**UNITED
      STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington, D.C.
      20549**




**Form 10-Q**




**(Mark One)****x**
            
            **QUARTERLY
                REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
                ACT OF
                1934****For
                the quarterly period ended September 30, 2008****OR****o**
            
            **TRANSITION
                REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
                ACT OF
                1934****For
                the transition period
                from          to****Commission
                File Number: 001-33756**




**Vanguard
      Natural Resources, LLC**


*(Exact
      Name of Registrant as Specified in Its Charter)*




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




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




**Telephone
      Number: (832) 327-2255**




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 filero
            Accelerated
                fileroNon-accelerated
                filerx
            Smaller
                reporting companyo(Do
                not check if a smaller reporting company)




Indicate
      by check mark whether the registrant is a shell company (as defined in
      Rule 12b-2 of the Exchange Act).  Yes o No x




Common
      units outstanding on November 10, 2008:    12,145,873.







**VANGUARD
      NATURAL RESOURCES, LLC**


**TABLE
      OF CONTENTS**





**Page****GLOSSARY
                OF TERMS****PART
                I - FINANCIAL INFORMATION**Item
                1.
            Unaudited
                Financial StatementsConsolidated
                Statements of Operations
            3Consolidated
                Balance Sheets
            4Consolidated
                Statements of Cash Flows
            5Consolidated
                Statements of Comprehensive Income (Loss)
            6Notes
                to Consolidated Financial Statements
            7Item
                2.
            Management’s
                Discussion and Analysis of Financial Condition and Results of
                Operations
            18Item
                3.
            Quantitative
                and Qualitative Disclosures about Market Risk
            32Item
                4.
            Controls
                and Procedures
            35**PART
                II – OTHER INFORMATION**Item
                1.
            Legal
                Proceedings
            37Item
                1A.
            Risk
                Factors
            37Item
                2.
            Unregistered
                Sales of Equity Securities and Use of Proceeds
            39Item
                3.
            Default
                in Senior Securities
            39Item
                4.
            Submission
                of Matters to a Vote of Securities Holders
            39Item
                5.
            Other
                Information
            40Item
                6.
            Exhibits
            40







**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 feetBbls
            
            =
                barrels
            
            Mcfe
            
            =
                thousand cubic feet of natural gas equivalentsBcfe
            
            =
                billion cubic feet of natural gas equivalents
            
            MMBtu
            
            =
                million British thermal unitsBtu
            
            =
                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**
                **September 30,**
              
              **Nine Months
                  Ended**
                **September 30,****2008**
              
              **2007**
              
              **2008**
              
              **2007****Revenues:**Natural
                  gas and oil sales
              
              $
              20,838,797
              
              $
              7,641,064
              
              $
              55,692,781
              
              $
              26,709,417Realized
                  gain (loss) on commodity cash flow hedges
              
              
              —
              
              
              940,566
              
              
              —
              
              
              (725,286
              )**Total
                  revenues**
              
              
              20,838,797
              
              
              8,581,630
              
              
              55,692,781
              
              
              25,984,131**Costs
                  and expenses:**Lease
                  operating expenses
              
              
              3,483,968
              
              
              1,347,565
              
              
              7,799,721
              
              
              3,807,985Depreciation,
                  depletion, amortization and accretion
              
              
              4,187,241
              
              
              2,267,050
              
              
              10,341,243
              
              
              6,587,339Selling,
                  general and administrative expenses
              
              
              1,561,031
              
              
              1,084,995
              
              
              4,843,497
              
              
              2,300,484Bad
                  debt expense
              
              
              —
              
              
              —
              
              
              —
              
              
              1,007,458Taxes
                  other than income taxes
              
              
              1,263,223
              
              
              326,175
              
              
              3,658,301
              
              
              1,217,167**Total
                  costs and expenses**
              
              
              10,495,463
              
              
              5,025,785
              
              
              26,642,762
              
              
              14,920,433**Income
                  from operations**
              
              
              10,343,334
              
              
              3,555,845
              
              
              29,050,019
              
              
              11,063,698**Other
                  income and (expense):**Interest
                  income
              
              
              4,265
              
              
              19,793
              
              
              16,272
              
              
              47,439Interest
                  expense
              
              
              (1,488,745
              )
              
              (2,524,427
              )
              
              (3,862,855
              )
              
              (6,944,241
              )Realized
                  gain (loss) on commodity derivative contracts
              
              
              (2,943,833
              )
              
              —
              
              
              (9,792,946
              )
              
              —Unrealized
                  gain (loss) on commodity derivative contracts
              
              
              66,353,176
              
              
              —
              
              
              (6,042,967
              )
              
              —Realized
                  loss on interest rate derivative contracts
              
              
              (39,058
              )
              
              —
              
              
              (90,364
              )
              
              —Unrealized
                  loss on interest rate derivative contracts
              
              
              (419,769
              )
              
              —
              
              
              (419,769
              )
              
              —Loss
                  on extinguishment of debt
              
              
              —
              
              
              —
              
              
              —
              
              
              (2,501,528
              )**Total
                  other expense, net**
              
              
              61,466,036
              
              
              (2,504,634
              )
              
              (20,192,629
              )
              
              (9,398,330
              )**Net
                  income**
              
              $
              71,809,370
              
              $
              1,051,211
              
              $
              8,857,390
              
              $
              1,665,368**Net
                  income per unit:**Common
                  & Class B units – basic
              
              $
              5.90
              
              $
              0.18
              
              $
              0.77
              
              $
              0.29Common
                  & Class B units – diluted
              
              $
              5.90
              
              $
              0.18
              
              $
              0.77
              
              $
              0.29**Weighted
                  average units outstanding:**Common
                  units – basic & diluted
              
              
              11,749,421
              
              
              5,540,000
              
              
              11,115,463
              
              
              5,540,000Class
                  B units – basic & diluted
              
              
              420,000
              
              
              393,098
              
              
              420,000
              
              
              231,410




*See
      accompanying notes to consolidated financial statements*


3





VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED
      BALANCE SHEETS





**September 30,**
              **2008**
            
            **December 31,**
              **2007****(Unaudited)****Assets****Current
                assets**Cash
                and cash equivalents
            
            $
            340,850
            
            $
            3,109,563Trade
                accounts receivable, net
            
            
            11,103,113
            
            
            4,372,731Derivative
                assets
            
            
            3,723,104
            
            
            4,017,085Other
                current assets
            
            
            940,824
            
            
            453,198**Total
                current assets**
            
            
            16,107,891
            
            
            11,952,577**Property
                and equipment, net of accumulated depreciation**
            
            
            195,682
            
            
            166,455Natural
                gas and oil properties, at cost
            
            
            278,974,900
            
            
            135,435,240Accumulated
                depletion
            
            
            (38,746,260
            )
            
            (28,451,891
            )**Natural
                gas and oil properties, net – full cost
                method**
            
            
            240,228,640
            
            
            106,983,349**Other
                assets**Derivative
                assets
            
            
            486,311
            
            
            1,329,511Deferred
                financing costs
            
            
            897,521
            
            
            941,833Non-current
                deposits
            
            
            45,963
            
            
            8,285,883Other
                assets
            
            
            1,909,537
            
            
            1,519,577**Total
                assets**
            
            $
            259,871,545
            
            $
            131,179,185**Liabilities
                and members’ equity****Current
                liabilities**Accounts
                payable – trade
            
            $
            184,726
            
            $
            1,056,627Accounts
                payable – natural gas and oil
            
            
            1,801,613
            
            
            257,073Payables
                to affiliates
            
            
            5,066,485
            
            
            3,838,328Accrued
                expenses
            
            
            2,503,386
            
            
            203,159**Total
                current liabilities**
            
            
            9,556,210
            
            
            5,355,187Long-term
                debt
            
            
            134,500,000
            
            
            37,400,000Derivative
                liabilities
            
            
            10,108,110
            
            
            5,903,384Asset
                retirement obligations
            
            
            2,404,429
            
            
            189,711**Total
                liabilities**
            
            
            156,568,749
            
            
            48,848,282**Commitments
                and contingencies****Members’
                equity**Members’
                capital, 12,145,873 common units issued and outstanding at September
                30,
                2008 and 10,795,000 December 31, 2007
            
            
            107,163,017
            
            
            90,257,856Class
                B units, 420,000 issued and outstanding at September 30, 2008 and
                December
                31, 2007
            
            
            4,016,122
            
            
            2,131,995Accumulated
                other comprehensive loss
            
            
            (7,876,343
            )
            
            (10,058,948
            )**Total
                members’ equity**
            
            
            103,302,796
            
            
            82,330,903**Total
                liabilities and members’ equity**
            
            $
            259,871,545
            
            $
            131,179,185





*See
      accompanying notes to consolidated financial statements*


4





VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED
      STATEMENTS OF CASH FLOWS


(Unaudited)




**Nine Months Ended**
              **September
                30,****2008**
            
            **2007****Operating
                activities**Net
                income
            
            $
            8,857,390
            
            $
            1,665,368Adjustments
                to reconcile net income to net cash provided by operating
                activities:Depreciation,
                depletion, amortization and accretion
            
            
            10,341,243
            
            
            6,587,339Amortization
                of deferred financing costs
            
            
            263,691
            
            
            217,739Bad
                debt expense
            
            
            —
            
            
            1,007,458Unit-based
                compensation
            
            
            2,708,381
            
            
            1,314,778Amortization
                of premiums paid and non-cash settlements on derivative
                contracts
            
            
            3,981,775
            
            
            —Unrealized
                losses on commodity and interest rate derivative contracts
            
            
            6,462,736
            
            
            —Changes
                in operating assets and liabilities:Trade
                accounts receivable
            
            
            (6,730,382
            )
            
            (811,658
            )Payables
                to affiliates
            
            
            661,767
            
            
            (1,303,192
            )Other
                current assets
            
            
            (434,416
            )
            
            (187,373
            )Price
                risk management activities, net
            
            
            (452,426
            )
            
            (5,928,677
            )Accounts
                payable
            
            
            672,639
            
            
            1,561,210Accrued
                expenses
            
            
            2,300,227
            
            
            (1,482,634
            )**Net
                cash provided by operating activities**
            
            
            28,632,625
            
            
            2,640,358**Investing
                activities**Additions
                to property and equipment
            
            
            (69,603
            )
            
            (45,760
            )Additions
                to natural gas and oil properties
            
            
            (13,359,807
            )
            
            (9,426,483
            )Acquisitions
                of natural gas and oil properties
            
            
            (99,814,585
            )
            
            —Deposits
                and prepayments of natural gas and oil properties
            
            
            (901,481
            )
            
            (1,225,273
            )**Net
                cash used in investing activities**
            
            
            (114,145,476
            )
            
            (10,697,516
            )**Financing
                activities**Proceeds
                from borrowings
            
            
            112,900,000
            
            
            114,600,000Repayment
                of debt
            
            
            (15,800,000
            )
            
            (101,867,500
            )Contributions
                from members
            
            
            —
            
            
            41,221,000Distributions
                to members
            
            
            (13,846,053
            )
            
            (41,220,000
            )Financing
                costs
            
            
            (219,379
            )
            
            (1,202,966
            )Offering
                costs
            
            
            (54,191
            )
            
            (2,021,898
            )Purchase
                of units for issuance as unit-based compensation
            
            
            (236,239
            )
            
            —**Net
                cash provided by financing activities**
            
            
            82,744,138
            
            
            9,508,636**Net
                (decrease) increase in cash and cash equivalents**
            
            
            (2,768,713
            )
            
            1,451,478**Cash
                and cash equivalents,**beginning of period
            
            
            3,109,563
            
            
            1,730,956**Cash
                and cash equivalents,**end of period
            
            $
            340,850
            
            $
            3,182,434**Supplemental
                cash flow information:**Cash
                paid for interest
            
            $
            3,341,880
            
            $
            7,055,565**Non-cash
                financing and investing activities:**Asset
                retirement obligations
            
            $
            2,155,010
            
            $
            157,514Assumption
                of natural gas and oil swaps
            
            $
            2,467,573
            
            $
            —Deferred
                swap liability
            
            $
            —
            
            $
            7,322,685Initial
                contribution of assets
            
            $
            —
            
            $
            3,289,055Issuance
                of common units for acquisition of natural gas and oil
                properties
            
            $
            21,360,000
            
            $
            —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**
                **September 30,**
              
              **Nine Months Ended**
                **September 30,****2008**
              
              **2007**
              
              **2008**
              
              **2007****Net
                  income**
              
              $
              71,809,370
              
              $
              1,051,211
              
              $
              8,857,390
              
              $
              1,665,368Net
                  gains (losses) from derivative contracts:Unrealized
                  mark-to-market gains (losses) arising during the period
              
              
              —
              
              
              4,584,832
              
              
              (2,747,150
              )
              
              (6,381,176
              )Reclassification
                  adjustments for settlements
              
              
              (6,766
              )
              
              (944,481
              )
              
              564,545
              
              
              (436,738
              )Other
                  comprehensive income (loss)
              
              
              (6,766
              )
              
              3,640,351
              
              
              (2,182,605
              )
              
              (6,817,914
              )**Comprehensive
                  income (loss)**
              
              $
              71,802,604
              
              $
              4,691,562
              
              $
              6,674,785
              
              $
              (5,152,546
              )




*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, in the Permian Basin, primarily
      in
      west Texas and southeastern New Mexico, and in South Texas.




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 in Appalachia 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 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
      September 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 September 30, 2008 and December 31,
      2007
      and for the three months and nine months ended September 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.


7


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**




(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 which made them ineffective.




Under
      SFAS No. 133, the fair value of hedge contracts is recognized in the
      Consolidated Balance Sheets as an asset or liability, and the amounts received
      or paid under the hedge contracts are reflected in earnings during the period
      in
      which the underlying production occurs. If the hedge 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 hedge contract does not qualify for
      hedge accounting treatment, the change in the fair value of the hedge 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 will restate its consolidated unaudited quarterly financial statements
      for March 31, 2008 and June 30, 2008 and expects to file amended Quarterly
      Reports on Form 10-Q/A as soon as practicable. The effect of the restatement
      has
      been reflected in the operating results for the nine months ended September
      30,
      2008 and 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.




(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.


8


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**





(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 September 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.





(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 into a Purchase and Sale Agreement with the Apache
      Corporation for the purchase of certain oil and natural gas properties located
      in ten separate fields in the Permian Basin of west Texas and southeastern
      New
      Mexico. 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 ended
      and nine months ended September 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.


9


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**





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





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 an adjusted purchase price of $51.4 million,
      subject to customary post-closing adjustments to be determined. This acquisition
      was funded with $30.0 million of borrowings under our reserve-based credit
      facility and through the issuance of 1,350,873 common units of the Company
      valued at $21.4 million. Upon closing this transaction, we assumed natural
      gas
      swaps and collars based on Houston Ship Channel pricing for approximately 85%
      of
      the estimated gas production from existing producing wells for the period
      beginning July 2008 through December 2011 which had a fair value of $3.6 million
      on July 28, 2008. At this time, we do not have the information available to
      provide pro-forma results of operations for the three months ended and nine
      months ended September 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 Segundo Navarro Drilling,
      Ltd. for the year ended December 31, 2007.





**December 31, 2007**(In thousands)Revenues
            
            $
            8,730Direct
                operating expenses
            
            
            (2,782
            )Excess
                of revenues over direct operating expenses
            
            $
            5,948








**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 nine months ended September 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**
            
            **September 30,**
              **2008**
            
            **December**********31,**
              **2007**$400
                million senior secured revolver facility
            
            
            Variable
            
            
            March 31, 2011
            
            
            134,500,000
            
            
            37,400,000Total
            
            
            
            
            
            
            
            $
            134,500,000
            
            $
            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
      in January 2008 pursuant to the acquisition of natural gas and oil properties
      in
      the Permian Basin and in July 2008 an additional $30.0 million was borrowed
      to
      fund a portion of the cash consideration paid in the South Texas acquisition.
      As
      a result, indebtedness under the reserve-based credit facility totaled $134.5
      million at September 30, 2008 and our borrowing base at September 30, 2008
      was
      $150.0 million. In October 2008, our reserved-based credit facility was amended
      and restated. See Note 11. *Subsequent
      Event* for
      further discussion.





Interest
      rates under the reserve-based credit facility are based on Eurodollar (LIBOR)
      or
      ABR (Prime) indications, plus a margin. Prior to the amendment of the
      reserve-based credit facility in October 2008, as discussed in Note 11. *Subsequent
      Event* ,
      at
      September 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 September 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”), Henry Hub or Houston Ship Channel
      for natural gas production and the West Texas Intermediate Light Sweet for
      oil
      production. Under put option agreements, we pay the counterparty 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 or Houston Ship Channel.


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 nine months ended
      September 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. In July 2008, in connection with the South Texas acquisition,
      we
      assumed natural gas swaps and collars based on Houston Ship Channel pricing
      for
      approximately 85% of the estimated gas production from existing producing wells
      for the period beginning July 2008 through December 2011.





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. As a result, the Company now recognizes changes in its derivatives
      fair value in current earnings under unrealized gains (losses) on commodity
      derivative contracts.




At
      September 30, 2008, the Company had open commodity derivative contracts covering
      our anticipated future production as follows:




**Swap
      Agreements**




**Gas**
            
            **Oil****Contract
                Period**
            
            **MMBtu**
            
            **Weighted**
              **Average**
              **Fixed Price**
            
            **Bbls**
            
            **WTI**
              **Price**2008
            
            
            713,831
            
            $
            9.00
            
            
            48,000
            
            $
            90.302009
            
            
            3,623,946
            
            $
            9.42
            
            
            181,500
            
            $
            87.232010
            
            
            3,236,040
            
            $
            9.10
            
            
            164,250
            
            $
            85.652011
            
            
            2,962,312
            
            $
            7.82
            
            
            151,250
            
            $
            85.502012
            
            
            —
            
            $
            —
            
            
            144,000
            
            $
            80.00


12


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**




**Put
      Option Contracts**





**Contract
                Period**
            
            **Volume in MMBtu**
            
            **Purchased NYMEX**
              **Price Floor**2008
            
            
            246,920
            
            $
            7.502009
            
            
            840,139
            
            $
            7.50





**Collars**




****
            
            **Gas**
            
            **Oil******
            
            **MMBtu**
            
            **Floor**
            
            **Ceiling**
            
            **Bbls**
            
            **Floor**
            
            **Ceiling**Production Period:October
                2008 – December 2008
            
            
            566,800
            
            $
            10.13
            
            $
            10.94
            
            
            9,200
            
            $
            100.00
            
            $
            127.00January
                2009 – December 2009
            
            
            1,000,000
            
            $
            7.50
            
            $
            9.00
            
            
            36,500
            
            $
            100.00
            
            $
            127.00January
                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. In August 2008, we entered into two interest rate basis swaps which
      changed the reset option from three month LIBOR to one month LIBOR on the total
      $60.0 million of outstanding interest rate swaps. By doing so, the company
      reduced its borrowing cost by 14 basis points below the 3.88% reflected below
      on
      $20.0 million of borrowings for a one year period starting September 10, 2008
      and 12 basis points on the 3.00% and 2.66% reflected below on $40.0 million
      of
      borrowings for a one year period starting October 31, 2008. As a result of
      these
      two basis swaps, the company chose to de-designate the interest rate swaps
      as
      cash flow hedges as the terms of the new contracts no longer matched the terms
      of the original contracts, thus causing the interest rate hedges to be
      ineffective. Beginning in the third quarter of 2008, the Company will record
      changes in the fair value of its interest rate derivatives in current earnings
      under unrealized gains (losses) on interest rate derivative contracts. The
      net
      unrealized gain at June 30, 2008 related to the de-designated cash flow hedges
      will continue to be reported in accumulated other comprehensive income and
      later
      reclassified to earnings in the month in which the transactions settle.





At
      September 30, 2008, the Company had open interest rate derivative contracts
      as
      follows:





**Notional**
            
            **Fixed**
              **Libor****Amount**
            
            **Rates**Period:October
                1, 2008 to December 10, 2010
            
            $
            20,000,000
            
            
            3.88
            %October
                1, 2008 to January 31, 2011
            
            $
            30,000,000
            
            
            3.00
            %October
                1, 2008 to March 31, 2011
            
            $
            10,000,000
            
            
            2.66
            %October
                10, 2008 to September 10, 2009 (Basis Swap)
            
            $
            20,000,000
            
            
            LIBOR
                1M vs. LIBOR 3MOctober
                31, 2008 to October 31, 2009 (Basis Swap)
            
            $
            40,000,000
            
            
            LIBOR 1M vs. LIBOR 3M





**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.


13


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**




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.




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 1 assets
                include
                short-term investments (such as Money Market Funds and Treasury
                Bills).Level 
                2
            
            Quoted
                market prices for similar instruments in active markets; quoted prices
                for
                identical or similar instruments in markets that are not active;
                and
                model-derived valuations in which all significant inputs and significant
                value drivers are observable in active markets.Level 3
            
            Valuations
                derived from valuation techniques in which one or more significant
                inputs
                or significant value drivers are unobservable. Level 3 assets and
                liabilities generally include financial instruments whose value is
                determined using pricing models, discounted cash flow methodologies,
                or
                similar techniques, as well as instruments for which the determination
                of
                fair value requires significant management judgment or estimation
                or for
                which there is a lack of transparency as to the inputs
                used.





As
      required by 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 utilizes the modified Black-Scholes option pricing
      model to estimate the fair value of natural gas and oil derivative contracts.
      Inputs to this model include observable inputs from the New York Mercantile
      Exchange (NYMEX) for commodity futures contracts, and inputs derived from
      NYMEX observable inputs, such as implied volatility of natural gas and prices.
      For interest rate derivative contracts, we infer forward rates from the LIBOR
      based yield curve. The Company has classified the fair values of all its
      derivative contracts as Level 2.


14


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**




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





**September 30, 2008****Fair Value Measurements Using**
            
            **Assets/Liabilities****Level 1**
            
            **Level 2**
            
            **Level 3**
            
            **at Fair value****Assets:**Commodity
                price derivative contracts
            
            $
            —
            
            $
            3,735,994
            
            $
            —
            
            $
            3,735,994Interest
                rate derivative contracts
            
            
            —
            
            
            473,421
            
            
            —
            
            
            473,421Total
                derivative instruments
            
            $
            —
            
            $
            4,209,415
            
            $
            —
            
            $
            4,209,415**Liabilities:**Commodity
                price derivative contracts
            
            $
            —
            
            $
            (9,978,747
            )
            $
            —
            
            $
            (9,978,747
            )Interest
                rate derivative contracts
            
            
            —
            
            
            (129,363
            )
            
            —
            
            
            (129,363
            )Total
                derivative instruments
            
            $
            —
            
            $
            (10,108,110
            )
            $
            —
            
            $
            (10,108,110
            )





**7.**
            **Asset
                Retirement Obligations**





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





**2008**
            
            **2007**Asset
                retirement obligations at January 1,
            
            $
            189,711
            
            $
            —Liabilities
                added during the current period
            
            
            2,155,010
            
            
            157,514Accretion
                expense
            
            
            59,708
            
            
            9,094Asset
                retirement obligation at September 30,
            
            $
            2,404,429
            
            $
            166,608





**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
      $0.1 million for each of the three months ended September 30, 2008 and 2007
      and
      $0.4 million for each of the nine months ended September 30, 2008 and 2007.
      Costs incurred under the GCA were $0.2 million for each of the three months
      ended September 30, 2008 and 2007 and $0.8 million and $0.9 million,
      respectively, for the nine months ended September 30, 2008 and 2007. A payable
      of $5.1 million and $3.8 million, respectively, is reflected on our September
      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. In
      September 2008, the Company acquired certain natural gas and oil properties
      in
      Appalachia from Vinland for a total purchase price of $4.0 million. The
      consideration included $3.1 million in cash and $0.9 million reduction in
      amounts previously due to Vanguard.


15


**VANGUARD
      NATURAL RESOURCES, LLC AND SUBSIDIARIES**


**NOTES TO
      CONSOLIDATED FINANCIAL STATEMENTS**


**(Unaudited)**




**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 September 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 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 nine months ended September 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.





Furthermore,
      on March 27, 2008, phantom units were granted to two officers in amounts equal
      to 1% 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 September 30, 2008, there has been no
      appreciation in the value of these units; therefore, no liability or expense
      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 September 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
            
            $
            18.14Granted
            
            
            15,000
            
            
            16.79Non-vested
                units at September 30, 2008
            
            
            440,000
            
            $
            18.10





At
      September 30, 2008, there was approximately $3.2 million of unrecognized
      compensation cost related to non-vested restricted units. The cost is expected
      to be recognized over an average period of approximately 1.1 years. Our
      consolidated statement of operations reflects non-cash compensation of $0.8
      million in the selling, general and administrative line item for each of the
      three months ended September 30, 2008 and 2007 and $2.7 million and $1.3 million
      for the nine months ended September 30, 2008 and 2007,
      respectively.




16




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




**11.**
            **Subsequent
                Event**





In
      October 2008, we amended and restated our reserve-based credit facility, which
      set our borrowing base under the facility at $175.0 million pursuant to our
      semi-annual redetermination and added a new lender, Compass Bank. In addition,
      the applicable margin on our Eurodollar (LIBOR) loans option was increased
      approximately half a percent from LIBOR plus 1.0% - 1.75% to LIBOR plus 1.5%
      -
      2.125% and the utilization percentages in the grid were adjusted. The amended
      borrowing base utilization grid is as follows:





**Borrowing
                Base Utilization Grid**Borrowing
                base utilization percentage
            
            
            *<33*
            *%*
            
            *>33%
                <66*
            *%*
            
            *>66%
                <85*
            *%*
            
            *>85*
            *%*Eurodollar
                loans
            
            
            1.500
            %
            
            1.750
            %
            
            2.000
            %
            
            2.125
            %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
            %





17


**Item 2.  Management’s
        Discussion and Analysis of Financial Condition and Results of
        Operations**
  The
        following discussion and analysis should be read in conjunction with the
        financial statements and related notes presented in Item 1 of this Quarterly
        Report on Form 10-Q and information disclosed in our 2007 Annual Report on
        Form 10-K/A.
  ***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, and those set
        forth from time to time in our filings with the SEC, which are available
        on our
        website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and
        Retrieval System (“EDGAR”) at http://www.sec.gov.
  All
        forward-looking statements included in this report are based on information
        available to us on the date of this report. We undertake no obligation to
        publicly update or revise any forward-looking statement, whether as a result
        of
        new information, future events or otherwise. All subsequent written and oral
        forward-looking statements attributable to us or persons acting on our behalf
        are expressly qualified in their entirety by the cautionary statements contained
        throughout this report.
  ***Overview***
  We
        are a
        publicly-traded limited liability company focused on the acquisition and
        development of mature, long-lived natural gas and oil properties in the United
        States. Our primary business objective is to generate stable cash flows allowing
        us to make quarterly cash distributions to our unitholders and over time
        to
        increase our quarterly cash distributions through the acquisition of new
        natural
        gas and oil properties. Our properties are located in the southern portion
        of
        the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee,
        the Permian Basin, primarily in west Texas and southeastern New Mexico, and
        in
        South Texas.
  We
        owned
        working interests in 1,506 gross (1,022 net) productive wells at September
        30,
        2008 and our average net production for the twelve months ended
        December 31, 2007 and for the three months and nine months ended September
        30, 2008 was 11,610 Mcfe per day, 16,932 Mcfe per day and 15,410 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. In addition, we have a 47.5% working interest in 4,705 gross acres
        in
        South Texas.
 
 ***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 which made them ineffective.
  18
  The
        Company will restate its consolidated unaudited quarterly financial statements
        for March 31, 2008 and June 30, 2008 and expects to file amended Quarterly
        Reports on Form 10-Q/A as soon as practicable. The effect of the restatement
        has
        been reflected in the operating results for the nine months ended September
        30,
        2008 and 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 liquidity, adjusted EBITDA,
        distributable cash flow, total assets, total liabilities, members’ capital, or
        the amount of available cash to pay distributions 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.
  ***Disruption
        to Functioning of Capital Markets***
 
 Multiple
        events during 2008 involving numerous financial institutions have effectively
        restricted current liquidity within the capital markets throughout the United
        States and around the world. Despite efforts by treasury and banking regulators
        in the United States, Europe and other nations around the world to provide
        liquidity to the financial sector, capital markets currently remain constrained.
        We expect that our ability to raise debt and equity at prices that are similar
        to offerings in recent years to be limited over the next three to six months
        and
        possibly longer should capital markets remain constrained.
 
 In
        the
        weeks following the third quarter, our unit price declined to a closing low
        of
        $7.49 on October 10, 2008. Since that date our unit price recovered partially
        to
        a level of $8.43 on November 10, 2008. We intend to move forward with our
        development drilling program, although our capital spending may be reduced
        to
        moderate our capital raising requirements and in recognition of the low
        commodity price environment. In the near-term we will focus on maintaining
        sufficient liquidity to fund our growth programs, see “Liquidity and Capital
        Resources.” Maintaining adequate liquidity may involve the issuance of debt and
        equity at less attractive terms, could involve the sale of non-core assets,
        could require reductions in our capital spending, and could require a reduction
        in our distribution.
 
 ***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 an adjusted purchase price of $51.4 million,
        subject to customary post-closing adjustments to be determined. This acquisition
        was funded with $30.0 million of borrowings under our reserve-based credit
        facility and through the issuance of 1,350,873 common units of the Company.
        In
        this purchase, we acquired an average of a 98% working interest in 91 producing
        wells and an average 47.5% working interest in approximately 4,705 gross
        acres
        with 41 identified proved undeveloped locations. An affiliate of Lewis Energy
        Group operates all the properties and is contractually obligated to drill
        six
        wells in 2008 and seven wells each year from 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. 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.
  19
  ***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.
        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.
  ***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 in January 2008 pursuant to the acquisition
        of
        natural gas and oil properties in the Permian Basin, and in July 2008 an
        additional $30.0 million was borrowed to fund a portion of the cash
        consideration paid in the South Texas acquisition. As a result, indebtedness
        under the reserve-based credit facility totaled $134.5 million at September
        30,
        2008 and the applicable margin and other fees increase as the utilization
        of the
        borrowing base increases as follows:
  20
  **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
        October 2008, we amended and restated our reserve-based credit facility which
        set our borrowing base under the facility at $175.0 million pursuant to our
        semi-annual redetermination and added a new lender, Compass Bank. In addition,
        the applicable margins and the utilization percentages on our borrowing base
        utilization grid were changed to reflect the following:
 
 **Borrowing
                  Base Utilization Grid**Borrowing
                  base utilization percentage
              
              
              *<33*
              *%*
              
              *>33%
                  <66*
              *%*
              
              *>66%
                  <85*
              *%*
              
              *>85*
              *%*Eurodollar
                  loans
              
              
              1.500
              %
              
              1.750
              %
              
              2.000
              %
              
              2.125
              %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
              %
 
 **Outlook**
  Our
        revenue, cash flow from operations and future growth depend substantially
        on
        factors beyond our control, such as access to capital, economic, political
        and
        regulatory developments, and competition from other sources of energy. 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 a portion of our proved producing
        and
        a portion of our 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 and voluntary
        reductions in capital spending in a low commodity price environment. Any
        delays
        in drilling, completion or connection to gathering lines of our new wells
        will
        negatively impact the rate of our production, which may have an adverse effect
        on our revenues and as a result, cash available for distribution. In accordance
        with our business plan, we intend to invest the capital necessary to maintain
        our production at existing levels over the long-term provided that it is
        economical to do so based on the commodity price environment. However, we
        cannot
        be certain that we will be able to issue our debt and equity securities on
        favorable terms, or at all, and we may be unable to refinance our reserve-based
        credit facility when it expires. Additionally, due to the significant decline
        in
        commodity prices, our borrowing base under our reserve-based credit facility
        may
        be redetermined such that it will not provide for the working capital necessary
        to fund our capital spending program and could affect our ability to make
        distributions.
  21
  **Results
        of Operations**
  The
        following table sets forth selected financial and operating data for the
        periods
        ended September 30:
  **Three Months Ended**
                **September 30,**
              
              **Nine Months Ended**
                **September 30,****2008(b)**
              
              **2007**
              
              **2008(a)(b)**
              
              **2007****Revenues:**Natural
                  gas and oil sales
              
              $
              20,838,797
              
              $
              7,641,064
              
              $
              55,692,781
              
              $
              26,709,417Realized
                  gain (loss) on commodity cash flow hedges
              
              
              —
              
              
              940,566
              
              
              —
              
              
              (725,286
              )**Total
                  revenues**
              
              **$**
              **20,838,797**
              
              **$**
              **8,581,630**
              
              **$**
              **55,692,781**
              
              **$**
              **25,984,131****Costs
                  and expenses:**Lease
                  operating expenses
              
              $
              3,483,968
              
              $
              1,347,565
              
              $
              7,799,721
              
              $
              3,807,985Depreciation,
                  depletion, amortization and accretion
              
              
              4,187,241
              
              
              2,267,050
              
              
              10,341,243
              
              
              6,587,339Selling,
                  general and administrative expenses
              
              
              1,561,031
              
              
              1,084,995
              
              
              4,843,497
              
              
              2,300,484Bad
                  debt expense
              
              
              —
              
              
              —
              
              
              —
              
              
              1,007,458Taxes
                  other than income taxes
              
              
              1,263,223
              
              
              326,175
              
              
              3,658,301
              
              
              1,217,167**Total
                  costs and expenses**
              
              **$**
              **10,495,463**
              
              **$**
              **5,025,785**
              
              **$**
              **26,642,762**
              
              **$**
              **14,920,433****Other
                  income and (expense):**Interest
                  expense, net
              
              $
              (1,484,480
              )
              $
              (2,504,634
              )
              $
              (3,846,583
              )
              $
              (6,896,802
              )Realized
                  gain (loss) on commodity derivative contracts
              
              $
              (2,943,833
              )
              $
              —
              
              $
              (9,792,946
              )
              $
              —Unrealized
                  gain (loss) on commodity derivative contracts
              
              $
              66,353,176
              
              $
              —
              
              $
              (6,042,967
              )
              $
              —Realized
                  loss on interest rate derivative contracts
              
              $
              (39,058
              )
              $
              —
              
              $
              (90,364
              )
              $
              —Unrealized
                  loss on interest rate derivative contracts
              
              $
              (419,769
              )
              $
              —
              
              $
              (419,769
              )
              $
              —Loss
                  on extinguishment of debt
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              (2,501,528
              )
  (a) 
                  The Permian acquisition closed on January 31, 2008 and as such
                  only eight
                  months of operations are included in the nine month period ended
                  September
                  30, 2008.(b) 
                  The South Texas acquisition closed on July 28, 2008 and as such
                  only two
                  months of operations are included in the three and nine month period
                  ended
                  September 30, 2008.
  **Three
        Months Ended September 30, 2008 Compared to Three Months Ended September
        30,
        2007**
  *Revenues*
  Natural
        gas and oil sales increased $13.2 million to $20.8 million during the three
        months ended September 30, 2008 as compared to the same period in 2007. The
        key
        revenue measurements were as follows:
 
 **Three Months Ended**
              
              **Percentage****September 30,**
              
              **Increase****2008**
              
              **2007**
              
              **(Decrease)**Net
                  Natural Gas Production:Appalachian
                  gas (MMcf)
              
              
              923
              
              
              1,002
              
              
              (8
              )%Permian
                  gas (MMcf)
              
              
              —
              
              
              —
              
              
              N/ASouth
                  Texas gas (MMcf)
              
              
              239
              (a)
              
              —
              
              
              N/A**Total
                  natural gas production (MMcf)**
              
              
              1,162
              
              
              1,002
              
              
              16
              %Average
                  Appalachian daily gas production (Mcf/day)
              
              
              10,031
              
              
              10,892
              
              
              (8
              )%Average
                  Permian daily gas production (Mcf/day)
              
              
              —
              
              
              —
              
              
              N/AAverage
                  South Texas daily gas production (Mcf/day)
              
              
              3,684
              (a)
              
              —
              
              
              N/A**Average
                  Vanguard daily gas production (Mcf/day)**
              
              
              13,715
              
              
              10,892Average
                  Natural Gas Sales Price per Mcf:Net
                  realized gas price, including realized gains (losses) on commodity
                  derivative contracts
              
              $
              11.35
              (b)
              $
              9.44
              (b)
              
              20
              %Net
                  realized gas price, excluding realized gains (losses) on commodity
                  derivative contracts
              
              $
              11.46
              
              $
              6.69
              
              
              71
              %Net
                  Oil Production:Appalachian
                  oil (Bbls)
              
              
              11,122
              
              
              11,348
              
              
              (2
              )%Permian
                  oil (Bbls)
              
              
              54,924
              
              
              —
              
              
              N/A**Total
                  oil (Bbls)**
              
              
              66,046
              
              
              11,348
              
              
              482
              %Average
                  Appalachian daily oil production (Bbls/day)
              
              
              121
              
              
              123
              
              
              (2
              )%Average
                  Permian daily oil production (Bbls/day)
              
              
              597
              
              
              —
              
              
              N/A**Average
                  Vanguard daily oil production (Bbls/day)**
              
              
              718
              
              
              123Average
                  Oil Sales Price per Bbl:Net
                  realized oil price, including realized gains (losses) on commodity
                  derivative contracts
              
              $
              93.26
              
              $
              82.46
              
              
              13
              %Net
                  realized oil price, excluding realized gains (losses) on commodity
                  derivative contracts
              
              $
              114.01
              
              $
              82.46
              
              
              38
              %
 (a)
                The
                    South Texas acquisition closed on July 28, 2008 and as such only
                    two
                    months of operations are included in the three month period ended
                    September 30, 2008.(b)
                Excludes
                    amortization of premiums paid and non-cash settlements on derivative
                    contracts.
  22
  The
        increase in natural gas and oil sales was due primarily to the impact of
        the
        Permian Basin acquisition completed on January 31, 2008, the South Texas
        acquisition completed on July 28, 2008 and increases in commodity prices.
        Production from the Permian Basin and South Texas acquisitions contributed
        $8.6
        million of natural gas and oil sales for the three month period ended September
        30, 2008. In Appalachia, we experienced an 8% decline in natural gas production
        which was more than offset by a 71% increase in the average realized natural
        gas
        sales price received (excluding hedges) and a 38% increase in the average
        realized oil price (excluding hedges).
  *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 $2.1 million to $3.5 million for the
        three
        months ended September 30, 2008 as compared to the three months ended September
        30, 2007, of which $1.8 million was related to the Permian Basin and South
        Texas
        acquisitions. 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 September 30, 2008 as compared to the same period
        in
        2007 of which $0.6 million related to the Permian Basin and South Texas
        acquisitions, and the remaining increase is attributable to higher severance
        taxes resulting from increased revenues.
  Depreciation,
        depletion, amortization and accretion increased to approximately $4.2 million
        for the three months ended September 30, 2008 from approximately $2.3 million
        for the three months ended September 30, 2007 due primarily to the additional
        depletion recorded on oil and gas properties acquired in the Permian Basin
        and
        South Texas acquisitions.
  Selling,
        general and administrative expenses include the costs of our administrative
        employees and executive officers, related benefits, office leases, professional
        fees and other costs not directly associated with field operations. These
        expenses for the three months ended September 30, 2008 increased $0.5 million
        as
        compared to the three months ended September 30, 2007. For the three months
        ended September 30, 2008 and 2007 these expenses included a $0.8 million
        non-cash compensation charge in each period related to the grant of restricted
        Class B units to management and an employee, the grant of unit options to
        management, and the grant of common units to board members during 2007 and
        2008.
        All other selling, general and administrative expenses increased $0.4 million
        during the three months ended September 30, 2008 as compared to the same
        period
        in 2007 principally due to incremental costs associated with being a public
        company.
  23
  Interest
        expense declined to $1.5 million for the three months ended September 30,
        2008
        compared to $2.5 million for the three months ended September 30, 2007 primarily
        due to lower interest rates, which more than offset the higher average
        outstanding debt during the quarter ended September 30, 2008.
 
 During
        the quarter ended September 30, 2008, the Company recognized a
        $2.9 million realized loss on commodity derivatives and a
        $66.4 million unrealized gain 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 gain on commodity derivatives relates to
        actual
        amounts received less premiums previously paid under these derivative contracts
        while the unrealized gain on commodity derivatives represents the change
        in the
        fair value of these derivative instruments.
  **Nine
        Months Ended September 30, 2008 Compared to Nine Months Ended September 30,
        2007**
  *Revenues*
  Natural
        gas and oil sales increased $29.0 million to $55.7 million during the nine
        months ended September 30, 2008 as compared to the same period in 2007. The
        key
        revenue measurements were as follows:
 **Nine Months Ended**
                
                **Percentage****September 30,**
                
                **Increase****2008**
                
                **2007**
                
                **(Decrease)**Net
                    Natural Gas Production:Appalachian
                    gas (MMcf)
                
                
                2,693
                
                
                3,102
                
                
                (13
                )%Permian
                    gas (MMcf)
                
                
                150
                (a)
                
                —
                
                
                N/ASouth
                    Texas gas (MMcf)
                
                
                240
                (b)
                
                —
                
                
                N/A**Total
                    natural gas production (MMcf)**
                
                
                3,083
                
                
                3,102
                
                
                —
                %Average
                    Appalachian daily gas production (Mcf/day)
                
                
                9,827
                
                
                11,363
                
                
                (14
                )%Average
                    Permian daily gas production (Mcf/day)
                
                
                618
                (a)
                
                —
                
                
                N/AAverage
                    South Texas daily gas production (Mcf/day)
                
                
                3,684
                (b)
                
                —
                
                
                N/A**Average
                    Vanguard daily gas production (Mcf/day)**
                
                
                14,129
                
                
                11,363Average
                    Natural Gas Sales Price per Mcf:Net
                    realized gas price, including realized gains (losses) on commodity
                    derivative contracts
                
                $
                10.78
                (c)
                $
                8.73
                (c)
                
                23
                %Net
                    realized gas price, excluding realized gains (losses) on commodity
                    derivative contracts
                
                $
                11.56
                
                $
                8.14
                
                
                42
                %Net
                    Oil Production:Appalachian
                    oil (Bbls)
                
                
                32,543
                
                
                19,861
                
                
                64
                %Permian
                    oil (Bbls)
                
                
                157,463
                (a)
                
                —
                
                
                N/A**Total
                    oil (Bbls)**
                
                
                190,006
                
                
                19,861
                
                
                857
                %Average
                    Appalachian daily oil production (Bbls/day)
                
                
                119
                
                
                73
                
                
                63
                %Average
                    Permian daily oil production (Bbls/day)
                
                
                648
                (a)
                
                —
                
                
                N/A**Average
                    Vanguard daily oil production (Bbls/day)**
                
                
                767
                
                
                73Average
                    Oil Sales Price per Bbl:Net
                    realized oil price, including realized gains (losses) on commodity
                    derivative contracts
                
                $
                87.62
                
                $
                73.03
                
                
                20
                %Net
                    realized oil price, excluding realized gains (losses) on commodity
                    derivative contracts
                
                $
                105.56
                
                $
                73.03
                
                
                45
                %
  24
  (a)
              The
                  Permian acquisition closed on January 31, 2008 and as such only
                  eight
                  months of operations are included in the nine month period ended
                  September
                  30, 2008.(b)
              The
                  South Texas acquisition closed on July 28, 2008 and as such only
                  two
                  months of operations are included in the nine month period ended
                  September
                  30, 2008.(c)
              Excludes
                  amortization of premiums paid and non-cash settlements 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, the South Texas
        acquisition completed on July 28, 2008 and increases in commodity prices
        during
        the period. Production from the Permian Basin and South Texas acquisitions
        contributed $20.9 million of natural gas and oil sales for the nine month
        period
        ended September 30, 2008. In Appalachia, a 13% decline in natural gas production
        was partially offset by a 64% increase in oil production for a net production
        decline of 10% on an Mcfe basis. However, the negative impact of the production
        decline was offset by a 42% increase in the average realized natural gas
        sales
        price received (excluding hedges) and a 45% increase in the average realized
        oil
        price (excluding hedges).
  *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 $4.0 million to $7.8 million for the
        nine
        months ended September 30, 2008 as compared to the nine months ended September
        30, 2007 of which $3.3 million related to the Permian Basin and South Texas
        acquisitions. 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 $2.4 million
        for the nine months ended September 30, 2008 as compared to the same period
        in
        2007 of which $1.4 million related to the Permian Basin and South Texas
        acquisitions, and the remaining increase is attributable to higher severance
        taxes resulting from increased revenues.
  Depreciation,
        depletion, amortization and accretion increased to approximately $10.3 million
        for the nine months ended September 30, 2008 from approximately $6.6 million
        for
        the nine months ended September 30, 2007 due primarily to the additional
        depletion recorded on the oil and gas properties acquired in the Permian
        Basin
        and South Texas acquisitions.
  Selling,
        general and administrative expenses include the costs of our administrative
        employees and executive officers, related benefits, office leases, professional
        fees and other costs not directly associated with field operations. These
        expenses for the nine months ended September 30, 2008 increased $2.5 million
        as
        compared to the nine months ended September 30, 2007. For the nine months
        ended
        September 30, 2008 and 2007 these expenses included a $2.7 million and $1.3
        million non-cash compensation charge related to the grant of restricted Class
        B
        units to management and an employee, the grant of unit options to management,
        and the grant of common units to board members during 2007 and 2008. All
        other
        selling, general and administrative expenses increased $1.1 million during
        the
        nine months ended September 30, 2008 as compared to the same period in 2007
        principally due to incremental costs associated with being a public
        company.
  Interest
        expense declined to $3.9 million for the nine months ended September 30,
        2008
        compared to $6.9 million for the nine months ended September 30, 2007 primarily
        due to a 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.
  25
  During
        the nine months ended September 30, 2008, the Company recognized
        $9.8 million and $6.0 million related to realized losses on commodity
        derivatives and unrealized losses 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 gain on commodity derivatives relates to
        actual
        amounts received less premiums previously paid under these derivative contracts
        while the unrealized gain 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
        September 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 which made them ineffective.
  Under
        SFAS No. 133, the fair value of hedge contracts is recognized in the
        Consolidated Balance Sheet as an asset or liability, and the amounts received
        or
        paid under the hedge contracts are reflected in earnings during the period
        in
        which the underlying production occurs. If the hedge 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 hedge contract does not qualify for
        hedge accounting treatment, the change in the fair value of the hedge 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 will restate its consolidated unaudited quarterly financial statements
        for March 31, 2008 and June 30, 2008 and expects to file amended Quarterly
        Reports on Form 10-Q/A as soon as practicable. The effect of the restatement
        has
        been reflected in the operating results for the nine months ended September
        30,
        2008 and 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.
  26
  **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. 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.
 
 **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 September 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 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.
  27
  **Liquidity
        and Capital Resources**
 
 **Disruption
        to Functioning of Capital Markets**
 
 Multiple
        events during 2008 involving numerous financial institutions have effectively
        restricted current liquidity within the capital markets throughout the United
        States and around the world. Despite efforts by treasury and banking regulators
        in the United States, Europe and other nations around the world to provide
        liquidity to the financial sector, capital markets currently remain constrained.
        We expect that our ability to issue debt and equity on favorable terms will
        be
        limited over the next three to six months and possibly longer should capital
        markets remain constrained. Although we intend to move forward with our
        development drilling program, we may revise the timing and scope of our
        development drilling program as necessary to adapt to existing economic
        conditions. The benefits expected to accrue to our unitholders from our
        expansion activities may be muted by substantial cost of capital increases
        during this period.
 
 ***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 and acquiring additional
        reserves. We expect to fund our drilling capital expenditures and
        distributions to unitholders with cash flow from operations, while funding
        any
        acquisition capital expenditures that we might incur with borrowings under
        our
        reserve-based credit facility and publicly offered equity, depending on market
        conditions. As of November 10, 2008, we have $40.0 million available to be
        borrowed under our reserve-based credit facility. Based upon current
        expectations, we believe existing liquidity and capital resources will be
        sufficient for the conduct of our business and operations for the foreseeable
        future.
 
 ***Cash
        Flow from Operations***
  Net
        cash
        provided by operating activities for the nine months ended September 30,
        2008
        was $28.6 million, compared to $2.6 million for the nine months ended September
        30, 2007. The increase in cash provided by operating activities during the
        nine months ended September 30, 2008 was substantially due to increased income,
        a decrease in cash used in price risk management activities and an increase
        in
        accrued expenses, offset by an increase in accounts receivable. The cash
        used in
        operating activities in the first nine 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
        contracts 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 $114.1 million for the nine months
        ended September 30, 2008, compared to $10.7 million for the nine months ended
        September 30, 2007. The increase in cash used in investing activities was
        primarily attributable to $99.8 million used for the acquisition of natural
        gas
        and oil properties in the Permian Basin and South Texas. In addition, the
        total
        for the nine months ended September 30, 2008 includes $13.4 million for the
        drilling and development of natural gas and oil properties as compared to
        $9.4
        million for the nine months ended September 30, 2007.
  ***Cash
        Flow from Financing Activities***
 
 Cash
        provided by financing activities was approximately $82.7 million for the
        nine
        months ended September 30, 2008, compared to $9.5 million for the nine months
        ended September 30, 2007. During the nine months ended September 30, 2008,
        total
        proceeds from borrowings under our reserve-based credit facility were $112.9
        million which were principally used to fund the Permian Basin and South Texas
        acquisitions. During the nine months ended September 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 nine months ended September 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 sole
        member at that time.
  28
  **Available
        Credit**
 
 Credit
        markets in the United States and around the world remain constrained due
        to a
        lack of liquidity and confidence in a number of financial institutions.
        Investors continue to seek perceived safe investments in securities of the
        United States government rather than individual entities. We may at times
        experience difficulty accessing the long-term credit markets due to prevailing
        market conditions. Additionally, existing constraints in the credit markets
        may
        increase the rates we are charged for utilizing these markets. Notwithstanding
        the continuing weakness in the United States credit markets, we expect that
        our
        available liquidity is sufficient to meet our operating and capital requirements
        into 2009 and for the foreseeable future.
  **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 of September 30, 2008, we had
        $134.5 million outstanding under our reserve-based credit facility and as
        of
        October 22, 2008, our reserve-based credit facility was amended and restated
        to
        increase the borrowing base to $175.0 million and add one lender, Compass
        Bank. The increase in the borrowing base was principally the result of
        inclusion of the reserves related to the South Texas acquisition in July
        2008.
 
 Borrowings
        under the reserve-based credit facility are available for the development
        and
        acquisition of natural gas and oil properties, working capital and general
        limited liability company purposes. Our obligations under the reserve-based
        credit facility are secured by substantially all of our assets.
  At
        our
        election, interest is determined by reference to:
  ·
              the
                  London interbank offered rate, or LIBOR, plus an applicable margin
                  between
                  1.50% and 2.125% 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
  29
  ·
              engage
                  in certain asset dispositions, including a sale of all or substantially
                  all of our assets.
  The
        reserve-based credit facility also contains covenants that, among other things,
        require us to maintain specified ratios or conditions as follows:
  ·
              consolidated
                  net income plus interest expense, income taxes, depreciation, depletion,
                  amortization, accretion, changes in fair value of derivative instruments
                  and other similar charges, minus all non-cash income added to consolidated
                  net income, and giving pro forma effect to any acquisitions or
                  capital
                  expenditures, to interest expense of not less than 2.5 to
                  1.0;
 
 ·
              consolidated
                  current assets, including the unused amount of the total commitments,
                  to
                  consolidated current liabilities of not less than 1.0 to 1.0, excluding
                  non-cash assets and liabilities under 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, accretion, changes in fair
                  value of
                  derivative instruments and other similar charges, minus all non-cash
                  income added to consolidated net income, and giving pro forma effect
                  to
                  any acquisitions or capital expenditures of not more than 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;
  30
  ·
              specified
                  events relating to our employee benefit plans that could reasonably
                  be
                  expected to result in liabilities in excess of $1.0 million in
                  any year;
                  and
  ·
              a
                  change of control, which includes (1) an acquisition of ownership,
                  directly or indirectly, beneficially or of record, by any person
                  or group
                  (within the meaning of the Securities Exchange Act of 1934 and
                  the rules
                  of the Securities Exchange Commission) of equity interests representing
                  more than 25% of the aggregate ordinary voting power represented by our
                  issued and outstanding equity interests other than by Majeed S.
                  Nami or
                  his affiliates, or (2) the replacement of a majority of our directors
                  by
                  persons not approved by our board of
                  directors.
  **Off-Balance
        Sheet Arrangements**
  At
        September 30, 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.
  **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 September 30, 2008, there were
        no
        loss contingencies.
  **Commitments
        and Contractual Obligations**
  A
        summary
        of our contractual obligations as of September 30, 2008 is provided in the
        following table:
  **Payments Due by Year (in thousands)****2008**
              
              **2009**
              
              **2010**
              
              **2011**
              
              **2012**
              
              **After 2012**
              
              **Total**Management compensation
              
              $
              150
              
              $
              600
              
              $
              100
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              850Asset
                  retirement obligations
              
              
              —
              
              
              12
              
              
              24
              
              
              180
              
              
              32
              
              
              2,156
              
              
              2,404Derivative
                  liabilities
              
              
              607
              
              
              3,484
              
              
              7,326
              
              
              5,999
              
              
              3,195
              
              
              —
              
              
              20,611Long-term
                  debt (1)
              
              
              —
              
              
              —
              
              
              —
              
              
              134,500
              
              
              —
              
              
              —
              
              
              134,500Operating
                  leases
              
              
              10
              
              
              41
              
              
              10
              
              
              —
              
              
              —
              
              
              —
              
              
              61Total
              
              $
              767
              
              $
              4,137
              
              $
              7,460
              
              $
              140,679
              
              $
              3,227
              
              $
              2,156
              
              $
              158,426
 
 (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);
 
 31
 
 •
              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
                  gains and losses 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.
  Our
        Adjusted EBITDA should not be considered as an alternative to net income,
        operating income, cash flow from operating activities or any other measure
        of
        financial performance or liquidity presented in accordance with GAAP. Our
        Adjusted EBITDA excludes some, but not all, items that affect net income
        and
        operating income and these measures may vary among other companies. Therefore,
        our Adjusted EBITDA may not be comparable to similarly titled measures of
        other
        companies.
  For
        the
        three months ended September 30, 2008 as compared to the three months ended
        September 30, 2007, Adjusted EBITDA increased 65%, from $8.4 million to $13.8
        million. For the nine months ended September 30, 2008 as compared to the
        nine
        months ended September 30, 2007, Adjusted EBITDA increased 55%, from $23.3
        million to $36.2 million. The following table presents a reconciliation of
        consolidated net income to Adjusted EBITDA:
  **Three Months Ended**
                  **September 30,**
                
                **Nine Months Ended**
                  **September 30,****2008**
                
                **2007**
                
                **2008**
                
                **2007****Net income**
                
                $
                71,809,370
                
                $
                1,051,211
                
                $
                8,857,390
                
                $
                1,665,368Plus:Interest
                    expense
                
                
                1,488,745
                
                
                2,524,427
                
                
                3,862,855
                
                
                6,944,241Loss
                    on extinguishment of debt
                
                
                —
                
                
                —
                
                
                —
                
                
                2,501,528Depreciation,
                    depletion, amortization and accretion
                
                
                4,187,241
                
                
                2,267,050
                
                
                10,341,243
                
                
                6,587,339Bad
                    debt expense
                
                
                —
                
                
                —
                
                
                —
                
                
                1,007,458Amortization
                    of premiums paid and non-cash settlements on derivative contracts
                
                
                1,450,582
                
                
                1,813,495
                
                
                3,981,775
                
                
                2,546,999Unrealized
                    (gains) losses on commodity and interest rate derivative
                    contracts
                
                
                (65,933,407
                )
                
                —
                
                
                6,462,736
                
                
                —Unit-based
                    compensation expense
                
                
                812,034
                
                
                751,635
                
                
                2,708,381
                
                
                1,314,778Realized
                    loss on cancelled derivatives
                
                
                —
                
                
                —
                
                
                —
                
                
                776,634Less:Interest
                    income
                
                
                4,265
                
                
                19,793
                
                
                16,272
                
                
                47,439**Adjusted
                    EBITDA**
                
                $
                13,810,300
                
                $
                8,388,025
                
                $
                36,198,108
                
                $
                23,296,906
 
 **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 and oil prices and interest rates. The disclosures
        are
        not meant to be precise indicators of expected future losses, but rather
        indicators of reasonably possible losses. This forward-looking information
        provides indicators of how we view and manage our ongoing market risk exposures.
        All of our market risk sensitive instruments were entered into for purposes
        other than speculative trading. Conditions sometimes arise where actual
        production is less than estimated, which has, and could result in overhedged
        volumes.
  32
  ***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”), Henry Hub and Houston Ship Channel for natural gas
        production and the West Texas Intermediate Light Sweet for oil production.
        Pricing for natural gas production has been volatile and unpredictable for
        several years, and we expect this volatility to continue in the future. The
        prices we receive for production depend on many factors outside our control.
        In
        addition, the potential exists that if commodity prices decline to a certain
        level, the borrowing base can be decreased at the borrowing base redetermination
        date to an amount lower than the amount of debt currently outstanding.
  We
        enter
        into derivative contracts with respect to a portion of our projected natural
        gas
        and oil production through various transactions that mitigate the volatility
        of
        future prices received. These transactions may include price swaps whereby
        we
        will receive a fixed-price for our production and pay a variable market price
        to
        the contract counterparty. Additionally, we 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 price and the counterparty pays us if the
        market price is below the floor price on a notional quantity. These activities
        are intended to support our realized commodity prices at targeted levels
        and to
        manage our exposure to natural gas and oil price fluctuations. It is never
        management’s intention to hold or issue derivative instruments for speculative
        trading purposes.
  At
        September 30, 2008, the fair value of commodity derivative contracts that
        settle
        during the next twelve months was an asset of approximately $3.7 million,
        which
        our counterparties owe us.
 
 The
        following table summarizes commodity derivative contracts in place applicable
        to
        periods subsequent to September 30, 2008:
 
 **October 1, -**
                **December 31,**
                **2008**
              
              **Year**
                **2009**
              
              **Year**
                **2010**
              
              **Year**
                **2011**
              
              **Year**
                **2012****Gas Positions:**Fixed
                  Price Swaps:Notional
                  Volume (MMBtu)
              
              
              713,831
              
              
              3,623,946
              
              
              3,236,040
              
              
              2,962,312
              
              
              —Fixed
                  Price ($/MMBtu)
              
              $
              9.00
              
              $
              9.42
              
              $
              9.10
              
              $
              7.82
              
              $
              -—Puts:Notional
                  Volume (MMBtu)
              
              
              246,920
              
              
              840,139
              
              
              —
              
              
              —
              
              
              —Floor
                  Price ($/MMBtu)
              
              $
              7.50
              
              $
              7.50
              
              $
              —
              
              $
              —
              
              $
              —Collars:Notional
                  Volume (MMBtu)
              
              
              566,800
              
              
              1,000,000
              
              
              730,000
              
              
              —
              
              
              —Floor
                  Price ($/MMBtu)
              
              $
              10.13
              
              $
              7.50
              
              $
              8.00
              
              $
              —
              
              $
              —Ceiling
                  Price ($/MMBtu)
              
              $
              10.94
              
              $
              9.00
              
              $
              9.30
              
              $
              —
              
              $
              —Total:Notional
                  Volume (MMBtu)
              
              
              1,527,551
              
              
              5,464,085
              
              
              3,966,040
              
              
              2,962,312
              
              
              —**Oil
                  Positions:**Fixed
                  Price Swaps:Notional
                  Volume (Bbls)
              
              
              48,000
              
              
              181,500
              
              
              164,250
              
              
              151,250
              
              
              144,000Fixed
                  Price ($/Bbl)
              
              $
              90.30
              
              $
              87.23
              
              $
              85.65
              
              $
              85.50
              
              $
              80.00Collars:Notional
                  Volume (Bbls)
              
              
              9,200
              
              
              36,500
              
              
              —
              
              
              —
              
              
              —Floor
                  Price ($/Bbl)
              
              $
              100.00
              
              $
              100.00
              
              $
              —
              
              $
              —
              
              $
              —Ceiling
                  Price ($/Bbl)
              
              $
              127.00
              
              $
              127.00
              
              $
              —
              
              $
              —
              
              $
              —Total:Notional
                  Volume (Bbls)
              
              
              57,200
              
              
              218,000
              
              
              164,250
              
              
              151,250
              
              
              144,000
  33
  ***Interest
        Rate Risks***
 
 At
        September 30, 2008, we had debt outstanding of $134.5 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 $0.7 million increase in annual interest expense after
        consideration of the interest rate swaps discussed below. In December 2007
        and
        during the first nine months 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.
 
 In
        August
        2008, we entered into two interest rate basis swaps which changed the reset
        option from three month LIBOR to one month LIBOR on the total $60.0 million
        of
        outstanding interest rate swaps. By doing so, the company reduced its borrowing
        cost by 14 basis points below the 3.88% reflected below on $20.0 million
        of
        borrowings for a one year period starting September 10, 2008 and 12 basis
        points
        on the 3.00% and 2.66% reflected below on $40.0 million of borrowings for
        a one
        year period starting October 31, 2008. As a result of these two basis swaps,
        the
        company chose to de-designate the interest rate swaps as cash flow hedges
        as the
        terms of the new contracts no longer matched the terms of the original
        contracts, thus causing the interest rate hedges to be ineffective. Beginning
        in
        the third quarter of 2008, the Company will record changes in the fair value
        of
        its interest rate derivatives in current earnings under unrealized gains
        (losses) on interest rate derivative contracts. The net unrealized gain at
        June
        30, 2008 related to the de-designated cash flow hedges will continue to be
        reported in accumulated other comprehensive income and later reclassified
        to
        earnings in the month in which the transactions settle.
 
 The
        following summarizes information concerning our positions in open interest
        rate
        derivative contracts applicable to periods subsequent to September 30,
        2008:
 
 ******Notional**
                ******Amount**
              
              **Fixed**
                **Libor**
                **Rates**Period:October
                  1, 2008 to December 10, 2010
              
              $
              20,000,000
              
              
              3.88
              %October
                  1, 2008 to January 31, 2011
              
              $
              30,000,000
              
              
              3.00
              %October
                  1, 2008 to March 31, 2011
              
              $
              10,000,000
              
              
              2.66
              %October
                  1, 2008 to September 10, 2009 (Basis Swap)
              
              $
              20,000,000
              
              
              LIBOR 1M vs. LIBOR 3MOctober
                  31, 2008 to October 31, 2009 (Basis Swap)
              
              $
              40,000,000
              
              
              LIBOR 1M vs. LIBOR 3M
  34
 
 ***Counterparty
        Risk***
 
 At
        September 30, 2008, based upon all of our open derivative contracts shown
        above
        and their respective mark to market values, the Company had the following
        current and long-term derivative assets and liabilities shown by counterparty
        with their current S&P financial strength rating in
        parentheses:
 
 **Citibank, N.A.**
                **(AA)**
              
              **BNP Paribas**
                **(AA+)**
              
              **The Bank of**
                **Nova Scotia**
                **(AA-)**
              
              **Wachovia**
                **Bank, N.A.**
                **(AA-)**
              
              **Total**Current Asset, net
              
              $
              —
              
              $
              3,466,419
              
              $
              215,306
              
              $
              41,379
              
              $
              3,723,104Current
                  Liability, net
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —
              
              $
              —Long-Term
                  Asset, net
              
              $
              —
              
              $
              —
              
              $
              268,241
              
              $
              218,070
              
              $
              486,311Long-Term
                  Liability, net
              
              $
              (6,245,146
              )
              $
              (3,862,964
              )
              $
              —
              
              $
              —
              
              $
              (10,108,110
              )**Total
                  Amount Due from Counterparty/(Owed to Counterparty)****at
                  September 30, 2008**
              
              $
              (6,245,146
              )
              $
              (396,545
              )
              $
              483,547
              
              $
              259,449
              
              $
              (5,898,695
              )
 
 **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.
 
 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 which
        made
        them ineffective. Accordingly, we will restate the consolidated financial
        statements for the three months ended March 31, 2008 and June 30, 2008 as
        reflected in our Form 10-Q’s to reflect the appropriate changes as soon as
        practicable. 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 September
        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.
  35
  **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. In addition,
        on July 28, 2008, we completed the acquisition of certain oil and gas properties
        in South Texas and have also outsourced the production accounting for these
        properties to the same third party that handles the Permian Basin properties.
        As
        a result, we are implementing new processes and modifying existing processes
        to
        ensure adequate internal controls over financial reporting.
  36
 
 **PART II —
        OTHER INFORMATION**
 
 **Item 1.  Legal
        Proceedings**
  Although
        we may, from time to time, be involved in litigation and claims arising out
        of
        our operations in the normal course of business, we are not currently a party
        to
        any material legal proceedings. In addition, we are not aware of any legal
        or
        government proceedings against us, or contemplated to be brought against
        us,
        under the various environmental statutes to which we are subject.
  **Item 1A. 
        Risk Factors**
  Our
        business faces many risks. Any of the risks discussed below or elsewhere
        in this
        Form 10-Q or our other SEC filings, could have a material impact on our
        business, financial position or results of operations. Additional risks and
        uncertainties not presently known to us or that we currently believe to be
        immaterial may also impair our business operations. For a detailed discussion
        of
        the risk factors that should be understood by any investor contemplating
        investment in our units, please refer to the section entitled “Item 1A. Risk
        Factors” in our Annual Report on Form 10-K/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.
 
 ***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.
 
 Furthermore,
        recent crude oil and natural gas prices have been particularly volatile.
        For
        example, the NYMEX crude oil spot price for the period between January 1,
        2008
        and October 31, 2008 has ranged from a high of $145.29 to a low of $62.73
        and
        the NYMEX natural gas spot price for the period January 1, 2008 to October
        31,
        2008 has ranged from a high of $13.58 to a low of $6.12.
 
 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.
 
 37
  ***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.
  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.
  38
  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.
 
 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**
  None.
 
 **Item 3.  Defaults
        Upon Senior Securities**
  None.
  **Item 4.  Submission
        of Matters to a Vote of Security Holders**
  None.
  39
  **Item 5.  Other
        Information**
  None.
 
 **Item 6. 
        Exhibits**
  **EXHIBIT
        INDEX**
 Each
        exhibit identified below is filed as a part of this Report.
  **Exhibit**
                **No.**
              
              **Exhibit Title**
              
              **Incorporated by Reference to the Following**3.1
              
              Certificate of
                  Formation of Vanguard Natural Resources, LLC
              
              Form
                  S-1/A, filed April 25, 2007 (File No. 333-142363)3.2
              
              Second
                  Amended and Restated Limited Liability Company Agreement of Vanguard
                  Natural Resources, LLC (including specimen unit certificate for
                  the
                  units)
              
              Form
                  8-K, filed November 2, 2007 (File No. 001-33756)10.1
              
              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, 200810.2
              
              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)
  40
  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)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,
                  200810.33
              
              Second
                  Amendment to First Amended and Restated Credit Agreement, dated
                  October
                  22, 2008, by and between Vanguard Natural Gas, LLC, Compass Bank,
                  as
                  lender, and Citibank, N.A., as administrative agent
              
              Filed
                  herewith31.1
              
              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
                  herewith31.2
              
              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
                  herewith32.1
              
              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
                  herewith32.2
              
              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
  **SIGNATURE**
  Pursuant
        to the requirements of the Securities Exchange Act of 1934, Vanguard Natural
        Resources, LLC has duly caused this report to be signed on its behalf by
        the
        undersigned thereunto duly authorized.
  VANGUARD
                  NATURAL RESOURCES, LLC(Registrant)Date:
                  November 14, 2008/s/ Richard
                  A. RobertRichard
                  A. RobertExecutive
                  Vice President andChief
                  Financial Officer(Principal
                  Financial Officer and Principal Accounting
                  Officer)
  42
  **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, 200810.2
              
              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)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)
  43
  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,
                  200810.33
              
              Second
                  Amendment to First Amended and Restated Credit Agreement, dated
                  October
                  22, 2008, by and between Vanguard Natural Gas, LLC, Compass Bank,
                  as
                  lender, and Citibank, N.A., as administrative agent
              
              Filed
                  herewith31.1
              
              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
                  herewith31.2
              
              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
                  herewith32.1
              
              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
                  herewith32.2
              
              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
  44