expense, net
     (59,176,390 )     (2,182,012 )     (81,658,665 )     (6,893,696 )
                                 
Net income (loss)
   $ (47,019,744 )   $ 2,239,906     $ (62,951,980 )   $ 614,157  
                                 
Net income (loss) per unit:
                                
Common & Class B units - basic
   $ (4.19 )   $ 0.38     $ (5.61 )   $ 0.11  
                                 
Common & Class B units - diluted
   $ (4.19 )   $ 0.38     $ (5.61 )   $ 0.11  
                                 
Weighted average units outstanding:
                                
Common units - basic & diluted
     10,795,000       5,540,000       10,795,000       5,540,000  
Class B units - basic & diluted
     420,000       296,813       420,000       149,227  
 
See accompanying notes to consolidated financial statements

3

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS 
 
   
June 30,
2008
    
December 31,
2007
  
   
Restated
(unaudited)
        
Assets
            
Current assets
            
Cash and cash equivalents
   $ 3,900,503     $ 3,109,563  
Trade accounts receivable, net
     10,825,985       4,372,731  
Derivative assets
     —       4,017,085  
Other current assets
     719,273       453,198  
Total current assets
     15,445,761       11,952,577  
                 
Property and equipment, net of accumulated depreciation
     203,037       166,455  
                 
Natural gas and oil properties, at cost
     219,299,247       135,435,240  
Accumulated depletion
     (34,594,152 )     (28,451,891 )
Natural gas and oil properties, net - full cost method
     184,705,095       106,983,349  
                 
Other assets
                
Derivative assets
     702,079       1,329,511  
Deferred financing costs
     973,191       941,833  
Non-current deposits
     45,963       8,285,883  
Other assets
     1,061,309       1,519,577  
Total assets
   $ 203,136,435     $ 131,179,185  
                 
Liabilities and members’ equity
                
                 
Current liabilities
                
Accounts payable - trade
   $ 947,507     $ 1,056,627  
Accounts payable - natural gas and oil
     1,034,750       257,073  
Payables to affiliates
     4,161,308       3,838,328  
Derivative liabilities
     27,109,030       —  
Accrued expenses
     3,435,907       203,159  
Total current liabilities
     36,688,502       5,355,187  
                 
Long-term debt
     102,500,000       37,400,000  
Derivative liabilities
     47,582,633       5,903,384  
Asset retirement obligations
     1,532,881       189,711  
Total liabilities
     188,304,016       48,848,282  
                 
Commitments and contingencies
                
                 
Members’ equity
                
Members’ capital, 10,795,000 common units issued and outstanding at June 30, 2008 and December 31, 2007
     19,220,375       90,257,856  
Class B units, 420,000 issued and outstanding at June 30, 2008 and December 31, 2007
     3,495,153       2,131,995  
Accumulated other comprehensive loss
     (7,883,109 )     (10,058,948 )
Total members’ equity
     14,832,419       82,330,903  
Total liabilities and members’ equity
   $ 203,136,435     $ 131,179,185  
 
See accompanying notes to consolidated financial statements
 
4
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
   
Six Months Ended
June 30,
  
   
2008
    
2007
  
Operating activities
  
Restated
        
Net income (loss)
   $ (62,951,980 )   $ 614,157  
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
                
Depreciation, depletion, amortization and accretion
     6,154,002       4,320,289  
Amortization of deferred financing costs
     173,045       142,234  
Bad debt expense
     —       1,007,458  
Unit-based compensation
     1,896,347       563,143  
Amortization of premiums paid and non-cash settlements on derivative contracts
     2,531,193       733,504  
Unrealized loss on commodity derivative contracts
     72,396,143       —  
Changes in operating assets and liabilities:
                
Trade accounts receivable
     (6,453,254 )     (322,027 )
Payables to affiliates
     614,969       (2,083,796 )
Other current assets
     (223,398 )     (12,372 )
Price risk management activities, net
     (442,840 )     (8,475,676 )
Accounts payable
     668,556       2,393,459  
Accrued expenses
     3,158,730       (1,713,858 )
Net cash provided by (used in) operating activities
     17,521,513       (2,833,485 )
                 
Investing activities
                
Additions to property and equipment
     (61,659 )     (31,211 )
Additions to natural gas and oil properties
     (6,677,962 )     (6,132,607 )
Acquisitions of natural gas and oil properties
     (66,389,952 )     —  
Deposits and prepayments of natural gas and oil properties
     48,074       (455,883 )
Net cash used in investing activities
     (73,081,499 )     (6,619,701 )
                 
Financing activities
                
Proceeds from borrowings
     74,400,000       114,600,000  
Repayment of debt
     (9,300,000 )     (99,667,500 )
Contributions from members
     —       41,221,000  
Distributions to members
     (8,254,240 )     (41,220,000 )
Financing costs
     (204,403 )     (1,194,270 )
Offering costs
     (54,192 )     (1,571,993 )
Purchase of units for unit-based compensation
     (236,239 )     —  
Net cash provided by financing activities
     56,350,926       12,167,237  
                 
Net increase in cash and cash equivalents
     790,940       2,714,051  
Cash and cash equivalents, beginning of period
     3,109,563       1,730,956  
Cash and cash equivalents, end of period
   $ 3,900,503     $ 4,445,007  
                 
Supplemental cash flow information:
                
Cash paid for interest
   $ 1,802,039     $ 4,826,132  
Non-cash financing and investing activities:
                
Asset retirement obligations
   $ 1,309,854     $ 155,800  
Assumption of fixed-price oil swaps
   $ 1,128,114     $ —  
Deferred swap liability
   $ —     $ 7,322,685  
Initial contribution of assets
   $ —     $ 3,289,055  
Transfer of deposit for acquisition of natural gas and oil properties
   $ 7,830,000       —  
 
 See accompanying notes to consolidated financial statements
 
5
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited) 
 
   
Three Months Ended
June 30,
    
Six Months Ended
June 30,
  
   
2008
    
2007
    
2008
    
2007
  
   
Restated
          
Restated
        
Net income (loss)
   $ (47,019,744 )   $ 2,239,906     $ (62,951,980 )   $ 614,157  
                                 
Net gains (losses) from cash flow hedging activities:
                                
Unrealized mark-to-market gains (losses) arising during the period
     1,256,501       698,959       2,747,150       (10,966,008 )
Reclassification adjustments for settlements
     (154,883 )     911,890       (571,311 )     507,743  
Other comprehensive income (loss)
     1,101,618       1,610,849       2,175,839       (10,458,265 )
                                 
Comprehensive income (loss)
   $ (45,918,126 )   $ 3,850,755     $ (60,776,141 )   $ (9,844,108 )
 
See accompanying notes to consolidated financial statements
 
6
 
 
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 and in 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 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.

 
1.
Summary of Significant Accounting Policies

The accompanying financial statements, other than the consolidated balance sheet data as of December 31, 2007, are unaudited and were prepared from the Company’s records. We derived the consolidated balance sheet as of December 31, 2007, from the audited financial statements filed in our 2007 Annual Report on Form 10-K/A. 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/A along with our 2007 Annual Report on Form 10-K/A, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which, except for the restatement discussed in note (b) below, are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income, members’ equity, or net cash flows.

As of June 30, 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/A with the exception noted in (b) below.

(a)
Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of June 30, 2008 and December 31, 2007 and for the three months and six months ended June 30, 2008 and 2007 include the accounts of VNR and its wholly owned subsidiaries.  The Company presents its financial statements in accordance with GAAP.  All intercompany transactions and balances have been eliminated upon consolidation.
  
(b)
Financial Statement Restatement:
 
On November 10, 2008, in connection with preparing its quarterly report for third quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, management of the Company and the Audit Committee of its Board of Directors concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). The primary reasons for this determination were that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient. Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas in the first quarter of 2008 which made them ineffective.
 
7
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

Under SFAS No. 133, the fair value of derivative contracts is recognized in the Consolidated Balance Sheets as an asset or liability, and the amounts received or paid under the contracts are reflected in earnings during the period in which the underlying production occurs.  If the derivative contracts qualify for hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income”, and changes in the fair value do not affect net income in the period.  If the derivative contract does not qualify for hedge accounting treatment, the change in the fair value of the contract is reflected in earnings during the period as unrealized gain or loss on commodity derivatives. Under the cash flow hedge accounting treatment used by the Company previously, the fair values of the hedge contracts were recognized in the consolidated balance sheets with the resulting unrealized gain or loss recorded initially in accumulated other comprehensive income and later reclassified through earnings when the hedged production affected earnings. As a result of the determination that the documentation failed to meet cash flow hedge accounting treatment, the unrealized gain or loss should have been recorded in the consolidated statements of operations as a component of earnings in 2008. In addition, the net derivative loss at December 31, 2007 related to the de-designated natural gas derivative contracts entered into in 2007 will continue to be reported in accumulated other comprehensive income until the month in which the transactions settle.
 
In this Form 10-Q/A, the Company is restating the Consolidated Financial Statements for the three months and six months ended June 30, 2008. A non-cash mark to market unrealized loss on commodity derivatives of $52.2 million has been reclassified from other comprehensive loss to a separate line on the Consolidated Statements of Operations. The effect of the reclassification on our financial statements is as follows:
 
   
Three Months Ended
June 30, 2008
    
Six Months Ended
June 30, 2008
  
   
Previously 
Reported
    
As
Restated
    
Previously 
Reported
    
As
Restated
  
                         
Consolidated Statements of Operations
                        
Unrealized loss on commodity derivative contracts
   $ —     $ (52,186,386 )   $ —     $ (72,396,143 )
Net income (loss)
   $ 5,164,168     $ (47,019,744 )   $ 9,440,188     $ (62,951,980 )
Basic and diluted net income (loss) per unit
   $ 0.46     $ (4.19 )   $ 0.84     $ (5.61 )
 
   
June 30, 2008
  
   
Previously
Reported
    
As
Restated
  
             
Consolidated Balance Sheets
            
                 
Accumulated other comprehensive loss
   $ (80,275,277 )   $ (7,883,109 )
 
   
For the Six Months Ended
June 30, 2008
  
   
Previously 
Reported
    
As 
Restated
  
             
Consolidated Statements of Cash Flows
            
Cash Flows from Operating Activities:
            
Net income (loss)
   $ 9,440,188     $ (62,951,980 )
Unrealized loss on commodity derivative contracts
   $ —     $ 72,396,143  

8
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

(c)
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 Measurements.  

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. Because the Company did not elect to apply the provisions of SFAS 159 to any eligible financial instrument, the adoption did not affect the consolidated financial statements.

(d)
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 June 30, 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 161on our consolidated financial statements.

9
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

(e)
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 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, accrued natural gas 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 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. The purchase price included 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. 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 reserve-based credit facility. At this time, we do not have the information available to provide pro-forma results of operations for the three months and six months ended June 30, 2007. In lieu of the pro-forma information, the table below reflects the audited statement of combined revenues and direct operating expenses of the oil and gas properties purchased from Apache for the year ended December 31, 2007.

   
Year Ended
December 31, 2007
  
   
(In thousands)
  
Revenues
   $ 18,205  
Direct operating expenses
     (6,624 )
Excess of revenues over direct operating expenses
   $ 11,581  

On July 28, 2008, we acquired certain natural gas and oil properties in South Texas. See Note 11. Subsequent Event for further discussion.

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 six months ended June 30, 2007. We began selling the oil production we formerly sold to this customer 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
  
June 30,
2008
    
December 31,
2007
  
$400 million senior secured revolver facility
  
Variable
  
March 31, 2011
     102,500,000       37,400,000  
Total
           $ 102,500,000     $ 37,400,000  
 
10
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

$400 Million Senior Secured Revolver Facility
 
In January 2007, the Company entered into a four-year $200 million 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, 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 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 pursuant to the acquisition of natural gas and oil properties in the Permian Basin in January 2008 and indebtedness under the reserve-based credit facility totaled $102.5 million at June 30, 2008.

Interest rates under the reserve-based credit facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. At June 30, 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 June 30, 2008, we were in compliance with our debt covenants.
 
The Credit Agreement required the Company to enter into a commodity price hedge position establishing certain minimum fixed prices for anticipated future production equal to approximately 84% of the projected production from proved developed producing reserves from the second half of 2007 through 2011. Also, the Credit Agreement required that certain production put option contracts for the years 2007, 2008 and 2009 be put in place to create a price floor for anticipated production from new wells drilled. See Note 5. Price Risk Management Activities for further discussion.    

5.     Price Risk Management Activities

We have entered into derivative contracts with counterparties that are lenders under our reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova Scotia and 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, the Company receives 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”) or Henry Hub for natural gas production and the West Texas Intermediate Light Sweet for oil production. Under put option agreements, we pay the counterparty the fair value 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.
 
11
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

Under SFAS No. 133, 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 derivative’s 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 realized gains (losses) on derivative contracts in the period that the related production is delivered. The unrealized gains (losses) on derivative contracts that do not qualify for hedge accounting treatment are recorded as current income or expense in the Consolidated Statements of Operations.

On January 3, 2007, our Predecessor’s natural gas price swaps were terminated, which resulted in the Company incurring swap termination fees of $2.8 million and an additional loss on derivative contracts of approximately $0.8 million included in our consolidated statement of operations for the six months ended June 30, 2007. New natural gas derivative contracts were put in place in conjunction with entering into the reserve-based credit facility as described in Note 4.Credit Facility and Long-Term Debt. The Company paid $6.5 million for the put option contracts and payments for the put option contracts and the swap termination fee were funded with borrowings under the reserve-based credit facility. At our election, also in January 2007, we entered into a NYMEX natural gas collar contract. In May 2007, we reset our 2007, 2008 and 2009 natural gas swaps at higher prices and incurred a $7.3 million deferred swap payment obligation with the derivative counterparty which accrued interest daily at 7.36% and was payable at the earlier of five days after the closing of an equity issuance or November 1, 2007. The deferred swap obligation was paid in October 2007 using proceeds from our IPO.

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 the Company of $0.3 million which was funded with cash on hand.

At June 30, 2008, the Company had open derivative contracts covering our anticipated future production as follows:
 
Swap Agreements

   
Gas
    
Oil
  
Contract Period  
  
MMBtu
    
Weighted
Average
Fixed Price
    
Bbls
    
WTI
Price
  
2008  
     1,452,439     $ 9.00       97,500     $ 90.30  
2009  
     2,657,046     $ 8.85       181,500     $ 87.23  
2010  
     2,387,640     $ 8.76       164,250     $ 85.65  
2011  
     2,196,012     $ 7.15       151,250     $ 85.50  
2012
     —     $ —       144,000     $ 80.00  
 
Put Option Contracts
 
Contract Period  
  
Volume in MMBtu
    
Purchased NYMEX
Price Floor
  
2008
     561,311     $ 7.50  
2009
     840,139     $ 7.50  

12
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

Collars

   
Gas
  
   
MMBtu
    
Floor
    
Ceiling
  
Production Period:
            
July – September 2008
     300,000     $ 9.00     $ 9.00  
October – December 2008
     300,000     $ 9.00     $ 9.25  
January 2009 – December 2009
     1,000,000     $ 7.50     $ 9.00  
January 2010 – December 2010
     730,000     $ 8.00     $ 9.30  
 
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. At June 30, 2008, the Company had open interest rate derivative contracts as follows:

   
Principal
    
Fixed
Libor
  
   
Balance
    
Rates
  
Period:
        
July 1, 2008 to December 10, 2010
   $ 20,000,000       3.88 %
July 1, 2008 to January 31, 2011
   $ 30,000,000       3.00 %
July 1, 2008 to March 31, 2011
   $ 10,000,000       2.66 %

6.     Fair Value Measurements

As discussed in Note 1. Summary of Significant Accounting Policies (c), we prospectively adopted SFAS 157 for financial assets and financial liabilities. SFAS 157 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 SFAS 157. Primarily, SFAS 157 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. SFAS 157 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.

Certain provisions of SFAS 157 have been deferred by the FASB. Accordingly, the Company has not applied the provisions of SFAS 157 to those non-financial assets and liabilities which are measured at fair value on a non-recurring basis. This includes asset retirement obligations, and any assets other than oil and natural gas properties, for which an impairment write-down is recorded during the period. There have been no such asset impairments in the current period.

13
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)

The Company has applied the provisions of SFAS 157 to assets and liabilities measured at fair value on a recurring basis. This includes oil and natural gas and interest rate derivatives contracts. SFAS 157 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 the company’s own credit standing (when valuing liabilities) and the buyer’s risk premium. In adopting SFAS 157, the Company determined that the impact of these additional assumptions on fair value measurements did not have a material effect on financial position or results of operations. The Company is still assessing the potential impact of implementation in 2009 of those portions of the guidance for which the effective date has been deferred by the FASB.

SFAS 157 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. SFAS 157 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 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 1assets include short-term investments (such as Money Market Funds and Treasury Bills).
     
Level  2
  
Quoted market prices for similar instruments in active markets; quoted priced 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 SFAS No. 157, 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. The Company has 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: 

   
June 30, 2008
  
   
Fair Value Measurements Using
    
Assets/Liabilities
  
   
Level 1
    
Level 2
    
Level 3
    
at Fair value
  
Assets: 
  
 
    
 
    
 
        
Commodity price derivative contracts
   $ —     $ —     $ —     $ —  
Interest rate derivative contracts
     —       702,079       —       702,079  
Total derivative instruments
   $ —     $ 702,079     $ —     $ 702,079  
                                 
Liabilities: 
                                
Commodity price derivative contracts
   $ —     $ (74,691,663 )   $ —     $ (74,691,663 )
Interest rate derivative contracts
     —       —       —       —  
Total derivative instruments
   $ —     $ (74,691,663 )   $ —     $ (74,691,663 )

 
14
 
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
7. Asset Retirement Obligations

The asset retirement obligations as of June 30 reported on our consolidated balance sheets and the changes in the asset retirement obligations for the six months ended June 30 were as follows:

   
2008
    
2007
  
   
 
   
   
 
Asset retirement obligations at January 1,
   $ 189,711     $ —  
Liabilities added during the current period
     1,309,854       424,806  
Accretion expense
     33,316       10,832  
Asset retirement obligation at June 30,
   $ 1,532,881     $ 435,638  
 
8. Related Party Transactions

Pursuant to the Restructuring, in Appalachia, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas. We reimburse Vinland $60 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our lease operating expenses. Also, Vinland receives a $0.25 per Mcf transportation fee on existing wells drilled at December 31, 2006 and $0.55 per Mcf transportation fee on any new wells drilled after December 31, 2006 within the area of mutual interest or “AMI.” 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 $0.2 million for each of the three months ended June 30, 2008 and 2007 and $0.3 million for each of the six months ended June 30, 2008 and 2007. Costs incurred under the GCA were $0.2 million and $0.4 million for the three months ended June 30, 2008 and 2007 and $0.5 million and $0.7 million for the six months ended June 30, 2008 and 2007. A payable of $4.1 million and $3.8 million is reflected on our June 30, 2008 and December 31, 2007 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.

9. Common Units and Net Income per Unit

Basic earnings per unit is computed in accordance with SFAS No. 128,“Earnings Per Share” (“SFAS 128”) 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.  The Company uses the treasury stock method to determine the dilutive effect.  At June 30, 2008, the Company had two classes of units outstanding:  (i) units representing limited liability company interests (“common units”) listed on NYSE Arca under the symbol VNR and (ii) Class B units, issued to management and an employee as discussed in Note 10.Unit-Based Compensation. The Class B units participate in distributions and no forfeiture is expected; therefore, all Class B units were considered in the computation of basic earnings per unit. The 175,000 options and phantom units granted to officers under our long-term incentive plan had no dilutive effect; therefore, have been excluded from the computation of diluted earnings per unit.

In accordance with SFAS 128, dual presentation of basic and diluted earnings per unit has been presented in the consolidated statements of operations for the three months and six months ended June 30, 2008 and 2007 for 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. 

10. Unit-Based Compensation

In April 2007, the sole member at that time reserved 460,000 restricted Class B units in VNR for issuance to employees. Certain members of management were granted 365,000 restricted Class B units in VNR in April 2007, which vest 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 and February 2008, four board members were granted 5,000 common units each of which will vest 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.


 
15
 
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
Furthermore, on March 27, 2008, phantom units were granted to two officers in amounts equal to 1.0% of our units outstanding at January 1, 2008 and the amount paid will equal the appreciation in value of the units, if any, from the date of the grant until the determination date (December 31, 2008), plus cash distributions paid on the units, less an 8% hurdle rate. As of June 30, 2008, a liability and expense of $0.1 million has been recognized. 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 SFAS No. 123(R), Share-Based Payment.

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 June 30, 2008 is presented below:

 
Number of 
Non-vested Units
  
Weighted Average
Grant Date Fair Value
  
 
                                        
  
 
  
Non-vested units at December 31, 2007
425,000
  
$
18.14
  
Granted
15,000
    
16.79
  
Non-vested units at June 30, 2008
440,000
  
$
18.10
  

At June 30, 2008, there was approximately $4.1 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.3 years. Our consolidated statement of operations reflects non-cash compensation of $1.0 million and $0.6 million in the selling, general and administrative line item for the three months ended June 30, 2008 and 2007 and $1.9 million and $0.6 million for the six months ended June 30, 2008 and 2007.

11.  Subsequent Event

On July 18, 2008, we entered in to a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd., 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. 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 the purchase price, subject to customary post-closing adjustments to be determined. This acquisition was funded with borrowings under our reserve-based credit facility and through the issuance of 1,350,873 common units of the Company. The effects of this acquisition are not reflected in the cash flows and other financial and operating information described herein due to the acquisition closing on July 28, 2008. 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 for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008.

 
16
 

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/A 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/A and this Quarterly report on Form 10-Q/A, 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, with the closing of our recent acquisition.
 
We owned working interests in 1,383 gross (917 net) productive wells at June 30, 2008 and our average net production for the twelve months ended December 31, 2007 and for the three months and six months ended June 30, 2008 was 11,610 Mcfe per day, 15,888 Mcfe per day and 15,505 Mcfe per day, respectively. We also have an approximate 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.

Financial Statement Restatement
 
On November 10, 2008, in connection with preparing its quarterly report for third quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, management of the Company and the Audit Committee of its Board of Directors concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). The primary reasons for this determination were that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient. Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas in the first quarter of 2008 which made them ineffective.

 
17
 
 
The Company has restated its consolidated unaudited quarterly financial statements for March 31, 2008 and June 30, 2008 to reflect the inability to qualify for hedge accounting treatment.  The effect of the restatement is to recognize a non-cash mark to market unrealized loss on commodity derivatives of $20.2 million in the first quarter of 2008 and a non-cash mark to market unrealized loss on commodity derivatives of $52.2 million in the second quarter of 2008. The restatement does not impact the economics of the hedge transactions nor does it affect the Company’s cash flow, liquidity, total assets, total liabilities, or members’ equity in any historical or future period.  The restatement did not have any impact on any of the Company’s financial covenants under its reserve-based credit facility. Details of the restatement are indicated in Note 1 to the Consolidated Financial Statements.
 
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 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. 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.

South Texas Acquisition

On July 18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro Drilling, Ltd., 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. 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 the purchase price, subject to customary post-closing adjustments to be determined. This acquisition was funded with 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 Energy Group will operate all the properties and is contractually obligated to drill six wells in 2008 and seven wells in 2009 through 2011. Based on internal reserve estimates, we acquired 20 Bcfe of proved reserves, 98% of which is natural gas and 65% of which is proved developed producing. The effects of this acquisition are not reflected in the cash flows and other financial and operating information described herein due to the acquisition closing on July 28, 2008. 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 for the period beginning July 2008 through December 2011 which had a fair value of $3.6 million on July 28, 2008.

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.

 
18
 
 
Restructuring Plan
 
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.”
 
Private Offering
 
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.

Reserve-Based Credit Facility
 
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 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. Additional borrowings were made pursuant to the acquisition of natural gas and oil properties in the Permian Basin in January 2008 and indebtedness under the reserve-based credit facility totaled $102.5 million at June 30, 2008. At June 30, 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
%
 
In July 2008, an additional $31.0 million was borrowed under the reserve-based credit facility to fund a portion of the cash consideration paid in the South Texas acquisition. As a result, as of August 12, 2008, borrowings under the reserve-based credit facility increased to $131.5 million and the borrowing base is in the process of being redetermined to include the natural gas and oil properties from the South Texas acquisition.

 
19
 
 
Outlook
 
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 2012 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 June 30:

   
Three Months Ended
June 30,
    
Six Months Ended
June 30,
  
   
2008
    
2007
    
2008(a)
    
2007
  
Revenues:
  
Restated
          
Restated
        
Natural gas and oil sales
   $ 20,852,386     $ 10,106,737     $ 34,853,984     $ 19,068,353  
Realized losses on commodity cash flow hedges  
     —       (918,044 )     —       (1,665,852 )
Total revenues
     20,852,386     $ 9,188,693       34,853,984     $ 17,402,501  
Costs and expenses:
                                
Lease operating expenses
   $ 2,300,076     $ 1,314,041     $ 4,315,753     $ 2,460,420  
Depreciation, depletion, amortization and accretion
     3,330,024       2,291,426       6,154,002       4,320,289  
Selling, general and administrative expenses
     1,636,675       781,198       3,282,466       1,215,489  
Bad debt expense
     —       —       —       1,007,458  
Taxes other than income taxes
     1,428,965       380,110       2,395,078       890,992  
Total costs and expenses
   $ 8,695,740     $ 4,766,775     $ 16,147,299     $ 9,894,648  
Other Income and (Expense):
                                
Interest expense, net
   $ (1,240,056 )   $ (2,182,012 )   $ (2,362,102 )   $ (4,392,168 )
Realized loss on commodity derivative contracts
   $ (5,703,498 )   $ —     $ (6,849,114 )   $ —  
Unrealized loss on commodity derivative contracts
   $ (52,186,386 )   $ —     $ (72,396,143 )   $ —  
Realized loss on interest rate derivative contracts
   $ (46,450 )   $ —     $ (51,306 )   $ —  
Loss on extinguishment of debt
   $ —     $ —     $ —     $ (2,501,528 )
 
 
(a)
The Permian acquisition closed on January 31, 2008 and as such only five months of operations are included in the six month period ended June 30, 2008.
 
20
 
Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007
 
Revenues
 
Natural gas and oil sales increased $10.7 million to $20.8 million during the three months ended June 30, 2008 as compared to the same period in 2007. The key revenue measurements were as follows:
 
   
Three Months Ended
 June 30,
    
Percentage 
Increase
  
   
2008
    
2007
    
(Decrease)
  
Net Natural Gas Production:
              
Appalachian gas (MMcf) 
     903       1,032       (13 )%
Permian gas (MMcf) 
     109       —       N/A  
Total natural gas production (MMcf)
     1,012       1,032       (2 )%
                         
Average Appalachian daily gas production (Mcf/day)
     9,922       11,340       (13 )%
Average Permian daily gas production (Mcf/day)
     1,202       —       N/A  
Average Vanguard daily gas production (Mcf/day)
     11,124         11,340          
                         
Average Natural Gas Sales Price per Mcf:
                        
Net realized gas price, including realized gains (losses) on commodity derivative contracts
   $ 10.35 (a)   $ 9.12 (a)     13 %
Net realized gas price, excluding realized gains (losses) on commodity derivative contracts
   $ 13.14     $ 9.30       41 %
                         
Net Oil Production:
                        
Appalachian oil (Bbls) 
     10,430       8,513       22 %
Permian oil (Bbls) 
     61,817       —       N/A  
Total oil (Bbls)
     72,247       8,513       749 %
                         
Average Appalachian daily oil production (Bbls/day)
     115       94       22 %
Average Permian daily oil production (Bbls/day)
     679       —       N/A  
Average Vanguard daily oil production (Bbls/day)
     794       94          
                         
Average Oil Sales Price per Bbl:
                        
Net realized oil price, including realized gains (losses) on commodity derivative contracts
   $ 81.01     $ 60.46       34 %
Net realized oil price, excluding realized gains (losses) on commodity derivative contracts
   $ 104.44     $ 60.46       73 %
 
 
(a)
Excludes amortization of premiums paid and non-cash settlement 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 and increases in commodity prices. Production from the Permian Basin contributed $8.0 million of natural gas and oil sales for the three month period ended June 30, 2008. In Appalachia, a decline in natural gas production was partially offset by an increase in oil production for a net production decline of 11% on an Mcfe basis. However, the negative impact of the production decline was offset by a 41% increase in the average realized natural gas sales price received (excluding realized gains (losses) on commodity derivative contracts) and a 73% increase in the average realized oil price (excluding realized gains (losses) on commodity derivative contracts). 
 
21
 
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 $1.0 million to $2.3 million for the three months ended June 30, 2008 as compared to the three months ended June 30, 2007 of which $0.9 million related to the 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 taxes increased by $1.0 million for the three months ended June 30, 2008 as compared to the same period in 2007, of which $0.6 million, related to the Permian Basin acquisition.
 
Depreciation, depletion and amortization increased to approximately $3.3 million for the three months ended June 30, 2008 from approximately $2.3 million for the three months ended June 30, 2007 due primarily to the additional depletion recorded on oil and gas properties acquired in the 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 June 30, 2008 increased $0.8 million as compared to the three months ended June 30, 2007. For the three months ended June 30, 2008 and 2007 these expenses included a $1.0 million and $0.6 million, respectively, 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, the grant of common units to board members and the grant of phantom units to management during 2007 and 2008. All other selling, general and administrative expenses were $0.6 million for the three months ended June 30, 2008 representing a $0.4 million increase from the same period in 2007 principally due to costs associated with additional employees and being a public company.
 
Interest expense declined to $1.2 million for the three months ended June 30, 2008 compared to $2.2 million for the three months ended June 30, 2007 primarily due to a reduction in the weighted average outstanding borrowings and lower interest rates.

During the quarter ended June 30, 2008, the Company recognized a $5.7 million realized loss on commodity derivatives and a $52.2 million unrealized loss on commodity derivatives, respectively. These amounts relate to derivative contracts that the Company entered into in order to mitigate commodity price exposure on a portion of our expected production. On November 10, 2008, the Company concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with SFAS No. 133.  The realized loss on commodity derivatives relates to actual amounts received less premiums previously paid under these derivative contracts while the unrealized loss on commodity derivatives represents the change in the fair value of these derivative instruments.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007
 
Revenues
 
Natural gas and oil sales increased $15.8 million to $34.9 million during the six months ended June 30, 2008 as compared to the same period in 2007. The key revenue measurements were as follows:  
 
22
 
   
Six Months Ended 
June 30,
    
Percentage 
Increase
  
   
2008
    
2007
    
(Decrease)
  
Net Natural Gas Production:
              
Appalachian gas (MMcf) 
     1,770       2,100       (16 )%
Permian gas (MMcf) 
     151 (a)     —       N/A  
Total natural gas production (MMcf)
     1,921       2,100       (9 )%
                         
Average Appalachian daily gas production (Mcf/day)
     9,724       11,602       (16 )%
Average Permian daily gas production (Mcf/day)
     1,000 (a)     —       N/A  
Average Vanguard daily gas production (Mcf/day)
     10,724       11,602          
                         
Average Natural Gas Sales Price per Mcf:
                        
Net realized gas price, including realized gains (losses) on commodity derivative contracts
   $ 10.41 (b)   $ 8.39 (b)     24 %
Net realized gas price, excluding realized gains (losses) on commodity derivative contracts
   $ 11.62     $ 8.84       31 %
                         
Net Oil Production:
                        
Appalachian oil (Bbls) 
     21,421       8,513       151 %
Permian oil (Bbls) 
     102,539 (a)     —       N/A  
Total oil (Bbls)
     123,960       8,513       1,356 %
                         
Average Appalachian daily oil production (Bbls/day)
     118       47       151 %
Average Permian daily oil production (Bbls/day)
     679 (a)     —       N/A  
Average Vanguard daily oil production (Bbls/day)
     797       47          
                         
Average Oil Sales Price per Bbl:
                        
Net realized oil price, including realized gains (losses) on commodity derivative contracts
   $ 84.61     $ 60.46       40 %
Net realized oil price, excluding realized gains (losses) on commodity derivative contracts
   $ 101.06     $ 60.46       67 %

 
(a)
The Permian acquisition closed on January 31, 2008 and as such only five months of operations are included in the six month period ended June 30, 2008.
 
 
(b)
Excludes amortization of premiums paid and non-cash settlement 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 and an increase in commodity prices. Five months of production from the Permian Basin contributed $12.3 million of natural gas and oil sales for the six month period ended June 30, 2008. In Appalachia, a decline in natural gas production was partially offset by an increase in oil production for a net production decline of 12% on an Mcfe basis. However, the negative impact of the production decline was offset by a 31% increase in the average realized natural gas sales price received (excluding realized gains (losses) on commodity derivative contracts) and a 67% increase in the average realized oil price (excluding realized gains (losses) on commodity derivative contracts).
 
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 $1.8 million to $4.3 million for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 of which $1.5 million related to the 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 taxes increased by $1.5 million for the six months ended June 30, 2008 as compared to the same period in 2007, of which $0.9 million, related to the Permian Basin acquisition.
 
Depreciation, depletion and amortization increased to approximately $6.1 million for the six months ended June 30, 2008 from approximately $4.3 million for the six months ended June 30, 2007 due primarily to the additional depletion recorded on the oil and gas properties acquired in the Permian Basin acquisition.
 
23
 
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 six months ended June 30, 2008 increased $2.1 million as compared to the six months ended June 30, 2007. For the six months ended June 30, 2008 and 2007 these expenses included a $1.9 million and $0.6 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, the grant of common units to board members and the grant of phantom units to management during 2007 and 2008. All other selling, general and administrative expenses were $1.4 million for the six months ended June 30, 2008 representing a $0.8 million increase from the same period in 2007 principally due to costs associated with additional employees and being a public company.
 
Interest expense declined to $2.4 million for the six months ended June 30, 2008 compared to $4.4 million for the six months ended June 30, 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.

During the six months ended June 30, 2008, the Company recognized a $6.8 million realized loss on commodity derivatives and a $72.4 million unrealized loss on commodity derivatives, respectively. These amounts relate to derivative contracts that the Company entered into in order to mitigate commodity price exposure on a portion of our expected production. On November 10, 2008, the Company concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with SFAS No. 133.  The realized loss on commodity derivatives relates to actual amounts received less premiums previously paid under these derivative contracts while the unrealized loss on commodity derivatives represents the change in the fair value of these derivative instruments.

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 June 30, 2008, the Company’s critical accounting policies are consistent with those discussed in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2007 with the exception noted below in Financial Statement Restatement.      

Financial Statement Restatement

On November 10, 2008, in connection with preparing its quarterly report for third quarter 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, management of the Company and the Audit Committee of its Board of Directors concluded that the contemporaneous formal documentation it had prepared to support its initial hedge designations and subsequent assessments for ineffectiveness in connection with the Company’s natural gas and oil hedging program in 2008 did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). The primary reasons for this determination were that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient. Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas in the first quarter of 2008 which made them ineffective.
 
Under SFAS No. 133, the fair value of derivative contracts is recognized in the Consolidated Balance Sheet as an asset or liability, and the amounts received or paid under the contracts are reflected in earnings during the period in which the underlying production occurs.  If the derivative contracts qualify for hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income”, and changes in the fair value do not affect net income in the period.  If the derivative contract does not qualify for hedge accounting treatment, the change in the fair value of the contract is reflected in earnings during the period as unrealized gain or loss on commodity derivatives.  Under the cash flow hedge accounting treatment used by the Company previously, the fair values of the hedge contracts were recognized in the consolidated balance sheets with the resulting unrealized gain or loss recorded initially in accumulated other comprehensive income and later reclassified through earnings when the hedged production affected earnings.  As a result of the determination that the documentation failed to meet cash flow hedge accounting treatment, the unrealized gain or loss should have been recorded in the consolidated statements of operations as a component of earnings in 2008. In addition, the net derivative loss at December 31, 2007 related to the de-designated natural gas derivative contracts entered into in 2007 will continue to be reported in accumulated other comprehensive income until the month in which the transactions settle.
 
The Company has restated its consolidated unaudited quarterly financial statements for March 31, 2008 and June 30, 2008 to reflect the inability to qualify for hedge accounting treatment.   The effect of the restatement is to recognize a non-cash mark to market unrealized loss on commodity derivatives of $20.2 million in the first quarter of 2008 and a non-cash mark to market unrealized loss on commodity derivatives of $52.2 in the second quarter of 2008.  The restatement does not impact the economics of the hedge transactions nor does it affect the Company’s cash flow, liquidity, total assets, total liabilities, or members’ equity in any historical or future period.  The restatement did not have any impact on any of the Company’s financial covenants under its reserve-based credit facility.

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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 Measurements.

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. Because the Company did not elect to apply the provisions of SFAS 159 to any eligible financial instruments, the adoption did not affect the 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 June 30, 2008 balance sheet, SFAS 160 would have no impact on the consolidated financial statements.
 
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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.

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 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, accrued natural gas 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.
 
Liquidity and Capital Resources

Overview

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 August 12, 2008, we have $18.5 million available to be borrowed under our reserve-based credit facility. However, the borrowing base must be redetermined after giving effect to the natural gas and oil properties acquired in July 2008 in South Texas and the amount of availability is expected to increase as a result. 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 for the six months ended June 30, 2008 was $17.5 million, compared to cash used in operating activities of $2.8 million for the six months ended June 30, 2007. The increase in cash provided by operating activities during the six months ended June 30, 2008 was substantially due to increased income and a decrease in cash used in price risk management activities. The cash used in operating activities in the first six months of 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 $73.1 million for the six months ended June 30, 2008, compared to $6.6 million for the six months ended June 30, 2007. The increase in cash used in investing activities was primarily attributable to $66.4 million used for the acquisition of natural gas and oil properties in the Permian Basin. In addition, the total for the six months ended June 30, 2008 includes $6.7 million for the drilling and development of natural gas and oil properties as compared to $6.1 million for the six months ended June 30, 2007.
 
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Cash Flow from Financing Activities

Cash provided by financing activities was approximately $56.4 million for the six months ended June 30, 2008, compared to $12.2 million for the six months ended June 30, 2007. During the six months ended June 30, 2008, total proceeds from borrowings under our reserve-based credit facility were $74.4 million which were principally used to fund the Permian Basin acquisition. During the six months ended June 30, 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. Additionally, during the six months ended June 30, 2007, we completed a private equity offering for $41.2 million and used the net proceeds of this private equity offering to make a distribution to Majeed S. Nami, VNR’s largest unitholder.
 
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 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. As a result, as of June 30, 2008, we had $102.5 million outstanding under our reserve-based credit facility and as of August 12, 2008, we have $18.5 million available to be borrowed. However, the borrowing base must be redetermined after giving effect to the natural gas and oil properties acquired in July 2008 in South Texas and the amount of availability is expected to increase as a result. Borrowings under the reserve-based credit facility are available for 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 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;

 
·
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;

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·
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
 
 
·
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 June 30, 2008, the Company 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.

 
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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 June 30, 2008, there were no loss contingencies.
 
Commitments and Contractual Obligations
 
A summary of our contractual obligations as of June 30, 2008 is provided in the following table:

   
Payments Due by Year (in thousands)
  
   
2008
   
2009
   
2010
   
2011
   
2012
   
After 2012
   
Total
 
Management compensation
   $ 300     $ 600     $ 100     $ —     $ —     $ —     $ 1,000  
Asset retirement obligations
     —       —       —       166       8       1,359       1,533  
Derivative liabilities
     14,267       23,409       25,113       14,484       6,847       —       84,120  
Long-term debt (1)
     —       —       —       102,500       —       —       102,500  
Operating leases
     20       41       10       —       —       —       71  
Total
   $ 14,587     $ 24,050     $ 25,223     $ 117,150     $ 6,855     $ 1,359     $ 189,224  
 
 
(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);
 
 
•
Loss on extinguishment of debt;
 
 
•
Depreciation, depletion and amortization (including accretion of asset retirement obligations);
 
 
•
Bad debt expenses;
 
 
•
Amortization of premiums paid and non-cash settlement on derivative contracts;
 
 
•
Unrealized gains and losses on commodity and interest rate derivative contracts;
 
 
•
Unit-based compensation expense; and
 
 
•
Realized (gain) loss on cancelled derivatives.
 
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.
 
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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 June 30, 2008 as compared to the three months ended June 30, 2007, Adjusted EBITDA increased 49%, from $8.0 million to $11.9 million. For the six months ended June 30, 2008 as compared to the six months ended June 30, 2007, Adjusted EBITDA increased 50%, from $14.9 million to $22.4 million. The following table presents a reconciliation of consolidated net income to adjusted EBITDA:
 
   
Three Months Ended
June 30,
    
Six Months Ended
June 30,
  
   
2008
    
2007
    
2008
    
2007
  
Net income
   $ (47,019,744 )    $ 2,239,906     $ (62,951,980 )    $ 614,157  
Plus:
                                
Interest expense
     1,244,450       2,196,691       2,374,110       4,419,814  
Loss on extinguishment of debt
     —       —       —       2,501,528  
Depreciation, depletion, amortization and accretion  
     3,330,024       2,291,426       6,154,002       4,320,289  
Bad debt expense
     —       —       —       1,007,458  
Amortization of premiums paid and non-cash settlement on derivative contracts
     1,230,584       733,504       2,531,193       733,504  
Unrealized loss on commodity derivative contracts
     52,186,386       —       72,396,143       —  
Non-cash compensation expense
     981,002       563,143       1,896,347       563,143  
Realized loss on cancelled derivatives
     —       —       —       776,633  
Less:
                                
Interest income
     4,394       14,679       12,008       27,646  
Adjusted EBITDA 
   $ 11,948,308     $ 8,009,991     $ 22,387,807     $ 14,908,880  
 
 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 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.
 
Commodity Price Risk
 
Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Realized pricing is primarily driven by the Columbia Gas Appalachian Index (“TECO Index”) 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 determination date to an amount lower than the amount of debt currently outstanding.
 
We enter into derivative contracts with respect to a portion of our projected natural gas and oil production through various transactions that hedge the 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 have put options for which we pay the counterparty the fair value at the purchase date. At the settlement date 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 and the counterparty pays us if the market price is below the floor on a notional quantity. These hedging 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.
 
At June 30, 2008, the fair value of commodity derivative contracts that settle during the next twelve months was a liability of approximately $27.1 million, which we will owe our counterparties.
 
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The following table summarizes commodity derivative contracts in place applicable to periods subsequent to June 30, 2008.
 
   
July 1, -
September 30,
2008
    
October 1, -
December 31,
2008
    
Year 2009
    
Year 2010
    
Year 2011
    
Year 2012
  
Gas Positions:
                        
Fixed Price Swaps:
                        
Notional Volume (MMBtu)
     738,608       713,831       2,657,046       2,387,640       2,196,012       —  
Fixed Price ($/MMBtu)
   $ 9.00     $ 9.00     $ 8.85     $ 8.76     $ 7.15     $ -—  
Puts:
                                                
Notional Volume (MMBtu)
     314,391       246,920       840,139       —       —       —  
Floor Price ($/MMBtu)
   $ 7.50     $ 7.50     $ 7.50     $ —     $ —     $ —  
Collars:
                                                
Notional Volume (MMBtu)
     300,000       300,000       1,000,000       730,000       —       —  
Floor Price ($/MMBtu)
   $ 9.00     $ 9.00     $ 7.50     $ 8.00     $ —     $ —  
Ceiling Price ($/MMBtu)
   $ 9.00     $ 9.25     $ 9.00     $ 9.30     $ —     $ —  
Total:
                                                
Notional Volume (MMBtu)
     1,352,999       1,260,751       4,497,185       3,117,640       2,196,012       —  
                                                 
Oil Positions:
                                                
Fixed Price Swaps:
                                                
Notional Volume (Bbls)
     49,500       48,000       181,500       164,250       151,250       144,000  
Fixed Price ($/Bbl)
   $ 90.30     $ 90.30     $ 87.23     $ 85.65     $ 85.50     $ 80.00  

Interest Rate Risks

At June 30, 2008, we had debt outstanding of $102.5 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 $0.4 million increase in annual interest expense after consideration of the interest hedges discussed below. In December 2007 and during the first quarter of 2008, 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.

The following summarizes information concerning our positions in open interest rate swaps applicable to periods subsequent to June 30, 2008.

   
Principal
Balance
    
Fixed
Libor
Rates
  
Period:
        
July 1, 2008 to December 10, 2010
   $ 20,000,000       3.88 %
July 1, 2008 to January 31, 2011
   $ 30,000,000       3.00 %
July 1, 2008 to March 31, 2011
   $ 10,000,000       2.66 %
 
Item 4.  Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
 
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As part of the preparation of our financial statements for the quarters ended March 31, 2008 and June 30, 2008, we undertook a review of our accounting for natural gas and oil and interest rate derivatives. We use derivative instruments as a means of reducing financial exposure to fluctuating natural gas and oil prices and interest rates. We included changes from period to period in the fair value of derivatives classified as cash flow hedges (“Hedges”) as increases or decreases to Accumulated Other Comprehensive Income (“AOCI”) as allowed by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”). This Hedge accounting treatment is allowed for certain derivatives, including the types of derivatives used by us to reduce exposure to changes in natural gas and oil prices associated with the sale of natural gas and oil production and fluctuations in interest rates. In order to qualify for Hedge accounting treatment, specific standards and documentation requirements must be met. We believed that we met those requirements and that our derivative accounting treatment was permitted under FAS 133. However, in connection with preparing our quarterly report for third quarter of 2008 and discussion with BDO Seidman, LLP, the Company’s new independent registered public accounting firm, we determined that our commodity derivative instruments did not qualify for Hedge accounting treatment under FAS 133 in 2008. Specifically, we determined that the formal hedge documentation lacked specificity of the hedged cash flow and the quantitative subsequent assessments for ineffectiveness were insufficient.  Therefore, the cash flow designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment for commodity derivative contracts entered into during periods subsequent to December 31, 2007; and, that accounting for commodity derivative instruments entered into during periods subsequent to December 31, 2007 as cash flow Hedges was, therefore, inappropriate.  In addition, the natural gas derivative swap contracts entered into in 2007 were de-designated as cash flow hedges in the first quarter of 2008 due to an overhedged position in natural gas during that quarter which made them ineffective.  Accordingly, we are restating the consolidated financial statements for the three months ended June 30, 2008 as reflected in this Form 10-Q/A which reflects the appropriate changes.  Management has concluded, based on the circumstances involving the restatement of the aforementioned financial statements that since March 31, 2008, a material weakness in internal control over financial reporting has existed with respect to the design of the Company’s controls over the proper recording and disclosure of derivative instruments in accordance with FAS 133.

We carried out an evaluation in accordance with Exchange Act Rules 13a-15 under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, due to the aforementioned material weakness, our disclosure controls and procedures were not effective as of June 30, 2008.  The Company is evaluating the necessary changes in control procedures required to remediate this material weakness such that the Company’s internal controls over financial reporting will be effective at the reasonable assurance level at December 31, 2008.
 
Changes in Internal Control over Financial Reporting
 
On January 31, 2008, we completed the acquisition of certain oil and gas properties in the Permian Basin of West Texas and Southeastern New Mexico. Pursuant to this transaction, we have outsourced our production accounting for the Permian Basin properties to a third party and have begun operating our own wells. As a result, we are implementing new processes and modifying existing processes to ensure adequate internal controls 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/A 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/A for the year ended December 31, 2007 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/A for the year ended December 31, 2007 other than those set forth below. For further information, see Part I, Item 1A, Risk Factors in our Annual Report on Form 10-K/A for the year ended December 31, 2007.

32
 
Crude oil and natural gas prices are volatile.  A decline in crude oil and natural gas prices could adversely affect our financial position, financial results, cash flow, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for our crude oil and natural gas production and the prices prevailing from time to time for crude oil and natural gas.  Crude oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions.  This price volatility also affects the amount of our cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital.  The prices for crude oil and natural gas are subject to a variety of factors, including:

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

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

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

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

 
·
the ability of the members of the Organization of Petroleum Exporting Countries to agree to maintain 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 crude oil and natural gas prices would not only reduce our revenue, but could reduce the amount of crude oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves.  If the oil and gas industry experiences significant price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can affect the value of our units.

We may not have sufficient cash from operations to pay quarterly distributions on our common units following establishment of cash reserves and payment of operating costs.
 
We may not have sufficient cash flow from operations each quarter to pay distributions.  Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
 
·
the amount of natural gas and oil we produce;
 
 
·
the price at which we are able to sell our natural gas and oil production;
 
 
·
the level of our operating costs;
 
 
·
the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon; and
 
 
·
the level of our capital expenditures.
 
33
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
 
·
the level of our capital expenditures;
 
 
·
our ability to make working capital borrowings under our credit facility to pay distributions;
 
 
·
the cost of acquisitions, if any;
 
 
·
our debt service requirements;
 
 
·
fluctuations in our working capital needs;
 
 
·
timing and collectibility of receivables;
 
 
·
restrictions on distributions contained in our credit facility;
 
 
·
prevailing economic conditions; and
 
 
·
the amount of cash reserves established by our board of directors for the proper conduct of our business.
 
As a result of these factors, the amount of cash we distribute in any quarter to our unitholders may fluctuate significantly from quarter to quarter.

We may not be able to obtain funding, obtain funding on acceptable terms or obtain funding under our current credit facility because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

In addition, we may be unable to obtain adequate funding under our current credit facility because our lending counterparties may be unwilling or unable to meet their funding obligations.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to grow our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our revenues and results of operations.

Growing the Company will require significant amounts of debt and equity financing which may not be available to us on acceptable terms, or at all.

We plan to fund our growth through acquisitions with proceeds from sales of our debt and equity securities and borrowings under our reserve-based credit facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms or in the proportions that we expect, or at all, and we may be unable refinance our reserve-based credit facility when it expires.   In addition, we may be unable to obtain adequate funding under our current reserve-based credit facility because our lending counterparties may be unwilling or unable to meet their funding obligations.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.
 
34
 
The cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our reserve-based credit facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or not purse growth opportunities.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our hedging arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Additionally, many of our vendors’, customers’ and counterparties' equity values have substantially declined.  The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’, customers’ and counterparties' liquidity and ability to make payments or perform on their obligations to us.  Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our ability to make distributions to our unitholders.
 
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
 During the six months ended June 30, 2008, one of our wholly-owned subsidiaries purchased 20,300 of our common units on the open market at the then prevailing market price. 15,000 of these units were subsequently granted to three of our independent directors, with Loren Singletary, John R. McGoldrick and Bruce W. McCullough each receiving 5,000 units. The grants were made by our Board of Directors upon the appointment of these independent directors on February 28, 2008. The following table summarizes the unit purchases that occurred during the six months ended June 30, 2008:

 
Period
  
Number of
common
units
repurchased
    
Weighted
average price
paid per
common unit
  
January 1, 2008 to January 31, 2008
       5,000     $ 14.50  
February 1, 2008 to February 29, 2008
       10,000     $ 16.28  
March 1, 2008 to March 31, 2008
       300     $ 14.70  
April 1, 2008 to April 30, 2008
       —       N/A  
May 1, 2008 to May 31, 2008
       —       N/A  
June 1, 2008 to June 30, 2008
       5,000     $ 16.97  
Total common units purchased
       20,300     $ 15.99  
 
 Item 3.  Defaults Upon Senior Securities
 
None.
 
Item 4.  Submission of Matters to a Vote of Security Holders
 
The annual meeting of unitholders of Vanguard Natural Resources, LLC was held on June 10, 2008 in Houston, Texas. At the annual meeting, holders of 11,215,000 units were entitled to vote on the specified unitholder matters, of which 10,145,022 units were present and voting, or 90% of the outstanding units, which constituted a quorum.
 
35
 
Proposals submitted to a vote of the unitholders were:

(1) The election of seven directors of Vanguard Natural Resources, LLC for a one-year term expiring at the 2009 annual meeting of unitholders and until their respective successors are elected and qualified.
 
   
Number of Voting Units
  
Director’s Name
  
For
    
Withheld
  
Scott W. Smith
     10,143,118       1,904  
W. Richard Anderson
     10,143,118       1,904  
Loren Singletary
     10,143,118       1,904  
Bruce W. McCullough
     10,143,118       1,904  
John R. McGoldrick
     10,143,118       1,904  
Lasse Wagene
     10,143,118       1,904  
Thomas Blake
     10,143,118       1,904  
 
(2) The ratification of UHY LLP as our independent registered public accountants for the fiscal year ended December 31, 2008.

For
  
Against
  
Abstained
  
10,142,822
    
1,700
    
500
  
 
Item 5.  Other Information
 
Indemnification Agreements

On August 7, 2008 Vanguard Natural Resources, LLC entered into Indemnification Agreements (each, an “Indemnification Agreement”) with each independent director of Vanguard Natural Resources, LLC (each, an “Indemnitee”). Each Indemnification Agreement provides that Vanguard Natural Resources, LLC will indemnify and hold harmless each Indemnitee against Expenses (as defined in the Indemnification Agreement) to the fullest extent permitted or authorized by law, including the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee.

The foregoing description of the Indemnification Agreements is qualified in its entirety by reference to the full text of the Form of Indemnification Agreement, which was previously filed with our Quarterly report on Form 10-Q on August 13, 2008 and incorporated herein by reference.
 
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
  
Amended and Restated Credit Agreement, dated February 14, 2008, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer and the lenders party thereto
  
Previously filed with our Form 10-K on March 31, 2008
10.2
  
Vanguard Natural Resources, LLC Long-Term Incentive Plan
  
Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.3
  
Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant Agreement
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
 
36
 
10.4
  
Vanguard Natural Resources, LLC Class B Unit Plan
  
Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.5
  
Form of Vanguard Natural Resources, LLC Class B Unit Plan Restricted Class B Unit Grant
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.6
  
Management Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.7
  
Participation Agreement, effective January 5, 2007, by and between Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.8
  
Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.9
  
Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy Company
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.10
  
Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC and Nami Resources Company, L.L.C.
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.11
  
Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.12
  
Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.13
  
Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC and Nami Resources Company, L.L.C.
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.14
  
Amended and Restated Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC, dated October 2, 2007 and effective as of January 5, 2007
  
Form S-1/A, filed October 22, 2007 (File No. 333-142363)
10.15
  
Operating Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.16
  
Amended and Restated Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard Natural Gas, LLC and Vanguard Natural Resources, LLC, dated September 11, 2007
  
Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.17
  
Revenue Payment Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company, dated April 18, 2007 and effective as of January 5, 2007
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.18
  
Gas Supply Agreement, dated April 18, 2007, by and between Nami Resources Company, L.L.C. and Trust Energy Company
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.19
  
Amended Employment Agreement, dated April 18, 2007, by and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural Resources, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.20
  
Amended Employment Agreement, dated April 18, 2007, by and between Richard A. Robert, VNR Holdings, LLC and Vanguard Natural Resources, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.21
  
Registration Rights Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC and the private investors named therein
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.22
  
Purchase Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC, Majeed S. Nami and the private investors named therein
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.23
  
Omnibus Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and Trust Energy Company, LLC.
  
Form 8-K, filed November 2, 2007 (File No. 001-33756)
10.24
  
Employment Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings, LLC and Vanguard Natural Resources, LLC
  
Form S-1/A, filed July 5, 2007 (File No. 333-142363)
10.25
  
Natural Gas Contract, dated May 26, 2003, between Nami Resources Company, Inc. and Osram Sylvania Products, Inc.
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.26
  
Natural Gas Purchase Contract, dated December 16, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.27
  
Natural Gas Purchase Contract, dated December 28, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.28
  
Director Compensation Agreement
  
Form S-1/A, filed September 18, 2007 (File No. 333-142363)
 
37
 
10.29
  
Purchase and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC and Apache Corporation
  
Form 8-K/A, filed February 13, 2008 (File No. 001-33756)
10.30
  
Amended Purchase and Sale Agreement, dated January 31, 2008, among Vanguard Permian, LLC and Apache Corporation
  
Form 8-K/A, filed February 4, 2008 (File No. 001-33756)
10.31
  
Purchase and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and Segundo Navarro Drilling, Ltd.
  
Form 8-K, filed July 21, 2008 (File No. 001-33756)
10.32
  
Form of Indemnity Agreement dated August 7, 2008
  
Previously filed with our Quarterly report on Form 10-Q on August 13, 2008
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
 
38

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: December 19, 2008
    
   
/s/ Richard A. Robert
   
Richard A. Robert
   
Executive Vice President and
   
Chief Financial Officer
   
(Principal Financial Officer and Principal Accounting Officer)
 
39
 
Vanguard Natural Resources, LLC
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
  
Amended and Restated Credit Agreement, dated February 14, 2008, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer and the lenders party thereto
  
Previously filed with our Form 10-K on March 31, 2008
10.2
  
Vanguard Natural Resources, LLC Long-Term Incentive Plan
  
Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.3
  
Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant Agreement
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.4
  
Vanguard Natural Resources, LLC Class B Unit Plan
  
Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.5
  
Form of Vanguard Natural Resources, LLC Class B Unit Plan Restricted Class B Unit Grant
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.6
  
Management Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.7
  
Participation Agreement, effective January 5, 2007, by and between Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.8
  
Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.9
  
Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy Company
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.10
  
Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC and Nami Resources Company, L.L.C.
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.11
  
Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.12
  
Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.13
  
Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC and Nami Resources Company, L.L.C.
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.14
  
Amended and Restated Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC, dated October 2, 2007 and effective as of January 5, 2007
  
Form S-1/A, filed October 22, 2007 (File No. 333-142363)
10.15
  
Operating Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.16
  
Amended and Restated Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard Natural Gas, LLC and Vanguard Natural Resources, LLC, dated September 11, 2007
  
Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.17
  
Revenue Payment Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company, dated April 18, 2007 and effective as of January 5, 2007
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.18
  
Gas Supply Agreement, dated April 18, 2007, by and between Nami Resources Company, L.L.C. and Trust Energy Company
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.19
  
Amended Employment Agreement, dated April 18, 2007, by and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural Resources, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.20
  
Amended Employment Agreement, dated April 18, 2007, by and between Richard A. Robert, VNR Holdings, LLC and Vanguard Natural Resources, LLC
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
 
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10.21
  
Registration Rights Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC and the private investors named therein
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.22
  
Purchase Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC, Majeed S. Nami and the private investors named therein
  
Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.23
  
Omnibus Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and Trust Energy Company, LLC.
  
Form 8-K, filed November 2, 2007 (File No. 001-33756)
10.24
  
Employment Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings, LLC and Vanguard Natural Resources, LLC
  
Form S-1/A, filed July 5, 2007 (File No. 333-142363)
10.25
  
Natural Gas Contract, dated May 26, 2003, between Nami Resources Company, Inc. and Osram Sylvania Products, Inc.
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.26
  
Natural Gas Purchase Contract, dated December 16, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.27
  
Natural Gas Purchase Contract, dated December 28, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.
  
Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.28
  
Director Compensation Agreement
  
Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.29
  
Purchase and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC and Apache Corporation
  
Form 8-K/A, filed February 13, 2008 (File No. 001-33756)
10.30
  
Amended Purchase and Sale Agreement, dated January 31, 2008, among Vanguard Permian, LLC and Apache Corporation
  
Form 8-K/A, filed February 4, 2008 (File No. 001-33756)
10.31
  
Purchase and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and Segundo Navarro Drilling, Ltd.
  
Form 8-K, filed July 21, 2008 (File No. 001-33756)
10.32
  
Form of Indemnity Agreement dated August 7, 2008
  
Previously filed with our Quarterly report on Form 10-Q on August 13, 2008
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
 
41