UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.
20549




Form 10-Q/A





(Mark One)


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





For
the quarterly period ended June 30, 2008


OR




 ̈
            TRANSITION REPORT PURSUANT TO
      SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934





For
the transition period from __________ to __________





Commission
File Number 001-33756




Vanguard
Natural Resources, LLC


(Exact
Name of Registrant as Specified in Its Charter)




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




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




Telephone
Number: (832) 327-2255




Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.  Yesx  Noo




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).  Yeso  Nox




Common
units outstanding on August 12, 2008: 12,145,873









EXPLANATORY
NOTE





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




Under
SFAS No. 133, the fair value of derivative contracts is recognized in the
Consolidated Balance Sheets as an asset or liability, and the amounts received
or paid under the contracts are reflected in earnings during the period in which
the underlying production occurs.  If the derivative contracts qualify
for hedge accounting treatment, the fair value of the hedge contract is recorded
in “accumulated other comprehensive income”, and changes in the fair value do
not affect net income in the period.  If the derivative contract does
not qualify for hedge accounting treatment, the change in the fair value of the
contract is reflected in earnings during the period as unrealized gain or loss
on commodity derivatives.  Under the cash flow hedge accounting
treatment used by the Company previously, the fair values of the hedge contracts
were recognized in the consolidated balance sheets with the resulting unrealized
gain or loss recorded initially in accumulated other comprehensive income and
later reclassified through earnings when the hedged production affected
earnings.  As a result of the determination that the documentation
failed to meet cash flow hedge accounting treatment, the unrealized gain or loss
should have been recorded in the consolidated statements of operations as a
component of earnings in 2008. In addition, the net derivative loss at December
31, 2007 related to the de-designated natural gas derivative contracts entered
into in 2007 will continue to be reported in accumulated other comprehensive
income until the month in which the transactions settle.




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









VANGUARD
NATURAL RESOURCES, LLC


TABLE
OF CONTENTS





PageGLOSSARY
      OF TERMSPART
      I - FINANCIAL INFORMATIONItem
      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
                    
                    17Item
      3.
                    Quantitative
      and Qualitative Disclosures about Market Risk
                    
                    30Item
      4.
                    Controls
      and Procedures
                    
                    31PART
      II - OTHER INFORMATIONItem
      1.
                    Legal
      Proceedings
                    
                    32Item
      1A.
                    Risk
      Factors
                    
                    32Item
      2.
                    Unregistered
      Sales of Equity Securities and Use of Proceeds
                    
                    35Item
      3.
                    Default
      in Senior Securities
                    
                    35Item
      4.
                    Submission
      of Matters to a Vote of Securities Holders
                    
                    35Item
      5.
                    Other
      Information
                    
                    36Item
      6.
                    Exhibits
                    
                    36










GLOSSARY
OF TERMS





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




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




See
accompanying notes to consolidated financial statements





3





VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED
BALANCE SHEETS




June 30,
                  2008
                
                
                December 31,
                  2007Restated
                  (unaudited)AssetsCurrent
      assetsCash
      and cash equivalents
                
                $
                3,900,503
                
                
                $
                3,109,563Trade
      accounts receivable, net
                
                
                10,825,985
                
                
                
                4,372,731Derivative
      assets
                
                
                —
                
                
                
                4,017,085Other
      current assets
                
                
                719,273
                
                
                
                453,198Total
      current assets
                
                
                15,445,761
                
                
                
                11,952,577Property
      and equipment, net of accumulated depreciation
                
                
                203,037
                
                
                
                166,455Natural
      gas and oil properties, at cost
                
                
                219,299,247
                
                
                
                135,435,240Accumulated
      depletion
                
                
                (34,594,152
                )
                
                
                (28,451,891
                )Natural
      gas and oil properties, net - full cost method
                
                
                184,705,095
                
                
                
                106,983,349Other
      assetsDerivative
      assets
                
                
                702,079
                
                
                
                1,329,511Deferred
      financing costs
                
                
                973,191
                
                
                
                941,833Non-current
      deposits
                
                
                45,963
                
                
                
                8,285,883Other
      assets
                
                
                1,061,309
                
                
                
                1,519,577Total
      assets
                
                $
                203,136,435
                
                
                $
                131,179,185Liabilities
      and members’ equityCurrent
      liabilitiesAccounts
      payable - trade
                
                $
                947,507
                
                
                $
                1,056,627Accounts
      payable - natural gas and oil
                
                
                1,034,750
                
                
                
                257,073Payables
      to affiliates
                
                
                4,161,308
                
                
                
                3,838,328Derivative
      liabilities
                
                
                27,109,030
                
                
                
                —Accrued
      expenses
                
                
                3,435,907
                
                
                
                203,159Total
      current liabilities
                
                
                36,688,502
                
                
                
                5,355,187Long-term
      debt
                
                
                102,500,000
                
                
                
                37,400,000Derivative
      liabilities
                
                
                47,582,633
                
                
                
                5,903,384Asset
      retirement obligations
                
                
                1,532,881
                
                
                
                189,711Total
      liabilities
                
                
                188,304,016
                
                
                
                48,848,282Commitments
      and contingenciesMembers’
      equityMembers’
      capital, 10,795,000 common units issued and outstanding at June 30, 2008
      and December 31, 2007
                
                
                19,220,375
                
                
                
                90,257,856Class
      B units, 420,000 issued and outstanding at June 30, 2008 and December 31,
      2007
                
                
                3,495,153
                
                
                
                2,131,995Accumulated
      other comprehensive loss
                
                
                (7,883,109
                )
                
                
                (10,058,948
                )Total
      members’ equity
                
                
                14,832,419
                
                
                
                82,330,903Total
      liabilities and members’ equity
                
                $
                203,136,435
                
                
                $
                131,179,185




See
accompanying notes to consolidated financial statements




4




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED
STATEMENTS OF CASH FLOWS


(Unaudited)




Six Months Ended
                  June 30,2008
                
                
                2007Operating
      activities
                
                RestatedNet
      income (loss)
                
                $
                (62,951,980
                )
                
                $
                614,157Adjustments
      to reconcile net income (loss) to net cash provided by (used in) operating
      activities:Depreciation,
      depletion, amortization and accretion
                
                
                6,154,002
                
                
                
                4,320,289Amortization
      of deferred financing costs
                
                
                173,045
                
                
                
                142,234Bad
      debt expense
                
                
                —
                
                
                
                1,007,458Unit-based
      compensation
                
                
                1,896,347
                
                
                
                563,143Amortization
      of premiums paid and non-cash settlements on derivative
      contracts
                
                
                2,531,193
                
                
                
                733,504Unrealized
      loss on commodity derivative contracts
                
                
                72,396,143
                
                
                
                —Changes
      in operating assets and liabilities:Trade
      accounts receivable
                
                
                (6,453,254
                )
                
                
                (322,027
                )Payables
      to affiliates
                
                
                614,969
                
                
                
                (2,083,796
                )Other
      current assets
                
                
                (223,398
                )
                
                
                (12,372
                )Price
      risk management activities, net
                
                
                (442,840
                )
                
                
                (8,475,676
                )Accounts
      payable
                
                
                668,556
                
                
                
                2,393,459Accrued
      expenses
                
                
                3,158,730
                
                
                
                (1,713,858
                )Net
      cash provided by (used in) operating activities
                
                
                17,521,513
                
                
                
                (2,833,485
                )Investing
      activitiesAdditions
      to property and equipment
                
                
                (61,659
                )
                
                
                (31,211
                )Additions
      to natural gas and oil properties
                
                
                (6,677,962
                )
                
                
                (6,132,607
                )Acquisitions
      of natural gas and oil properties
                
                
                (66,389,952
                )
                
                
                —Deposits
      and prepayments of natural gas and oil properties
                
                
                48,074
                
                
                
                (455,883
                )Net
      cash used in investing activities
                
                
                (73,081,499
                )
                
                
                (6,619,701
                )Financing
      activitiesProceeds
      from borrowings
                
                
                74,400,000
                
                
                
                114,600,000Repayment
      of debt
                
                
                (9,300,000
                )
                
                
                (99,667,500
                )Contributions
      from members
                
                
                —
                
                
                
                41,221,000Distributions
      to members
                
                
                (8,254,240
                )
                
                
                (41,220,000
                )Financing
      costs
                
                
                (204,403
                )
                
                
                (1,194,270
                )Offering
      costs
                
                
                (54,192
                )
                
                
                (1,571,993
                )Purchase
      of units for unit-based compensation
                
                
                (236,239
                )
                
                
                —Net
      cash provided by financing activities
                
                
                56,350,926
                
                
                
                12,167,237Net
      increase in cash and cash equivalents
                
                
                790,940
                
                
                
                2,714,051Cash and cash
      equivalents, beginning of period
                
                
                3,109,563
                
                
                
                1,730,956Cash and cash
      equivalents, end of period
                
                $
                3,900,503
                
                
                $
                4,445,007Supplemental
      cash flow information:Cash
      paid for interest
                
                $
                1,802,039
                
                
                $
                4,826,132Non-cash
      financing and investing activities:Asset
      retirement obligations
                
                $
                1,309,854
                
                
                $
                155,800Assumption
      of fixed-price oil swaps
                
                $
                1,128,114
                
                
                $
                —Deferred
      swap liability
                
                $
                —
                
                
                $
                7,322,685Initial
      contribution of assets
                
                $
                —
                
                
                $
                3,289,055Transfer
      of deposit for acquisition of natural gas and oil
    properties
                
                $
                7,830,000
                
                
                
                —




See accompanying notes to
consolidated financial statements




5




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


(Unaudited)




Three Months Ended
                  June 30,
                
                
                Six Months Ended
                  June 30,2008
                
                
                2007
                
                
                2008
                
                
                2007Restated
                
                
                
                
                
                RestatedNet
      income (loss)
                
                $
                (47,019,744
                )
                
                $
                2,239,906
                
                
                $
                (62,951,980
                )
                
                $
                614,157Net
      gains (losses) from cash flow hedging activities:Unrealized
      mark-to-market gains (losses) arising during the period
                
                
                1,256,501
                
                
                
                698,959
                
                
                
                2,747,150
                
                
                
                (10,966,008
                )Reclassification
      adjustments for settlements
                
                
                (154,883
                )
                
                
                911,890
                
                
                
                (571,311
                )
                
                
                507,743Other
      comprehensive income (loss)
                
                
                1,101,618
                
                
                
                1,610,849
                
                
                
                2,175,839
                
                
                
                (10,458,265
                )Comprehensive
      income (loss)
                
                $
                (45,918,126
                )
                
                $
                3,850,755
                
                
                $
                (60,776,141
                )
                
                $
                (9,844,108
                )




See
accompanying notes to consolidated financial statements




6






VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)




Description
of the Business:





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




References
in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are
to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard
Natural Gas, LLC, Trust Energy Company, LLC, (“TEC”), VNR Holdings, Inc.
(“VNRH”), Ariana Energy, LLC (“Ariana Energy”) and Vanguard Permian, LLC
(“Vanguard Permian”) and (2) “Vanguard Predecessor,” “Predecessor,” “our
operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.




We were
formed in October 2006 but effective January 5, 2007, Vanguard Natural Gas, LLC
(formerly Nami Holding Company, LLC) was separated into our operating subsidiary
and Vinland Energy Eastern, LLC ("Vinland"). As part of the separation, we
retained all of our Predecessor’s proved producing wells and associated
reserves. We also retained 40% of our Predecessor’s working interest in the
known producing horizons in approximately 95,000 gross undeveloped acres and a
contract right to receive approximately 99% of the net proceeds from the sale of
production from certain producing gas and oil wells. In the separation, Vinland
was conveyed the remaining 60% of our Predecessor’s working interest in the
known producing horizons in this acreage, 100% of our Predecessor’s working
interest in depths above and 100 feet below our known producing horizons, all of
our gathering and compression assets and all employees other than our President
and Chief Executive Officer and our Executive Vice President and Chief Financial
Officer. Vinland acts as the operator of our existing wells and all of the wells
that we drill in Appalachia. We refer to these events as the
"Restructuring."




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





1.
            Summary
      of Significant Accounting Policies





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





As of
June 30, 2008, the Company’s significant accounting policies are consistent with
those discussed in Note 1 of the Company’s consolidated financial statements
contained in the Company’s 2007 Annual Report on Form 10-K/A with the exception
noted in (b) below.





(a)
            Basis of
      Presentation and Principles of
  Consolidation:





The
consolidated financial statements as of June 30, 2008 and December 31, 2007 and
for the three months and six months ended June 30, 2008 and 2007 include the
accounts of VNR and its wholly owned subsidiaries.  The Company
presents its financial statements in accordance with GAAP.  All
intercompany transactions and balances have been eliminated upon
consolidation.





(b)
            Financial
      Statement Restatement:




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




7




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





Under
SFAS No. 133, the fair value of derivative contracts is recognized in the
Consolidated Balance Sheets as an asset or liability, and the amounts received
or paid under the contracts are reflected in earnings during the period in which
the underlying production occurs.  If the derivative contracts qualify
for hedge accounting treatment, the fair value of the hedge contract is recorded
in “accumulated other comprehensive income”, and changes in the fair value do
not affect net income in the period.  If the derivative contract does
not qualify for hedge accounting treatment, the change in the fair value of the
contract is reflected in earnings during the period as unrealized gain or loss
on commodity derivatives. Under the cash flow hedge accounting treatment used by
the Company previously, the fair values of the hedge contracts were recognized
in the consolidated balance sheets with the resulting unrealized gain or loss
recorded initially in accumulated other comprehensive income and later
reclassified through earnings when the hedged production affected earnings. As a
result of the determination that the documentation failed to meet cash flow
hedge accounting treatment, the unrealized gain or loss should have been
recorded in the consolidated statements of operations as a component of earnings
in 2008. In addition, the net derivative loss at December 31, 2007 related to
the de-designated natural gas derivative contracts entered into in 2007 will
continue to be reported in accumulated other comprehensive income until the
month in which the transactions settle.




In this
Form 10-Q/A, the Company is restating the Consolidated Financial Statements for
the three months and six months ended June 30, 2008. A non-cash mark to market
unrealized loss on commodity derivatives of $52.2 million has been reclassified
from other comprehensive loss to a separate line on the Consolidated Statements
of Operations. The effect of the reclassification on our financial statements is
as follows:




Three Months Ended
                  June 30, 2008
                
                
                Six Months Ended
                  June 30, 2008Previously
                  Reported
                
                
                As
                  Restated
                
                
                Previously
                  Reported
                
                
                As
                  RestatedConsolidated
      Statements of OperationsUnrealized
      loss on commodity derivative contracts
                
                $
                —
                
                
                $
                (52,186,386
                )
                
                $
                —
                
                
                $
                (72,396,143
                )Net
      income (loss)
                
                $
                5,164,168
                
                
                $
                (47,019,744
                )
                
                $
                9,440,188
                
                
                $
                (62,951,980
                )Basic
      and diluted net income (loss) per unit
                
                $
                0.46
                
                
                $
                (4.19
                )
                
                $
                0.84
                
                
                $
                (5.61
                )




June 30, 2008Previously
                          Reported
                        
                        
                        As
                          RestatedConsolidated
      Balance SheetsAccumulated
      other comprehensive loss
                        
                        $
                        (80,275,277
                        )
                        
                        $
                        (7,883,109
                        )




For the Six Months Ended
                    June 30, 2008Previously
                    Reported
                  
                  
                  As
                    RestatedConsolidated
      Statements of Cash FlowsCash
      Flows from Operating Activities:Net
      income (loss)
                  
                  $
                  9,440,188
                  
                  
                  $
                  (62,951,980
                  )Unrealized
      loss on commodity derivative contracts
                  
                  $
                  —
                  
                  
                  $
                  72,396,143





8




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





(c)
            Recently
      Adopted Accounting
Pronouncements:





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





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





(d)
            New
      Pronouncements Issued But Not Yet
  Adopted:





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





In
December 2007, the FASB issued SFAS No. 160,“Non-controlling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling
owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only
those entities that have an outstanding non-controlling interest in one or more
subsidiaries or that deconsolidate a subsidiary. This statement is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008, which will be our fiscal year 2009. Based upon the June 30, 2008 balance
sheet, SFAS 160 would have no impact on the consolidated financial
statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is intended to
improve financial reporting about derivative instruments and hedging activities
by requiring enhanced disclosures to enable investors to better understand their
effects on an entity’s financial position, financial performance, and cash
flows. SFAS 161 achieves these improvements by requiring disclosure of the fair
values of derivative instruments and their gains and losses in a tabular format.
It also provides more information about an entity’s liquidity by requiring
disclosure of derivative features that are credit risk-related. Finally, it
requires cross-referencing within footnotes to enable financial statement users
to locate important information about derivative instruments. SFAS 161 is
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application encouraged. We are
currently evaluating the impact of adopting SFAS 161on our consolidated
financial statements.





9




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





(e)
            Use of
      Estimates:





The
preparation of financial statements in conformity with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. The most significant estimates pertain to proved
natural gas and oil reserves and related cash flow estimates used in impairment
tests of natural gas and oil properties, the fair value of derivative contracts
and asset retirement obligations, accrued natural gas and oil revenues and
expenses, as well as estimates of expenses related to depreciation, depletion,
amortization and accretion. Actual results could differ from those
estimates.





2.    
Acquisitions





On
December 21, 2007, we entered in to a Purchase and Sale Agreement with the
Apache Corporation for the purchase of certain oil and natural gas properties
located in ten separate fields in the Permian Basin of West Texas and
Southeastern New Mexico. The purchase price for said assets was $78.3 million
with an effective date of October 1, 2007. We completed this acquisition on
January 31, 2008 for an adjusted purchase price of $73.4 million, subject to
customary post closing adjustments. The post closing adjustments reduced the
final purchase price to $71.5 million and included a purchase price adjustment
of $6.8 million for the cash flow from the acquired properties for the period
between the effective date, October 1, 2007, and the final settlement date. The
purchase price included a payment of $7.8 million paid by us to the seller in
December 2007 and this amount is reported in non-current deposits in our
consolidated balance sheet at December 31, 2007. As part of this acquisition, we
assumed fixed-price oil swaps covering approximately 90% of the estimated proved
developed producing oil reserves through 2011 at a weighted average price of
$87.29. The fair value of these fixed-price oil swaps was a liability of
$1,128,114 at January 31, 2008. This acquisition was funded with borrowings
under our existing reserve-based credit facility. At this time, we do not have
the information available to provide pro-forma results of operations for the
three months and six months ended June 30, 2007. In lieu of the pro-forma
information, the table below reflects the audited statement of combined revenues
and direct operating expenses of the oil and gas properties purchased from
Apache for the year ended December 31, 2007.





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





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





3.    
Accounts Receivable and Allowance for Doubtful Accounts





We
established an approximate $1 million provision for a loss on the entire amount
due from a customer which filed for protection under Chapter 11 of the
Bankruptcy Code in May 2007. The account receivable was due from oil sales
through December 2006 at which time we ceased selling oil to the customer. As
the amount of any potential recovery is uncertain, we elected to reserve the
entire balance and it is reflected as bad debt expense on our consolidated
statement of operations for the six months ended June 30, 2007. We began selling
the oil production we formerly sold to this customer to a new customer beginning
in March 2007.




4.   
Credit Facilities and Long-Term Debt





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




Amount OutstandingDescription
                    
                    Interest
                      Rate
                    
                    Maturity
                      Date
                    
                    June 30,
                      2008
                    
                    
                    December31,
                      2007$400
      million senior secured revolver facility
                    
                    Variable
                    
                    March
      31, 2011
                    
                    
                    102,500,000
                    
                    
                    
                    37,400,000Total
                    
                    
                    
                    
                    
                    $
                    102,500,000
                    
                    
                    $
                    37,400,000




10




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





$400
Million Senior Secured Revolver Facility




In
January 2007, the Company entered into a four-year $200 million revolving credit
facility (“reserve-based credit facility”) with Citibank, N.A. and BNP Paribas.
All of our Predecessor’s outstanding debt was repaid with borrowings under this
reserve-based credit facility, including an early prepayment penalty of $2.5
million. The available credit line (“Borrowing Base”) is subject to adjustment
from time to time but not less than on a semi-annual basis based on the
projected discounted present value (as determined by independent petroleum
engineers) of estimated future net cash flows from certain proved natural gas
and oil reserves of the Company. The initial Borrowing Base was set at $115.5
million and is secured by a first lien security interest in all of the Company’s
natural gas and oil properties. However, the borrowing base was subject to $1
million reductions per month starting on July 1, 2007 through November 1, 2007,
which resulted in a borrowing base of $110.5 million as reaffirmed in November
2007 pursuant to the semi-annual borrowing base redetermination . We applied
$80.0 million of the net proceeds from our IPO in October 2007 to reduce our
indebtedness under the reserve-based credit facility. In February 2008, our
reserve-based credit facility was amended and restated to extend the maturity
from January 3, 2011 to March 31, 2011, increase the facility amount from $200.0
million to $400.0 million, increase our borrowing base from $110.5 million to
$150.0 million and add two additional financial institutions as lenders,
Wachovia Bank, N.A. and The Bank of Nova Scotia. Additional borrowings were made
pursuant to the acquisition of natural gas and oil properties in the Permian
Basin in January 2008 and indebtedness under the reserve-based credit facility
totaled $102.5 million at June 30, 2008.





Interest
rates under the reserve-based credit facility are based on Euro-Dollars (LIBOR)
or ABR (Prime) indications, plus a margin. At June 30, 2008, the applicable
margin and other fees increase as the utilization of the borrowing base
increases as follows:





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




The
Credit Agreement contains a number of customary covenants that require the
Company to maintain certain financial ratios, limit the Company’s ability to
incur additional debt, sell assets, create liens, or make certain distributions.
At June 30, 2008, we were in compliance with our debt covenants.




The
Credit Agreement required the Company to enter into a commodity price hedge
position establishing certain minimum fixed prices for anticipated future
production equal to approximately 84% of the projected production from proved
developed producing reserves from the second half of 2007 through 2011. Also,
the Credit Agreement required that certain production put option contracts for
the years 2007, 2008 and 2009 be put in place to create a price floor for
anticipated production from new wells drilled. SeeNote 5. Price Risk Management
Activities for further discussion.





5.    
Price Risk Management Activities





We have
entered into derivative contracts with counterparties that are lenders under our
reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova
Scotia and Wachovia Bank, N.A., to hedge price risk associated with a portion of
our natural gas and oil production. While it is never management’s intention to
hold or issue derivative instruments for speculative trading purposes,
conditions sometimes arise where actual production is less than estimated which
has, and could, result in overhedged volumes. Under fixed-priced commodity swap
agreements, the Company receives a fixed price on a notional quantity in
exchange for paying a variable price based on a market index, such as the
Columbia Gas Appalachian Index (‘TECO Index”) or Henry Hub for natural gas
production and the West Texas Intermediate Light Sweet for oil production. Under
put option agreements, we pay the counterparty the fair value at the purchase
date. At settlement date we receive the excess, if any, of the fixed floor over
floating rate. Under collar contracts, we pay the counterparty if the market
price is above the ceiling price and the counterparty pays us if the market
price is below the floor price on a notional quantity. The collars and put
options for natural gas are settled based on the NYMEX price for natural gas at
Henry Hub.




11




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





Under
SFAS No. 133, all derivative instruments are recorded on the consolidated
balance sheets at fair value as either short-term or long-term assets or
liabilities based on their anticipated settlement date.  We net
derivative assets and liabilities for counterparties where we have a legal right
of offset. Changes in the derivative’s fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For qualifying cash
flow hedges, the unrealized gain or loss on the derivative is deferred in
accumulated other comprehensive income (loss) in the equity section of the
consolidated balance sheets to the extent the hedge is effective. Gains and
losses on cash flow hedges included in accumulated other comprehensive income
(loss) are reclassified to realized gains (losses) on derivative contracts in
the period that the related production is delivered. The unrealized gains
(losses) on derivative contracts that do not qualify for hedge accounting
treatment are recorded as current income or expense in the Consolidated
Statements of Operations.





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





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





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




Swap
Agreements





Gas
                  
                  
                  OilContract
      Period
                  
                  MMBtu
                  
                  
                  Weighted
                    Average
                    FixedPrice
                  
                  
                  Bbls
                  
                  
                  WTI
                    Price2008
                  
                  
                  1,452,439
                  
                  
                  $
                  9.00
                  
                  
                  
                  97,500
                  
                  
                  $
                  90.302009
                  
                  
                  2,657,046
                  
                  
                  $
                  8.85
                  
                  
                  
                  181,500
                  
                  
                  $
                  87.232010
                  
                  
                  2,387,640
                  
                  
                  $
                  8.76
                  
                  
                  
                  164,250
                  
                  
                  $
                  85.652011
                  
                  
                  2,196,012
                  
                  
                  $
                  7.15
                  
                  
                  
                  151,250
                  
                  
                  $
                  85.502012
                  
                  
                  —
                  
                  
                  $
                  —
                  
                  
                  
                  144,000
                  
                  
                  $
                  80.00




Put Option
Contracts




Contract
      Period
                      
                      Volume in MMBtu
                      
                      
                      Purchased NYMEX
                        Price Floor2008
                      
                      
                      561,311
                      
                      
                      $
                      7.502009
                      
                      
                      840,139
                      
                      
                      $
                      7.50





12




VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





Collars





GasMMBtu
                
                
                Floor
                
                
                CeilingProduction
      Period:July
      – September 2008
                
                
                300,000
                
                
                $
                9.00
                
                
                $
                9.00October
      – December 2008
                
                
                300,000
                
                
                $
                9.00
                
                
                $
                9.25January
      2009 – December 2009
                
                
                1,000,000
                
                
                $
                7.50
                
                
                $
                9.00January
      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. At June 30, 2008, the Company had open interest rate derivative
contracts as follows:





Principal
                
                
                Fixed
                  LiborBalance
                
                
                RatesPeriod:July
      1, 2008 to December 10, 2010
                
                $
                20,000,000
                
                
                
                3.88
                %July
      1, 2008 to January 31, 2011
                
                $
                30,000,000
                
                
                
                3.00
                %July
      1, 2008 to March 31, 2011
                
                $
                10,000,000
                
                
                
                2.66
                %





6.    
Fair Value Measurements





As
discussed inNote 1.Summary of Significant
Accounting Policies (c), we prospectively adopted SFAS 157 for financial assets
and financial liabilities. SFAS 157 does not expand the use of fair value
measurements, but rather, provides a framework for consistent measurement of
fair value for those assets and liabilities already measured at fair value under
other accounting pronouncements. Certain specific fair value measurements, such
as those related to share-based compensation, are not included in the scope of
SFAS 157. Primarily, SFAS 157 is applicable to assets and liabilities related to
financial instruments, to some long-term investments and liabilities, to initial
valuations of assets and liabilities acquired in a business combination, and to
long-lived assets carried at fair value subsequent to an impairment write-down.
It does not apply to oil and natural gas properties accounted for under the full
cost method, which are subject to impairment based on SEC rules. SFAS 157
applies to assets and liabilities carried at fair value on the consolidated
balance sheet, as well as to supplemental fair value information about financial
instruments not carried at fair value.





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





13


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


The
Company has applied the provisions of SFAS 157 to assets and liabilities
measured at fair value on a recurring basis. This includes oil and natural gas
and interest rate derivatives contracts. SFAS 157 provides a definition of fair
value and a framework for measuring fair value, as well as expanding disclosures
regarding fair value measurements. The framework requires fair value measurement
techniques to include all significant assumptions that would be made by willing
participants in a market transaction. These assumptions include certain factors
not consistently provided for previously by those companies utilizing fair value
measurement; examples of such factors would include the company’s own credit
standing (when valuing liabilities) and the buyer’s risk premium. In adopting
SFAS 157, the Company determined that the impact of these additional assumptions
on fair value measurements did not have a material effect on financial position
or results of operations. The Company is still assessing the potential impact of
implementation in 2009 of those portions of the guidance for which the effective
date has been deferred by the FASB.





SFAS 157
defines fair value as the exchange price that would be received for an asset or
paid to transfer a liability (an exit price) in the principal or most
advantageous market for the asset or liability in an orderly transaction between
market participants on the measurement date. SFAS 157 provides a hierarchy of
fair value measurements, based on the inputs to the fair value estimation
process. It requires disclosure of fair values classified according to the
“levels” described below. The hierarchy is based on the reliability of the
inputs used in estimating fair value and requires an entity to maximize the use
of observable inputs and minimize the use of unobservable inputs when measuring
fair value. The framework for fair value measurement assumes that transparent
“observable” (Level 1) inputs generally provide the most reliable evidence of
fair value and should be used to measure fair value whenever available. The
classification of a fair value measurement is determined based on the lowest
level (with Level 3 as lowest) of significant input to the fair value estimation
process.





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





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





As
required by SFAS No. 157, financial assets and liabilities are classified
based on the lowest level of input that is significant to the fair value
measurement. Our assessment of the significance of a particular input to the
fair value measurement requires judgment, and may affect the valuation of the
fair value of assets and liabilities and their placement within the fair value
hierarchy levels. The Company has classified the fair values of all its
derivative contracts as Level 2.





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





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





14


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


7. Asset
Retirement Obligations





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





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




8. Related
Party Transactions





Pursuant
to the Restructuring, in Appalachia, we rely on Vinland to execute our drilling
program, operate our wells and gather our natural gas. We reimburse Vinland $60
per well per month (in addition to normal third party operating costs) for
operating our current natural gas and oil properties in Appalachia under a
Management Services Agreement (“MSA”) which costs are reflected in our lease
operating expenses. Also, Vinland receives a $0.25 per Mcf transportation fee on
existing wells drilled at December 31, 2006 and $0.55 per Mcf transportation fee
on any new wells drilled after December 31, 2006 within the area of mutual
interest or “AMI.” This transportation fee only encompasses transporting the
natural gas to third party pipelines at which point additional transportation
fees to natural gas markets would apply. These transportation fees are outlined
under a Gathering and Compression Agreement (“GCA”) with Vinland and are
reflected in our lease operating expenses. Costs incurred under the MSA were
$0.2 million for each of the three months ended June 30, 2008 and 2007 and $0.3
million for each of the six months ended June 30, 2008 and 2007. Costs incurred
under the GCA were $0.2 million and $0.4 million for the three months ended June
30, 2008 and 2007 and $0.5 million and $0.7 million for the six months ended
June 30, 2008 and 2007. A payable of $4.1 million and $3.8 million is reflected
on our June 30, 2008 and December 31, 2007 consolidated balance sheets in
connection with these agreements and direct expenses incurred by Vinland related
to the drilling of new wells and operations of all of our existing wells in
Appalachia.





9. Common
Units and Net Income per Unit





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





In
accordance with SFAS 128, dual presentation of basic and diluted earnings
per unit has been presented in the consolidated statements of operations for the
three months and six months ended June 30, 2008 and 2007 for each class of units
issued and outstanding at that date: common units and Class B
units. Net income (loss) per unit is allocated to the common units and the
Class B units on an equal basis.





10. Unit-Based
Compensation





In April
2007, the sole member at that time reserved 460,000 restricted Class B units in
VNR for issuance to employees. Certain members of management were granted
365,000 restricted Class B units in VNR in April 2007, which vest two years from
the date of grant. In addition, another 55,000 restricted VNR Class B units were
issued in August 2007 to two other employees that were hired in April and May of
2007, which will vest after three years. The remaining 40,000 restricted Class B
units are available to be awarded to new employees or members of our board of
directors as they are retained. In October 2007 and February 2008, four board
members were granted 5,000 common units each of which will vest after one year.
Additionally, in October 2007, two officers were granted options to purchase an
aggregate of 175,000 units under our long-term incentive plan with an exercise
price equal to the initial public offering price of $19.00 which vested
immediately upon being granted and had a fair value of $0.1 million on the date
of grant.








15


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


Furthermore,
on March 27, 2008, phantom units were granted to two officers in amounts equal
to 1.0% of our units outstanding at January 1, 2008 and the amount paid will
equal the appreciation in value of the units, if any, from the date of the grant
until the determination date (December 31, 2008), plus cash distributions paid
on the units, less an 8% hurdle rate. As of June 30, 2008, a liability and
expense of $0.1 million has been recognized. These common units, Class B units,
options and phantom units were granted as partial consideration for services to
be performed under employment contracts and thus will be subject to accounting
for these grants under SFAS No. 123(R),Share-Based
Payment.





The fair
value of restricted units issued is determined based on the fair market value of
common units on the date of the grant. This value is amortized over the vesting
period as referenced above. A summary of the status of the non-vested units as
of June 30, 2008 is presented below:





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





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





11.  Subsequent
Event





On July
18, 2008, we entered in to a Purchase and Sale Agreement with Segundo Navarro
Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, for the
acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas. The purchase price for said assets was
$53.4 million with an effective date of June 1, 2008. We completed this
acquisition on July 28, 2008 for the purchase price, subject to customary
post-closing adjustments to be determined. This acquisition was funded with
borrowings under our reserve-based credit facility and through the issuance of
1,350,873 common units of the Company. The effects of this acquisition are not
reflected in the cash flows and other financial and operating information
described herein due to the acquisition closing on July 28, 2008. Upon closing
this transaction, we assumed natural gas swaps and collars based on Houston Ship
Channel pricing for approximately 85% of the estimated gas production from
existing producing wells for the period beginning July 2008 through December
2011 which had a fair value of $3.6 million on July 28, 2008.





16





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




The
following discussion and analysis should be read in conjunction with the
financial statements and related notes presented in Item 1 of this Quarterly
Report on Form 10-Q/A and information disclosed in our 2007 Annual Report
on Form 10-K.




Forward-Looking
Statements




This
report contains “forward-looking statements” intended to qualify for the safe
harbors from liability established by the Private Securities Litigation Reform
Act of 1995. Statements included in this quarterly report that are not
historical facts (including any statements concerning plans and objectives of
management for future operations or economic performance, or assumptions or
forecasts related thereto), including, without limitation, the information set
forth in Management’s Discussion and Analysis of Financial Condition and Results
of Operations, are forward-looking statements. These statements can be
identified by the use of forward-looking terminology including “may,” “believe,”
“expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar
words. These statements discuss future expectations, contain projections of
results of operations or of financial condition, or state other
“forward-looking” information. We and our representatives may from time to time
make other oral or written statements that are also forward-looking
statements.




Such
forward-looking statements are subject to various risks and uncertainties that
could cause actual results to differ materially from those anticipated as of the
date of this report. Although we believe that the expectations reflected in
these forward-looking statements are based on reasonable assumptions, no
assurance can be given that these expectations will prove to be correct.
Important factors that could cause our actual results to differ materially from
the expectations reflected in these forward-looking statements include, among
other things, those set forth in the Risk Factor section of the 2007 Annual
Report on Form 10-K/A and this Quarterly report on Form 10-Q/A, and those set
forth from time to time in our filings with the SEC, which are available on our
website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and
Retrieval System (“EDGAR”) at http://www.sec.gov.




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




Overview




We are a
publicly-traded limited liability company focused on the acquisition and
development of mature, long-lived natural gas and oil properties in the United
States. Our primary business objective is to generate stable cash flows allowing
us to make quarterly cash distributions to our unitholders and over time to
increase our quarterly cash distributions through the acquisition of new natural
gas and oil properties. Our properties are located in the southern portion of
the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee,
the Permian Basin, primarily in West Texas and Southeastern New Mexico and in
South Texas, with the closing of our recent acquisition.




We owned
working interests in 1,383 gross (917 net) productive wells at June 30, 2008 and
our average net production for the twelve months ended December 31, 2007
and for the three months and six months ended June 30, 2008 was 11,610 Mcfe per
day, 15,888 Mcfe per day and 15,505 Mcfe per day, respectively. We also have an
approximate 40% working interest in the known producing horizons in
approximately 104,000 gross undeveloped acres surrounding or adjacent to our
existing wells located in southeast Kentucky and northeast Tennessee. Vinland
Energy Operations, LLC (“Vinland”) acts as the operator of our existing wells in
Appalachia and all of the wells that we will drill in this area.





Financial
Statement Restatement




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





17




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




Initial
Public Offering




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




Permian
Basin Acquisition





On
December 21, 2007, we entered in to a Purchase and Sale Agreement with the
Apache Corporation for the purchase of certain oil and natural gas properties
located in ten separate fields in the Permian Basin of West Texas and
Southeastern New Mexico. The purchase price for said assets was $78.3 million
with an effective date of October 1, 2007. We completed this acquisition on
January 31, 2008 for an adjusted purchase price of $73.4 million, subject to
customary post closing adjustments. The post closing adjustments reduced the
final purchase price to $71.5 million and included a purchase price adjustment
of $6.8 million for the cash flow from the acquired properties for the period
between the effective date, October 1, 2007, and the final settlement date. This
acquisition was funded with borrowings under our reserve-based credit facility.
Through this acquisition, we acquired working interests in 390 gross wells (67
net wells), 49 of which we operate. With respect to operations, we have
established two district offices, one in Lovington, New Mexico and the other in
Christoval, Texas to manage these assets. Our operating focus will be on
maximizing existing production and looking for complementary acquisitions that
we can add to this operating platform. With this acquisition, based on internal
reserve estimates, we acquired 4.4 million barrels of oil equivalent, 83% of
which is oil and 90% of which is proved developed producing.





South
Texas Acquisition





On July
18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro
Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, for the
acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas. The purchase price for said assets was
$53.4 million with an effective date of June 1, 2008. We completed this
acquisition on July 28, 2008 for the purchase price, subject to customary
post-closing adjustments to be determined. This acquisition was funded with
borrowings under our reserve-based credit facility and through the issuance of
1,350,873 common units of the Company. In this purchase, we acquired an average
of a 98% working interest in 91 producing wells and an average 47.5% working
interest in approximately 4,705 gross acres with 41 identified proved
undeveloped locations. An affiliate of Lewis Energy Group will operate all the
properties and is contractually obligated to drill six wells in 2008 and seven
wells in 2009 through 2011. Based on internal reserve estimates, we acquired 20
Bcfe of proved reserves, 98% of which is natural gas and 65% of which is proved
developed producing. The effects of this acquisition are not reflected in the
cash flows and other financial and operating information described herein due to
the acquisition closing on July 28, 2008. Upon closing this transaction, we
assumed natural gas swaps and collars based on Houston Ship Channel pricing for
approximately 85% of the estimated gas production from existing producing wells
for the period beginning July 2008 through December 2011 which had a fair value
of $3.6 million on July 28, 2008.





Our
Relationship with Vinland




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





18




Restructuring
Plan




Prior to
the separation, our Predecessor owned all of the assets that are currently owned
by us and Vinland in Appalachia. As part of the separation of our operating
company and Vinland, effective January 5, 2007, we conveyed to Vinland 60%
of our Predecessor’s working interest in the known producing horizons in
approximately 95,000 gross undeveloped acres in the AMI, 100% of our
Predecessor’s interest in an additional 125,000 undeveloped acres and certain
coalbed methane rights located in the Appalachian Basin, the rights to any
natural gas and oil located on our acreage at depths above and 100 feet below
our known producing horizons, all of our gathering and compression assets, and
all employees other than our President and Chief Executive Officer and our
Executive Vice President and Chief Financial Officer. We retained all of our
Predecessor’s proved producing wells and associated reserves. We also retained
40% of our Predecessor’s working interest in the known producing horizons in
approximately 95,000 gross undeveloped acres in the AMI and a contract right to
receive approximately 99% of the net proceeds, after deducting royalties paid to
other parties, severance taxes, third-party transportation costs, costs incurred
in the operation of wells and overhead costs, from the sale of production from
certain producing natural gas and oil wells, which accounted for approximately
4.5% of our estimated proved reserves as of December 31, 2007. In addition,
we changed the name of our operating company from Nami Holding Company, LLC to
Vanguard Natural Gas, LLC. Collectively, we refer to these events as the
“Restructuring.”




Private
Offering




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





Reserve-Based
Credit Facility




On
January 3, 2007, our operating company entered into a reserve-based credit
facility which is available for our general limited liability company purposes,
including, without limitation, capital expenditures and acquisitions. Our
obligations under the reserve-based credit facility are secured by substantially
all of our assets. Our initial borrowing base under the reserve-based credit
facility was set at $115.5 million. However, the borrowing base was subject to
$1.0 million reductions per month starting on July 1, 2007 through November 1,
2007, which resulted in a borrowing base of $110.5 million as reaffirmed in
November 2007 pursuant to a semi-annual borrowing base redetermination. We
applied $80.0 million of the net proceeds from our IPO in October 2007 to reduce
our indebtedness under the reserve-based credit facility. In February 2008, our
reserve-based credit facility was amended and restated to extend the maturity
from January 3, 2011 to March 31, 2011, increase the facility amount from $200.0
million to $400.0 million, increase our borrowing base from $110.5 million to
$150.0 million and add two additional financial institutions as lenders.
Additional borrowings were made pursuant to the acquisition of natural gas and
oil properties in the Permian Basin in January 2008 and indebtedness under the
reserve-based credit facility totaled $102.5 million at June 30, 2008. At June
30, 2008, the applicable margin and other fees increase as the utilization of
the borrowing base increases as follows:




Borrowing
Base Utilization Grid





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




In July
2008, an additional $31.0 million was borrowed under the reserve-based credit
facility to fund a portion of the cash consideration paid in the South Texas
acquisition. As a result, as of August 12, 2008, borrowings under the
reserve-based credit facility increased to $131.5 million and the borrowing base
is in the process of being redetermined to include the natural gas and oil
properties from the South Texas acquisition.





19




Outlook




Our
revenue, cash flow from operations and future growth depend substantially on
factors beyond our control, such as economic, political and regulatory
developments, competition from other sources of energy, and access to capital.
Natural gas and oil prices historically have been volatile and may fluctuate
widely in the future. Sustained periods of low prices for natural gas or oil
could materially and adversely affect our financial position, our results of
operations, the quantities of natural gas and oil reserves that we can
economically produce and our access to capital. As required by our reserve-based
credit facility, we have mitigated this volatility for the years 2007 through
2012 by implementing a hedging program on our proved producing and total
anticipated production during this time frame.




We face
the challenge of natural gas and oil production declines. As a given well’s
initial reservoir pressures are depleted, natural gas and oil production
decreases, thus reducing our total reserves. We attempt to overcome this natural
decline both by drilling on our properties and acquiring additional reserves. We
will maintain our focus on controlling costs to add reserves through drilling
and acquisitions, as well as controlling the corresponding costs necessary to
produce such reserves. Our ability to add reserves through drilling is dependent
on our capital resources and can be limited by many factors, including the
ability to timely obtain drilling permits and regulatory approvals. Any delays
in drilling, completion or connection to gathering lines of our new wells will
negatively impact the rate of our production, which may have an adverse effect
on our revenues and as a result, cash available for distribution. In accordance
with our business plan, we intend to invest the capital necessary to maintain
our production at existing levels over the long-term.




Results of
Operations




The
following table sets forth selected financial and operating data for the periods
ended June 30:





Three Months Ended
                  June 30,
                
                
                Six Months Ended
                  June 30,2008
                
                
                2007
                
                
                2008(a)
                
                
                2007Revenues:
                
                Restated
                
                
                
                
                
                RestatedNatural
      gas and oil sales
                
                $
                20,852,386
                
                
                $
                10,106,737
                
                
                $
                34,853,984
                
                
                $
                19,068,353Realized
      losses on commodity cash flow hedges
                
                
                —
                
                
                
                (918,044
                )
                
                
                —
                
                
                
                (1,665,852
                )Total
      revenues
                
                
                20,852,386
                
                
                $
                9,188,693
                
                
                
                34,853,984
                
                
                $
                17,402,501Costs
      and expenses:Lease
      operating expenses
                
                $
                2,300,076
                
                
                $
                1,314,041
                
                
                $
                4,315,753
                
                
                $
                2,460,420Depreciation,
      depletion, amortization and accretion
                
                
                3,330,024
                
                
                
                2,291,426
                
                
                
                6,154,002
                
                
                
                4,320,289Selling,
      general and administrative expenses
                
                
                1,636,675
                
                
                
                781,198
                
                
                
                3,282,466
                
                
                
                1,215,489Bad
      debt expense
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                1,007,458Taxes
      other than income taxes
                
                
                1,428,965
                
                
                
                380,110
                
                
                
                2,395,078
                
                
                
                890,992Total
      costs and expenses
                
                $
                8,695,740
                
                
                $
                4,766,775
                
                
                $
                16,147,299
                
                
                $
                9,894,648Other
      Income and (Expense):Interest
      expense, net
                
                $
                (1,240,056
                )
                
                $
                (2,182,012
                )
                
                $
                (2,362,102
                )
                
                $
                (4,392,168
                )Realized
      loss on commodity derivative contracts
                
                $
                (5,703,498
                )
                
                $
                —
                
                
                $
                (6,849,114
                )
                
                $
                —Unrealized
      loss on commodity derivative contracts
                
                $
                (52,186,386
                )
                
                $
                —
                
                
                $
                (72,396,143
                )
                
                $
                —Realized
      loss on interest rate derivative contracts
                
                $
                (46,450
                )
                
                $
                —
                
                
                $
                (51,306
                )
                
                $
                —Loss
      on extinguishment of debt
                
                $
                —
                
                
                $
                —
                
                
                $
                —
                
                
                $
                (2,501,528
                )




(a)
              The
      Permian acquisition closed on January 31, 2008 and as such only five
      months of operations are included in the six month period ended June 30,
      2008.




20




Three
Months Ended June 30, 2008 Compared to Three Months Ended June 30,
2007




Revenues




Natural
gas and oil sales increased $10.7 million to $20.8 million during the three
months ended June 30, 2008 as compared to the same period in 2007. The key
revenue measurements were as follows:




Three Months Ended
                              June 30,
                            
                            
                            Percentage
                              Increase2008
                            
                            
                            2007
                            
                            
                            (Decrease)Net Natural Gas Production:Appalachian
      gas (MMcf)
                            
                            
                            903
                            
                            
                            
                            1,032
                            
                            
                            
                            (13
                            )%Permian
      gas (MMcf)
                            
                            
                            109
                            
                            
                            
                            —
                            
                            
                            
                            N/ATotal
      natural gas production (MMcf)
                            
                            
                            1,012
                            
                            
                            
                            1,032
                            
                            
                            
                            (2
                            )%Average
      Appalachian daily gas production (Mcf/day)
                            
                            
                            9,922
                            
                            
                            
                            11,340
                            
                            
                            
                            (13
                            )%Average
      Permian daily gas production (Mcf/day)
                            
                            
                            1,202
                            
                            
                            
                            —
                            
                            
                            
                            N/AAverage
      Vanguard daily gas production (Mcf/day)
                            
                            
                            11,124
                            
                            
                            
                            11,340Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including realized gains (losses) on commodity
      derivative contracts
                            
                            $
                            10.35
                            (a)
                            
                            $
                            9.12
                            (a)
                            
                            
                            13
                            %Net
      realized gas price, excluding realized gains (losses) on commodity
      derivative contracts
                            
                            $
                            13.14
                            
                            
                            $
                            9.30
                            
                            
                            
                            41
                            %Net
      Oil Production:Appalachian
      oil (Bbls)
                            
                            
                            10,430
                            
                            
                            
                            8,513
                            
                            
                            
                            22
                            %Permian
      oil (Bbls)
                            
                            
                            61,817
                            
                            
                            
                            —
                            
                            
                            
                            N/ATotal
      oil (Bbls)
                            
                            
                            72,247
                            
                            
                            
                            8,513
                            
                            
                            
                            749
                            %Average
      Appalachian daily oil production (Bbls/day)
                            
                            
                            115
                            
                            
                            
                            94
                            
                            
                            
                            22
                            %Average
      Permian daily oil production (Bbls/day)
                            
                            
                            679
                            
                            
                            
                            —
                            
                            
                            
                            N/AAverage
      Vanguard daily oil production (Bbls/day)
                            
                            
                            794
                            
                            
                            
                            94Average
      Oil Sales Price per Bbl:Net
      realized oil price, including realized gains (losses) on commodity
      derivative contracts
                            
                            $
                            81.01
                            
                            
                            $
                            60.46
                            
                            
                            
                            34
                            %Net
      realized oil price, excluding realized gains (losses) on commodity
      derivative contracts
                            
                            $
                            104.44
                            
                            
                            $
                            60.46
                            
                            
                            
                            73
                            %




(a)
            Excludes
      amortization of premiums paid and non-cash settlement on derivative
      contracts.





The
increase in natural gas and oil sales was due primarily to the impact of the
Permian Basin acquisition completed on January 31, 2008 and increases in
commodity prices. Production from the Permian Basin contributed $8.0 million of
natural gas and oil sales for the three month period ended June 30, 2008. In
Appalachia, a decline in natural gas production was partially offset by an
increase in oil production for a net production decline of 11% on an Mcfe basis.
However, the negative impact of the production decline was offset by a 41%
increase in the average realized natural gas sales price received (excluding
realized gains (losses) on commodity derivative contracts) and a 73% increase in
the average realized oil price (excluding realized gains (losses) on commodity
derivative contracts).




21




Costs
and Expenses




Production
costs consist of the lease operating expenses and taxes other than income taxes
(severance and ad valorem taxes). Lease operating expenses include third-party
transportation costs, gathering and compression fees, field personnel and other
customary charges. Lease operating expenses in Appalachia also include a $60 per
month per well administrative charge pursuant to a management services agreement
with Vinland, a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge
for production from wells drilled pre and post January 1, 2007, respectively,
paid to Vinland pursuant to a gathering and compression agreement with Vinland.
Lease operating expenses increased by $1.0 million to $2.3 million for the three
months ended June 30, 2008 as compared to the three months ended June 30, 2007
of which $0.9 million related to the Permian Basin acquisition. Severance taxes
are a function of volumes and revenues generated from production. Ad valorem
taxes vary by state/county and are based on the value of our reserves. Taxes
other than income taxes increased by $1.0 million for the three months ended
June 30, 2008 as compared to the same period in 2007, of which $0.6 million,
related to the Permian Basin acquisition.




Depreciation,
depletion and amortization increased to approximately $3.3 million for the three
months ended June 30, 2008 from approximately $2.3 million for the three months
ended June 30, 2007 due primarily to the additional depletion recorded on oil
and gas properties acquired in the Permian Basin acquisition.




Selling,
general and administrative expenses include the costs of our administrative
employees and executive officers, related benefits, office leases, professional
fees and other costs not directly associated with field operations. These
expenses for the three months ended June 30, 2008 increased $0.8 million as
compared to the three months ended June 30, 2007. For the three months ended
June 30, 2008 and 2007 these expenses included a $1.0 million and $0.6 million,
respectively, non-cash compensation charge related to the grant of restricted
Class B units to management and an employee, the grant of unit options to
management, the grant of common units to board members and the grant of phantom
units to management during 2007 and 2008. All other selling, general and
administrative expenses were $0.6 million for the three months ended June 30,
2008 representing a $0.4 million increase from the same period in 2007
principally due to costs associated with additional employees and being a public
company.




Interest
expense declined to $1.2 million for the three months ended June 30, 2008
compared to $2.2 million for the three months ended June 30, 2007 primarily due
to a reduction in the weighted average outstanding borrowings and lower interest
rates.





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





Six
Months Ended June 30, 2008 Compared to Six Months Ended June 30,
2007




Revenues




Natural
gas and oil sales increased $15.8 million to $34.9 million during the six months
ended June 30, 2008 as compared to the same period in 2007. The key revenue
measurements were as follows:




22




Six Months Ended
                  June 30,
                
                
                Percentage
                  Increase2008
                
                
                2007
                
                
                (Decrease)Net Natural Gas Production:Appalachian
      gas (MMcf)
                
                
                1,770
                
                
                
                2,100
                
                
                
                (16
                )%Permian
      gas (MMcf)
                
                
                151
                (a)
                
                
                —
                
                
                
                N/ATotal
      natural gas production (MMcf)
                
                
                1,921
                
                
                
                2,100
                
                
                
                (9
                )%Average
      Appalachian daily gas production (Mcf/day)
                
                
                9,724
                
                
                
                11,602
                
                
                
                (16
                )%Average
      Permian daily gas production (Mcf/day)
                
                
                1,000
                (a)
                
                
                —
                
                
                
                N/AAverage
      Vanguard daily gas production (Mcf/day)
                
                
                10,724
                
                
                
                11,602Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including realized gains (losses) on commodity
      derivative contracts
                
                $
                10.41
                (b)
                
                $
                8.39
                (b)
                
                
                24
                %Net
      realized gas price, excluding realized gains (losses) on commodity
      derivative contracts
                
                $
                11.62
                
                
                $
                8.84
                
                
                
                31
                %Net
      Oil Production:Appalachian
      oil (Bbls)
                
                
                21,421
                
                
                
                8,513
                
                
                
                151
                %Permian
      oil (Bbls)
                
                
                102,539
                (a)
                
                
                —
                
                
                
                N/ATotal
      oil (Bbls)
                
                
                123,960
                
                
                
                8,513
                
                
                
                1,356
                %Average
      Appalachian daily oil production (Bbls/day)
                
                
                118
                
                
                
                47
                
                
                
                151
                %Average
      Permian daily oil production (Bbls/day)
                
                
                679
                (a)
                
                
                —
                
                
                
                N/AAverage
      Vanguard daily oil production (Bbls/day)
                
                
                797
                
                
                
                47Average
      Oil Sales Price per Bbl:Net
      realized oil price, including realized gains (losses) on commodity
      derivative contracts
                
                $
                84.61
                
                
                $
                60.46
                
                
                
                40
                %Net
      realized oil price, excluding realized gains (losses) on commodity
      derivative contracts
                
                $
                101.06
                
                
                $
                60.46
                
                
                
                67
                %





(a)
            The
      Permian acquisition closed on January 31, 2008 and as such only five
      months of operations are included in the six month period ended June 30,
      2008.




(b)
            Excludes
      amortization of premiums paid and non-cash settlement on derivative
      contracts.





The
increase in natural gas and oil sales was due primarily to the impact of the
Permian Basin acquisition completed on January 31, 2008 and an increase in
commodity prices. Five months of production from the Permian Basin contributed
$12.3 million of natural gas and oil sales for the six month period ended June
30, 2008. In Appalachia, a decline in natural gas production was partially
offset by an increase in oil production for a net production decline of 12% on
an Mcfe basis. However, the negative impact of the production decline was offset
by a 31% increase in the average realized natural gas sales price received
(excluding realized gains (losses) on commodity derivative contracts) and a 67%
increase in the average realized oil price (excluding realized gains (losses) on
commodity derivative contracts).




Costs
and Expenses




Production
costs consist of the lease operating expenses and taxes other than income taxes
(severance and ad valorem taxes). Lease operating expenses include third-party
transportation costs, gathering and compression fees, field personnel and other
customary charges. Lease operating expenses in Appalachia also include a $60 per
month per well administrative charge pursuant to a management services agreement
with Vinland, a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge
for production from wells drilled pre and post January 1, 2007, respectively,
paid to Vinland pursuant to a gathering and compression agreement with Vinland.
Lease operating expenses increased by $1.8 million to $4.3 million for the six
months ended June 30, 2008 as compared to the six months ended June 30, 2007 of
which $1.5 million related to the Permian Basin acquisition. Severance taxes are
a function of volumes and revenues generated from production. Ad valorem taxes
vary by state/county and are based on the value of our reserves. Taxes other
than income taxes increased by $1.5 million for the six months ended June 30,
2008 as compared to the same period in 2007, of which $0.9 million, related to
the Permian Basin acquisition.




Depreciation,
depletion and amortization increased to approximately $6.1 million for the six
months ended June 30, 2008 from approximately $4.3 million for the six months
ended June 30, 2007 due primarily to the additional depletion recorded on the
oil and gas properties acquired in the Permian Basin acquisition.




23




Selling,
general and administrative expenses include the costs of our administrative
employees and executive officers, related benefits, office leases, professional
fees and other costs not directly associated with field operations. These
expenses for the six months ended June 30, 2008 increased $2.1 million as
compared to the six months ended June 30, 2007. For the six months ended June
30, 2008 and 2007 these expenses included a $1.9 million and $0.6 million
non-cash compensation charge related to the grant of restricted Class B units to
management and an employee, the grant of unit options to management, the grant
of common units to board members and the grant of phantom units to management
during 2007 and 2008. All other selling, general and administrative expenses
were $1.4 million for the six months ended June 30, 2008 representing a $0.8
million increase from the same period in 2007 principally due to costs
associated with additional employees and being a public company.




Interest
expense declined to $2.4 million for the six months ended June 30, 2008 compared
to $4.4 million for the six months ended June 30, 2007 primarily due to a
reduction in the weighted average outstanding borrowings and lower interest
rates. All of our Predecessor’s outstanding debt was repaid with borrowings
under our reserve-based credit facility in January 2007, including an early
prepayment penalty of $2.5 million.





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





Critical
Accounting Policies and Estimates





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




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





Financial
Statement Restatement





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




Under
SFAS No. 133, the fair value of derivative contracts is recognized in the
Consolidated Balance Sheet as an asset or liability, and the amounts received or
paid under the contracts are reflected in earnings during the period in which
the underlying production occurs.  If the derivative contracts qualify
for hedge accounting treatment, the fair value of the hedge contract is recorded
in “accumulated other comprehensive income”, and changes in the fair value do
not affect net income in the period.  If the derivative contract does
not qualify for hedge accounting treatment, the change in the fair value of the
contract is reflected in earnings during the period as unrealized gain or loss
on commodity derivatives.  Under the cash flow hedge accounting
treatment used by the Company previously, the fair values of the hedge contracts
were recognized in the consolidated balance sheets with the resulting unrealized
gain or loss recorded initially in accumulated other comprehensive income and
later reclassified through earnings when the hedged production affected
earnings.  As a result of the determination that the documentation
failed to meet cash flow hedge accounting treatment, the unrealized gain or loss
should have been recorded in the consolidated statements of operations as a
component of earnings in 2008. In addition, the net derivative loss at December
31, 2007 related to the de-designated natural gas derivative contracts entered
into in 2007 will continue to be reported in accumulated other comprehensive
income until the month in which the transactions settle.




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





24




Recently
Adopted Accounting Pronouncements





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





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





New
Pronouncements Issued But Not Yet Adopted





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





In
December 2007, the FASB issued SFAS No. 160,“Non-controlling Interests in
Consolidated Financial statements—an amendment of ARB No. 51” (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling
owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only
those entities that have an outstanding non-controlling interest in one or more
subsidiaries or that deconsolidate a subsidiary. This statement is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008, which will be our fiscal year 2009. Based upon the June 30, 2008 balance
sheet, SFAS 160 would have no impact on the consolidated financial
statements.




25




In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities” (“ SFAS 161”). SFAS 161 is intended
to improve financial reporting about derivative instruments and hedging
activities by requiring enhanced disclosures to enable investors to better
understand their effects on an entity’s financial position, financial
performance, and cash flows. SFAS 161 achieves these improvements by requiring
disclosure of the fair values of derivative instruments and their gains and
losses in a tabular format. It also provides more information about an entity’s
liquidity by requiring disclosure of derivative features that are credit
risk-related. Finally, it requires cross-referencing within footnotes to enable
financial statement users to locate important information about derivative
instruments. SFAS 161 is effective for financial statements issued for fiscal
years and interim periods beginning after November 15, 2008, with early
application encouraged. We are evaluating the impact of SFAS 161 on our
consolidated financial statements.





Use
of Estimates





The
preparation of financial statements in conformity with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. The most significant estimates pertain to proved
natural gas and oil reserves and related cash flow estimates used in impairment
tests of natural gas and oil properties, the fair value of derivative contracts
and asset retirement obligations, accrued natural gas and oil revenues and
expenses, as well as estimates of expenses related to depreciation, depletion,
amortization and accretion. Actual results could differ from those
estimates.




Liquidity
and Capital Resources





Overview





We have
utilized private equity, proceeds from bank borrowings, cash flow from
operations and, with our recent IPO, the public equity markets for capital
resources and liquidity. To date, the primary use of capital has been for
the acquisition and development of natural gas and oil properties; however, as a
result of our IPO, we expect to distribute to unitholders a significant portion
of our free cash flow.  As we execute our business strategy, we will
continually monitor the capital resources available to us to meet future
financial obligations, planned capital expenditures, acquisition capital and
distributions to our unitholders. Our future success in growing reserves,
production and cash flow will be highly dependent on the capital resources
available to us and our success in drilling for or acquiring additional
reserves. We expect to fund our maintenance capital expenditures and
distributions to unitholders with cash flow from operations, while funding any
acquisition capital expenditures that we might incur with borrowings under our
reserve-based credit facility and publicly offered equity, depending on market
conditions. As of August 12, 2008, we have $18.5 million available to be
borrowed under our reserve-based credit facility. However, the borrowing base
must be redetermined after giving effect to the natural gas and oil properties
acquired in July 2008 in South Texas and the amount of availability is expected
to increase as a result. Based upon current expectations, we believe existing
liquidity and capital resources will be sufficient for the conduct of our
business and operations for the foreseeable future.




Cash
Flow from Operations




Net cash
provided by operating activities for the six months ended June 30, 2008 was
$17.5 million, compared to cash used in operating activities of $2.8 million for
the six months ended June 30, 2007. The increase in cash provided by
operating activities during the six months ended June 30, 2008 was substantially
due to increased income and a decrease in cash used in price risk management
activities. The cash used in operating activities in the first six months of
2007 included the termination of existing natural gas swaps at a cost of
approximately $2.8 million, cash paid on early extinguishment of debt of
approximately $2.5 million and the payment of $6.5 million for put option
derivative contracts.




Cash flow
from operations is subject to many variables, the most significant of which is
the volatility of natural gas and oil prices. Natural gas and oil prices
are determined primarily by prevailing market conditions, which are dependent on
regional and worldwide economic activity, weather and other factors beyond our
control. Future cash flow from operations will depend on our ability to
maintain and increase production through our drilling program and acquisitions,
as well as the prices received for production. We enter into derivative
arrangements to reduce the impact of commodity price volatility on
operations. Currently, we use a combination of fixed-price swaps and NYMEX
collars and put options to reduce our exposure to the volatility in natural gas
and oil prices. See Note 5 in Notes to Consolidated Financial
Statements and Part 1—Item 3—Quantitative and Qualitative Disclosures About
Market Risk—Commodity Price Risk for details about derivatives in place through
2012.




Cash
Flow from Investing Activities





Cash used
in investing activities was approximately $73.1 million for the six months ended
June 30, 2008, compared to $6.6 million for the six months ended June 30,
2007. The increase in cash used in investing activities was primarily
attributable to $66.4 million used for the acquisition of natural gas and oil
properties in the Permian Basin. In addition, the total for the six months ended
June 30, 2008 includes $6.7 million for the drilling and development of natural
gas and oil properties as compared to $6.1 million for the six months ended June
30, 2007.




26




Cash Flow from
Financing Activities





Cash
provided by financing activities was approximately $56.4 million for the six
months ended June 30, 2008, compared to $12.2 million for the six months ended
June 30, 2007. During the six months ended June 30, 2008, total proceeds from
borrowings under our reserve-based credit facility were $74.4 million which were
principally used to fund the Permian Basin acquisition. During the six months
ended June 30, 2007, total proceeds from borrowings under our reserve-based
credit facility were $114.6 million, which was principally used to pay off our
Predecessor’s outstanding borrowings. Additionally, during the six months ended
June 30, 2007, we completed a private equity offering for $41.2 million and used
the net proceeds of this private equity offering to make a distribution to
Majeed S. Nami, VNR’s largest unitholder.




Reserve-Based
Credit Facility





On
January 3, 2007, our operating company, Vanguard Natural Gas, LLC (formerly Nami
Holding Company, LLC), entered into a reserve-based credit facility under which
our initial borrowing base was set at $115.5 million. Our reserve-based credit
facility was amended and restated in February 2008 to extend the maturity date
from January 2011 to March 2011, increase the facility amount from $200.0
million to $400.0 million, increase our borrowing base from $110.5 million to
$150.0 million and add two additional financial institutions as lenders,
Wachovia Bank, N.A. and The Bank of Nova Scotia. The increase in the borrowing
base was principally the result of inclusion of the reserves related to the
Permian Basin acquisition in January 2008. As a result, as of June 30, 2008, we
had $102.5 million outstanding under our reserve-based credit facility and as of
August 12, 2008, we have $18.5 million available to be borrowed. However, the
borrowing base must be redetermined after giving effect to the natural gas and
oil properties acquired in July 2008 in South Texas and the amount of
availability is expected to increase as a result. Borrowings under the
reserve-based credit facility are available for development and acquisition of
natural gas and oil properties, working capital and general limited liability
company purposes. Our obligations under the reserve-based credit facility are
secured by substantially all of our assets.




At our
election, interest is determined by reference to:




·
            the
      London interbank offered rate, or LIBOR, plus an applicable margin between
      1.00% and 1.75% per annum; or




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




Interest
is generally payable quarterly for domestic bank rate loans and at the
applicable maturity date for LIBOR loans, but not less frequently than
quarterly.




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




·
            incur
      indebtedness;





·
            grant
      certain liens;




·
            make
      certain loans, acquisitions, capital expenditures and
      investments;




·
            make
      distributions;




·
            merge
      or consolidate; or




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




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




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





27





·
            consolidated
      current assets, including the unused amount of the total commitments, to
      consolidated current liabilities of not less than 1.0 to 1.0, excluding
      non-cash assets and liabilities under SFAS No. 133, which includes the
      current portion of derivative
contracts;




·
            consolidated
      debt to consolidated net income plus interest expense, income taxes,
      depreciation, depletion, amortization, changes in fair value of derivative
      instruments and other similar charges, minus all non-cash income added to
      consolidated net income, and giving pro forma effect to any acquisitions
      or capital expenditures of not more than 4.0 to
  1.0.





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





We
believe that we are in compliance with the terms of our reserve-based credit
facility. If an event of default exists under the reserve-based credit
agreement, the lenders will be able to accelerate the maturity of the credit
agreement and exercise other rights and remedies. Each of the following will be
an event of default:




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





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




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




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




·
            bankruptcy
      or insolvency events involving us or our
  subsidiaries;




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





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




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




Off-Balance
Sheet Arrangements




At June
30, 2008, the Company did not have any off-balance sheet arrangements that have,
or are reasonably likely to have, an effect on our financial position or results
of operations.





28







Contingencies




The
Company regularly analyzes current information and accrues for probable
liabilities on the disposition of certain matters, as necessary. Liabilities for
loss contingencies arising from claims, assessments, litigation and other
sources are recorded when it is probable that a liability has been incurred and
the amount can be reasonably estimated. As of June 30, 2008, there were no loss
contingencies.




Commitments
and Contractual Obligations




A summary
of our contractual obligations as of June 30, 2008 is provided in the following
table:





Payments
      Due by Year (in thousands)2008
                                          
                                          
                                          2009
                                          
                                          
                                          2010
                                          
                                          
                                          2011
                                          
                                          
                                          2012
                                          
                                          
                                          After
      2012
                                          
                                          
                                          TotalManagement
      compensation
                                          
                                          $
                                          300
                                          
                                          
                                          $
                                          600
                                          
                                          
                                          $
                                          100
                                          
                                          
                                          $
                                          —
                                          
                                          
                                          $
                                          —
                                          
                                          
                                          $
                                          —
                                          
                                          
                                          $
                                          1,000Asset
      retirement obligations
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          166
                                          
                                          
                                          
                                          8
                                          
                                          
                                          
                                          1,359
                                          
                                          
                                          
                                          1,533Derivative
      liabilities
                                          
                                          
                                          14,267
                                          
                                          
                                          
                                          23,409
                                          
                                          
                                          
                                          25,113
                                          
                                          
                                          
                                          14,484
                                          
                                          
                                          
                                          6,847
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          84,120Long-term
      debt (1)
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          102,500
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          102,500Operating
      leases
                                          
                                          
                                          20
                                          
                                          
                                          
                                          41
                                          
                                          
                                          
                                          10
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          —
                                          
                                          
                                          
                                          71Total
                                          
                                          $
                                          14,587
                                          
                                          
                                          $
                                          24,050
                                          
                                          
                                          $
                                          25,223
                                          
                                          
                                          $
                                          117,150
                                          
                                          
                                          $
                                          6,855
                                          
                                          
                                          $
                                          1,359
                                          
                                          
                                          $
                                          189,224




(1)
            This
      table does not include interest to be paid on the principal balances shown
      as the interest rates on the reserve-based credit facility are
      variable.





Non-GAAP
Financial Measure





Adjusted
EBITDA





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





•
            Net
      interest expense (including write-off of deferred financing
      fees);




•
            Loss
      on extinguishment of debt;




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




•
            Bad
      debt expenses;




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




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




•
            Unit-based
      compensation expense; and




•
            Realized
      (gain) loss on cancelled
derivatives.




Adjusted
EBITDA is a significant performance metric used by our management to measure
(prior to the establishment of any cash reserves by our board of directors) the
cash distributions we could pay our unitholders. Specifically, this financial
measure indicates to investors whether or not we are generating cash flow at a
level that can sustain or support an increase in our quarterly distribution
rates. Adjusted EBITDA is also a quantitative standard used throughout the
investment community with respect to publicly-traded partnerships and limited
liability companies.




29




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




For the
three months ended June 30, 2008 as compared to the three months ended June 30,
2007, Adjusted EBITDA increased 49%, from $8.0 million to $11.9 million. For the
six months ended June 30, 2008 as compared to the six months ended June 30,
2007, Adjusted EBITDA increased 50%, from $14.9 million to $22.4 million. The
following table presents a reconciliation of consolidated net income to adjusted
EBITDA:




Three
      Months Ended
                                                        June
      30,
                                                      
                                                      
                                                      Six
      Months Ended
                                                        June
      30,2008
                                                      
                                                      
                                                      2007
                                                      
                                                      
                                                      2008
                                                      
                                                      
                                                      2007Net
      income
                                                      
                                                      $
                                                      (47,019,744
                                                      )
                                                      
                                                      $
                                                      2,239,906
                                                      
                                                      
                                                      $
                                                      (62,951,980
                                                      )
                                                      
                                                      $
                                                      614,157Plus:Interest
      expense
                                                      
                                                      
                                                      1,244,450
                                                      
                                                      
                                                      
                                                      2,196,691
                                                      
                                                      
                                                      
                                                      2,374,110
                                                      
                                                      
                                                      
                                                      4,419,814Loss
      on extinguishment of debt
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      2,501,528Depreciation,
      depletion, amortization and accretion
                                                      
                                                      
                                                      3,330,024
                                                      
                                                      
                                                      
                                                      2,291,426
                                                      
                                                      
                                                      
                                                      6,154,002
                                                      
                                                      
                                                      
                                                      4,320,289Bad
      debt expense
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      1,007,458Amortization
      of premiums paid and non-cash settlement on derivative
      contracts
                                                      
                                                      
                                                      1,230,584
                                                      
                                                      
                                                      
                                                      733,504
                                                      
                                                      
                                                      
                                                      2,531,193
                                                      
                                                      
                                                      
                                                      733,504Unrealized
      loss on commodity derivative contracts
                                                      
                                                      
                                                      52,186,386
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      72,396,143
                                                      
                                                      
                                                      
                                                      —Non-cash
      compensation expense
                                                      
                                                      
                                                      981,002
                                                      
                                                      
                                                      
                                                      563,143
                                                      
                                                      
                                                      
                                                      1,896,347
                                                      
                                                      
                                                      
                                                      563,143Realized
      loss on cancelled derivatives
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      —
                                                      
                                                      
                                                      
                                                      776,633Less:Interest
      income
                                                      
                                                      
                                                      4,394
                                                      
                                                      
                                                      
                                                      14,679
                                                      
                                                      
                                                      
                                                      12,008
                                                      
                                                      
                                                      
                                                      27,646Adjusted
      EBITDA
                                                      
                                                      $
                                                      11,948,308
                                                      
                                                      
                                                      $
                                                      8,009,991
                                                      
                                                      
                                                      $
                                                      22,387,807
                                                      
                                                      
                                                      $
                                                      14,908,880




Item 3. Quantitative and Qualitative
Disclosures About Market Risk





The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse
changes in natural gas prices and interest rates. The disclosures are not meant
to be precise indicators of expected future losses, but rather indicators of
reasonably possible losses. This forward-looking information provides indicators
of how we view and manage our ongoing market risk exposures. All of our market
risk sensitive instruments were entered into for purposes other than speculative
trading.




Commodity
Price Risk




Our major
market risk exposure is in the pricing applicable to our natural gas and oil
production. Realized pricing is primarily driven by the Columbia Gas Appalachian
Index (“TECO Index”) for natural gas production and the West Texas Intermediate
Light Sweet for oil production. Pricing for natural gas production has been
volatile and unpredictable for several years, and we expect this volatility to
continue in the future. The prices we receive for production depend on many
factors outside our control. In addition, the potential exists that if commodity
prices decline to a certain level, the borrowing base can be decreased at the
borrowing base determination date to an amount lower than the amount of debt
currently outstanding.




We enter
into derivative contracts with respect to a portion of our projected natural gas
and oil production through various transactions that hedge the future prices
received. These transactions may include price swaps whereby we will receive a
fixed-price for our production and pay a variable market price to the contract
counterparty. Additionally, we have put options for which we pay the
counterparty the fair value at the purchase date. At the settlement date we
receive the excess, if any, of the fixed floor over the floating rate.
Furthermore, we may enter into collars where we pay the counterparty if the
market price is above the ceiling and the counterparty pays us if the market
price is below the floor on a notional quantity. These hedging activities are
intended to support our realized commodity prices at targeted levels and to
manage our exposure to natural gas and oil price fluctuations. It is never
management’s intention to hold or issue derivative instruments for speculative
trading purposes.




At June
30, 2008, the fair value of commodity derivative contracts that settle during
the next twelve months was a liability of approximately $27.1 million, which we
will owe our counterparties.




30




The
following table summarizes commodity derivative contracts in place applicable to
periods subsequent to June 30, 2008.




July
      1, -
                                                    September
      30,
                                                    2008
                                                  
                                                  
                                                  October
      1, -
                                                    December
      31,
                                                    2008
                                                  
                                                  
                                                  Year
      2009
                                                  
                                                  
                                                  Year
      2010
                                                  
                                                  
                                                  Year
      2011
                                                  
                                                  
                                                  Year
      2012Gas
      Positions:Fixed
      Price Swaps:Notional
      Volume (MMBtu)
                                                  
                                                  
                                                  738,608
                                                  
                                                  
                                                  
                                                  713,831
                                                  
                                                  
                                                  
                                                  2,657,046
                                                  
                                                  
                                                  
                                                  2,387,640
                                                  
                                                  
                                                  
                                                  2,196,012
                                                  
                                                  
                                                  
                                                  —Fixed
      Price ($/MMBtu)
                                                  
                                                  $
                                                  9.00
                                                  
                                                  
                                                  $
                                                  9.00
                                                  
                                                  
                                                  $
                                                  8.85
                                                  
                                                  
                                                  $
                                                  8.76
                                                  
                                                  
                                                  $
                                                  7.15
                                                  
                                                  
                                                  $
                                                  -—Puts:Notional
      Volume (MMBtu)
                                                  
                                                  
                                                  314,391
                                                  
                                                  
                                                  
                                                  246,920
                                                  
                                                  
                                                  
                                                  840,139
                                                  
                                                  
                                                  
                                                  —
                                                  
                                                  
                                                  
                                                  —
                                                  
                                                  
                                                  
                                                  —Floor
      Price ($/MMBtu)
                                                  
                                                  $
                                                  7.50
                                                  
                                                  
                                                  $
                                                  7.50
                                                  
                                                  
                                                  $
                                                  7.50
                                                  
                                                  
                                                  $
                                                  —
                                                  
                                                  
                                                  $
                                                  —
                                                  
                                                  
                                                  $
                                                  —Collars:Notional
      Volume (MMBtu)
                                                  
                                                  
                                                  300,000
                                                  
                                                  
                                                  
                                                  300,000
                                                  
                                                  
                                                  
                                                  1,000,000
                                                  
                                                  
                                                  
                                                  730,000
                                                  
                                                  
                                                  
                                                  —
                                                  
                                                  
                                                  
                                                  —Floor
      Price ($/MMBtu)
                                                  
                                                  $
                                                  9.00
                                                  
                                                  
                                                  $
                                                  9.00
                                                  
                                                  
                                                  $
                                                  7.50
                                                  
                                                  
                                                  $
                                                  8.00
                                                  
                                                  
                                                  $
                                                  —
                                                  
                                                  
                                                  $
                                                  —Ceiling
      Price ($/MMBtu)
                                                  
                                                  $
                                                  9.00
                                                  
                                                  
                                                  $
                                                  9.25
                                                  
                                                  
                                                  $
                                                  9.00
                                                  
                                                  
                                                  $
                                                  9.30
                                                  
                                                  
                                                  $
                                                  —
                                                  
                                                  
                                                  $
                                                  —Total:Notional
      Volume (MMBtu)
                                                  
                                                  
                                                  1,352,999
                                                  
                                                  
                                                  
                                                  1,260,751
                                                  
                                                  
                                                  
                                                  4,497,185
                                                  
                                                  
                                                  
                                                  3,117,640
                                                  
                                                  
                                                  
                                                  2,196,012
                                                  
                                                  
                                                  
                                                  —Oil
      Positions:Fixed
      Price Swaps:Notional
      Volume (Bbls)
                                                  
                                                  
                                                  49,500
                                                  
                                                  
                                                  
                                                  48,000
                                                  
                                                  
                                                  
                                                  181,500
                                                  
                                                  
                                                  
                                                  164,250
                                                  
                                                  
                                                  
                                                  151,250
                                                  
                                                  
                                                  
                                                  144,000Fixed
      Price ($/Bbl)
                                                  
                                                  $
                                                  90.30
                                                  
                                                  
                                                  $
                                                  90.30
                                                  
                                                  
                                                  $
                                                  87.23
                                                  
                                                  
                                                  $
                                                  85.65
                                                  
                                                  
                                                  $
                                                  85.50
                                                  
                                                  
                                                  $
                                                  80.00





Interest
Rate Risks





At June
30, 2008, we had debt outstanding of $102.5 million, which incurred interest at
floating rates based on LIBOR in accordance with our reserve-based credit
facility and if the debt remains the same, a 1% increase in LIBOR would result
in an estimated $0.4 million increase in annual interest expense after
consideration of the interest hedges discussed below. In December 2007 and
during the first quarter of 2008, we entered into interest rate swaps, which
require exchanges of cash flows that serve to synthetically convert a portion of
our variable interest rate exposures to fixed interest rates.





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





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




Item 4.  Controls
and Procedures




Evaluation
of Disclosure Controls and Procedures




Our
management has established and maintains a system of disclosure controls and
procedures to provide reasonable assurances that information required to be
disclosed by us in reports that we file or submit under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms, and that such information is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate to allow timely decisions regarding required
disclosure.




31




As part
of the preparation of our financial statements for the quarters ended March 31,
2008 and June 30, 2008, we undertook a review of our accounting for natural gas
and oil and interest rate derivatives. We use derivative instruments as a means
of reducing financial exposure to fluctuating natural gas and oil prices and
interest rates. We included changes from period to period in the fair value of
derivatives classified as cash flow hedges (“Hedges”) as increases or decreases
to Accumulated Other Comprehensive Income (“AOCI”) as allowed by Statement of
Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“FAS 133”). This Hedge accounting
treatment is allowed for certain derivatives, including the types of derivatives
used by us to reduce exposure to changes in natural gas and oil prices
associated with the sale of natural gas and oil production and fluctuations in
interest rates. In order to qualify for Hedge accounting treatment, specific
standards and documentation requirements must be met. We believed that we met
those requirements and that our derivative accounting treatment was permitted
under FAS 133. However, in connection with preparing our quarterly report for
third quarter of 2008 and discussion with BDO Seidman, LLP, the Company’s new
independent registered public accounting firm, we determined that our commodity
derivative instruments did not qualify for Hedge accounting treatment under FAS
133 in 2008. Specifically, we determined that the formal hedge documentation
lacked specificity of the hedged cash flow and the quantitative subsequent
assessments for ineffectiveness were insufficient.  Therefore, the
cash flow designations failed to meet hedge documentation requirements for cash
flow hedge accounting treatment for commodity derivative contracts entered into
during periods subsequent to December 31, 2007; and, that accounting for
commodity derivative instruments entered into during periods subsequent to
December 31, 2007 as cash flow Hedges was, therefore,
inappropriate.  In addition, the natural gas derivative swap contracts
entered into in 2007 were de-designated as cash flow hedges in the first quarter
of 2008 due to an overhedged position in natural gas during that quarter which
made them ineffective.  Accordingly, we are restating the consolidated
financial statements for the three months ended June 30, 2008 as reflected in
this Form 10-Q/A which reflects the appropriate changes.  Management
has concluded, based on the circumstances involving the restatement of the
aforementioned financial statements that since March 31, 2008, a material
weakness in internal control over financial reporting has existed with respect
to the design of the Company’s controls over the proper recording and disclosure
of derivative instruments in accordance with FAS 133.





We
carried out an evaluation in accordance with Exchange Act Rules 13a-15
under the supervision and with the participation of management, including our
Chief Executive Officer and our Chief Financial Officer, of the effectiveness of
our disclosure controls and procedures as of the end of the period covered by
this report. Based on that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that, due to the aforementioned material weakness,
our disclosure controls and procedures were not effective as of June 30,
2008.  The Company is evaluating the necessary changes in control
procedures required to remediate this material weakness such that the Company’s
internal controls over financial reporting will be effective at the reasonable
assurance level at December 31, 2008.




Changes
in Internal Control over Financial Reporting




On
January 31, 2008, we completed the acquisition of certain oil and gas properties
in the Permian Basin of West Texas and Southeastern New Mexico. Pursuant to this
transaction, we have outsourced our production accounting for the Permian Basin
properties to a third party and have begun operating our own wells. As a result,
we are implementing new processes and modifying existing processes to ensure
adequate internal controls over financial reporting.





PART II —
OTHER INFORMATION




Item 1.  Legal
Proceedings




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




Item 1A. 
Risk Factors




Our
business faces many risks. Any of the risks discussed below or elsewhere in this
Form 10-Q/A or our other SEC filings, could have a material impact on our
business, financial position or results of operations. Additional risks and
uncertainties not presently known to us or that we currently believe to be
immaterial may also impair our business operations. For a detailed discussion of
the risk factors that should be understood by any investor contemplating
investment in our units, please refer to the section entitled “Item 1A. Risk
Factors” in our Annual Report on Form 10-K/A for the year ended December 31,
2007 as supplemented by the risk factors set forth below. There has been no
material change in the risk factors set forth in our Annual Report on Form
10-K/A for the year ended December 31, 2007 other than those set forth below.
For further information, see Part I, Item 1A, Risk Factors in our Annual Report
on Form 10-K/A for the year ended December 31, 2007.


32




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





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





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





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





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





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





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





·
            domestic
      and foreign governmental regulations and
taxes;





·
            the
      price and availability of alternative fuel
  sources;





·
            weather
      conditions;





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





·
            technological
      advances affecting energy consumption;
and





·
            worldwide
      economic conditions.





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





We
may not have sufficient cash from operations to pay quarterly distributions on
our common units following establishment of cash reserves and payment of
operating costs.




We may
not have sufficient cash flow from operations each quarter to pay
distributions.  Under the terms of our limited liability company
agreement, the amount of cash otherwise available for distribution will be
reduced by our operating expenses and the amount of any cash reserve amounts
that our board of directors establishes to provide for future operations, future
capital expenditures, future debt service requirements and future cash
distributions to our unitholders. The amount of cash we can distribute on our
common units principally depends upon the amount of cash we generate from our
operations, which will fluctuate from quarter to quarter based on, among other
things:




·
            the
      amount of natural gas and oil we
produce;




·
            the
      price at which we are able to sell our natural gas and oil
      production;




·
            the
      level of our operating costs;




·
            the
      level of our interest expense which depends on the amount of our
      indebtedness and the interest payable thereon;
  and




·
            the
      level of our capital expenditures.




33




In
addition, the actual amount of cash we will have available for distribution will
depend on other factors, some of which are beyond our control,
including:




·
            the
      level of our capital expenditures;




·
            our
      ability to make working capital borrowings under our credit facility to
      pay distributions;




·
            the
      cost of acquisitions, if any;




·
            our
      debt service requirements;




·
            fluctuations
      in our working capital needs;




·
            timing
      and collectibility of receivables;




·
            restrictions
      on distributions contained in our credit
  facility;




·
            prevailing
      economic conditions; and




·
            the
      amount of cash reserves established by our board of directors for the
      proper conduct of our business.




As a
result of these factors, the amount of cash we distribute in any quarter to our
unitholders may fluctuate significantly from quarter to quarter.





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





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





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





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





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





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





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





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




34




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





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





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





We are
exposed to risks of loss in the event of nonperformance by our vendors,
customers and by counterparties to our hedging arrangements. Some of our
vendors, customers and counterparties may be highly leveraged and subject to
their own operating and regulatory risks. Many of our vendors, customers and
counterparties finance their activities through cash flow from operations, the
incurrence of debt or the issuance of equity. Recently, there has been a
significant decline in the credit markets and the availability of credit.
Additionally, many of our vendors’, customers’ and counterparties' equity values
have substantially declined.  The combination of reduction of cash
flow resulting from declines in commodity prices and the lack of availability of
debt or equity financing may result in a significant reduction in our vendors’,
customers’ and counterparties' liquidity and ability to make payments or perform
on their obligations to us.  Even if our credit review and analysis
mechanisms work properly, we may experience financial losses in our dealings
with other parties. Any increase in the nonpayment or nonperformance by our
vendors, customers and/or counterparties could reduce our ability to make
distributions to our unitholders.




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




During
the six months ended June 30, 2008, one of our wholly-owned subsidiaries
purchased 20,300 of our common units on the open market at the then
prevailing market price. 15,000 of these units were subsequently granted
to three of our independent directors, with Loren Singletary, John R.
McGoldrick and Bruce W. McCullough each receiving 5,000 units. The grants
were made by our Board of Directors upon the appointment of these independent
directors on February 28, 2008. The following table summarizes the unit
purchases that occurred during the six months ended June 30, 2008:





Period
              
              Number of
                common
                units
                repurchased
              
              
              Weighted
                average price
                paid per
                common unitJanuary
      1, 2008 to January 31, 2008
              
              
              5,000
              
              
              $
              14.50February
      1, 2008 to February 29, 2008
              
              
              10,000
              
              
              $
              16.28March
      1, 2008 to March 31, 2008
              
              
              300
              
              
              $
              14.70April
      1, 2008 to April 30, 2008
              
              
              —
              
              
              
              N/AMay
      1, 2008 to May 31, 2008
              
              
              —
              
              
              
              N/AJune
      1, 2008 to June 30, 2008
              
              
              5,000
              
              
              $
              16.97Total
      common units purchased
              
              
              20,300
              
              
              $
              15.99




Item 3.  Defaults Upon
Senior Securities




None.




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




The
annual meeting of unitholders of Vanguard Natural Resources, LLC was held on
June 10, 2008 in Houston, Texas. At the annual meeting, holders of 11,215,000
units were entitled to vote on the specified unitholder matters, of which
10,145,022 units were present and voting, or 90% of the outstanding units, which
constituted a quorum.




35




Proposals
submitted to a vote of the unitholders were:





(1) The
election of seven directors of Vanguard Natural Resources, LLC for a one-year
term expiring at the 2009 annual meeting of unitholders and until their
respective successors are elected and qualified.




NumberofVotingUnitsDirector’sName
                    
                    For
                    
                    
                    WithheldScott
      W. Smith
                    
                    
                    10,143,118
                    
                    
                    
                    1,904W.
      Richard Anderson
                    
                    
                    10,143,118
                    
                    
                    
                    1,904Loren
      Singletary
                    
                    
                    10,143,118
                    
                    
                    
                    1,904Bruce
      W. McCullough
                    
                    
                    10,143,118
                    
                    
                    
                    1,904John
      R. McGoldrick
                    
                    
                    10,143,118
                    
                    
                    
                    1,904Lasse
      Wagene
                    
                    
                    10,143,118
                    
                    
                    
                    1,904Thomas
      Blake
                    
                    
                    10,143,118
                    
                    
                    
                    1,904




(2) The
ratification of UHY LLP as our independent registered public accountants for the
fiscal year ended December 31, 2008.





For
                          
                          Against
                          
                          Abstained10,142,822
                          
                          
                          1,700
                          
                          
                          500







Item 5.  Other
Information




Indemnification
Agreements





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





The
foregoing description of the Indemnification Agreements is qualified in its
entirety by reference to the full text of the Form of Indemnification Agreement,
which was previously filed with our Quarterly report on Form 10-Q on August 13,
2008 and incorporated herein by reference.




Item 6. 
Exhibits




EXHIBIT
INDEX


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





Exhibit No.
                
                Exhibit Title
                
                Incorporated by Reference to the
      Following3.1
                
                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)  36
  10.4
                                  
                                  Vanguard
      Natural Resources, LLC Class B Unit Plan
                                  
                                  Form
      8-K, filed October 24, 2007 (File No. 001-33756)10.5
                                  
                                  Form of
      Vanguard Natural Resources, LLC Class B Unit Plan Restricted
      Class B Unit Grant
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.6
                                  
                                  Management
      Services Agreement, effective January 5, 2007, by and between Vinland
      Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company,
      LLC and Ariana Energy, LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.7
                                  
                                  Participation
      Agreement, effective January 5, 2007, by and between Vinland Energy
      Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and
      Ariana Energy, LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.8
                                  
                                  Gathering
      and Compression Agreement, effective January 5, 2007, by and between
      Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard
      Natural Gas, LLC and Ariana Energy, LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.9
                                  
                                  Gathering
      and Compression Agreement, effective January 5, 2007, by and between
      Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard
      Natural Gas, LLC and Trust Energy Company
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.10
                                  
                                  Gathering
      and Compression Agreement, effective January 5, 2007, by and between
      Vinland Energy Gathering, LLC and Nami Resources Company,
      L.L.C.
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.11
                                  
                                  Well
      Services Agreement, effective January 5, 2007, by and between Vinland
      Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy,
      LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.12
                                  
                                  Well
      Services Agreement, effective January 5, 2007, by and between Vinland
      Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy
      Company, LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.13
                                  
                                  Well
      Services Agreement, effective January 5, 2007, by and between Vinland
      Energy Operations, LLC and Nami Resources Company, L.L.C.
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.14
                                  
                                  Amended
      and Restated Operating Agreement by and between Vinland Energy Operations,
      LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC, dated October 2,
      2007 and effective as of January 5, 2007
                                  
                                  Form
      S-1/A, filed October 22, 2007 (File No. 333-142363)10.15
                                  
                                  Operating
      Agreement, effective January 5, 2007, by and between Vinland Energy
      Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company,
      LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.16
                                  
                                  Amended
      and Restated Indemnity Agreement by and between Nami Resources Company,
      L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard
      Natural Gas, LLC and Vanguard Natural Resources, LLC, dated September 11,
      2007
                                  
                                  Form
      S-1/A, filed September 18, 2007 (File No. 333-142363)10.17
                                  
                                  Revenue
      Payment Agreement by and between Nami Resources Company, L.L.C. and Trust
      Energy Company, dated April 18, 2007 and effective as of January 5,
      2007
                                  
                                  Form
      S-1/A, filed August 21, 2007 (File No. 333-142363)10.18
                                  
                                  Gas
      Supply Agreement, dated April 18, 2007, by and between Nami Resources
      Company, L.L.C. and Trust Energy Company
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.19
                                  
                                  Amended
      Employment Agreement, dated April 18, 2007, by and between Scott W.
      Smith, VNR Holdings, LLC and Vanguard Natural Resources,
    LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.20
                                  
                                  Amended
      Employment Agreement, dated April 18, 2007, by and between Richard A.
      Robert, VNR Holdings, LLC and Vanguard Natural Resources,
    LLC
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.21
                                  
                                  Registration
      Rights Agreement, dated April 18, 2007, between Vanguard Natural
      Resources, LLC and the private investors named therein
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.22
                                  
                                  Purchase
      Agreement, dated April 18, 2007, between Vanguard Natural Resources,
      LLC, Majeed S. Nami and the private investors named
therein
                                  
                                  Form
      S-1/A, filed April 25, 2007 (File No. 333-142363)10.23
                                  
                                  Omnibus
      Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard Natural
      Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and Trust
      Energy Company, LLC.
                                  
                                  Form
      8-K, filed November 2, 2007 (File No. 001-33756)10.24
                                  
                                  Employment
      Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings,
      LLC and Vanguard Natural Resources, LLC
                                  
                                  Form
      S-1/A, filed July 5, 2007 (File No. 333-142363)10.25
                                  
                                  Natural
      Gas Contract, dated May 26, 2003, between Nami Resources Company,
      Inc. and Osram Sylvania Products, Inc.
                                  
                                  Form
      S-1/A, filed August 21, 2007 (File No. 333-142363)10.26
                                  
                                  Natural
      Gas Purchase Contract, dated December 16, 2004, between Nami
      Resources Company, LLC and Dominion Field Services, Inc.
                                  
                                  Form
      S-1/A, filed August 21, 2007 (File No. 333-142363)10.27
                                  
                                  Natural
      Gas Purchase Contract, dated December 28, 2004, between Nami
      Resources Company, LLC and Dominion Field Services, Inc.
                                  
                                  Form
      S-1/A, filed August 21, 2007 (File No. 333-142363)10.28
                                  
                                  Director
      Compensation Agreement
                                  
                                  Form
      S-1/A, filed September 18, 2007 (File No.
  333-142363)




37


10.29
                                                                              
                                                                              Purchase
      and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC
      and Apache Corporation
                                                                              
                                                                              Form
      8-K/A, filed February 13, 2008 (File No. 001-33756)10.30
                                                                              
                                                                              Amended
      Purchase and Sale Agreement, dated January 31, 2008, among Vanguard
      Permian, LLC and Apache Corporation
                                                                              
                                                                              Form
      8-K/A, filed February 4, 2008 (File No. 001-33756)10.31
                                                                              
                                                                              Purchase
      and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and
      Segundo Navarro Drilling, Ltd.
                                                                              
                                                                              Form
      8-K, filed July 21, 2008 (File No. 001-33756)10.32
                                                                              
                                                                              Form
      of Indemnity Agreement dated August 7, 2008
                                                                              
                                                                              Previously
      filed with our Quarterly report on Form 10-Q on August 13,
      200831.1
                                                                              
                                                                              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


38





SIGNATURE




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




VANGUARD
      NATURAL RESOURCES, LLC(Registrant)Date:
      December 19, 2008/s/ Richard
      A. RobertRichard
      A. RobertExecutive
      Vice President andChief
      Financial Officer(Principal
      Financial Officer and Principal Accounting
  Officer)




39




Vanguard
Natural Resources, LLC


EXHIBIT
INDEX




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




Exhibit No.
                  
                  Exhibit Title
                  
                  Incorporated by Reference to the
      Following3.1
                  
                  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)




40




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,
      200831.1
                      
                      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