UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.
20549





Form 10-Q





(Mark One)x
            
            QUARTERLY
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934For
      the quarterly period ended September 30, 2009ORo
            
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934For
      the transition period
      from          toCommission
      File Number:  001-33756





Vanguard
Natural Resources, LLC


(Exact
Name of Registrant as Specified in Its Charter)





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





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





Telephone
Number: (832) 327-2255


Internet
Website: www.vnrllc.com




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





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).


Yeso   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
      filerxNon-accelerated
      filero
            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 November 4, 2009: 16,078,673.














4


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 Members’
      Equity
            5Consolidated Statements of Cash Flows
            6Consolidated Statements of Comprehensive
    Loss
            7Notes to Consolidated Financial
    Statements
            8Item 2.
            Management’s Discussion and Analysis of Financial
      Condition and Results of Operations
            21Item 3.
            Quantitative and Qualitative Disclosures about
      Market Risk
            38Item 4.
            Controls and Procedures
            40PART II – OTHER INFORMATIONItem 1.
            Legal Proceedings
            42Item 1A.
            Risk Factors
            42Item 2.
            Unregistered Sales of Equity Securities and Use of
      Proceeds
            43Item 3.
            Defaults Upon Senior Securities
            43Item 4.
            Submission of Matters to a Vote of Securities
      Holders
            43Item 5.
            Other Information
            43Item 6.
            Exhibits
            44











GLOSSARY OF TERMS





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





/day
            =
            per
      day
            
            Mcf
            =
            thousand
      cubic 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 feetGal
            =
            gallons
            
            NGL
            =
            natural
      gas liquids





When we
refer to natural gas, natural gas liquids and oil in “equivalents,” we are doing
so to compare quantities of natural gas liquids and oil with quantities of
natural gas or to express these different commodities in a common unit. In
calculating equivalents, we use a generally recognized standard in which 42
gallons is equal to one Bbl of oil and one Bbl of oil is equal to six Mcf of
natural gas. Also, when we refer to cubic feet measurements, all measurements
are at a pressure of 14.73 pounds per square inch.





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











PART I – FINANCIAL INFORMATION





Item 1. Financial Statements





VANGUARD NATURAL RESOURCES, LLC AND
SUBSIDIARIES


CONSOLIDATED STATEMENTS OF OPERATIONS


(in
thousands, except per unit data)


(Unaudited)





Three Months
      Ended
              September
      30,
            
            
            Nine Months
      Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008Revenues:Natural
      gas, natural gas liquids and oil sales
            
            $
            11,324
            
            
            $
            20,839
            
            
            $
            29,930
            
            
            $
            55,693Gain
      (loss) on commodity cash flow hedges
            
            
            (463
            )
            
            
            45
            
            
            
            (1,737
            )
            
            
            616Gain
      (loss) on other commodity derivative contracts
            
            
            (4,210
            )
            
            
            63,364
            
            
            
            7,302
            
            
            
            (16,453
            )Total
      revenues
            
            
            6,651
            
            
            
            84,248
            
            
            
            35,495
            
            
            
            39,856Costs
      and expenses:Lease
      operating expenses
            
            
            3,322
            
            
            
            3,485
            
            
            
            9,233
            
            
            
            7,800Depreciation,
      depletion, amortization, and accretion
            
            
            3,272
            
            
            
            4,187
            
            
            
            9,700
            
            
            
            10,341Impairment
      of natural gas and oil properties
            
            
            —
            
            
            
            —
            
            
            
            63,818
            
            
            
            —Selling,
      general and administrative expenses
            
            
            2,137
            
            
            
            1,560
            
            
            
            8,230
            
            
            
            4,843Production
      and other taxes
            
            
            974
            
            
            
            1,263
            
            
            
            2,537
            
            
            
            3,658Total
      costs and expenses
            
            
            9,705
            
            
            
            10,495
            
            
            
            93,518
            
            
            
            26,642Income
      (loss) from operations
            
            
            (3,054
            )
            
            
            73,753
            
            
            
            (58,023
            )
            
            
            13,214Other
      income and (expense):Interest
      income
            
            
            —
            
            
            
            4
            
            
            
            —
            
            
            
            16Interest
      expense
            
            
            (1,042
            )
            
            
            (1,489
            )
            
            
            (3,034
            )
            
            
            (3,863
            )Gain
      on acquisition of natural gas and oil properties
            
            
            5,878
            
            
            
            —
            
            
            
            5,878
            
            
            
            —Loss
      on interest rate derivative contracts
            
            
            (1,081
            )
            
            
            (459
            )
            
            
            (853
            )
            
            
            (510
            )Total
      other income (expense)
            
            
            3,755
            
            
            
            (1,944
            )
            
            
            1,991
            
            
            
            (4,357
            )Net
      income (loss)
            
            $
            701
            
            
            $
            71,809
            
            
            $
            (56,032
            )
            
            $
            8,857Net
      income (loss) per unit:Common
      & Class B units – basic
            
            $
            0.05
            
            
            $
            5.90
            
            
            $
            (4.24
            )
            
            $
            0.77Common
      & Class B units – diluted
            
            $
            0.05
            
            
            $
            5.90
            
            
            $
            (4.24
            )
            
            $
            0.77Weighted
      average units outstanding:Common
      units – basic & diluted
            
            
            14,027,186
            
            
            
            11,749,421
            
            
            
            12,779,869
            
            
            
            11,115,463Class
      B units – basic & diluted
            
            
            420,000
            
            
            
            420,000
            
            
            
            420,000
            
            
            
            420,000





See
accompanying notes to consolidated financial statements


3


VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED BALANCE SHEETS


(in
thousands)


September
      30,
              2009
            
            
            December 31,
              2008(Unaudited)AssetsCurrent
      assetsCash
      and cash equivalents
            
            $
            2,046
            
            
            $
            3Trade
      accounts receivable, net
            
            
            5,410
            
            
            
            6,083Derivative
      assets
            
            
            19,516
            
            
            
            22,184Other
      receivables
            
            
            2,912
            
            
            
            2,763Other
      current assets
            
            
            766
            
            
            
            845Total
      current assets
            
            
            30,650
            
            
            
            31,878Natural gas and oil properties, at cost
            
            
            341,898
            
            
            
            284,447Accumulated depletion
            
            
            (175,493
            )
            
            
            (102,178
            )Natural
      gas and oil properties evaluated, net – full cost
    method
            
            
            166,405
            
            
            
            182,269Other
      assetsDerivative assets
            
            
            6,850
            
            
            
            15,749Deferred financing costs
            
            
            3,301
            
            
            
            882Other assets
            
            
            1,627
            
            
            
            1,784Total
      assets
            
            $
            208,833
            
            
            $
            232,562Liabilities
      and members’ equityCurrent
      liabilitiesAccounts payable – trade
            
            $
            611
            
            
            $
            2,148Accounts payable – natural gas and oil
            
            
            1,525
            
            
            
            1,327Payables to affiliates
            
            
            866
            
            
            
            2,555Deferred swap liability
            
            
            997
            
            
            
            —Derivative liabilities
            
            
            29
            
            
            
            486Phantom unit compensation accrual
            
            
            3,034
            
            
            
            —Accrued ad valorem taxes
            
            
            1,591
            
            
            
            34Accrued expenses
            
            
            344
            
            
            
            1,214Total
      current liabilities
            
            
            8,997
            
            
            
            7,764Long-term debt
            
            
            123,500
            
            
            
            135,000Derivative liabilities
            
            
            2,801
            
            
            
            2,313Deferred swap liability
            
            
            2,075
            
            
            
            —Asset retirement obligations
            
            
            4,133
            
            
            
            2,134Total
      liabilities
            
            
            141,506
            
            
            
            147,211Commitments
      and contingenciesMembers’
      equityMembers’ capital, 16,078,673 common units issued and outstanding at
      September  30, 2009 and 12,145,873 at December 31,
      2008
            
            
            67,409
            
            
            
            88,550Class B units, 420,000 issued and outstanding at September 30, 2009 and
      December 31, 2008
            
            
            6,045
            
            
            
            4,606Accumulated other comprehensive loss
            
            
            (6,127
            )
            
            
            (7,805
            )Total
      members’ equity
            
            
            67,327
            
            
            
            85,351Total
      liabilities and members’ equity
            
            $
            208,833
            
            
            $
            232,562





See
accompanying notes to consolidated financial statements


4


VANGUARD NATURAL RESOURCES, LLC AND
SUBSIDIARIES


CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY


FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2009 AND THE YEAR
ENDED DECEMBER 31, 2008


(in thousands, except unit data)


(Unaudited)




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







See
accompanying notes to consolidated financial statements


5


VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS


(Unaudited)


(in
thousands)


Nine Months Ended
              September
      30,2009
            
            
            2008Operating
      activitiesNet
      income (loss)
            
            $
            (56,032
            )
            
            $
            8,857Adjustments
      to reconcile net income (loss) to net cash provided by operating
      activities:Depreciation,
      depletion, amortization, and accretion
            
            
            9,700
            
            
            
            10,341Impairment
      of natural gas and oil properties
            
            
            63,818
            
            
            
            —Amortization
      of deferred financing costs
            
            
            363
            
            
            
            264Unit-based
      compensation
            
            
            2,311
            
            
            
            2,708Unrealized
      fair value of phantom units granted to officers
            
            
            3,034
            
            
            
            —Amortization
      of premiums paid and non-cash settlements on derivative
      contracts
            
            
            4,383
            
            
            
            3,982Unrealized
      losses on other commodity and interest rate derivative
      contracts
            
            
            16,105
            
            
            
            6,463Gain
      on acquisition of natural gas and oil properties
            
            
            (5,878
            )
            
            
            —Changes
      in operating assets and liabilities:Trade
      accounts receivable
            
            
            673
            
            
            
            (6,730
            )Other
      receivables
            
            
            (149
            )
            
            
            —Payables
      to affiliates
            
            
            (1,689
            )
            
            
            662Other
      current assets
            
            
            11
            
            
            
            (435
            )Price
      risk management activities, net
            
            
            (13
            )
            
            
            (452
            )Accounts
      payable
            
            
            (1,339
            )
            
            
            673Accrued
      expenses
            
            
            687
            
            
            
            2,300Other
      assets
            
            
            (27
            )
            
            
            —Net
      cash provided by operating activities
            
            
            35,958
            
            
            
            28,633Investing
      activitiesAdditions
      to property and equipment
            
            
            (9
            )
            
            
            (70
            )Additions
      to natural gas and oil properties
            
            
            (2,981
            )
            
            
            (13,360
            )Acquisitions
      of natural gas and oil properties
            
            
            (49,964
            )
            
            
            (99,815
            )Deposits
      and prepayments of natural gas and oil properties
            
            
            (699
            )
            
            
            (901
            )Net
      cash used in investing activities
            
            
            (53,653
            )
            
            
            (114,146
            )Financing
      activitiesProceeds
      from borrowings
            
            
            16,800
            
            
            
            112,900Repayment
      of debt
            
            
            (28,300
            )
            
            
            (15,800
            )Distributions
      to members
            
            
            (18,849
            )
            
            
            (13,846
            )Proceeds
      from equity offering
            
            
            53,192
            
            
            
            —Financing
      costs
            
            
            (2,781
            )
            
            
            (274
            )Purchase
      of units for issuance as unit-based compensation
            
            
            (324
            )
            
            
            (236
            )Net
      cash provided by financing activities
            
            
            19,738
            
            
            
            82,744Net
      increase (decrease) in cash and cash equivalents
            
            
            2,043
            
            
            
            (2,769
            )Cash and cash
      equivalents, beginning of period
            
            
            3
            
            
            
            3,110Cash and cash
      equivalents, end of period
            
            $
            2,046
            
            
            $
            341Supplemental
      cash flow information:Cash
      paid for interest
            
            $
            2,964
            
            
            $
            3,342Non-cash
      financing and investing activities:Asset
      retirement obligations
            
            $
            1,913
            
            
            $
            2,155Derivatives
      assumed in acquisition of natural gas and oil properties
            
            $
            4,128
            
            
            $
            2,468Deferred
      swap liability
            
            $
            3,072
            
            
            $
            —Non-monetary
      exchange of natural gas and oil properties
            
            $
            2,660
            
            
            $
            —Issuance
      of common units for acquisition of natural gas and oil
      properties
            
            $
            —
            
            
            $
            21,360Transfer
      of deposit for natural gas and oil properties
            
            $
            —
            
            
            $
            7,830


See
accompanying notes to consolidated financial statements





6


VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


(Unaudited)


(in
thousands)









Three Months
      Ended
                September
      30,
              
              
              Nine
      Months Ended
                September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008Net
      income (loss)
              
              $
              701
              
              
              $
              71,809
              
              
              $
              (56,032
              )
              
              $
              8,857Net
      gains (losses) from derivative contracts:Unrealized
      mark-to-market gains arising during the period
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              2,747Reclassification
      adjustments for settlements
              
              
              434
              
              
              
              7
              
              
              
              1,678
              
              
              
              (564
              )Other
      comprehensive income
              
              
              434
              
              
              
              7
              
              
              
              1,678
              
              
              
              2,183Comprehensive income
      (loss)
              
              $
              1,135
              
              
              $
              71,816
              
              
              $
              (54,354
              )
              
              $
              11,040






See
accompanying notes to consolidated financial statements





7





VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES


NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS


(Unaudited)





Description of the Business:





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





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





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





1.
            Summary
      of Significant Accounting Policies





The
accompanying financial statements are unaudited and were prepared from our
records. We derived the consolidated balance sheet as of December 31, 2008,
from the audited financial statements filed in our 2008 Annual Report on
Form 10-K.  Because this is an interim period filing presented
using a condensed format, it does not include all of the disclosures required by
U.S. generally accepted accounting principles (“GAAP”). You should read
this Quarterly Report on Form 10-Q along with our 2008 Annual Report on
Form 10-K, which contains a summary of our significant accounting policies and
other disclosures. In our opinion, we have made all adjustments which are of a
normal, recurring nature to fairly present our interim period results.
Information for interim periods may not be indicative of our operating results
for the entire year. Additionally, our financial statements for prior periods
include reclassifications that were made to conform to the current period
presentation. Those reclassifications did not impact our reported net loss,
members’ equity, or net cash flows.





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





(a)
            Basis of
      Presentation and Principles of
  Consolidation:





The
consolidated financial statements as of September 30, 2009 and December 31, 2008
and for the three and nine months ended September 30, 2009 and 2008 include our
accounts and those of our wholly-owned subsidiaries.  We present our
financial statements in accordance with GAAP.  All intercompany
transactions and balances have been eliminated upon consolidation.





(b)
            Recently
      Adopted Accounting Pronouncements:





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





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





8


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





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





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





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





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





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





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





9


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


(c)
            New
      Pronouncements Issued But Not Yet
Adopted:




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





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





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





(d)
            Use
      of Estimates:





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





2.
            Acquisitions





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




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





10


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




The
following unaudited pro-forma results for the three and nine months ended
September 30, 2008 show the effect on our consolidated results of operations as
if the Permian Basin acquisition and the South Texas acquisition had occurred on
January 1, 2008. The pro-forma results for the 2008 periods presented are the
results of combining our statement of operations with the revenues and direct
operating expenses of the oil and gas properties acquired adjusted for (1)
assumption of asset retirement obligations and accretion expense for the
properties acquired, (2) depletion expense applied to the adjusted basis of the
properties acquired using the purchase method of accounting, (3) interest
expense on additional borrowings necessary to finance the acquisition, and (4)
the impact of common units issued to partially finance the July 2008
acquisition. The pro-forma information is based upon these assumptions, and is
not necessarily indicative of future results of operations:





Pro-forma
              (in
      thousands, except per unit data)
              (unaudited)Three
      Months Ended
              September
      30, 2008
            
            
            Nine
      Months Ended
              September
      30, 2008Total
      revenues
            
            $
            85,166
            
            
            $
            48,181Net
      income
            
            $
            72,138
            
            
            $
            11,840Net
      income per unit:Common & Class B units – basic
            
            $
            5.74
            
            
            $
            0.94Common &
      Class B units – diluted
            
            $
            5.74
            
            
            $
            0.94






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





(in
      thousands)Fair
      value of assets and liabilities acquired:Natural
      gas and oil properties
            
            $
            54,942Derivative
      assets
            
            
            4,128Other
      currents assets
            
            
            187Accrued
      expenses
            
            
            (298
            )Asset
      retirement obligations
            
            
            (2,254
            )Total
      fair value of assets and liabilities acquired
            
            
            56,705Fair
      value of consideration transferred
            
            
            50,827Gain
      on acquisition of natural gas and oil properties
            
            $
            5,878










11


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





The
following unaudited pro-forma results for the three and nine months ended
September 30, 2009 and September 30, 2008 show the effect on our consolidated
results of operations as if this acquisition had occurred on January 1, 2009 and
on January 1, 2008, respectively. The pro-forma results for the 2009 and 2008
periods presented are the results of combining our statement of operations with
the revenues and direct operating expenses of the oil and gas properties
acquired adjusted for (1) assumption of asset retirement obligations and
accretion expense for the properties acquired, (2) depletion expense applied to
the adjusted basis of the properties acquired using the purchase method of
accounting, and (3) interest expense on additional borrowings necessary to
finance the acquisition. The pro-forma information is based upon these
assumptions, and is not necessarily indicative of future results of
operations:


Pro-forma
                    (in thousands,
      except per unit data)
                    (unaudited)Three
      Months Ended
                    September
      30,
                  
                  Nine
      Months Ended
                    September
      30,2009
                  
                  
                  2008
                  
                  
                  2009
                  
                  
                  2008Total
      revenues
                  
                  $
                  8,156
                  
                  
                  $
                  91,959
                  
                  
                  $
                  41,880
                  
                  
                  $
                  62,852Net
      income (loss)
                  
                  $
                  1,858
                  
                  
                  $
                  77,997
                  
                  
                  $
                  (53,002
                  )
                  
                  $
                  26,814Net
      income (loss) per unit:Common & Class B units – basic
                  
                  $
                  0.11
                  
                  
                  $
                  4.73
                  
                  
                  $
                  (3.21
                  )
                  
                  $
                  1.63Common &
      Class B units – diluted
                  
                  $
                  0.11
                  
                  
                  $
                  4.73
                  
                  
                  $
                  (3.21
                  )
                  
                  $
                  1.63


3.
            Credit
      Facility and Long-Term Debt





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





Amount Outstanding
              (in
      thousands)Description
            InterestRate
            MaturityDate
            
            September
      30,
              2009
            
            
            December31,
              2008Senior secured
      reserve-based credit facility
            Variable
      (1)
            October
      1, 2012
            
            $
            123,500
            
            
            $
            135,000


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




Senior
Secured Reserve-Based Credit Facility





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





12


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





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





Borrowing
      Base Utilization Percentage
            
            <50%
            
            >50%
      <75%
            
            >75%
      <90%
            
            >90%Eurodollar
      Loans
            
            2.25%
            
            2.50%
            
            2.75%
            
            3.00%ABR
      Loans
            
            1.25%
            
            1.50%
            
            1.75%
            
            2.00%Commitment
      Fee Rate
            
            0.50%
            
            0.50%
            
            0.50%
            
            0.50%Letter
      of Credit Fee
            
            2.25%
            
            2.50%
            
            2.75%
            
            3.00%





Our
reserve-based credit facility contains a number of customary covenants that
require us to maintain certain financial ratios, limit our ability to incur
indebtedness, enter into commodity and interest rate derivatives, grant certain
liens, make certain loans, acquisitions, capital expenditures and investments,
merge or consolidate, engage in certain asset dispositions, including a sale of
all or substantially all of the Company’s assets, or make distributions to our
unitholders when our outstanding borrowings exceed 90% of our borrowing base. At
September 30, 2009, we were in compliance with our debt
covenants.





4.
            Price
      Risk Management Activities





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





Under ASC
Topic 815 “Derivatives and
Hedging,” all derivative instruments are recorded on the consolidated
balance sheets at fair value as either short-term or long-term assets or
liabilities based on their anticipated settlement date.  We net
derivative assets and liabilities for counterparties where we have a legal right
of offset. Changes in the derivatives’ fair value are recognized currently in
earnings unless specific hedge accounting criteria are met. For qualifying cash
flow hedges, the unrealized gain or loss on the derivative is deferred in
accumulated other comprehensive income (loss) in the equity section of the
consolidated balance sheets to the extent the hedge is
effective.  Gains and losses on cash flow hedges included in
accumulated other comprehensive income (loss) are reclassified to gains (losses)
on commodity cash flow hedges or gains (losses) on interest rate derivative
contracts in the period that the related production is delivered or the contract
settles.  The unrealized gains (losses) on derivative contracts that
do not qualify for hedge accounting treatment are recorded as gains (losses) on
other commodity derivative contracts or gains (losses) on interest rate
derivative contracts in the consolidated statements of operations.





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





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





13


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





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





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





Swap
Agreements





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





Put Option
Contracts





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





Collars





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





Interest Rate
Swaps





We enter
into interest rate swap agreements, which require exchanges of cash flows that
serve to synthetically convert a portion of our variable interest rate exposures
to fixed interest rates.





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





14


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





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





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





Balance Sheet
Presentation





Our
commodity derivatives and interest rate swap derivatives are presented on a net
basis in “derivative assets” and “derivative liabilities” on the consolidated
balance sheets. The following summarizes the fair value of derivatives
outstanding on a gross basis.





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





By using
derivative instruments to economically hedge exposures to changes in commodity
prices and interest rates, we expose ourselves to credit risk and market
risk. Credit risk is the failure of the counterparty to perform under the
terms of the derivative contract. When the fair value of a derivative
contract is positive, the counterparty owes us, which creates credit risk. Our
counterparties are participants in our reserve-based credit facility (See Note
3. Credit Facilities and
Long-Term Debt for further discussion) which is secured by our natural
gas and oil properties; therefore, we are not required to post any
collateral. The maximum amount of loss due to credit risk that we would
incur if our counterparties failed completely to perform according to the terms
of the contracts, based on the gross fair value of financial instruments, was
approximately $30.7 million at September 30, 2009.





15


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





We
minimize the credit risk in derivative instruments by: (i) entering into
derivative instruments only with counterparties that are also lenders in our
reserve-based credit facility and (ii) monitoring the creditworthiness of
our counterparties on an ongoing basis. In accordance with our standard
practice, our commodity and interest rate swap derivatives are subject to
counterparty netting under agreements governing such derivatives and therefore
the risk of such loss is somewhat mitigated as of September 30,
2009.





Gain (Loss) on
Derivatives





Gains and
losses on derivatives are reported on the consolidated statement of operations
in “gain (loss) on other commodity derivative contracts” and “loss on interest
rate derivative contracts” and include realized and unrealized gains
(losses). Realized gains (losses) represent amounts related to the
settlement of derivative instruments. Unrealized gains (losses) represent
the change in fair value of the derivative instruments that will settle in the
future and are non-cash items.





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





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





5.
            Fair
      Value Measurements





As
discussed inNote 1.Summary of Significant
Accounting Policies (b), we adopted ASC Topic 820 for financial assets and
financial liabilities as of January 1, 2008 and for non-financial assets and
liabilities as of January 1, 2009. ASC Topic 820 does not expand the use of fair
value measurements, but rather, provides a framework for consistent measurement
of fair value for those assets and liabilities already measured at fair value
under other accounting pronouncements. Certain specific fair value measurements,
such as those related to share-based compensation, are not included in the scope
of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and
liabilities related to financial instruments, to some long-term investments and
liabilities, to initial valuations of assets and liabilities acquired in a
business combination, and to long-lived assets carried at fair value subsequent
to an impairment write-down. It does not apply to oil and natural gas properties
accounted for under the full cost method, which are subject to impairment based
on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair
value on the consolidated balance sheet, as well as to supplemental fair value
information about financial instruments not carried at fair value.




The
estimated fair values of our financial instruments closely approximate the
carrying amounts as discussed below:





Cash and cash equivalents, accounts
receivable, other current assets, accounts payable, payables to affiliates,
deferred swap liability, phantom unit compensation accrual, accrued ad valorem
taxes and accrued expenses.The carrying amounts approximate fair value
due to the short maturity of these instruments.





Long-term debt.The carrying
amount of our reserve-based credit facility approximates fair value because our
current borrowing rate does not materially differ from market rates for similar
bank borrowings.





We have
applied the provisions of ASC Topic 820 to assets and liabilities measured at
fair value on a recurring basis. This includes natural gas, oil and interest
rate derivatives contracts. ASC Topic 820 provides a definition of fair value
and a framework for measuring fair value, as well as expanding disclosures
regarding fair value measurements. The framework requires fair value measurement
techniques to include all significant assumptions that would be made by willing
participants in a market transaction. These assumptions include certain factors
not consistently provided for previously by those companies utilizing fair value
measurement; examples of such factors would include our own credit standing
(when valuing liabilities) and the buyer’s risk premium. In adopting ASC Topic
820, we determined that the impact of these additional assumptions on fair value
measurements did not have a material effect on our financial position or results
of operations.


16


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





ASC Topic
820 defines fair value as the exchange price that would be received for an asset
or paid to transfer a liability (an exit price) in the principal or most
advantageous market for the asset or liability in an orderly transaction between
market participants on the measurement date. ASC Topic 820 provides a hierarchy
of fair value measurements, based on the inputs to the fair value estimation
process. It requires disclosure of fair values classified according to the
“levels” described below. The hierarchy is based on the reliability of the
inputs used in estimating fair value and requires an entity to maximize the use
of observable inputs and minimize the use of unobservable inputs when measuring
fair value. The framework for fair value measurement assumes that transparent
“observable” (Level 1) inputs generally provide the most reliable evidence of
fair value and should be used to measure fair value whenever available. The
classification of a fair value measurement is determined based on the lowest
level (with Level 3 as the lowest) of significant input to the fair value
estimation process.





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


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





As
required by ASC Topic 820, financial assets and liabilities are classified based
on the lowest level of input that is significant to the fair value measurement.
Our assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels. Our commodity derivative instruments consist of swaps and options. We
estimate the fair values of the swaps based on published forward commodity price
curves for the underlying commodities as of the date of the estimate. We
estimate the option value of the contract floors and ceilings using an option
pricing model which takes into account market volatility, market prices and
contract parameters. The discount rate used in the discounted cash flow
projections is based on published LIBOR rates, Eurodollar futures rates and
interest swap rates. In order to estimate the fair value of our interest rate
swaps, we use a yield curve based on money market rates and interest rate swaps,
extrapolate a forecast of future interest rates, estimate each future cash flow,
derive discount factors to value the fixed and floating rate cash flows of each
swap, and then discount to present value all known (fixed) and forecasted
(floating) swap cash flows. Curve building and discounting techniques used to
establish the theoretical market value of interest bearing securities are based
on readily available money market rates and interest rate swap market data. To
extrapolate future cash flows, discount factors incorporating our
counterparties’ and our credit standing are used to discount future cash flows.
We have classified the fair values of all its derivative contracts as Level
2.





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





September
      30, 2009
              (in
      thousands)Fair Value Measurements Using
            
            
            Assets/LiabilitiesLevel
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            at Fair valueAssets:Commodity
      price derivative contracts
            
            $
            —
            
            
            $
            26,366
            
            
            $
            —
            
            
            $
            26,366Total
      derivative instruments
            
            $
            —
            
            
            $
            26,366
            
            
            $
            —
            
            
            $
            26,366Liabilities:Commodity
      price derivative contracts
            
            $
            —
            
            
            $
            (371
            )
            
            $
            —
            
            
            $
            (371
            )Interest
      rate derivative contracts
            
            
            —
            
            
            
            (2,459
            )
            
            
            —
            
            
            
            (2,459
            )Total
      derivative instruments
            
            $
            —
            
            
            $
            (2,830
            )
            
            $
            —
            
            
            $
            (2,830
            )





17


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





On
January 1, 2009, we adopted the previously-deferred provisions of ASC Topic 820
for nonfinancial assets and liabilities, which are comprised primarily of asset
retirement costs and obligations initially measured at fair value in accordance
with ASC Topic 410 Subtopic 20 “Asset Retirement Obligations”
(“ASC Topic 410-20”).  These assets and liabilities are recorded at
fair value when incurred but not re-measured at fair value in subsequent
periods.  We classify such initial measurements as Level 3 since
certain significant unobservable inputs are utilized in their
determination.  A reconciliation of the beginning and ending balance
of our asset retirement obligations is presented in Note 6, in accordance with
ASC Topic 410-20.  During the nine months ended September 30, 2009, in
connection with natural gas and oil properties acquired in the Sun TSH
acquisition, we incurred and recorded asset retirement obligations totaling $2.3
million at fair value. The fair value of additions to the asset retirement
obligation liability is measured using valuation techniques consistent with the
income approach, converting future cash flows to a single discounted
amount.  Inputs to the valuation include: (1) estimated plug and
abandon cost per well based on our experience; (2) estimated remaining life
per well based on average reserve life per field; (3) our credit-adjusted
risk-free interest rate (2.4%); and (4) the ten year average inflation factor
(2.4%).  The adoption of ASC Topic 820 on January 1, 2009, as it
relates to nonfinancial assets and nonfinancial liabilities, did not have a
material impact on our financial position or results of operations.





6.
            Asset
      Retirement Obligations





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





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





7.
            Related
      Party Transactions





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





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





18
 VANGUARD
NATURAL RESOURCES, LLC AND SUBSIDIARIES
 NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
 (Unaudited)


8.
            Common
      Units and Net Income per Unit





Basic
earnings per unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC
Topic 260”), by
dividing net income (loss) attributable to unitholders by the weighted average
number of units outstanding during the period. Diluted earnings per unit is
computed by adjusting the average number of units outstanding for the dilutive
effect, if any, of unit equivalents.  We use the treasury stock method to
determine the dilutive effect. As of September 30, 2009, we have two
classes of units outstanding:  (i) units representing limited
liability company interests (“common units”) listed on NYSE under the symbol VNR
and (ii) Class B units, issued to management and an employee as
discussed inNote
9. Unit-Based
Compensation. The Class B units participate in distributions and no
forfeiture is expected; therefore, all Class B units were considered in the
computation of basic earnings per unit. The 175,000 options granted to officers
under our long-term incentive plan had no dilutive effect as the exercise price
was higher than the market price at September 30, 2009; therefore, they have
been excluded from the computation of diluted earnings per unit. In addition,
the phantom units granted to officers under our long-term incentive plan will
have no dilutive effect unless there is a liability at December 31, 2009 and if
the officers elect to have the liability satisfied in units; therefore, they
have been excluded from the computation of diluted earnings per
unit.





In
accordance with ASC Topic 260, dual presentation of basic and diluted earnings
per unit has been presented in the consolidated statements of operations for the
three and nine months ended September 30, 2009 and 2008 including each class of
units issued and outstanding at that date: common units and Class B
units. Net income (loss) per unit is allocated to the common units and the
Class B units on an equal basis.





9.
            Unit-Based
      Compensation





In April
2007, the sole member at that time reserved 460,000 restricted Class B units in
VNR for issuance to employees. Certain members of management were granted
365,000 restricted Class B units in VNR in April 2007, which vested two years
from the date of grant. In addition, another 55,000 restricted VNR Class B units
were issued in August 2007 to two other employees that were hired in April and
May of 2007, which will vest after three years. The remaining 40,000 restricted
Class B units are available to be awarded to new employees or members of our
board of directors as they are retained.





In
October 2007, one board member was granted 5,000 common units and in February
2008, three board members were granted 5,000 common units each of which vested
after one year. Additionally, in October 2007, two officers were granted options
to purchase an aggregate of 175,000 units under our long-term incentive plan
with an exercise price equal to the initial public offering price of $19.00
which vested immediately upon being granted and had a fair value of $0.1 million
on the date of grant. The grant date fair value for these option awards was
calculated in accordance with ASC Topic 718 “Compensation- Stock
Compensation” (“ASC Topic 718”), by calculating the Black-Scholes value
of each option, using a volatility rate of 12.18%, an expected dividend yield of
8.95% and a discount rate of 5.12%, and multiplying the Black-Scholes value by
the number of options awarded.





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





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





These
common units, Class B units, options and phantom units were granted as partial
consideration for services to be performed under employment contracts and thus
will be subject to accounting for these grants under ASC Topic 718. The fair
value of restricted units issued is determined based on the fair market value of
common units on the date of the grant. This value is amortized over the vesting
period as referenced above. A summary of the status of the non-vested units as
of September 30, 2009 is presented below:





19


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






Number of
              Non-vested Units
            
            
            Weighted Average
              Grant Date Fair ValueNon-vested
      units at December 31, 2008
            
            
            440,000
            
            
            $
            18.10Granted
            
            
            37,950
            
            
            $
            8.07Vested
            
            
            (385,000
            )
            
            $
            (17.97
            )Non-vested
      units at September 30, 2009
            
            
            92,950
            
            
            $
            14.54





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





10.
            Shelf
      Registration Statement





During
the third quarter 2009, we filed a registration statement with the SEC which
registered offerings of up to $300.0 million of any combination of debt
securities, common units and guarantees of debt securities by our subsidiaries.
Net proceeds, terms and pricing of the offering of securities issued under the
shelf registration statement will be determined at the time of the offerings.
The shelf registration statement does not provide assurance that we will or
could sell any such securities. Our ability to utilize the shelf registration
statement for the purpose of issuing, from time to time, any combination of debt
securities or common units will depend upon, among other things, market
conditions and the existence of investors who wish to purchase our securities at
prices acceptable to us.





In August
2009, we completed an offering of 3.9 million shares of its common units. The
units were offered to the public at a price of $14.25 per unit. We received net
proceeds of approximately $53.2 million from the offering, after deducting
underwriting discounts
of $2.4 million and offering costs of $0.5 million. As a result of the offering,
we have approximately $244.0 million remaining available under our 2009 shelf
registration statement as of September 30, 2009.





11.
            Subsequent
      Event





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


20


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





The
following discussion and analysis should be read in conjunction with the
financial statements and related notes presented in Item 1 of this Quarterly
Report on Form 10-Q and information disclosed in our 2008 Annual Report on
Form 10-K.





Forward-Looking
Statements





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





Such
forward-looking statements are subject to various risks and uncertainties that
could cause actual results to differ materially from those anticipated as of the
date of this report. Although we believe that the expectations reflected in
these forward-looking statements are based on reasonable assumptions, no
assurance can be given that these expectations will prove to be correct.
Important factors that could cause our actual results to differ materially from
the expectations reflected in these forward-looking statements include, among
other things, those set forth in the Risk Factor section of the 2008 Annual
Report on Form 10-K and this Quarterly Report on Form 10-Q, and those set forth
from time to time in our filings with the SEC, which are available on our
website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and
Retrieval System (“EDGAR”) at http://www.sec.gov.





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





Overview





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





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





Disruption
to Functioning of Capital Markets





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





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





21


Permian
Basin Acquisition





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





South
Texas Acquisition





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





Sun
TSH Acquisition





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





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





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





(1)
            Price
      is calculated based on weighted average
pricing.





22


Reserve-Based
Credit Facility





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





Borrowing
      Base Utilization Percentage
            
            <50%
            
            >50%
      <75%
            
            >75%
      <90%
            
            >90%Eurodollar
      Loans
            
            2.25%
            
            2.50%
            
            2.75%
            
            3.00%ABR
      Loans
            
            1.25%
            
            1.50%
            
            1.75%
            
            2.00%Commitment
      Fee Rate
            
            0.50%
            
            0.50%
            
            0.50%
            
            0.50%Letter
      of Credit Fee
            
            2.25%
            
            2.50%
            
            2.75%
            
            3.00%





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





Outlook





Our
revenue, cash flow from operations, and future growth depend substantially on
factors beyond our control, such as access to capital, economic, political and
regulatory developments, and competition from other sources of energy. Multiple
events during 2008 and 2009 involving numerous financial institutions
effectively restricted liquidity within the capital markets throughout the
United States and around the world. While capital markets remain volatile,
efforts by treasury and banking regulators in the United States, Europe and
other nations around the world to provide liquidity to the financial sector
appears to have improved the situation. As evidenced by our recent successful
equity offering, successful amendment of our reserve-based credit facility and
recent successful equity and debt offerings by our peers, we believe that our
access to capital has improved and we have been successful in improving our
financial position to date.





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





23


We face
the challenge of natural gas, natural gas liquids and oil production declines.
As a given well’s initial reservoir pressures are depleted, natural gas, natural
gas liquids and oil production decreases, thus reducing our total reserves. We
attempt to overcome this natural decline both by drilling on our properties and
acquiring additional reserves. We will maintain our focus on controlling costs
to add reserves through drilling and acquisitions, as well as controlling the
corresponding costs necessary to produce such reserves. During the nine months
ended September 30, 2009, we did not drill any wells on our operated properties
and there was limited drilling on non-operated properties. Our ability to add
reserves through drilling is dependent on our capital resources and can be
limited by many factors, including the ability to timely obtain drilling permits
and regulatory approvals and voluntary reductions in capital spending in a low
commodity price environment. Any delays in drilling, completion or connection to
gathering lines of our new wells will negatively impact the rate of our
production, which may have an adverse effect on our revenues and as a result,
cash available for distribution. In accordance with our business plan, we intend
to invest the capital necessary to maintain our production at existing levels
over the long-term provided that it is economical to do so based on the
commodity price environment. However, we cannot be certain that we will be able
to issue equity securities on favorable terms, or at all, and we may be unable
to refinance our reserve-based credit facility when it expires. Additionally,
due to the significant decline in commodity prices, our borrowing base under our
reserve-based credit facility may be redetermined such that it will not provide
for the working capital necessary to fund our capital spending program and could
affect our ability to make distributions. The next scheduled redetermination of
our borrowing base is April 2010.





Results
of Operations





The
following table sets forth selected financial and operating data for the periods
indicated (in thousands):





Three Months Ended
              September 30,
            
            
            Nine Months Ended
              September 30,2009(c)
            
            
            2008(b)
            
            
            2009(c)
            
            
            2008(a)(b)Revenues:Natural
      gas sales
            
            $
            4,742
            
            
            $
            12,708
            
            
            $
            15,500
            
            
            $
            34,812Natural
      gas liquids sales
            
            
            1,136
            
            
            
            601
            
            
            
            1,811
            
            
            
            824Oil
      sales
            
            
            5,446
            
            
            
            7,530
            
            
            
            12,619
            
            
            
            20,057Natural
      gas, natural gas liquids and oil sales
            
            
            11,324
            
            
            
            20,839
            
            
            
            29,930
            
            
            
            55,693Realized
      gain (loss) on commodity cash flow hedges
            
            
            (463
            )
            
            
            45
            
            
            
            (1,737
            )
            
            
            616Realized
      gain (loss) on other commodity derivative contracts
            
            
            8,010
            
            
            
            (2,989
            )
            
            
            23,794
            
            
            
            (10,410
            )Unrealized
      gain (loss) on other commodity derivative contracts
            
            
            (12,220
            )
            
            
            66,353
            
            
            
            (16,492
            )
            
            
            (6,043
            )Total
      revenues
            
            $
            6,651
            
            
            $
            84,248
            
            
            $
            35,495
            
            
            $
            39,856Costs
      and expenses:Lease
      operating expenses
            
            $
            3,322
            
            
            $
            3,485
            
            
            $
            9,233
            
            
            $
            7,800Depreciation,
      depletion, amortization, and accretion
            
            
            3,272
            
            
            
            4,187
            
            
            
            9,700
            
            
            
            10,341Impairment
      of natural gas and oil properties
            
            
            —
            
            
            
            —
            
            
            
            63,818
            
            
            
            —Selling,
      general and administrative expenses
            
            
            2,137
            
            
            
            1,560
            
            
            
            8,230
            
            
            
            4,843Production
      and other taxes
            
            
            974
            
            
            
            1,263
            
            
            
            2,537
            
            
            
            3,658Total
      costs and expenses
            
            $
            9,705
            
            
            $
            10,495
            
            
            $
            93,518
            
            
            $
            26,642Other
      income and (expense):Interest
      expense, net
            
            $
            (1,042
            )
            
            $
            (1,485
            )
            
            $
            (3,034
            )
            
            $
            (3,847
            )Gain
      on acquisition of natural gas and oil properties
            
            
            5,878
            
            
            
            —
            
            
            
            5,878
            
            
            
            —Realized
      loss on interest rate derivative contracts
            
            $
            (506
            )
            
            $
            (39
            )
            
            $
            (1,240
            )
            
            $
            (90
            )Unrealized
      gain (loss) on interest rate derivative contracts
            
            $
            (575
            )
            
            $
            (420
            )
            
            $
            387
            
            
            $
            (420
            )





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





24


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





Revenues





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





Three Months Ended
              September
      30,
            
            Percentage
              Increase
              (Decrease)2009
            
            2008Net
      Natural Gas Production:Appalachian
      gas (MMcf)
            
            
            773
            
            923
            
            (16)
            %Permian
      gas (MMcf)
            
            
            57
            
            —
            
            N/ASouth
      Texas gas (MMcf)
            
            
            196
            
            160
            (a)
            23
            %Sun
      TSH gas (MMcf)
            
            
            139
            (b)
            —
            
            N/ATotal
      natural gas production (MMcf)
            
            
            1,165
            
            1,083
            
            8
            %Average
      Appalachian daily gas production (Mcf/day)
            
            
            8,403
            
            10,031
            
            (16)
            %Average
      Permian daily gas production (Mcf/day)
            
            
            617
            
            —
            
            N/AAverage
      South Texas daily gas production (Mcf/day)
            
            
            2,136
            
            2,463
            (a)
            (13)
            %Average
      Sun TSH daily gas production (Mcf/day)
            
            
            3,
      088
            (b)
            —
            
            N/AAverage
      Vanguard daily gas production (Mcf/day)
            
            
            14,244
            
            12,494Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including hedges
            
            $
            11.12
            (c)
            $10.84
            (c)
            3
            %Net
      realized gas price, excluding hedges
            
            $
            4.07
            
            $10.94
            
            (63)
            %Net
      Oil Production:Appalachian
      oil (Bbls)
            
            
            25,451
            
            11,122
            
            129
            %Permian
      oil (Bbls)
            
            
            57,525
            
            54,924
            
            5
            %Sun
      TSH oil (Bbls)
            
            
            2,425
            (b)
            —
            
            N/ATotal
      oil production (Bbls)
            
            
            85,401
            
            66,046
            
            29
            %Average
      Appalachian daily oil production (Bbls/day)
            
            
            277
            
            121
            
            129
            %Average
      Permian daily oil production (Bbls/day)
            
            
            625
            
            597
            
            5
            %Average
      Sun TSH daily oil production (Bbls/day)
            
            
            54
            (b)
            —
            
            N/AAverage
      Vanguard daily oil production (Bbls/day)
            
            
            956
            
            718Average
      Oil Sales Price per Bbl:Net
      realized oil price, including hedges
            
            $
            77.15
            (c)
            $93.26
            (c)
            (17)
            %Net
      realized oil price, excluding hedges
            
            $
            63.76
            
            $114.01
            
            (44)
            %Net
      Natural Gas Liquids Production:Permian
      natural gas liquids (Gal)
            
            
            105,336
            
            128,171
            
            (18)
            %South
      Texas natural gas liquids (Gal)
            
            
            436,922
            
            421,680
            (a)
            4
            %Sun
      TSH natural gas liquids (Gal)
            
            
            848,954
            (b)
            —
            
            N/ATotal natural gas
      liquids production
      (Gal)
            
            
            1,391,212
            
            549,851
            
            153
            %Average
      Permian daily natural gas liquids production (Gal/day)
            
            
            1,145
            
            1,393
            
            (18)
            %Average
      South Texas daily natural gas liquids production (Gal/day)
            
            
            4,749
            
            6,487
            (a)
            (27)
            %Average
      Sun TSH daily natural gas liquids production (Gal/day)
            
            
            18,866
            (b)
            —
            
            N/AAverage Vanguard daily natural
      gas liquids production
      (Gal/day)
            
            
            24,760
            
            7,880Average
      Natural Gas Liquids Sales Price per Gal:Net
      realized natural gas liquids price, including hedges
            
            $
            0.82
            (c)
            $1.09
            (c)
            (25)
            %Net
      realized natural gas liquids price, excluding hedges
            
            $
            0.82
            
            $1.09
            
            (25)
            %





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





25


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





Hedging
and Price Risk Management Activities





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





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





26


The
purpose of our hedging program is to mitigate the volatility in our cash flow.
Depending on the type of derivative contract used, hedging generally achieves
this by the counterparty paying us when commodity prices are below the hedged
price and we pay the counterparty when commodity prices are above the hedged
price.  In either case, the impact on our cash flow is approximately
the same. However, because the majority of our hedges are not designated as cash
flow hedges, there can be a significant amount of volatility in our earnings
when we record the change in the fair value of all of our derivative contracts.
As commodity prices fluctuate, the fair value of those contracts will fluctuate
and the impact is reflected as a non-cash, unrealized gain or loss in our
consolidated statement of operations. However, these fair value changes that are
reflected in the consolidated statement of operations only reflect the value of
the derivative contracts to be settled in the future and do not take into
consideration the value of the underlying commodity. If the fair value of the
derivative contract goes down, it means that the value of the commodity being
hedged has gone up, and the net impact to our cash flow when the contract
settles and the commodity is sold in the market will be approximately the same.
Conversely, if the fair value of the derivative contract goes up, it means the
value of the commodity being hedged has gone down and again the net impact to
our cash flow when the contract settles and the commodity is sold in the market
will be approximately the same.





Costs
and Expenses





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





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





Selling,
general and administrative expenses include the costs of our administrative
employees and executive officers, related benefits, office leases, professional
fees and other costs not directly associated with field operations. These
expenses for the three months ended September 30, 2009 increased $0.6 million as
compared to the three months ended September 30, 2008 principally due to an
increase in non-cash charges.  For the three months ended September
30, 2009 and 2008, non-cash compensation charges amounted to $1.3 million and
$0.8 million, respectively, related to the grant of restricted Class B units to
officers and an employee, the grant of unit options to management, the grant of
phantom units to officers and the grant of common units to board members and
employees during 2007 through 2009.





Production
and other taxes include severance, ad valorem, and other taxes. Severance taxes
are a function of volumes and revenues generated from production. Ad valorem
taxes vary by state/county and are based on the value of our reserves.
Production and other taxes decreased by $0.3 million for the three months ended
September 30, 2009 as compared to the same period in 2008 as a result of
decreased natural gas and oil revenues.





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





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





Revenues





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





27




Nine Months Ended
              September
      30,
            
            Percentage
              Increase
              (Decrease)2009
            
            2008Net
      Natural Gas Production:Appalachian
      gas (MMcf)
            
            
            2,372
            
            2,693
            
            (12)
            %Permian
      gas (MMcf)
            
            
            153
            
            132
            (a)
            16
            %South
      Texas gas (MMcf)
            
            
            624
            
            179
            (b)
            249
            %Sun
      TSH gas (MMcf)
            
            
            139
            (c)
            —
            
            N/ATotal
      natural gas production (MMcf)
            
            
            3,288
            
            3,004
            
            9
            %Average
      Appalachian daily gas production (Mcf/day)
            
            
            8,691
            
            9,827
            
            (12)
            %Average
      Permian daily gas production (Mcf/day)
            
            
            560
            
            543
            (a)
            3
            %Average
      South Texas daily gas production (Mcf/day)
            
            
            2,286
            
            2,757
            (b)
            (17)
            %Average
      Sun TSH daily gas production (Mcf/day)
            
            
            3,088
            (c)
            —
            
            N/AAverage
      Vanguard daily gas production (Mcf/day)
            
            
            14,625
            
            13,127Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including hedges
            
            $
            11.13
            (d)
            $10.52
            (d)
            6
            %Net
      realized gas price, excluding hedges
            
            $
            4.71
            
            $11.29
            
            (58)
            %Net
      Oil Production:Appalachian
      oil (Bbls)
            
            
            63,148
            
            32,543
            
            94
            %Permian
      oil (Bbls)
            
            
            175,175
            
            157,463
            (a)
            11
            %Sun
      TSH oil (Bbls)
            
            
            2,425
            (c)
            —
            
            N/ATotal
      oil production (Bbls)
            
            
            240,748
            
            190,006
            
            27
            %Average
      Appalachian daily oil production (Bbls/day)
            
            
            231
            
            119
            
            94
            %Average
      Permian daily oil production (Bbls/day)
            
            
            642
            
            648
            (a)
            (1)
            %Average
      Sun TSH daily oil production (Bbls/day)
            
            
            54
            (c)
            —
            
            N/AAverage
      Vanguard daily oil production (Bbls/day)
            
            
            927
            
            767Average
      Oil Sales Price per Bbl:Net
      realized oil price, including hedges
            
            $
            74.64
            (d)
            $87.61
            (d)
            (15)
            %Net
      realized oil price, excluding hedges
            
            $
            52.42
            
            $105.56
            
            (50)
            %Net
      Natural Gas Liquids Production:Permian
      natural gas liquids (Gal)
            
            
            340,536
            
            128,171
            (a)
            166
            %South
      Texas natural gas liquids (Gal)
            
            
            1,268,161
            
            421,680
            (b)
            201
            %Sun
      TSH natural gas liquids (Gal)
            
            
            848,954
            (c)
            —
            
            N/ATotal
      natural gas liquids production (Gal)
            
            
            2,457,651
            
            549,851
            
            347
            %Average
      Permian daily natural gas liquids production (Gal/day)
            
            
            1,247
            
            527
            (a)
            137
            %Average
      South Texas daily natural gas liquids production (Gal/day)
            
            
            4,645
            
            6,487
            (b)
            (28)
            %Average
      Sun TSH daily natural gas liquids production (Gal/day)
            
            
            18,866
            (c)
            —
            
            N/AAverage Vanguard daily natural
      gas liquids production
      (Gal/day)
            
            
            24,758
            
            7,014Average
      Natural Gas Liquids Sales Price per Gal:Net
      realized natural gas liquids price, including hedges
            
            $
            0.74
            (d)
            $1.50
            (d)
            (51)
            %Net
      realized natural gas liquids price, excluding hedges
            
            $
            0.74
            
            $1.50
            
            (51)
            %





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





28


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





Hedging
and Price Risk Management Activities





During
the nine months ended September 30, 2009, we recognized $1.7 million
related to losses on commodity cash flow hedges compared to gains of $0.6
million during the same period in 2008. These amounts relate to derivative
contracts that we entered into in order to mitigate commodity price exposure on
a portion of our expected production and designated as cash flow hedges. The
loss on commodity cash flow hedges for the nine months ended September 30, 2009
relates to the amount that settled in 2009 and has been reclassified to earnings
from accumulated other comprehensive loss.





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





The
purpose of our hedging program is to mitigate the volatility in our cash flow.
Depending on the type of derivative contract used, hedging generally achieves
this by the counterparty paying us when commodity prices are below the hedged
price and we pay the counterparty when commodity prices are above the hedged
price.  In either case, the impact on our cash flow is approximately
the same. However, because the majority of our hedges are not designated as cash
flow hedges, there can be a significant amount of volatility in our earnings
when we record the change in the fair value of all of our derivative contracts.
As commodity prices fluctuate, the fair value of those contracts will fluctuate
and the impact is reflected as a non-cash, unrealized gain or loss in our
consolidated statement of operations. However, these fair value changes that are
reflected in the consolidated statement of operations only reflect the value of
the derivative contracts to be settled in the future and do not take into
consideration the value of the underlying commodity. If the fair value of the
derivative contract goes down, it means that the value of the commodity being
hedged has gone up, and the net impact to our cash flow when the contract
settles and the commodity is sold in the market will be approximately the same.
Conversely, if the fair value of the derivative contract goes up, it means the
value of the commodity being hedged has gone down and again the net impact to
our cash flow when the contract settles and the commodity is sold in the market
will be approximately the same.





29


Costs
and Expenses





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





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





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





Selling,
general and administrative expenses include the costs of our administrative
employees and executive officers, related benefits, office leases, professional
fees and other costs not directly associated with field operations. These
expenses for the nine months ended September 30, 2009 increased $3.4 million as
compared to the nine months ended September 30, 2008 principally due to an
increase in non-cash charges.  For the nine months ended September 30,
2009 and 2008, non-cash compensation charges amounted to $5.3 million and $2.7
million, respectively, related to the grant of restricted Class B units to
officers and an employee, the grant of unit options to management, the grant of
phantom units to officers and the grant of common units to board members and
employees during 2007 through 2009. All other cash selling, general and
administrative expenses increased $0.8 million during the nine months ended
September 30, 2009 as compared to the same period in 2008 principally due to
incremental costs associated with the company’s growth and
acquisitions.





Production
and other taxes include severance, ad valorem, and other taxes. Severance taxes
are a function of volumes and revenues generated from production. Ad valorem
taxes vary by state/county and are based on the value of our reserves.
Production and other taxes decreased by $1.1 million for the nine months ended
September 30, 2009 as compared to the same period in 2008 as a result of
decreased natural gas and oil revenues.





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




Critical Accounting Policies and
Estimates





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





As of
September 30, 2009, our critical accounting policies are consistent with those
discussed in our Annual Report on Form 10-K for the year ended December 31,
2008.





30


Recently
Adopted Accounting Pronouncements





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





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





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





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





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





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





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





31


In May
2009, the FASB issued general standards of accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are issued or are available to be issued. This guidance is contained in ASC
Topic 855, “Subsequent
Events” (“ASC Topic 855”). In particular, this guidance sets forth: (1)
the period after the balance sheet date during which management of a reporting
entity should evaluate events or transactions that may occur for potential
recognition or disclosure in the financial statements; (2) the circumstances
under which an entity should recognize events or transactions occurring after
the balance sheet date in its financial statements; and (3) the disclosures that
an entity should make about events or transactions that occurred after the
balance sheet date. In accordance with this guidance, an entity should apply the
requirements to interim or annual financial periods ending after June 15, 2009.
We adopted the provisions of ASC Topic 855 effective June 30, 2009 and the
adoption did not have a material impact on our financial statements. The date
through which subsequent events have been evaluated is November 4, 2009, the
date on which the financial statements were issued. See Note 10 on Part 1—Item
1—Notes to Consolidated Financial Statements for further
discussion.





New
Pronouncements Issued But Not Yet Adopted





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





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





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





Use
of Estimates





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





Liquidity
and Capital Resources





Disruption
to Functioning of Capital Markets





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





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


32





Overview





We have
utilized private equity, proceeds from bank borrowings, cash flow from
operations and more recently the public equity markets for capital resources and
liquidity. To date, the primary use of capital has been for the acquisition
and development of natural gas and oil properties; however, we expect to
distribute to unitholders a significant portion of our free cash flow.  As
we execute our business strategy, we will continually monitor the capital
resources available to us to meet future financial obligations, planned capital
expenditures, acquisition capital and distributions to our unitholders. Our
future success in growing reserves, production and cash flow will be highly
dependent on the capital resources available to us and our success in drilling
for and acquiring additional reserves. We expect to fund our drilling
capital expenditures and distributions to unitholders with cash flow from
operations, while funding any acquisition capital expenditures that we might
incur with borrowings under our reserve-based credit facility and publicly
offered equity, depending on market conditions. As of October 31, 2009, we have
$52.0 million available to be borrowed under our reserve-based credit
facility.





The
borrowing base is subject to adjustment from time to time but not less than on a
semi-annual basis based on the projected discounted present value (as determined
by independent petroleum engineers) of estimated future net cash flows
(utilizing the bank’s internal projection of future natural gas, natural gas
liquids and oil prices) from our proved natural gas, natural gas liquids and oil
reserves. Based on the current commodity price environment, banks have lowered
their internal projections of future natural gas, natural gas liquids and oil
prices which has decreased the borrowing base and thus decreased the amount
available to be borrowed under our reserve-based credit facility. In October
2009, we entered into the First Amendment to the Second Amended and Restated
Credit Agreement, which reduced our borrowing base under the reserve-based
credit facility from $175.0 million to $170.0 million pursuant to our
semi-annual redetermination and changed the definition of majority lenders from
75% to 66.67%. All other terms under the reserve-based credit facility remained
the same. If commodity prices continue to decline and banks continue to lower
their internal projections of natural gas, natural gas liquids and oil prices,
it is possible that we will be subject to additional decreases in our borrowing
base availability in the future. If our outstanding borrowings under the
reserve-based credit facility exceed 90% of the borrowing base, we would be
required to suspend distributions to our unitholders until we have reduced our
borrowings to below the 90% threshold. As a result, absent accretive
acquisitions, to the extent available after unitholder distributions, debt
service, and capital expenditures, it is our current intention to utilize our
excess cash flow during the remainder of 2009 to reduce our borrowings under our
reserve-based credit facility. Based upon current expectations, we believe
existing liquidity and capital resources will be sufficient for the conduct of
our business and operations for the foreseeable future.





Cash
Flow from Operations





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





Cash flow
from operations is subject to many variables, the most significant of which is
the volatility of natural gas, natural gas liquids and oil prices. Natural
gas, natural gas liquids and oil prices are determined primarily by prevailing
market conditions, which are dependent on regional and worldwide economic
activity, weather, and other factors beyond our control. Future cash flow
from operations will depend on our ability to maintain and increase production
through our drilling program and acquisitions, as well as the prices received
for production. We enter into derivative contracts to reduce the impact of
commodity price volatility on our cash flows. It is never management’s
intention to hold or issue derivative instruments for speculative trading
purposes, and as such, we classify these cash flows as operating activities.
Currently, we use a combination of fixed-price swaps and NYMEX collars and put
options to reduce our exposure to the volatility in natural gas, natural gas
liquids and oil prices. See Note 4 in Notes to Consolidated Financial
Statements and Part 1—Item 3—Quantitative and Qualitative Disclosures About
Market Risk—Commodity Price Risk for details about derivatives in place through
2011.





Cash
Flow from Investing Activities





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





33


Cash Flow from
Financing Activities





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





Reserve-Based
Credit Facility





On
January 3, 2007, we entered into a reserve-based credit facility under which our
initial borrowing base was set at $115.5 million. Our reserve-based credit
facility was amended and restated in February 2008 to extend the maturity date
from January 2011 to March 2011, increase the maximum facility amount from
$200.0 million to $400.0 million, increase our borrowing base from $110.5
million to $150.0 million and add two additional financial institutions as
lenders, Wachovia Bank, N.A. and the Bank of Nova Scotia. The increase in the
borrowing base was principally the result of inclusion of the reserves related
to the Permian Basin acquisition in January 2008. In May 2008, our reserve-based
credit facility was amended in response to a potential acquisition that
ultimately did not occur. As a result, none of the provisions included in this
amendment went into effect. As of October 22, 2008, our reserve-based credit
facility was amended to increase the borrowing base to $175.0 million and add
one lender, BBVA Compass Bank. The increase in the borrowing base was
principally the result of inclusion of the reserves related to the South Texas
acquisition in July 2008. In February 2009, a third amendment was entered into
which amended covenants to allow the company to repurchase up to $5.0 million of
our own units. In May 2009, our borrowing base was set at $154.0 million
pursuant to our semi-annual redetermination. In June 2009, a fourth amendment to
our reserve-based credit facility was entered into which temporarily increased
the percentage of outstanding indebtedness for which interest rate derivatives
could be used. The percentage was increased from 75% to 85% but was to revert
back to 75% in one year at June 2010. In August 2009, our reserve-based credit
facility was amended and restated to (1) extend the maturity from March 31, 2011
to October 1, 2012, (2) increase our borrowing base from $154.0 million to
$175.0 million, (3) increase our borrowing costs, (4) permanently allow 85% of
our outstanding indebtedness to be covered under interest rate derivatives, and
(5) add two financial institutions as lenders, Comerica Bank and Royal Bank of
Canada. At September 30, 2009, we had $123.5 million outstanding under our
reserve-based credit facility and as of October 31, 2009, we have $52.0 million
available to be borrowed under our reserve-based credit facility.





The
borrowing base is subject to adjustment from time to time but not less than on a
semi-annual basis based on the projected discounted present value (as determined
by independent petroleum engineers) of estimated future net cash flows
(utilizing the bank’s internal projection of future natural gas, natural gas
liquids and oil prices) from our proved natural gas, natural gas liquids and oil
reserves. Based on the current commodity price environment, banks have lowered
their internal projections of future natural gas, natural gas liquids and oil
prices which has decreased the borrowing base and thus decreased the amount
available to be borrowed under our reserve-based credit facility. In October
2009, we entered into the First Amendment to the Second Amended and Restated
Credit Agreement, which reduced our borrowing base under the reserve-based
credit facility from $175.0 million to $170.0 million pursuant to our
semi-annual redetermination and changed the definition of majority lenders from
75% to 66.67%. All other terms under the reserve-based credit facility remained
the same. If commodity prices continue to decline and banks continue to lower
their internal projections of natural gas, natural gas liquids and oil prices,
it is possible that we will be subject to additional decreases in our borrowing
base availability in the future. If our outstanding borrowings under the
reserve-based credit facility exceed 90% of the borrowing base, we would be
required to suspend distributions to our unitholders until we have reduced our
borrowings to below the 90% threshold. As a result, absent accretive
acquisitions, to the extent available after unitholder distributions, debt
service, and capital expenditures, it is our current intention to utilize our
excess cash flow during the remainder of 2009 to reduce our borrowings under our
reserve-based credit facility.





Borrowings
under the reserve-based credit facility are available for the development and
acquisition of natural gas and oil properties, working capital, and general
limited liability company purposes. Our obligations under the reserve-based
credit facility are secured by substantially all of our assets.





At our
election, interest is determined by reference to:





34


·
            the
      London interbank offered rate, or LIBOR, plus an applicable margin between
      2.25% and 3.00% per annum; or





·
            a
      domestic bank rate plus an applicable margin between 1.25% and 2.00% per
      annum.





As of
September 30, 2009, we have elected for interest to be determined by reference
to the LIBOR method described above. Interest is generally payable quarterly for
domestic bank rate loans and at the applicable maturity date for LIBOR loans,
but not less frequently than quarterly.





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





·
            incur
      indebtedness;





·
            grant
      certain liens;





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





·
            make
      distributions;





·
            merge
      or consolidate; or





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





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





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





·
            consolidated
      current assets, including the unused amount of the total commitments, to
      consolidated current liabilities of not less than 1.0 to 1.0, excluding
      non-cash assets and liabilities under ASC Topic 815, which includes the
      current portion of derivative contracts;
and





·
            consolidated
      debt to consolidated net income plus interest expense, income taxes,
      depreciation, depletion, amortization, accretion, changes in fair value of
      derivative instruments and other similar charges, minus all non-cash
      income added to consolidated net income, and giving pro-forma effect to
      any acquisitions or capital expenditures of not more than 3.5 to
      1.0.





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





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





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





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





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





35
 
 ·
                default
      by us on the payment of any other indebtedness in excess of $2.0 million,
      or any event occurs that permits or causes the acceleration of the
      indebtedness;
 
 ·
                bankruptcy
      or insolvency events involving us or our
  subsidiaries;
 
 ·
                the
      entry of, and failure to pay, one or more adverse judgments in excess of
      $1.0 million or one or more non-monetary judgments that could reasonably
      be expected to have a material adverse effect and for which enforcement
      proceedings are brought or that are not stayed pending
    appeal;
 
 ·
                specified
      events relating to our employee benefit plans that could reasonably be
      expected to result in liabilities in excess of $1.0 million in any year;
      and
 
 ·
                a
      change of control, which includes (1) an acquisition of ownership,
      directly or indirectly, beneficially or of record, by any person or group
      (within the meaning of the Securities Exchange Act of 1934 and the rules
      of the Securities Exchange Commission) of equity interests representing
      more than 25% of the aggregate ordinary voting power represented by our
      issued and outstanding equity interests other than by Majeed S. Nami or
      his affiliates, or (2) the replacement of a majority of our directors by
      persons not approved by our board of
directors.


Off-Balance
Sheet Arrangements





At
September 30, 2009, we did not have any off-balance sheet arrangements that
have, or are reasonably likely to have, an effect on our financial position or
results of operations.





Contingencies





We
regularly analyze current information and accrue for probable liabilities on the
disposition of certain matters, as necessary. Liabilities for loss contingencies
arising from claims, assessments, litigation and other sources are recorded when
it is probable that a liability has been incurred and the amount can be
reasonably estimated. As of September 30, 2009, there were no loss
contingencies.





Commitments
and Contractual Obligations





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





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





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





36





Non-GAAP
Financial Measure





Adjusted
EBITDA





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





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





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





•
            Impairment
      of natural gas and oil properties;





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





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





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





•
            Deferred
      taxes;





•
            Unit-based
      compensation expense; and





•
            Unrealized
      fair value of phantom units granted to
officers.





Adjusted
EBITDA is a significant performance metric used by management as a tool to
measure (prior to the establishment of any cash reserves by our board of
directors, debt service and capital expenditures) the cash distributions we
could pay our unitholders. Specifically, this financial measure indicates to
investors whether or not we are generating cash flow at a level that can sustain
or support an increase in our quarterly distribution rates. Adjusted EBITDA is
also used as a quantitative standard by our management and by external users of
our financial statements such as investors, research analysts, and others to
assess the financial performance of our assets without regard to financing
methods, capital structure, or historical cost basis; the ability of our assets
to generate cash sufficient to pay interest costs and support our indebtedness;
and our operating performance and return on capital as compared to those of
other companies in our industry.





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





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




Three
      Months Ended
                  September
      30,
              
              
              Nine
      Months Ended
                September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008Net
      income (loss)
              
              $
              701
              
              
              $
              71,809
              
              
              $
              (56,032
              )
              
              $
              8,857Plus:Interest expense, including realized losses on interest rate derivative
      contracts
              
              
              1,548
              
              
              
              1,489
              
              
              
              4,274
              
              
              
              3,863Depreciation, depletion, amortization, and accretion
              
              
              3,272
              
              
              
              4,187
              
              
              
              9,700
              
              
              
              10,341Impairment of natural gas and oil properties
              
              
              -
              
              
              
              -
              
              
              
              63,818
              
              
              
              -Amortization of premiums paid and non-cash settlements on derivative
      contracts
              
              
              1,811
              
              
              
              1,451
              
              
              
              4,383
              
              
              
              3,982Unrealized (gains) losses on other commodity and interest rate derivative
      contracts
              
              
              12,795
              
              
              
              (65,933
              )
              
              
              16,105
              
              
              
              6,463Gain on acquisition of natural gas and oil properties
              
              
              (5,878
              )
              
              
              -
              
              
              
              (5,878
              )
              
              
              -Deferred taxes
              
              
              (3
              )
              
              
              -
              
              
              
              (204
              )
              
              
              -Unit-based compensation expense
              
              
              548
              
              
              
              812
              
              
              
              2,311
              
              
              
              2,708Unrealized fair value of phantom units granted to officers
              
              
              782
              
              
              
              -
              
              
              
              3,034
              
              
              
              -Less:Interest
      income
              
              
              -
              
              
              
              4
              
              
              
              -
              
              
              
              16Adjusted
      EBITDA
              
              $
              15,576
              
              
              $
              13,811
              
              
              $
              41,511
              
              
              $
              36,198







37


Item
3.Quantitative and
Qualitative Disclosures About Market Risk





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





Commodity
Price Risk





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





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





We enter
into derivative contracts with respect to a portion of our projected natural gas
and oil production through various transactions that mitigate the volatility of
future prices received. These transactions may include price swaps whereby we
will receive a fixed-price for our production and pay a variable market price to
the contract counterparty. Additionally, we may acquire put options for which we
pay the counterparty an option premium, equal to the fair value of the option at
the purchase date. As each monthly contract settles, we receive the excess, if
any, of the fixed floor over the floating rate. Furthermore, we may enter into
collars where we pay the counterparty if the market price is above the ceiling
price and the counterparty pays us if the market price is below the floor on a
notional quantity. In deciding which type of derivative instrument to use, our
management considers the relative benefit of each type against any cost that
would be incurred, prevailing commodity market conditions and management’s view
on future commodity pricing. The amount of natural gas and oil production which
is hedged is determined by applying a percentage to the expected amount of
production in our most current reserve report in a given year. Typically,
management intends to hedge 75% to 95% of projected production for a three year
period. These activities are intended to support our realized commodity prices
at targeted levels and to manage our exposure to natural gas and oil price
fluctuations. It is never management’s intention to hold or issue derivative
instruments for speculative trading purposes. Management will consider
liquidating a derivative contract if they believe that they can take advantage
of an unusual market condition allowing them to realize a current gain and then
have the ability to enter into a new derivative contract in the future at or
above the commodity price of the contract that was liquidated.





At
September 30, 2009, the fair value of commodity derivative contracts was an
asset of approximately $26.0 million, of which $19.5 million settles during the
next twelve months.





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





38





October
      1, -
              December
      31, 2009
            
            
            Year
              2010
            
            
            Year
              2011Gas
      Positions:Fixed
      Price Swaps:Notional
      Volume (MMBtu)
            
            
            864,806
            
            
            
            4,731,040
            
            
            
            3,328,312Fixed
      Price ($/MMBtu)
            
            $
            9.34
            
            
            $
            8.66
            
            
            $
            7.83Puts:Notional
      Volume (MMBtu)
            
            
            651,446
            
            
            
            —
            
            
            
            —Floor
      Price ($/MMBtu)
            
            $
            7.85
            
            
            $
            —
            
            
            $
            —Collars:Notional
      Volume (MMBtu)
            
            
            249,999
            
            
            
            1,607,500
            
            
            
            1,933,500Floor
      Price ($/MMBtu)
            
            $
            7.50
            
            
            $
            7.73
            
            
            $
            7.34Ceiling
      Price ($/MMBtu)
            
            $
            9.00
            
            
            $
            8.92
            
            
            $
            8.44Total:Notional
      Volume (MMBtu)
            
            
            1,766,251
            
            
            
            6,320,540
            
            
            
            5,261,812Oil
      Positions:Fixed
      Price Swaps:Notional
      Volume (Bbls)
            
            
            44,000
            
            
            
            164,250
            
            
            
            151,250Fixed
      Price ($/Bbl)
            
            $
            87.23
            
            
            $
            85.65
            
            
            $
            85.50Collars:Notional
      Volume (Bbls)
            
            
            9,200
            
            
            
            —
            
            
            
            —Floor
      Price ($/Bbl)
            
            $
            100.00
            
            
            $
            —
            
            
            $
            —Ceiling
      Price ($/Bbl)
            
            $
            127.00
            
            
            $
            —
            
            
            $
            —Total:Notional
      Volume (Bbls)
            
            
            53,200
            
            
            
            164,250
            
            
            
            151,250





Interest
Rate Risks





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





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


39


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





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





Counterparty
Risk





At
September 30, 2009, based upon all of our open commodity and interest rate
derivative contracts shown above and their respective mark to market values, we
had the following current and long-term derivative assets and liabilities shown
by counterparty with their current S&P financial strength rating in
parentheses (in thousands):


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






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





Item 4.  Controls and
Procedures





Evaluation
of Disclosure Controls and Procedures





As of the
end of the period covered by this Quarterly Report on Form 10-Q, the
effectiveness of our disclosure controls and procedures (as defined in
Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) was
evaluated by our management, with the participation of our Chief Executive
Officer and our Chief Financial Officer, in accordance with rules of the
Securities Exchange Act of 1934, as amended. Based on that evaluation, our Chief
Executive Officer and Chief Financial Officer have concluded that our disclosure
controls and procedures were effective as of September 30, 2009 to provide
reasonable assurance that information required to be disclosed in our reports
filed or submitted under the Securities Exchange Act of 1934, as amended, is
accumulated and communicated to management and recorded, processed, summarized
and reported within the time periods specified in the SEC’s rules and
forms.





40


Changes
in Internal Control over Financial Reporting





On August 17, 2009, we completed the
acquisition of certain natural gas and oil properties in South Texas. Pursuant
to this transaction, we have outsourced our production accounting for these
properties to the same third party that handles the production accounting for
the Permian Basin and our other South Texas properties.  As a result,
there were no changes in our internal control over financial reporting that
occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect our internal control over financial
reporting.


41





PART II — OTHER INFORMATION





Item 1.  Legal Proceedings





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





Item 1A.  Risk Factors





Our
business faces many risks. Any of the risks discussed below or elsewhere in this
Form 10-Q or our other SEC filings, could have a material impact on our
business, financial position or results of operations. Additional risks and
uncertainties not presently known to us or that we currently believe to be
immaterial may also impair our business operations. For a detailed discussion of
the risk factors that should be understood by any investor contemplating
investment in our units, please refer to the section entitled “Item 1A. Risk
Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008
as supplemented by the risk factors set forth below. There has been no material
change in the risk factors set forth in our Annual Report on Form 10-K for the
year ended December 31, 2008 other than those set forth below. For further
information, see Part I—Item 1A—Risk Factors in our Annual Report on Form 10-K
for the year ended December 31, 2008.





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





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





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





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





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





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





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





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





42


·
            domestic
      and foreign governmental regulations and
taxes;





·
            the
      price and availability of alternative fuel
  sources;





·
            weather
      conditions;





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





·
            technological
      advances affecting energy consumption;
and





·
            worldwide
      economic conditions.





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





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





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








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











Item 3.  Defaults Upon Senior
Securities





None.





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





None.




Item 5.  Other Information




None.





43







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
            
            Underwriting
      Agreement dated August 12, 2009, by and among Vanguard Natural
      Resources, LLC and Citigroup Global Markets Inc., Wells Fargo Securities,
      LLC and RBC Capital Markets Corporation, as representatives of the several
      underwriters named therein
            
            Form
      8-K, filed August 12, 2009 (File No. 001-33756)10.2
            
            Second
      Amended and Restated Credit Agreement dated August 31, 2009, by and
      between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent
      and the lenders party hereto
            
            Form
      8-K, filed September 1, 2009 (File No. 001-33756)10.3
            
            First
      Amendment to Second Amended and Restated Credit Agreement dated October
      14, 2009, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as
      administrative agent and the lenders party hereto
            
            Filed
      herewith31.1
            
            Certification
      of Chief Executive Officer Pursuant to Rule 13a — 14 of the
      Securities and Exchange Act of 1934, as Adopted Pursuant to
      Section 302 of the Sarbanes-Oxley Act of 2002
            
            Filed
      herewith31.2
            
            Certification
      of Chief Financial Officer Pursuant to Rule 13a — 14 of the
      Securities and Exchange Act of 1934, as Adopted Pursuant to
      Section 302 of the Sarbanes-Oxley Act of 2002
            
            Filed
      herewith32.1
            
            Certification
      of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350,
      as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002
            
            Filed
      herewith32.2
            
            Certification
      of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350,
      as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002
            
            Filed
      herewith


44








SIGNATURE





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





VANGUARD
      NATURAL RESOURCES, LLC(Registrant)Date:
      November 4, 2009/s/ Richard
      A. RobertRichard
      A. RobertExecutive
      Vice President andChief
      Financial Officer(Principal
      Financial Officer and Principal Accounting
  Officer)