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 June 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




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 July 30, 2009: 12,145,873.




















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 Cash Flows
                5Consolidated Statements of Comprehensive
    Loss
                6Notes to Consolidated Financial
    Statements
                7Item 2.
                Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
                20Item 3.
                Quantitative and Qualitative Disclosures about Market
      Risk
                35Item 4.
                Controls and Procedures
                38PART II – OTHER INFORMATIONItem 1.
                Legal Proceedings
                39Item 1A.
                Risk Factors
                39Item 2.
                Unregistered Sales of Equity Securities and Use of
      Proceeds
                41Item 3.
                Defaults Upon Senior Securities
                41Item 4.
                Submission of Matters to a Vote of Securities
      Holders
                41Item 5.
                Other Information
                42Item 6.
                Exhibits
                42
















GLOSSARY OF TERMS





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




/day
            =
            per
      day
            
            Mcf
            =
            thousand
      cubic feetBbls
            =
            barrels
            
            Mcfe
            =
            thousand
      cubic feet of natural gas equivalentsBcfe
            =
            billion
      cubic feet of natural gas equivalents
            
            MMBtu
            =
            million
      British thermal unitsBtu
            =
            British
      thermal unit
            
            MMcf
            =
            million
      cubic feet




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




References
in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are
to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard
Natural Gas, LLC, Trust Energy Company, LLC (“TEC”), VNR Holdings, Inc.
(“VNRH”), Ariana Energy, LLC (“Ariana Energy”), 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
                  June
      30,
                
                
                Six Months
      Ended
                  June
      30,2009
                
                
                2008
                
                
                2009
                
                
                2008Revenues:Natural
      gas and oil sales
                
                $
                9,404
                
                
                $
                20,852
                
                
                $
                18,606
                
                
                $
                34,854Gain
      (loss) on commodity cash flow hedges
                
                
                (378
                )
                
                
                155
                
                
                
                (1,274
                )
                
                
                571Gain
      (loss) on other commodity derivative contracts
                
                
                (6,137
                )
                
                
                (58,045
                )
                
                
                11,512
                
                
                
                (79,817
                )Total
      revenues
                
                
                2,889
                
                
                
                (37,038
                )
                
                
                28,844
                
                
                
                (44,392
                )Costs
      and expenses:Lease
      operating expenses
                
                
                2,778
                
                
                
                2,300
                
                
                
                5,911
                
                
                
                4,315Depreciation,
      depletion, amortization, and accretion
                
                
                2,645
                
                
                
                3,330
                
                
                
                6,428
                
                
                
                6,154Impairment
      of natural gas and oil properties
                
                
                —
                
                
                
                —
                
                
                
                63,818
                
                
                
                —Selling,
      general and administrative expenses
                
                
                2,941
                
                
                
                1,637
                
                
                
                6,093
                
                
                
                3,283Production
      and other taxes
                
                
                921
                
                
                
                1,429
                
                
                
                1,563
                
                
                
                2,395Total
      costs and expenses
                
                
                9,285
                
                
                
                8,696
                
                
                
                83,813
                
                
                
                16,147Loss
      from operations
                
                
                (6,396
                )
                
                
                (45,734
                )
                
                
                (54,969
                )
                
                
                (60,539
                )Other
      income and (expense):Interest
      income
                
                
                —
                
                
                
                4
                
                
                
                —
                
                
                
                12Interest
      expense
                
                
                (979
                )
                
                
                (1,244
                )
                
                
                (1,992
                )
                
                
                (2,374
                )Gain
      (loss) on interest rate derivative contracts
                
                
                607
                
                
                
                (46
                )
                
                
                228
                
                
                
                (51
                )Total
      other expense
                
                
                (372
                )
                
                
                (1,286
                )
                
                
                (1,764
                )
                
                
                (2,413
                )Net
      loss
                
                $
                (6,768
                )
                
                $
                (47,020
                )
                
                $
                (56,733
                )
                
                $
                (62,952
                )Net
      loss per unit:Common
      & Class B units – basic
                
                $
                (0.54
                )
                
                $
                (4.19
                )
                
                $
                (4.51
                )
                
                $
                (5.61
                )Common
      & Class B units – diluted
                
                $
                (0.54
                )
                
                $
                (4.19
                )
                
                $
                (4.51
                )
                
                $
                (5.61
                )Weighted
      average units outstanding:Common
      units – basic & diluted
                
                
                12,145,873
                
                
                
                10,795,000
                
                
                
                12,145,873
                
                
                
                10,795,000Class
      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)


June
      30,
                          2009
                        
                        
                        December 31,
                          2008(Unaudited)AssetsCurrent
      assetsCash
      and cash equivalents
                        
                        $
                        3,715
                        
                        
                        $
                        3Trade
      accounts receivable, net
                        
                        
                        4,563
                        
                        
                        
                        6,083Derivative
      assets
                        
                        
                        21,538
                        
                        
                        
                        22,184Other
      receivables
                        
                        
                        3,160
                        
                        
                        
                        2,763Other
      current assets
                        
                        
                        691
                        
                        
                        
                        845Total
      current assets
                        
                        
                        33,667
                        
                        
                        
                        31,878Natural gas and oil properties, at cost
                        
                        
                        287,389
                        
                        
                        
                        284,447Accumulated depletion
                        
                        
                        (172,303
                        )
                        
                        
                        (102,178
                        )Natural
      gas and oil properties evaluated, net – full cost
    method
                        
                        
                        115,086
                        
                        
                        
                        182,269Other
      assetsDerivative assets
                        
                        
                        10,824
                        
                        
                        
                        15,749Deferred financing costs
                        
                        
                        709
                        
                        
                        
                        882Other assets
                        
                        
                        1,015
                        
                        
                        
                        1,784Total
      assets
                        
                        $
                        161,301
                        
                        
                        $
                        232,562Liabilities
      and members’ equityCurrent
      liabilitiesAccounts payable – trade
                        
                        $
                        427
                        
                        
                        $
                        2,148Accounts payable – natural gas and oil
                        
                        
                        1,113
                        
                        
                        
                        1,327Payables to affiliates
                        
                        
                        829
                        
                        
                        
                        2,555Derivative liabilities
                        
                        
                        156
                        
                        
                        
                        486Accrued expenses
                        
                        
                        3,673
                        
                        
                        
                        1,248Total
      current liabilities
                        
                        
                        6,198
                        
                        
                        
                        7,764Long-term debt
                        
                        
                        132,500
                        
                        
                        
                        135,000Derivative liabilities
                        
                        
                        1,682
                        
                        
                        
                        2,313Asset retirement obligations
                        
                        
                        2,185
                        
                        
                        
                        2,134Total
      liabilities
                        
                        
                        142,565
                        
                        
                        
                        147,211Commitments
      and contingenciesMembers’
      equityMembers’ capital, 12,145,873 common units issued and outstanding at June
      30, 2009 and December 31, 2008
                        
                        
                        19,513
                        
                        
                        
                        88,550Class B units, 420,000 issued and outstanding at June 30, 2009 and
      December 31, 2008
                        
                        
                        5,784
                        
                        
                        
                        4,606Accumulated other comprehensive loss
                        
                        
                        (6,561
                        )
                        
                        
                        (7,805
                        )Total
      members’ equity
                        
                        
                        18,736
                        
                        
                        
                        85,351Total
      liabilities and members’ equity
                        
                        $
                        161,301
                        
                        
                        $
                        232,562





See
accompanying notes to consolidated financial statements





4





VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF CASH FLOWS


(Unaudited)


(in
thousands)


Six Months Ended
                          June
      30,2009
                        
                        
                        2008Operating
      activitiesNet
      loss
                        
                        $
                        (56,733
                        )
                        
                        $
                        (62,952
                        )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depreciation,
      depletion, amortization, and accretion
                        
                        
                        6,428
                        
                        
                        
                        6,154Impairment
      of natural gas and oil properties
                        
                        
                        63,818
                        
                        
                        
                        —Amortization
      of deferred financing costs
                        
                        
                        202
                        
                        
                        
                        173Unit-based
      compensation
                        
                        
                        4,015
                        
                        
                        
                        1,896Amortization
      of premiums paid and non-cash settlements on derivative
      contracts
                        
                        
                        2,572
                        
                        
                        
                        2,531Unrealized
      losses on other commodity and interest rate derivative
      contracts
                        
                        
                        3,310
                        
                        
                        
                        72,396Changes
      in operating assets and liabilities:Trade
      accounts receivable
                        
                        
                        1,521
                        
                        
                        
                        (6,453
                        )Other
      receivables
                        
                        
                        (398
                        )
                        
                        
                        —Payables
      to affiliates
                        
                        
                        (1,726
                        )
                        
                        
                        615Other
      current assets
                        
                        
                        267
                        
                        
                        
                        (223
                        )Price
      risk management activities, net
                        
                        
                        (30
                        )
                        
                        
                        (443
                        )Accounts
      payable
                        
                        
                        (1,934
                        )
                        
                        
                        669Accrued
      expenses
                        
                        
                        173
                        
                        
                        
                        3,159Other
      assets
                        
                        
                        (25
                        )
                        
                        
                        —Net
      cash provided by operating activities
                        
                        
                        21,460
                        
                        
                        
                        17,522Investing
      activitiesAdditions
      to property and equipment
                        
                        
                        (9
                        )
                        
                        
                        (62
                        )Additions
      to natural gas and oil properties
                        
                        
                        (1,912
                        )
                        
                        
                        (6,678
                        )Acquisitions
      of natural gas and oil properties
                        
                        
                        (218
                        )
                        
                        
                        (66,390
                        )Deposits
      and prepayments of natural gas and oil properties
                        
                        
                        (42
                        )
                        
                        
                        48Net
      cash used in investing activities
                        
                        
                        (2,181
                        )
                        
                        
                        (73,082
                        )Financing
      activitiesProceeds
      from borrowings
                        
                        
                        10,500
                        
                        
                        
                        74,400Repayment
      of debt
                        
                        
                        (13,000
                        )
                        
                        
                        (9,300
                        )Distributions
      to members
                        
                        
                        (12,566
                        )
                        
                        
                        (8,254
                        )Financing
      costs
                        
                        
                        (177
                        )
                        
                        
                        (259
                        )Purchase
      of units for issuance as unit-based compensation
                        
                        
                        (324
                        )
                        
                        
                        (236
                        )Net
      cash provided by (used in) financing activities
                        
                        
                        (15,567
                        )
                        
                        
                        56,351Net
      increase (decrease) in cash and cash equivalents
                        
                        
                        3,712
                        
                        
                        
                        791Cash and cash
      equivalents, beginning of period
                        
                        
                        3
                        
                        
                        
                        3,110Cash and cash
      equivalents, end of period
                        
                        $
                        3,715
                        
                        
                        $
                        3,901Supplemental
      cash flow information:Cash
      paid for interest
                        
                        $
                        1,892
                        
                        
                        $
                        1,802Non-cash
      financing and investing activities:Asset
      retirement obligations
                        
                        $
                        —
                        
                        
                        $
                        1,310Derivative
      liabilities assumed in acquisition of natural gas and oil
      properties
                        
                        $
                        —
                        
                        
                        $
                        1,128Transfer
      of deposit for natural gas and oil properties
                        
                        $
                        —
                        
                        
                        $
                        7,830Non-monetary
      exchange of natural gas and oil properties
                        
                        $
                        2,660
                        
                        
                        $
                        —








See
accompanying notes to consolidated financial statements





5


VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES


CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS


(Unaudited)


(in
thousands)





Three Months
      Ended
                  June 30,
                
                
                Six
      Months Ended
                  June
      30,2009
                
                
                2008
                
                
                2009
                
                
                2008Net
      loss
                
                $
                (6,768
                )
                
                $
                (47,020
                )
                
                $
                (56,733
                )
                
                $
                (62,952
                )Net
      gains (losses) from derivative contracts:Unrealized
      mark-to-market gains arising during the period
                
                
                —
                
                
                
                1,257
                
                
                
                —
                
                
                
                2,747Reclassification
      adjustments for settlements
                
                
                357
                
                
                
                (155
                )
                
                
                1,244
                
                
                
                (571
                )Other
      comprehensive income
                
                
                357
                
                
                
                1,102
                
                
                
                1,244
                
                
                
                2,176Comprehensive
      loss
                
                $
                (6,411
                )
                
                $
                (45,918
                )
                
                $
                (55,489
                )
                
                $
                (60,776
                )





See
accompanying notes to consolidated financial statements








6
 VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (Unaudited)








Description
of the Business:





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




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





(a)
            Basis
      ofPresentation
      andPrinciples
      ofConsolidation:





The
consolidated financial statements as of June 30, 2009 and December 31, 2008 and
for the three and six months ended June 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:





On
January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157
“FairValue Measurements” (“SFAS
157”) as it relates to financial assets and financial liabilities. In February
2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position
No. FAS 157-2, “Effective Date
of FASB Statement No. 157” (“FSP 157-2”), which delayed the effective
date of SFAS 157 for all non-financial assets and non-financial liabilities,
except those that are recognized or disclosed at fair value in the financial
statements on at least an annual basis, until January 1, 2009 for calendar
year-end entities. Also in February 2008, the FASB issued FASB Staff Position
No. FAS 157-1, “Application of
FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting
Pronouncements That Address Fair Value Measurements for Purposes of Lease
Classification or Measurement under Statement 13” (“FSP 157-1”),which states that
Statement of Financial Accounting Standards No. 13, “Accounting for Leases,”
(“SFAS 13”) and other accounting pronouncements that address fair value
measurements for purposes of lease classification or measurement under SFAS 13
are excluded from the provisions of SFAS 157, except for assets and liabilities
related to leases assumed in a business combination that are required to be
measured at fair value under Statement of Financial Accounting Standards No.
141, “Business
Combinations,” (“SFAS 141”) or Statement of Financial Accounting
Standards No. 141 (revised 2007), “Business Combinations,”
(“SFAS 141(R)”). In October 2008, the FASB issued FASB Staff Position No. FAS
157-3, “Determining the Fair
value of a Financial Asset in a Market That Is Not Active” (“FSP 157-3”),
which clarifies the application of SFAS 157 when the market of a financial asset
is inactive and provides an example to illustrate key considerations in
determining the fair value of a financial asset when the market for that
financial asset is not active. The guidance in FSP 157-3 was effective
immediately upon issuance and had no impact on our consolidated financial
statements.





7


SFAS 157
defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. The provisions of this standard apply
to other accounting pronouncements that require or permit fair value
measurements and are to be applied prospectively with limited exceptions. In
adopting SFAS 157 on January 1, 2008, as it relates to financial assets and
financial liabilities, 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. The adoption of SFAS 157 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. See Note 5. Fair Value Measurements for
further discussion.





In April
2009, the FASB issued FASB Staff Position No. FAS 157-4, “Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly” (“FSP
157-4”). FSP 157-4 provides additional guidance on estimating fair value when
the volume and level of activity for an asset or liability have significantly
decreased in relation to normal activity for the asset or liability. FSP 157-4
also provides additional guidance on circumstances that may indicate that a
transaction is not orderly. FSP 157-4 is effective for interim and annual
periods ending after June 15, 2009. We adopted FSP-157-4 on June 30, 2009
and the adoption did not have a material impact on our consolidated financial
statements.





In
December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations”(“SFAS
141(R)”), which replaces SFAS No. 141“Business Combinations”
(“SFAS 141.”) SFAS 141(R) establishes principles and requirements for how an
acquirer recognizes and measures in its financial statements the identifiable
assets acquired, the liabilities assumed, any non-controlling interest in the
acquiree and the goodwill acquired. The Statement also establishes disclosure
requirements that will enable users to evaluate the nature and financial effects
of the business combination. SFAS 141(R) is effective for acquisitions that
occur in an entity’s fiscal year that begins after December 15, 2008. Effective
January 1, 2009, we adopted SFAS 141(R). However, since we did not consummate
any business combinations during the six months ended June 30, 2009, the
adoption did not affect our consolidated financial statements.





In April
2009, the FASB issued FASB Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies.” This Staff Position amends 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 SFAS No. 141(R.) This Staff Position carries forward the requirements in
SFAS 141 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 SFAS No. 5,
“Accounting for
Contingencies.”This Staff Position has the same effective date as SFAS
141(R), and the adoption did not affect our consolidated financial
statements.





In
December 2007, the FASB issued SFAS No. 160,“Non-controlling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling
owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only
those entities that have an outstanding non-controlling interest in one or more
subsidiaries or that deconsolidate a subsidiary. This statement is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008. Effective January 1, 2009, we adopted SFAS 160; however, since we do not
own any “non-controlling interests,” the adoption did not affect our
consolidated financial statements.





8


In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is intended to
improve financial reporting about derivative instruments and hedging activities
by requiring enhanced disclosures to enable investors to better understand their
effects on an entity’s financial position, financial performance, and cash
flows. SFAS 161 achieves these improvements by requiring disclosure of the fair
values of derivative instruments and their gains and losses in a tabular format.
It also provides more information about an entity’s liquidity by requiring
disclosure of derivative features that are credit risk-related. Finally, it
requires cross-referencing within footnotes to enable financial statement users
to locate important information about derivative instruments. SFAS 161 is
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008. Effective January 1, 2009, we adopted SFAS
161. The adoption did not have a material impact on our consolidated financial
statements. See Note 4. Price
Risk Management Activitiesfor further discussion.




In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (“SFAS 162”). This statement identifies the
sources of accounting principles and the framework for selecting the principles
to be used in the preparation of financial statements in conformity with GAAP in
the United States. This statement became effective on November 15, 2008.
The adoption of SFAS 162 did not have a material effect on our consolidated
financial statements.
 
 In April
2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures About Fair
Value of Financial Instruments” (“FSP 107-1.”) FSP 107-1 amends SFAS No.
107, “Disclosures about Fair
Values of Financial Instruments” and Accounting Principles Board Opinion
No. 28, “Interim Financial
Reporting,” to require disclosures about fair value of financial
instruments in interim financial statements. FSP 107-1 is effective for interim
periods ending after June 15, 2009, with early adoption permitted for periods
ending after March 15, 2009. We adopted FSP-107-1 on June 30, 2009 and the
adoption did not have a material impact on our consolidated financial
statements.
 
 In May
2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS
165”). SFAS 165 establishes 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. In particular, this
Statement 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 SFAS 165, an entity
should apply the requirements to interim or annual financial periods ending
after June 15, 2009. We adopted SFAS 165 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 July 31, 2009, the date
on which the financial statements were issued. See Note 10. Subsequent Events for further
discussion.





(c)
            New
      Pronouncements Issued But Not Yet
Adopted:





In
December 2008, the Securities and Exchange Commission (“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 SFAS No. 166, “Accounting for Transfers of
Financial Assets - An Amendment of FASB Statement No. 140” (“SFAS 166”).
SFAS 166 improves the relevance, representational faithfulness, and
comparability of the information that a reporting entity provides in its
financial statements about a transfer of financial assets; the effects of a
transfer on its financial position, financial performance, and cash flows; and a
transferor’s continuing involvement, if any, in transferred financial assets.
The Board undertook this project to address (1) practices that have developed
since the issuance of FASB Statement No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities, that
are not consistent with the original intent and key requirements of that
Statement and (2) concerns of financial statement users that many of the
financial assets (and related obligations) that have been derecognized should
continue to be reported in the financial statements of transferors. SFAS 166
must be applied as of the beginning of each reporting entity’s first annual
reporting period that begins after November 15, 2009, for interim periods within
that first annual reporting period and for interim and annual reporting periods
thereafter. Earlier application is prohibited. SFAS 166 must be applied to
transfers occurring on or after the effective date. SFAS 166 will be effective
for us on January 1, 2010. We do not anticipate consummating any transfers of
financial assets; therefore, we do not anticipate SFAS 166 having any impact on
our consolidated financial statements.





9


In June
2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation
No. 46(R)” (“SFAS 167”). SFAS 167 improves financial reporting by
enterprises involved with variable interest entities. The Board undertook this
project to address (1) the effects on certain provisions of FASB Interpretation
No. 46 (revised December 2003), Consolidation of Variable Interest
Entities, as a result of the elimination of the qualifying
special-purpose entity concept in SFAS 166, and (2) constituent concerns about
the application of certain key provisions of Interpretation 46(R), including
those in which the accounting and disclosures under the Interpretation do not
always provide timely and useful information about an enterprise’s involvement
in a variable interest entity. SFAS 167 shall be effective as of the beginning
of each reporting entity’s first annual reporting period that begins after
November 15, 2009, for interim periods within that first annual reporting
period, and for interim and annual reporting periods thereafter. Earlier
application is prohibited. SFAS 167 will be effective for us on January 1, 2010.
We do not have any interests in variable interest entities; therefore, we do not
anticipate SFAS 167 having any impact on our consolidated financial
statements.





In June
2009, the FASBissued
SFAS No. 168,“The FASB
Accounting Standards CodificationTMand the Hierarchy of Generally
Accepted Accounting Principles – a replacement of FASB Statement
No. 162” (“SFAS 168”).  The FASB Accounting Standards CodificationTM,
(“Codification”) will become the source of authoritative GAAP recognized by the
FASB to be applied by nongovernmental entities. Rules and interpretive releases
of the SEC under authority of federal securities laws are also sources of
authoritative GAAP for SEC registrants. On the effective date of SFAS 168, the
Codification will supersede all then-existing non-SEC accounting and reporting
standards. All other non-grandfathered non-SEC accounting literature not
included in the Codification will become non-authoritative. SFAS 168 is
effective for financial statements issued for interim and annual periods ending
after September 15, 2009. We will adopt the requirements of SFAS 168 in the
third quarter of fiscal 2009.





(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 and oil reserves and related cash flow estimates used in impairment
tests of natural gas and oil properties, the fair value of derivative contracts
and asset retirement obligations, accrued natural gas and oil revenues and
expenses, as well as estimates of expenses related to depreciation, depletion,
amortization, and accretion. Actual results could differ from those
estimates.





2.
            Acquisitions





On
December 21, 2007, we entered into a Purchase and Sale Agreement with the Apache
Corporation for the purchase of certain oil and natural gas properties located
in ten separate fields in the Permian Basin of west Texas and southeastern New
Mexico. The purchase price for said assets was $78.3 million with an effective
date of October 1, 2007. We completed this acquisition on January 31, 2008 for
an adjusted purchase price of $73.4 million, subject to customary post closing
adjustments. The post closing adjustments reduced the final purchase price to
$71.5 million and included a purchase price adjustment of $6.8 million for the
cash flow from the acquired properties for the period between the effective
date, October 1, 2007, and the final settlement date. 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., a wholly owned subsidiary of the Lewis Energy Group, for the
acquisition of certain natural gas and oil properties located in the Dos
Hermanos Field in Webb County, Texas. The purchase price for said assets was
$53.4 million with an effective date of June 1, 2008. We completed this
acquisition on July 28, 2008 for an adjusted purchase price of $51.4 million,
subject to customary post-closing adjustments to be determined. This acquisition
was funded with $30.0 million of borrowings under our reserve-based credit
facility and through the issuance of 1,350,873 common units of the Company
valued at $21.4 million. Upon closing this transaction, we assumed natural gas
swaps and collars based on Houston Ship Channel pricing for approximately 85% of
the estimated gas production from existing producing wells 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.





The
following unaudited pro forma results for the three and six months ended June
30, 2008 show the effect on our consolidated results of operations as if the
January 2008 acquisition and July 2008 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 added
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 numerous assumptions, and is not necessarily
indicative of future results of operations:





10


Proforma
                        (in
      thousands,
                        except
      per unit data)
                        (unaudited)Three
      Months Ended
                        June
      30, 2008
                      
                      
                      Six
      Months Ended
                        June
      30, 2008Total
      revenues
                      
                      $
                      (34,285
                      )
                      
                      $
                      (36,985
                      )Net
      loss
                      
                      $
                      (46,022
                      )
                      
                      $
                      (60,305
                      )Net
      loss per unit:Common & Class B units – basic
                      
                      $
                      (3.66
                      )
                      
                      $
                      (4.80
                      )Common &
      Class B units – diluted
                      
                      $
                      (3.66
                      )
                      
                      $
                      (4.80
                      )





On July
17, 2009, we entered into a Purchase and Sale agreement to acquire certain
natural gas and oil properties in South Texas. SeeNote 10.Subsequent Events for
further discussion.





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
                                  
                                  June
      30,
                                    2009
                                  
                                  
                                  December31,
                                    2008Senior secured
      reserve-based credit facility
                                  Variable
                                  March 31, 2011
                                  
                                  $
                                  132,500
                                  
                                  
                                  $
                                  135,000




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 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 set the allowed interest
rate swap hedge percentage at 85% of the outstanding principal balance of
indebtedness for the period June 26, 2009 to June 25, 2010. Following this
period, the percentage will return to 75%. Our indebtedness under the
reserve-based credit facility totaled $132.5 million at June 30,
2009.





11


Interest
rates under the reserve-based credit facility are based on Eurodollar (LIBOR) or
ABR (Prime) indications, plus a margin. At June 30, 2009 the applicable margin
and other fees increase as the utilization of the borrowing base increases as
follows:




Borrowing
      Base Utilization Percentage
                  
                  <33%
                  
                  
                  >33%
      <66%
                  
                  
                  >66%
      <85%
                  
                  
                  >85%Eurodollar
      Loans
                  
                  
                  1.500
                  %
                  
                  
                  1.750
                  %
                  
                  
                  2.000
                  %
                  
                  
                  2.125
                  %ABR
      Loans
                  
                  
                  0.000
                  %
                  
                  
                  0.250
                  %
                  
                  
                  0.500
                  %
                  
                  
                  0.750
                  %Commitment
      Fee Rate
                  
                  
                  0.250
                  %
                  
                  
                  0.300
                  %
                  
                  
                  0.375
                  %
                  
                  
                  0.375
                  %Letter
      of Credit Fee
                  
                  
                  1.000
                  %
                  
                  
                  1.250
                  %
                  
                  
                  1.500
                  %
                  
                  
                  1.750
                  %





Our
reserve-based credit facility contains a number of customary covenants that
require us to maintain certain financial ratios, limit our ability to incur
additional debt, sell assets, create liens, or make distributions to our
unitholders when our outstanding borrowings exceed 90% of our borrowing base. At
June 30, 2009, we were in compliance with our debt covenants.





The
Credit Agreement required us to enter into a commodity price hedge position
establishing certain minimum fixed prices for anticipated future production
equal to approximately 84% of our projected production from proved developed
producing reserves from the second half of 2007 through 2011. Also, the Credit
Agreement required that certain production put option contracts for the years
2007, 2008, and 2009 be put in place to create a price floor for anticipated
production from new wells drilled. SeeNote 4.Price Risk Management
Activities for further discussion.





4.
            Price
      Risk Management Activities





We have
entered into derivative contracts with counterparties that are lenders under our
reserve-based credit facility, Citibank N.A., BNP Paribas, The Bank of Nova
Scotia, and Wachovia Bank, N.A., to hedge price risk associated with a portion
of our natural gas and oil production. While it is never management’s intention
to hold or issue derivative instruments for speculative trading purposes,
conditions sometimes arise where actual production is less than estimated which
has, and could, result in overhedged volumes. Under fixed-priced commodity swap
agreements, 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
Statement of Financial Accounting Standards No. 133 “Accounting forDerivativeInstruments and Hedging
Activities” (“SFAS 133”), all derivative instruments are recorded on the
consolidated balance sheets at fair value as either short-term or long-term
assets or liabilities based on their anticipated settlement date.  We
net derivative assets and liabilities for counterparties where we have a legal
right of offset.  Changes in the 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 current market by using the proceeds of the
liquidation of the 2012 oil swap.





12


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




Swap
Agreements




Gas
                
                OilContract
      Period
                MMBtu
                
                Weighted
                  Average
                  FixedPrice
                
                Bbls
                
                WTI
                  PriceJuly
      1, 2009 - December 31, 2009
                1,756,188
                
                $
                9.32
                
                89,000
                
                $
                87.23January
      1, 2010 - December 31, 2010
                3,782,040
                
                $
                8.95
                
                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 FloorJuly
      1, 2009 - December 31, 2009
                  396,265
                  
                  $
                  7.50





Collars





Gas
                  
                  
                  OilMMBtu
                  
                  
                  Floor
                  
                  
                  Ceiling
                  
                  
                  Bbls
                  
                  
                  Floor
                  
                  
                  CeilingProduction
      Period:July
      1, 2009 - December 31, 2009
                  
                  
                  499,998
                  
                  
                  $
                  7.50
                  
                  
                  $
                  9.00
                  
                  
                  
                  18,400
                  
                  
                  $
                  100.00
                  
                  
                  $
                  127.00January
      1, 2010 - December 31, 2010
                  
                  
                  914,000
                  
                  
                  $
                  7.90
                  
                  
                  $
                  9.24
                  
                  
                  
                  —
                  
                  
                  $
                  —
                  
                  
                  $
                  —January
      1, 2011 - December 31, 2011
                  
                  
                  364,000
                  
                  
                  $
                  7.50
                  
                  
                  $
                  9.00
                  
                  
                  
                  —
                  
                  
                  $
                  —
                  
                  
                  $
                  —




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.





13


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





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




June
      30, 2009
                        December
      31, 2008(in
      thousands)Assets:Commodity
      derivatives
                        
                        $
                        36,262
                        
                        
                        $
                        39,875Interest
      rate swaps
                        
                        
                        7
                        
                        
                        
                        —$
                        36,269
                        
                        
                        $
                        39,875Liabilities:Commodity
      derivatives
                        
                        $
                        (3,900
                        )
                        
                        $
                        (1,942
                        )Interest
      rate swaps
                        
                        
                        (1,845
                        )
                        
                        
                        (2,799
                        )$
                        (5,745
                        )
                        
                        $
                        (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 $36.3 million at June 30, 2009.





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 June 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 and are non-cash
items.




14


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





Three Months Ended
                            June
      30,
                          
                          
                          Six Months Ended
                            June
      30,2009
                          
                          
                          2008
                          
                          
                          2009
                          
                          
                          2008Realized
      gains (losses):Other
      commodity derivatives
                          
                          $
                          7,964
                          
                          
                          $
                          (5,859
                          )
                          
                          $
                          15,784
                          
                          
                          $
                          (7,421
                          )Interest
      rate swaps
                          
                          
                          (398
                          )
                          
                          
                          (46
                          )
                          
                          
                          (734
                          )
                          
                          
                          (51
                          )$
                          7,566
                          
                          
                          $
                          (5,905
                          )
                          
                          $
                          15,050
                          
                          
                          $
                          (7,472
                          )Unrealized
      gains (losses):Other
      commodity derivatives
                          
                          $
                          (14,101
                          )
                          
                          $
                          (52,186
                          )
                          
                          $
                          (4,272
                          )
                          
                          $
                          (72,396
                          )Interest
      rate swaps
                          
                          
                          1,005
                          
                          
                          
                          —
                          
                          
                          
                          962
                          
                          
                          
                          —$
                          (13,096
                          )
                          
                          $
                          (52,186
                          )
                          
                          $
                          (3,310
                          )
                          
                          $
                          (72,396
                          )Total
      gains (losses):Other
      commodity derivatives
                          
                          $
                          (6,137
                          )
                          
                          $
                          (58,045
                          )
                          
                          $
                          11,512
                          
                          
                          $
                          (79,817
                          )Interest
      rate swaps
                          
                          
                          607
                          
                          
                          
                          (46
                          )
                          
                          
                          228
                          
                          
                          
                          (51
                          )$
                          (5,530
                          )
                          
                          $
                          (58,091
                          )
                          
                          $
                          11,740
                          
                          
                          $
                          (79,868
                          )




5.
            Fair
      Value Measurements





As
discussed inNote 1.Summary of Significant
Accounting Policies (b), we adopted SFAS 157 for financial assets and financial
liabilities as of January 1, 2008 and for non-financial assets and liabilities
as of January 1, 2009. SFAS 157 does not expand the use of fair value
measurements, but rather, provides a framework for consistent measurement of
fair value for those assets and liabilities already measured at fair value under
other accounting pronouncements. Certain specific fair value measurements, such
as those related to share-based compensation, are not included in the scope of
SFAS 157. Primarily, SFAS 157 is applicable to assets and liabilities related to
financial instruments, to some long-term investments and liabilities, to initial
valuations of assets and liabilities acquired in a business combination, and to
long-lived assets carried at fair value subsequent to an impairment write-down.
It does not apply to oil and natural gas properties accounted for under the full
cost method, which are subject to impairment based on SEC rules. SFAS 157
applies to assets and liabilities carried at fair value on the consolidated
balance sheet, as well as to supplemental fair value information about financial
instruments not carried at fair value.





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, 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 SFAS 157 to assets and liabilities measured at fair
value on a recurring basis. This includes natural gas, oil and interest rate
derivatives contracts. SFAS 157 provides a definition of fair value and a
framework for measuring fair value, as well as expanding disclosures regarding
fair value measurements. The framework requires fair value measurement
techniques to include all significant assumptions that would be made by willing
participants in a market transaction. These assumptions include certain factors
not consistently provided for previously by those companies utilizing fair value
measurement; examples of such factors would include our own credit standing
(when valuing liabilities) and the buyer’s risk premium. In adopting SFAS 157,
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.





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





15


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 SFAS 157, financial assets and liabilities are classified based on
the lowest level of input that is significant to the fair value measurement. Our
assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value hierarchy
levels. 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:





June
      30, 2009
                    (in
      thousands)Fair Value Measurements Using
                  
                  
                  Assets/LiabilitiesLevel
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  at Fair valueAssets:Commodity
      price derivative contracts
                  
                  $
                  —
                  
                  
                  $
                  32,362
                  
                  
                  $
                  —
                  
                  
                  $
                  32,362Total
      derivative instruments
                  
                  $
                  —
                  
                  
                  $
                  32,362
                  
                  
                  $
                  —
                  
                  
                  $
                  32,362Liabilities:Interest
      rate derivative contracts
                  
                  $
                  —
                  
                  
                  $
                  (1,838
                  )
                  
                  $
                  —
                  
                  
                  $
                  (1,838
                  )Total
      derivative instruments
                  
                  $
                  —
                  
                  
                  $
                  (1,838
                  )
                  
                  $
                  —
                  
                  
                  $
                  (1,838
                  )





On
January 1, 2009, we adopted the previously-deferred provisions of SFAS 157 for
nonfinancial assets and liabilities, which are comprised primarily of asset
retirement costs and obligations initially measured at fair value in accordance
with SFAS No. 143, “Accounting
for Asset Retirement Obligations” (“SFAS 143”).  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 SFAS 143.  During the six months ended June 30,
2009, we did not incur asset retirement obligations. The adoption of SFAS 157 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.





16


6.
            Asset
      Retirement Obligations





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





2009
                
                
                2008(in
      thousands)Asset
      retirement obligations at January 1,
                
                $
                2,134
                
                
                $
                190Liabilities
      added during the current period
                
                
                —
                
                
                
                1,310Accretion
      expense
                
                
                51
                
                
                
                33Asset
      retirement obligation at June 30,
                
                $
                2,185
                
                
                $
                1,533





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, 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 June 30, 2009 and 2008 and $0.7 million and $0.3 million for the six
months ended June 30, 2009 and 2008, respectively. Costs incurred under the GCA
were $0.3 million for each of the three months ended June 30, 2009 and 2008 and
$0.5 million and $0.5 million, respectively, for the six months ended June 30,
2009 and 2008. A payable of $0.8 million and $2.6 million, respectively, is
reflected on our June 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 June 30, 2009, beneficially owned 26.8% 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.





8.
            Common
      Units and Net Income per Unit





Basic
earnings per unit is computed in accordance with SFAS No. 128,“Earnings Per Share”
(“SFAS 128”) by dividing net income (loss) attributable to unitholders by
the weighted average number of units outstanding during the period. Diluted
earnings per unit is computed by adjusting the average number of units
outstanding for the dilutive effect, if any, of unit equivalents.  We use
the treasury stock method to determine the dilutive effect. As of June 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 is higher than the
market price; 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 it is satisfied in units; therefore, they
have been excluded from the computation of diluted earnings per
unit.





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





17


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





In
October 2007 and February 2008, four board members were granted 5,000 common
units each of which 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.





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 and the amount paid in either cash or
units 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 June 30, 2009, a
liability and non-cash compensation expense totaling $2.3 million has been
recognized.





Furthermore,
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 which 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 SFAS No. 123(R),Share-Based Payment.The
fair value of restricted units issued is determined based on the fair market
value of common units on the date of the grant. This value is amortized over the
vesting period as referenced above. A summary of the status of the non-vested
units as of June 30, 2009 is presented below:





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
                
                
                (20,000
                )
                
                
                (17.34
                )Non-vested
      units at June 30, 2009
                
                
                457,950
                
                
                $
                17.30





At June
30, 2009, there was approximately $0.9 million of unrecognized compensation cost
related to non-vested restricted units. The cost is expected to be recognized
over an average period of approximately 0.6 years. Our consolidated statement of
operations reflects non-cash compensation of $1.8 million and $1.0 million in
the selling, general and administrative line item for the three months ended
June 30, 2009 and 2008 and $4.0 million and $1.9 million for the six months
ended June 30, 2009 and 2008, respectively.





10.
            Subsequent
      Events





On July
17, 2009, we entered into a Purchase and Sale Agreement to acquire certain
natural gas and oil properties in South Texas for $52.3 million from an
affiliate of Lewis Energy Group, L.P. (“Lewis”) and paid a non-refundable
deposit of $2.6 million. The properties to be acquired have total estimated
proved reserves of 27 Bcfe as of July 1, 2009, of which 94% is natural gas and
70% is proved developed. In the press release and related Form 8-K filed on July
21, 2009, proved developed reserves were disclosed as 74%, however, based on
more recent data, the proved developed reserves percentage is 70%. Lewis will
operate all of the wells acquired in this transaction. Based on the current net
daily production of approximately 5,000 Mcfe, the properties have a reserve to
production ratio of approximately 15 years. The acquisition has a July 1, 2009
effective date, is subject to customary closing conditions and purchase price
adjustments and is expected to close in the third quarter of 2009. We are
evaluating options for financing this acquisition. At closing, we will assume
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. In
the press release and related Form 8-K filed on July 21, 2009, the percentage of
the estimated gas production hedged under the natural gas puts and swaps assumed
was reported as 67%, however, based on more recent data, the percentage hedged
is 61%.  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 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:


18


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. In the press release and
      related Form 8-K filed on July 21, 2009, the weighted average pricing was
      reported as $7.25 - $8.25. The weighted average pricing reflected above is
      based on more recent
data.


We expect
that the SEC will soon declare effective the Company’s registration statement
filed with the SEC that registers securities of up to $300.0 million of any
combination of debt securities, common units and guarantees of debt securities
by the Company’s subsidiaries. The proceeds, terms and pricing of any offerings
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 the Company will or could sell any such securities. The Company’s
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 the Company’s securities at prices acceptable to
the Company. 19


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 1,444 gross (958 net) productive wells at June 30, 2009,
and our average net production for the twelve months ended December 31,
2008 and for the six months ended June 30, 2009 was 16,206 Mcfe per day and
17,721 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 5,300 undeveloped acres
surrounding our existing wells. Based on internal reserve estimates at June 30,
2009, approximately 28% or 26.8 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. 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 but,
capital markets remain volatile. As evidenced by recent successful equity and
debt offerings by our peers, we expect that we could issue debt and equity if
needed.





During
the first six months of 2009, our unit price increased from a closing low of
$6.35 on January 2, 2009 to a closing high of $14.49 on June 11, 2009. Also,
during the six months ended June 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.





20


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 will be on maximizing existing production
and looking for complementary acquisitions that we can add to this operating
platform. At June 30, 2009, based on internal reserve estimates, we own 3.6
million barrels of oil equivalent, 87% of which is oil and 87% of which is
proved developed producing.





South
Texas Acquisitions





On July
18, 2008, we entered into a Purchase and Sale Agreement with Segundo Navarro
Drilling, Ltd., a wholly owned subsidiary of the Lewis Energy Group, 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 Energy Group operates all the properties and is contractually obligated to
drill seven wells each year from 2009 through 2011 unless mutually agreed not 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 June 30, 2009, based on internal reserve estimates,
we own 20.5 Bcfe of proved reserves, 100% of which is natural gas and 57% of
which is proved developed producing.





On July
17, 2009, we entered into a Purchase and Sale Agreement to acquire certain
natural gas and oil properties in South Texas for $52.3 million from an
affiliate of Lewis and paid a non-refundable deposit of $2.6 million. The
properties to be acquired have total estimated proved reserves of 27 Bcfe as of
July 1, 2009, of which 94% is natural gas and 70% is proved developed. In the
press release and related Form 8-K filed on July 21, 2009, proved developed
reserves were disclosed as 74%, however, based on more recent data, the proved
developed reserves percentage is 70%. Lewis will operate all of the wells
acquired in this transaction. Based on the current net daily production of
approximately 5,000 Mcfe, the properties have a reserve to production ratio of
approximately 15 years. The acquisition has a July 1, 2009 effective date, is
subject to customary closing conditions and purchase price adjustments and is
expected to close in the third quarter of 2009. We are evaluating options for
financing this acquisition and are currently in the process of amending our
existing reserve-based credit facility. As part of the amendment the term of the
reserve-based credit facility would be extended and the borrowing base, margins
and other fees are expected to increase. At closing, we will assume 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. In the press release
and related Form 8-K filed on July 21, 2009, the percentage of the estimated gas
production hedged under the natural gas puts and swaps assumed was reported as
67%, however, based on more recent data, the percentage hedged is 61%. 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 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. In the press release and
      related Form 8-K filed on July 21, 2009, the weighted average pricing was
      reported as $7.25 - $8.25. The weighted average pricing reflected above is
      based on more recent
data.


21


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 set the
allowed interest rate swap hedge percentage at 85% of the outstanding principal
balance of indebtedness for the period June 26, 2009 to June 25, 2010. Following
this period, the percentage will return to 75%. Indebtedness under the
reserve-based credit facility totaled $132.5 million at June 30, 2009 and the
applicable margins and other fees increase as the utilization of the borrowing
base increases as follows:





Borrowing
      Base Utilization GridBorrowing
      base utilization percentage
                    <33%
                    >33%
      <66%
                    >66%
      <85%
                    >85%Eurodollar
      loans
                    1.500%
                    1.750%
                    2.000%
                    2.125%ABR
      loans
                    0.000%
                    0.250%
                    0.500%
                    0.750%Commitment
      fee rate
                    0.250%
                    0.300%
                    0.375%
                    0.375%Letter
      of credit fee
                    1.000%
                    1.250%
                    1.500%
                    1.750%





We are
evaluating options for financing the July 2009 south Texas acquisition and are
currently in the process of amending our existing reserve-based credit facility.
As part of the amendment the term of the reserve-based credit facility would be
extended and the borrowing base, margins and other fees are expected to
increase.





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. 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 but,
capital markets remain volatile. As evidenced by recent successful equity and
debt offerings by our peers, we expect that we could issue debt and equity if
needed.





Natural
gas and oil prices historically have been volatile and may fluctuate widely in
the future. Sustained periods of low prices for natural gas or oil could
materially and adversely affect our financial position, our results of
operations, the quantities of natural gas and oil reserves that we can
economically produce and our access to capital. As required by our reserve-based
credit facility, we have mitigated this volatility for the years 2007 through
2011 by implementing a hedging program on a portion of our proved producing and
a portion of our total anticipated production during this time
frame.




We face
the challenge of natural gas and oil production declines. As a given well’s
initial reservoir pressures are depleted, natural gas and oil production
decreases, thus reducing our total reserves. We attempt to overcome this natural
decline both by drilling on our properties and acquiring additional reserves. We
will maintain our focus on controlling costs to add reserves through drilling
and acquisitions, as well as controlling the corresponding costs necessary to
produce such reserves. During the six months ended June 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 our debt and equity securities
on favorable terms, or at all, and we may be unable to refinance our
reserve-based credit facility when it expires. Additionally, due to the
significant decline in commodity prices, our borrowing base under our
reserve-based credit facility may be redetermined such that it will not provide
for the working capital necessary to fund our capital spending program and could
affect our ability to make distributions. The next scheduled redetermination of
our borrowing base is October 2009.




22


Results
of Operations




The
following table sets forth selected financial and operating data for the periods
indicated:





Three Months Ended
                                  June 30,
                                
                                
                                Six Months Ended
                                  June 30,2009(b)
                                
                                
                                2008
                                
                                
                                2009(a)(b)
                                
                                
                                2008Revenues:Gas
      sales
                                
                                $
                                5,111
                                
                                
                                $
                                13,307
                                
                                
                                $
                                11,433
                                
                                
                                $
                                22,327Oil
      sales
                                
                                
                                4,293
                                
                                
                                
                                7,545
                                
                                
                                
                                7,173
                                
                                
                                
                                12,527Natural
      gas and oil sales
                                
                                
                                9,404
                                
                                
                                
                                20,852
                                
                                
                                
                                18,606
                                
                                
                                
                                34,854Realized
      gain (loss) on commodity cash flow hedges
                                
                                
                                (378
                                )
                                
                                
                                155
                                
                                
                                
                                (1,274
                                )
                                
                                
                                571Realized
      gain (loss) on other commodity derivative contracts
                                
                                
                                7,964
                                
                                
                                
                                (5,859
                                )
                                
                                
                                15,784
                                
                                
                                
                                (7,421
                                )Unrealized
      gain (loss) on other commodity derivative contracts
                                
                                
                                (14,101
                                )
                                
                                
                                (52,186
                                )
                                
                                
                                (4,272
                                )
                                
                                
                                (72,396
                                )Total
      revenues
                                
                                $
                                2,889
                                
                                
                                $
                                (37,038
                                )
                                
                                $
                                28,844
                                
                                
                                $
                                (44,392
                                )Costs
      and expenses:Lease
      operating expenses
                                
                                $
                                2,778
                                
                                
                                $
                                2,300
                                
                                
                                $
                                5,911
                                
                                
                                $
                                4,315Depreciation,
      depletion, amortization, and accretion
                                
                                
                                2,645
                                
                                
                                
                                3,330
                                
                                
                                
                                6,428
                                
                                
                                
                                6,154Impairment
      of natural gas and oil properties
                                
                                
                                —
                                
                                
                                
                                —
                                
                                
                                
                                63,818
                                
                                
                                
                                —Selling,
      general and administrative expenses
                                
                                
                                2,941
                                
                                
                                
                                1,637
                                
                                
                                
                                6,093
                                
                                
                                
                                3,283Production
      and other taxes
                                
                                
                                921
                                
                                
                                
                                1,429
                                
                                
                                
                                1,563
                                
                                
                                
                                2,395Total
      costs and expenses
                                
                                $
                                9,285
                                
                                
                                $
                                8,696
                                
                                
                                $
                                83,813
                                
                                
                                $
                                16,147Other
      income and (expense):Interest
      expense, net
                                
                                $
                                (979
                                )
                                
                                $
                                (1,240
                                )
                                
                                $
                                (1,992
                                )
                                
                                $
                                (2,362
                                )Realized
      loss on interest rate derivative contracts
                                
                                $
                                (398
                                )
                                
                                $
                                (46
                                )
                                
                                $
                                (734
                                )
                                
                                $
                                (51
                                )Unrealized
      gain on interest rate derivative contracts
                                
                                $
                                1,005
                                
                                
                                $
                                —
                                
                                
                                $
                                962
                                
                                
                                $
                                —





(a)
            The
      Permian acquisition closed on January 31, 2008 and, as such, only five
      months of operations are included in the six month period ended June 30,
      2008.(b)
            The
      south Texas acquisition closed on July 28, 2008 and, as such, no
      operations are included in the three month or six month period ended June
      30, 2008.




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




Revenues




Natural
gas and oil sales decreased $11.4 million to $9.4 million during the three
months ended June 30, 2009 as compared to the same period in 2008. The key
revenue measurements were as follows:





23


Three Months Ended
                            June
      30,
                          
                          Percentage
                            Increase
                            (Decrease)2009
                          
                          2008Net
      Natural Gas Production:Appalachian
      gas (MMcf)
                          
                          
                          794
                          
                          903
                          
                          (12)
                          %Permian
      gas (MMcf)
                          
                          
                          70
                          
                          109
                          
                          (36)
                          %South
      Texas gas (MMcf)
                          
                          
                          271
                          
                          —
                          (a)
                          N/ATotal
      natural gas production (MMcf)
                          
                          
                          1,135
                          
                          1,012Average
      Appalachian daily gas production (Mcf/day)
                          
                          
                          8,726
                          
                          9,922
                          
                          (12)
                          %Average
      Permian daily gas production (Mcf/day)
                          
                          
                          773
                          
                          1,202
                          
                          (36)
                          %Average
      south Texas daily gas production (Mcf/day)
                          
                          
                          2,977
                          
                          —
                          (a)
                          N/AAverage
      Vanguard daily gas production (Mcf/day)
                          
                          
                          12,476
                          
                          11,124Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including hedges
                          
                          $
                          10.71
                          (b)
                          $10.35
                          (b)
                          3
                          %Net
      realized gas price, excluding hedges
                          
                          $
                          4.50
                          
                          $13.14
                          
                          (66)
                          %Net
      Oil Production:Appalachian
      oil (Bbls)
                          
                          
                          21,186
                          
                          10,430
                          
                          103
                          %Permian
      oil (Bbls)
                          
                          
                          56,969
                          
                          61,817
                          
                          (8)
                          %Total
      oil (Bbls)
                          
                          
                          78,155
                          
                          72,247Average
      Appalachian daily oil production (Bbls/day)
                          
                          
                          233
                          
                          115
                          
                          103
                          %Average
      Permian daily oil production (Bbls/day)
                          
                          
                          626
                          
                          679
                          
                          (8)
                          %Average
      Vanguard daily oil production (Bbls/day)
                          
                          
                          859
                          
                          794Average
      Oil Sales Price per Bbl:Net
      realized oil price, including hedges
                          
                          $
                          75.95
                          
                          $81.01
                          
                          (6)
                          %Net
      realized oil price, excluding hedges
                          
                          $
                          54.93
                          
                          $104.44
                          
                          (47)
                          %




(a)
            The
      south Texas acquisition closed on July 28, 2008 and, as such, no
      operations are included in the three month period ended June 30,
      2008.(b)
            Excludes
      amortization of premiums paid and non-cash settlements on derivative
      contracts.





The
decrease in natural gas and oil sales during the three months ended June 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 103% increase in oil production
during the three months ended June 30, 2009 compared to the same period in 2008
for a net production decline of 5% on a Mcfe basis. The 103% increase in
Appalachian oil production was primarily due to the focus on the completion of
oil zones as oil prices increased during the first three quarters of 2008 which
adversely affected the amount of natural gas produced.  We experienced
a 66% decrease in the average realized natural gas sales price received
(excluding hedges) and a 47% decrease in the average realized oil price
(excluding hedges). The decrease in commodity prices was partially offset by
an 11% increase in our total production on a Mcfe basis. The increase in
production for the three months ended June 30, 2009 over the comparable period
in 2008 was primarily attributable to the impact from the south Texas
acquisition completed in July 2008.




24


Hedging
and Price Risk Management Activities





During
the three months ended June 30, 2009, we recognized $0.4 million related to
losses on commodity cash flow hedges compared to gains of $0.2 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 three months ended June 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 June 30, 2009, we recognized $6.1 million related to
losses on other commodity derivative contracts compared to losses of $58.0
million during the same period in 2008. The losses on other commodity derivative
contracts for the three months ended June 30, 2009 includes a $14.1 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 loss on other
commodity derivative contracts for the three months ended June 30, 2008 includes
a $52.2 million unrealized loss related to the change in fair value of
derivative contracts not meeting the criteria for cash flow hedge accounting and
a $5.8 million realized loss related to the settlements recognized during the
period. The decrease in unrealized losses on other commodity derivative
contracts during the three months ended June 30, 2009 compared to the same
period in 2008 resulted from the increase in derivative contracts assumed or
entered into as a result of the Permian Basin and south Texas acquisitions as
well as a decrease in commodity prices. The increase in realized gains on other
commodity derivative contracts during the three months ended June 30, 2009
compared to the same period in 2008 also resulted from the decrease in commodity
prices which increased the dollar amount of settlements received.





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 $0.5 million to $2.8 million for the three
months ended June 30, 2009 as compared to the three months ended June 30, 2008,
of which $0.3 million of the increase was related to the inclusion of the south
Texas wells in the three months ended June 30, 2009.




Depreciation,
depletion, amortization and accretion decreased to approximately $2.6 million
for the three months ended June 30, 2009 from approximately $3.3 million for the
three months ended June 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 June 30, 2009 increased $1.3 million as
compared to the three months ended June 30, 2008 principally due to an increase
in non-cash charges.  For the three months ended June 30, 2009 and
2008, non-cash compensation charges amounted to $1.8 million and $1.0
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 $0.5 million during the three months ended
June 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 $0.5 million for the three months ended
June 30, 2009 as compared to the same period in 2008 as a result of decreased
revenues.





Interest
expense declined slightly to $1.0 million for the three months ended June 30,
2009 compared to $1.2 million for the three months ended June 30, 2008 primarily
due to lower interest rates which more than offset the higher average
outstanding debt during the three months ended June 30, 2009.




25


Six
Months Ended June 30, 2009 Compared to Six Months Ended June 30,
2008




Revenues




Natural
gas and oil sales decreased $16.3 million to $18.6 million during the six months
ended June 30, 2009 as compared to the same period in 2008. The key revenue
measurements were as follows:





Six Months Ended
                    June
      30,
                  
                  Percentage
                    Increase
                    (Decrease)2009
                  
                  2008Net
      Natural Gas Production:Appalachian
      gas (MMcf)
                  
                  
                  1,599
                  
                  1,770
                  
                  (10)
                  %Permian
      gas (MMcf)
                  
                  
                  129
                  
                  151
                  (a)
                  (15)
                  %South
      Texas gas (MMcf)
                  
                  
                  547
                  
                  —
                  (b)
                  N/ATotal
      natural gas production (MMcf)
                  
                  
                  2,275
                  
                  1,921Average
      Appalachian daily gas production (Mcf/day)
                  
                  
                  8,837
                  
                  9,724
                  
                  (9)
                  %Average
      Permian daily gas production (Mcf/day)
                  
                  
                  716
                  
                  1,000
                  (a)
                  (28)
                  %Average
      south Texas daily gas production (Mcf/day)
                  
                  
                  3,019
                  
                  —
                  (b)
                  N/AAverage
      Vanguard daily gas production (Mcf/day)
                  
                  
                  12,572
                  
                  10,724Average
      Natural Gas Sales Price per Mcf:Net
      realized gas price, including hedges
                  
                  $
                  10.68
                  (c)
                  $10.41
                  (c)
                  3
                  %Net
      realized gas price, excluding hedges
                  
                  $
                  5.02
                  
                  $11.62
                  
                  (57)
                  %Net
      Oil Production:Appalachian
      oil (Bbls)
                  
                  
                  37,697
                  
                  21,421
                  
                  76
                  %Permian
      oil (Bbls)
                  
                  
                  117,649
                  
                  102,539
                  (a)
                  15
                  %Total
      oil (Bbls)
                  
                  
                  155,346
                  
                  123,960Average
      Appalachian daily oil production (Bbls/day)
                  
                  
                  208
                  
                  118
                  
                  76
                  %Average
      Permian daily oil production (Bbls/day)
                  
                  
                  650
                  
                  679
                  (a)
                  (4)
                  %Average
      Vanguard daily oil production (Bbls/day)
                  
                  
                  858
                  
                  797Average
      Oil Sales Price per Bbl:Net
      realized oil price, including hedges
                  
                  $
                  73.26
                  
                  $84.61
                  
                  (13)
                  %Net
      realized oil price, excluding hedges
                  
                  $
                  46.18
                  
                  $101.61
                  
                  (55)
                  %




(a)
            The
      Permian acquisition closed on January 31, 2008 and, as such, only five
      months of operations are included in the six month period ended June 30,
      2008.(b)
            The
      south Texas acquisition closed on July 28, 2008 and, as such, no
      operations are included in the six month period ended June 30,
      2008.(c)
            Excludes
      amortization of premiums paid and non-cash settlements on derivative
      contracts.





The
decrease in natural gas and oil sales during the six months ended June 30, 2009
compared to the same period in 2008 was due primarily to the decreases in
commodity prices. In Appalachia, we experienced a 10% decrease in natural gas
production which was partially offset by a 76% increase in oil production during
the six months ended June 30, 2009 compared to the same period in 2008 for a net
production decline of 4% on a Mcfe basis. The 76% increase in Appalachian oil
production was primarily due to the focus on the completion of oil zones as oil
prices increased during the first three quarters of 2008 which adversely
affected the amount of natural gas produced.  We experienced a 57%
decrease in the average realized natural gas sales price received (excluding
hedges) and a 55% 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 six months
ended June 30, 2009 over the comparable period in 2008 was primarily
attributable to the impact from the Permian Basin acquisition completed in
January 2008 and the south Texas acquisition completed in July
2008.




26


Hedging
and Price Risk Management Activities





During
the six months ended June 30, 2009, we recognized $1.3 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 six months ended June 30, 2009 relates to the amount
that settled in 2009 and has been reclassified to earnings from accumulated
other comprehensive loss.





During
the six months ended June 30, 2009, we recognized $11.5 million related to
gains on other commodity derivative contracts compared to losses of $79.8
million during the same period in 2008. The gains on other commodity derivative
contracts for the six months ended June 30, 2009 includes a $4.3 million
unrealized loss related to the change in fair value of derivative contracts not
meeting the criteria for cash flow hedge accounting and a $15.8 million realized
gain related to the settlements recognized during the period. The loss on other
commodity derivative contracts for the six months ended June 30, 2008 includes a
$72.4 million unrealized loss related to the change in fair value of derivative
contracts not meeting the criteria for cash flow hedge accounting and a $7.4
million realized loss related to the settlements recognized during the period.
The decrease in unrealized losses on other commodity derivative contracts during
the six months ended June 30, 2009 compared to the same period in 2008 resulted
from the increase in derivative contracts assumed or entered into as a result of
the Permian Basin and south Texas acquisitions as well as a decrease in
commodity prices. The increase in realized gains on other commodity derivative
contracts during the six months ended June 30, 2009 compared to the same period
in 2008 also resulted from the decrease in commodity prices which increased the
dollar amount of settlements received.





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 $1.6 million to $5.9 million for the six months
ended June 30, 2009 as compared to the six months ended June 30, 2008, of which
$1.3 million of the increase was related to the inclusion of the Permian and
south Texas wells for the entire six months in 2009.




Depreciation,
depletion, amortization, and accretion increased to approximately $6.4 million
for the six months ended June 30, 2009 from approximately $6.2 million for the
six months ended June 30, 2008 due primarily to additional depletion recorded on
natural gas and oil properties acquired in the Permian Basin and south Texas
acquisitions, offset by 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.





An
impairment of natural gas and oil properties in the amount of $63.8 million was
recognized during the six months ended June 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 generally accepted accounting principles 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 six months ended June 30, 2009 increased $2.8 million as
compared to the six months ended June 30, 2008 principally due to an increase in
non-cash charges.  For the six months ended June 30, 2009 and 2008,
non-cash compensation charges amounted to $4.0 million and $1.9 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 $0.7 million during the six months ended June 30, 2009 as compared to
the same period in 2008 principally due to incremental costs associated with the
company’s growth and acquisitions.




27


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 $0.8 million for the six months ended
June 30, 2009 as compared to the same period in 2008 as a result of decreased
revenues.





Interest
expense declined slightly to $2.0 million for the six months ended June 30, 2009
compared to $2.4 million for the six months ended June 30, 2008 primarily due to
lower interest rates which more than offset the higher average outstanding debt
during the six months ended June 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
June 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.




Recently
Adopted Accounting Pronouncements





On
January 1, 2008, we adopted Statement of Financial Accounting Standards No. 157
“FairValue Measurements” (“SFAS
157”) as it relates to financial assets and financial liabilities. In February
2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position
No. FAS 157-2, “Effective Date
of FASB Statement No. 157” (“FSP 157-2”), which delayed the effective
date of SFAS 157 for all non-financial assets and non-financial liabilities,
except those that are recognized or disclosed at fair value in the financial
statements on at least an annual basis, until January 1, 2009 for calendar
year-end entities. Also in February 2008, the FASB issued FASB Staff Position
No. FAS 157-1, “Application of
FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting
Pronouncements That Address Fair Value Measurements for Purposes of Lease
Classification or Measurement under Statement 13” (“FSP 157-1”),which states that
Statement of Financial Accounting Standards No. 13, “Accounting for Leases,”
(“SFAS 13”) and other accounting pronouncements that address fair value
measurements for purposes of lease classification or measurement under SFAS 13
are excluded from the provisions of SFAS 157, except for assets and liabilities
related to leases assumed in a business combination that are required to be
measured at fair value under Statement of Financial Accounting Standards No.
141, “Business
Combinations,” (“SFAS 141”) or Statement of Financial Accounting
Standards No. 141 (revised 2007), “Business Combinations,”
(“SFAS 141(R)”). In October 2008, the FASB issued FASB Staff Position No. FAS
157-3, “Determining the Fair
value of a Financial Asset in a Market That Is Not Active” (“FSP 157-3”),
which clarifies the application of SFAS 157 when the market of a financial asset
is inactive and provides an example to illustrate key considerations in
determining the fair value of a financial asset when the market for that
financial asset is not active. The guidance in FSP 157-3 was effective
immediately upon issuance and had no impact on our consolidated financial
statements.





SFAS 157
defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. The provisions of this standard apply
to other accounting pronouncements that require or permit fair value
measurements and are to be applied prospectively with limited exceptions. In
adopting SFAS 157 on January 1, 2008, as it relates to financial assets and
financial liabilities, 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. The adoption of SFAS 157 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. See Note 5 in Part 1—Item 1—Notes to Consolidated
Financial Statements for further discussion.





In April
2009, the FASB issued FASB Staff Position No. FAS 157-4, “Determining Fair Value When the
Volume and Level of Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not Orderly” (“FSP
157-4”). FSP 157-4 provides additional guidance on estimating fair value when
the volume and level of activity for an asset or liability have significantly
decreased in relation to normal activity for the asset or liability. FSP 157-4
also provides additional guidance on circumstances that may indicate that a
transaction is not orderly. FSP 157-4 is effective for interim and annual
periods ending after June 15, 2009. We adopted FSP-157-4 on June 30, 2009
and the adoption did not have a material impact on our consolidated financial
statements.





In
December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations”(“SFAS
141(R)”), which replaces SFAS No. 141“Business Combinations”
(“SFAS 141.”) SFAS 141(R) establishes principles and requirements for how an
acquirer recognizes and measures in its financial statements the identifiable
assets acquired, the liabilities assumed, any non-controlling interest in the
acquiree and the goodwill acquired. The Statement also establishes disclosure
requirements that will enable users to evaluate the nature and financial effects
of the business combination. SFAS 141(R) is effective for acquisitions that
occur in an entity’s fiscal year that begins after December 15, 2008. Effective
January 1, 2009, we adopted SFAS 141(R). However, since we did not consummate
any business combinations during the six months ended June 30, 2009, the
adoption did not affect our consolidated financial statements.





28


In April
2009, the FASB issued FASB Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies.” This Staff Position amends 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 SFAS No. 141(R.) This Staff Position carries forward the requirements in
SFAS 141 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 SFAS No. 5,
“Accounting for
Contingencies.”This Staff Position has the same effective date as SFAS
141(R), and the adoption did not affect our consolidated financial
statements.





In
December 2007, the FASB issued SFAS No. 160,“Non-controlling Interests in
Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS
160”). SFAS 160 requires that accounting and reporting for minority interests
will be recharacterized as non-controlling interests and classified as a
component of equity. SFAS 160 also establishes reporting requirements that
provide sufficient disclosures that clearly identify and distinguish between the
interests of the parent and the interests of the non-controlling
owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only
those entities that have an outstanding non-controlling interest in one or more
subsidiaries or that deconsolidate a subsidiary. This statement is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008. Effective January 1, 2009, we adopted SFAS 160; however, since we do not
own any “non-controlling interests,” the adoption did not affect our
consolidated financial statements.





In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 is intended to
improve financial reporting about derivative instruments and hedging activities
by requiring enhanced disclosures to enable investors to better understand their
effects on an entity’s financial position, financial performance, and cash
flows. SFAS 161 achieves these improvements by requiring disclosure of the fair
values of derivative instruments and their gains and losses in a tabular format.
It also provides more information about an entity’s liquidity by requiring
disclosure of derivative features that are credit risk-related. Finally, it
requires cross-referencing within footnotes to enable financial statement users
to locate important information about derivative instruments. SFAS 161 is
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008. Effective January 1, 2009, we adopted SFAS
161. The adoption did not have a material impact on our consolidated financial
statements. See Note 4 in Part 1—Item 1—Notes to Consolidated Financial
Statements for further discussion.





In May
2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted
Accounting Principles” (“SFAS 162”). This statement identifies the
sources of accounting principles and the framework for selecting the principles
to be used in the preparation of financial statements in conformity with GAAP in
the United States. This statement became effective on November 15, 2008.
The adoption of SFAS 162 did not have a material effect on our consolidated
financial statements.





In April
2009, the FASB issued FSP SFAS 107-1 and APB 28-1, “Interim Disclosures About Fair
Value of Financial Instruments” (“FSP 107-1.”) FSP 107-1 amends SFAS No.
107, “Disclosures about Fair
Values of Financial Instruments” and Accounting Principles Board Opinion
No. 28, “Interim Financial
Reporting,” to require disclosures about fair value of financial
instruments in interim financial statements. FSP 107-1 is effective for interim
periods ending after June 15, 2009, with early adoption permitted for periods
ending after March 15, 2009. We adopted FSP-107-1 on June 30, 2009 and the
adoption did not have a material impact on our consolidated financial
statements.





In May
2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS
165”). SFAS 165 establishes 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. In particular, this
Statement 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 SFAS 165, an entity
should apply the requirements to interim or annual financial periods ending
after June 15, 2009. We adopted SFAS 165 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 July 31, 2009, the date
on which the financial statements were issued. See Note 10 in Part 1—Item
1—Notes to Consolidated Financial Statements for discussion of subsequent
events.





29


New
Pronouncements Issued But Not Yet Adopted





In
December 2008, the Securities and Exchange Commission (“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 SFAS No. 166, “Accounting for Transfers of
Financial Assets - An Amendment of FASB Statement No. 140” (“SFAS 166”).
SFAS 166 improves the relevance, representational faithfulness, and
comparability of the information that a reporting entity provides in its
financial statements about a transfer of financial assets; the effects of a
transfer on its financial position, financial performance, and cash flows; and a
transferor’s continuing involvement, if any, in transferred financial assets.
The Board undertook this project to address (1) practices that have developed
since the issuance of FASB Statement No. 140, Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities, that
are not consistent with the original intent and key requirements of that
Statement and (2) concerns of financial statement users that many of the
financial assets (and related obligations) that have been derecognized should
continue to be reported in the financial statements of transferors. SFAS 166
must be applied as of the beginning of each reporting entity’s first annual
reporting period that begins after November 15, 2009, for interim periods within
that first annual reporting period and for interim and annual reporting periods
thereafter. Earlier application is prohibited. SFAS 166 must be applied to
transfers occurring on or after the effective date. SFAS 166 will be effective
for us on January 1, 2010. We do not anticipate consummating any transfers of
financial assets; therefore, we do not anticipate SFAS 166 having any impact on
our consolidated financial statements.





In June
2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation
No. 46(R)” (“SFAS 167”). SFAS 167 improves financial reporting by
enterprises involved with variable interest entities. The Board undertook this
project to address (1) the effects on certain provisions of FASB Interpretation
No. 46 (revised December 2003), Consolidation of Variable Interest
Entities, as a result of the elimination of the qualifying
special-purpose entity concept in SFAS 166, and (2) constituent concerns about
the application of certain key provisions of Interpretation 46(R), including
those in which the accounting and disclosures under the Interpretation do not
always provide timely and useful information about an enterprise’s involvement
in a variable interest entity. SFAS 167 shall be effective as of the beginning
of each reporting entity’s first annual reporting period that begins after
November 15, 2009, for interim periods within that first annual reporting
period, and for interim and annual reporting periods thereafter. Earlier
application is prohibited. SFAS 167 will be effective for us on January 1, 2010.
We do not have any interests in variable interest entities; therefore, we do not
anticipate SFAS 167 having any impact on our consolidated financial
statements.





In June
2009, the FASBissued
SFAS No. 168,“The FASB
Accounting Standards CodificationTMand the Hierarchy of Generally
Accepted Accounting Principles – a replacement of FASB Statement
No. 162” (“SFAS 168”).  The FASB Accounting Standards CodificationTM,
(“Codification”) will become the source of authoritative GAAP recognized by the
FASB to be applied by nongovernmental entities. Rules and interpretive releases
of the SEC under authority of federal securities laws are also sources of
authoritative GAAP for SEC registrants. On the effective date of SFAS 168, the
Codification will supersede all then-existing non-SEC accounting and reporting
standards. All other non-grandfathered non-SEC accounting literature not
included in the Codification will become non-authoritative. SFAS 168 is
effective for financial statements issued for interim and annual periods ending
after September 15, 2009. We will adopt the requirements of SFAS 168 in the
third quarter of fiscal 2009.





Use
of Estimates





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





30


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. 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 but,
capital markets remain volatile. As evidenced by recent successful equity and
debt offerings by our peers, we expect that we could issue debt and equity if
needed. During the six months ended June 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. The benefits expected to accrue
to our unitholders from our expansion activities may be muted by substantial
cost of capital increases during this period.





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 June 30, 2009 ranged from a high of
$72.69 to a low of $34.03 and the NYMEX natural gas spot price per MMBtu for the
period January 1, 2009 to June 30, 2009 ranged from a high of $6.07 to a low of
$3.25. As of July 30, 2009, the NYMEX crude oil spot price per barrel was $66.94
and the NYMEX natural gas spot price per MMBtu was $3.74.





Overview





We have
utilized private equity, proceeds from bank borrowings, cash flow from
operations and 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 July 30, 2009, we have
$25.0 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 and oil prices)
from our proved natural gas and oil reserves. Based on the current commodity
price environment, banks have lowered their internal projections of future
natural gas 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 May 2009, our borrowing base was reduced from $175.0 million to
$154.0 million. If commodity prices continue to decline and banks continue to
lower their internal projections of natural gas 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. We are currently in the
process of amending our existing reserve-based credit facility. As part of the
amendment, the term of the reserve-based credit facility would be extended and
the borrowing base, margins and other fees are expected to
increase.





Cash
Flow from Operations




Net cash
provided by operating activities for the six months ended June 30, 2009 was
$21.5 million, compared to $17.5 million for the six months ended June 30,
2008. The increase in cash provided by operating activities during the six
months ended June 30, 2009 was substantially due to increased income, after
adjusting for non-cash items, offset by a $2.2 million net decrease in operating
assets and liabilities. The increased income during the six months ended June
30, 2009, was largely a result of increased hedged production associated with
the Permian and south Texas acquisitions.




Cash flow
from operations is subject to many variables, the most significant of which is
the volatility of natural gas and oil prices. Natural gas and oil prices
are determined primarily by prevailing market conditions, which are dependent on
regional and worldwide economic activity, weather, and other factors beyond our
control. Future cash flow from operations will depend on our ability to
maintain and increase production through our drilling program and acquisitions,
as well as the prices received for production. We enter into derivative
contracts to reduce the impact of commodity price volatility on
operations. Currently, we use a combination of fixed-price swaps and NYMEX
collars and put options to reduce our exposure to the volatility in natural gas
and oil prices. See Note 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.




31


Cash
Flow from Investing Activities





Cash used
in investing activities was approximately $2.2 million for the six months ended
June 30, 2009, compared to $73.1 million for the six months ended June 30,
2008. The decrease in cash used in investing activities was primarily
attributable to $66.4 million used for the acquisition of natural gas and oil
properties in the Permian Basin during the six months ended June 30, 2008. In
addition, the total for the six months ended June 30, 2009 includes $1.9 million
for the drilling and development of natural gas and oil properties as compared
to $6.7 million for the six months ended June 30, 2008.




Cash Flow from
Financing Activities





Cash used
in financing activities was approximately $15.6 million for the six months ended
June 30, 2009, compared to cash provided by financing activities of $56.4
million for the six months ended June 30, 2008. During the six months ended June
30, 2009, total net repayments under our reserve-based credit facility were $2.5
million and $12.6 million was used for distributions to unitholders
compared to $8.3 million in distribution to unitholders in the comparable period
in 2008. During the six months ended June 30, 2008, total proceeds from
borrowings under our reserve-based credit facility were $74.4 million, which
were principally used to fund the Permian Basin acquisition.





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 June 2009, a fourth amendment to our reserve-based credit
facility was entered into which set the allowed interest rate swap hedge
percentage at 85% of the outstanding principal balance of indebtedness for the
period June 26, 2009 to June 25, 2010. Following this period, the percentage
will return to 75%. At June 30, 2009, we had $132.5 million outstanding under
our reserve-based credit facility and as of July 30, 2009, we have $25.0 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 and oil prices)
from our proved natural gas and oil reserves. Based on the current commodity
price environment, banks have lowered their internal projections of future
natural gas 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 May 2009, our borrowing base was reduced from $175.0 million to
$154.0 million. If commodity prices continue to decline and banks continue to
lower their internal projections of natural gas 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. We are currently in the process of amending our
existing reserve-based credit facility. As part of the amendment, the term of
the reserve-based credit facility would be extended and the borrowing base,
margins and other fees are expected to increase.


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




At our
election, interest is determined by reference to:




·
            the
      London interbank offered rate, or LIBOR, plus an applicable margin between
      1.50% and 2.125% per annum; or





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




32


As of
June 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 SFAS 133, 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 4.0 to
      1.0.





We
have the ability to borrow under the reserve-based credit facility to pay
distributions to unitholders as long as there has not been a default or event of
default. 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;





·
            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;





33


·
            bankruptcy
      or insolvency events involving us or our
  subsidiaries;





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





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





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




Off-Balance
Sheet Arrangements




At June
30, 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 June 30, 2009, there were no loss
contingencies.




Commitments
and Contractual Obligations




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





Payments Due by Year (in thousands)2009
                  
                  
                  2010
                  
                  
                  2011
                  
                  
                  2012
                  
                  
                  2013
                  
                  
                  After 2013
                  
                  
                  TotalManagement
      compensation
                  
                  $
                  338
                  
                  
                  $
                  112
                  
                  
                  $
                  —
                  
                  
                  $
                  —
                  
                  
                  $
                  —
                  
                  
                  $
                  —
                  
                  
                  $
                  450Asset
      retirement obligations
                  
                  
                  —
                  
                  
                  
                  38
                  
                  
                  
                  187
                  
                  
                  
                  33
                  
                  
                  
                  14
                  
                  
                  
                  1,914
                  
                  
                  
                  2,186Derivative
      liabilities
                  
                  
                  116
                  
                  
                  
                  3,712
                  
                  
                  
                  1,227
                  
                  
                  
                  690
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  5,745Long-term
      debt (1)
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  132,500
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  132,500Operating
      leases
                  
                  
                  61
                  
                  
                  
                  31
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  92Total
                  
                  $
                  515
                  
                  
                  $
                  3,893
                  
                  
                  $
                  133,914
                  
                  
                  $
                  723
                  
                  
                  $
                  14
                  
                  
                  $
                  1,914
                  
                  
                  $
                  140,973





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




Non-GAAP
Financial Measure





Adjusted
EBITDA





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





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





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





34


•
            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;





•
            Deferred
      taxes; and





•
            Unit-based
      compensation expense.




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 June 30, 2009 as compared to the three months ended June 30,
2008, Adjusted EBITDA increased 11%, from $11.9 million to $13.3 million. For
the six months ended June 30, 2009 as compared to the six months ended June 30,
2008, Adjusted EBITDA increased 16%, from $22.4 million to $25.9 million. The
following table presents a reconciliation of consolidated net loss to Adjusted
EBITDA:




Three
      Months Ended
                    June
      30,
                
                
                Six
      Months Ended
                  June
      30,2009
                
                
                2008
                
                
                2009
                
                
                2008Net
      loss
                
                $
                (6,768
                )
                
                $
                (47,020
                )
                
                $
                (56,733
                )
                
                $
                (62,952
                )Plus:Interest expense,
      including realized losses on interest rate derivative
      contracts
                
                
                1,377
                
                
                
                1,244
                
                
                
                2,726
                
                
                
                2,374Depreciation,
      depletion, amortization, and accretion
                
                
                2,645
                
                
                
                3,330
                
                
                
                6,428
                
                
                
                6,154Impairment of natural
      gas and oil properties
                
                
                —
                
                
                
                —
                
                
                
                63,818
                
                
                
                —Amortization of
      premiums paid and non-cash settlements on derivative
    contracts
                
                
                1,107
                
                
                
                1,230
                
                
                
                2,572
                
                
                
                2,531Unrealized losses
      on other commodity and interest rate derivative contracts
                
                
                13,096
                
                
                
                52,186
                
                
                
                3,310
                
                
                
                72,396Deferred
      taxes
                
                
                (4
                )
                
                
                —
                
                
                
                (201
                )
                
                
                —Unit-based
      compensation expense
                
                
                1,827
                
                
                
                981
                
                
                
                4,015
                
                
                
                1,896Less:Interest income
                
                
                —
                
                
                
                4
                
                
                
                —
                
                
                
                12Adjusted
      EBITDA
                
                $
                13,280
                
                
                $
                11,947
                
                
                $
                25,935
                
                
                $
                22,387




Item
3. Quantitative and
Qualitative Disclosures About Market Risk





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




35


Commodity
Price Risk




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





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




At June
30, 2009, the fair value of commodity derivative contracts was an asset of
approximately $32.4 million, of which $21.5 million settles during the next
twelve months.





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





July
      1, - December 31, 2009
                
                
                Year
                  2010
                
                
                Year
                  2011Gas
      Positions:Fixed
      Price Swaps:Notional
      Volume (MMBtu)
                
                
                1,756,188
                
                
                
                3,782,040
                
                
                
                3,328,312Fixed
      Price ($/MMBtu)
                
                $
                9.32
                
                
                $
                8.95
                
                
                $
                7.83Puts:Notional
      Volume (MMBtu)
                
                
                396,265
                
                
                
                —
                
                
                
                —Floor
      Price ($/MMBtu)
                
                $
                7.50
                
                
                $
                —
                
                
                $
                —Collars:Notional
      Volume (MMBtu)
                
                
                499,998
                
                
                
                914,000
                
                
                
                364,000Floor
      Price ($/MMBtu)
                
                $
                7.50
                
                
                $
                7.90
                
                
                $
                7.50Ceiling
      Price ($/MMBtu)
                
                $
                9.00
                
                
                $
                9.24
                
                
                $
                9.00Total:Notional
      Volume (MMBtu)
                
                
                2,652,451
                
                
                
                4,696,040
                
                
                
                3,692,312Oil
      Positions:Fixed
      Price Swaps:Notional
      Volume (Bbls)
                
                
                89,000
                
                
                
                164,250
                
                
                
                151,250Fixed
      Price ($/Bbl)
                
                $
                87.23
                
                
                $
                85.65
                
                
                $
                85.50Collars:Notional
      Volume (Bbls)
                
                
                18,400
                
                
                
                —
                
                
                
                —Floor
      Price ($/Bbl)
                
                $
                100.00
                
                
                $
                —
                
                
                $
                —Ceiling
      Price ($/Bbl)
                
                $
                127.00
                
                
                $
                —
                
                
                $
                —Total:Notional
      Volume (Bbls)
                
                
                107,400
                
                
                
                164,250
                
                
                
                151,250





36


Interest
Rate Risks





At June
30, 2009, we had debt outstanding of $132.5 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 $0.3 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.





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





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




37


Counterparty
Risk





At June
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-)
                                      
                                      
                                      Wachovia
      Bank, N.A.
                                        (AA)
                                      
                                      
                                      TotalCurrent
      Asset, net
                                      $
                                      1,991
                                      
                                      
                                      $
                                      19,024
                                      
                                      
                                      $
                                      523
                                      
                                      
                                      $
                                      —
                                      
                                      
                                      $
                                      21,538Current
      Liability, net
                                      
                                      (53
                                      )
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      (103
                                      )
                                      
                                      
                                      (156
                                      )Long-Term
      Asset, net
                                      
                                      1,739
                                      
                                      
                                      
                                      9,085
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      —
                                      
                                      
                                      
                                      10,824Long-Term
      Liability, net
                                      
                                      —
                                      
                                      
                                      
                                      (683
                                      )
                                      
                                      
                                      (720
                                      )
                                      
                                      
                                      (279
                                      )
                                      
                                      
                                      (1,682
                                      )Total
      Amount Due from Counterparty/(Owed to Counterparty)
                                        at
      June 30, 2009
                                      $
                                      3,677
                                      
                                      
                                      $
                                      27,426
                                      
                                      
                                      $
                                      (197
                                      )
                                      
                                      $
                                      (382
                                      )
                                      
                                      $
                                      30,524





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 June 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.





Changes
in Internal Control over Financial Reporting




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.





38


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 and oil prices are volatile.  A decline in natural gas 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 and oil production and the prices prevailing from
time to time for natural gas 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 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 May 2009, our borrowing base was reduced from $175.0 million to $154.0
million. It is possible that we will be subject to a further reduction in our
borrowing base at our next scheduled redetermination. 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. We are evaluating
options for financing the July 2009 south Texas acquisition and are currently in
the process of amending our existing reserve-based credit facility. As part of
the amendment, the term of the reserve-based credit facility would be extended
and the borrowing base, margins and other fees are expected to
increase.





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 June 30, 2009 ranged from a high of
$72.69 to a low of $34.03 and the NYMEX natural gas spot price per MMBtu for the
period January 1, 2009 to June 30, 2009 ranged from a high of $6.07 to a low of
$3.25. As of July 30, 2009, the NYMEX crude oil spot price per barrel was $66.94
and the NYMEX natural gas spot price per MMBtu was $3.74. 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 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;





·
            domestic
      and foreign governmental regulations and
taxes;





39


·
            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. 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.





Certain
federal income tax deductions currently available with respect to oil and gas
drilling and development may be eliminated as a result of future legislation.
Additionally, federal income tax rates may be increased for certain investors,
in which case any income resulting from an investment in us may result in higher
federal income tax payments.





The
White House released a preview of its budget for Fiscal Year 2010 on February
26, 2009, entitled “A New Era of Responsibility: Renewing America’s Promise.”
Among the new administration’s proposed changes are the outright elimination of
many of the key federal income tax benefits historically associated with oil and
gas. Although presented in very summary form, among other significant energy tax
items, the administration’s budget appears to propose the complete elimination
of (1) expensing of intangible drilling costs, and (2) the “percentage
depletion” method of deduction with respect to oil and gas wells. Additionally,
the budget proposes to reinstate for single individuals making greater than
$200,000 per year, and for couples making greater than $250,000 per year, the
maximum ordinary income rates of 36% and 39.6%, respectively and increase the
maximum long-term capital gain rate to 20%. Although no legislation has yet been
formally introduced, the administration’s apparent effective date would be
January 1, 2011. It is unclear whether such proposal will be proposed as actual
legislation and, if so, whether it will actually be enacted. In addition, there
are other significant tax changes under discussion in the Congress. If this
proposal (or others) is enacted into law, it could represent an extremely
significant reduction in the tax benefits that have historically applied to
certain investments in oil and gas.




The
adoption of climate change legislation by Congress could result in increased
operating costs and reduced demand for the oil and natural gas we
produce.





On June
26, 2009, the U.S. House of Representatives approved adoption of the “American
Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey
cap-and-trade legislation” or ACESA. The purpose of ACESA is to control and
reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs
are certain gases, including carbon dioxide and methane, that may be
contributing to warming of the Earth’s atmosphere and other climatic changes.
ACESA would establish an economy-wide cap on emissions of GHGs in the United
States and would require an overall reduction in GHG emissions of 17% (from 2005
levels) by 2020, and by over 80% by 2050. Under ACESA, most sources of GHG
emissions would be required to obtain GHG emission “allowances” corresponding to
their annual emissions of GHGs. The number of emission allowances issued each
year would decline as necessary to meet ACESA’s overall emission reduction
goals. As the number of GHG emission allowances declines each year, the cost or
value of allowances is expected to escalate significantly. The net effect of
ACESA will be to impose increasing costs on the combustion of carbon-based fuels
such as oil, refined petroleum products, and natural gas.





The U.S.
Senate has begun work on its own legislation for controlling and reducing
emissions of GHGs in the United States. If the Senate adopts GHG legislation
that is different from ACESA, the Senate legislation would need to be reconciled
with ACESA and both chambers would be required to approve identical legislation
before it could become law. President Obama has indicated that he is in support
of the adoption of legislation to control and reduce emissions of GHGs through
an emission allowance permitting system that results in fewer allowances being
issued each year but that allows parties to buy, sell and trade allowances as
needed to fulfill their GHG emission obligations. Although it is not possible at
this time to predict whether or when the Senate may act on climate change
legislation or how any bill approved by the Senate would be reconciled with
ACESA, any laws or regulations that may be adopted to restrict or reduce
emissions of GHGs would likely require us to incur increased operating costs,
and could have an adverse effect on demand for the oil and natural gas we
produce.





40


The
adoption of derivatives legislation by Congress could have an adverse impact on
our ability to hedge risks associated with our business.





Congress
is currently considering legislation to impose restrictions on
certain transactions involving derivatives, which could affect the use of
derivatives in hedging transactions. ACESA contains provisions that would
prohibit private energy commodity derivative and hedging transactions. ACESA
would expand the power of the Commodity Futures Trading Commission, or CFTC, to
regulate derivative transactions related to energy commodities, including oil
and natural gas, and to mandate clearance of such derivative contracts through
registered derivative clearing organizations. Under ACESA, the CFTC’s expanded
authority over energy derivatives would terminate upon the adoption of general
legislation covering derivative regulatory reform. The Chairman of the CFTC has
announced that the CFTC intends to conduct hearings to determine whether to set
limits on trading and positions in commodities with finite supply, particularly
energy commodities, such as crude oil, natural gas and other energy products.
The CFTC also is evaluating whether position limits should be applied
consistently across all markets and participants. In addition, the Treasury
Department recently has indicated that it intends to propose legislation to
subject all OTC derivative dealers and all other major OTC derivative market
participants to substantial supervision and regulation, including by imposing
conservative capital and margin requirements and strong business conduct
standards. Derivative contracts that are not cleared through central
clearinghouses and exchanges may be subject to substantially higher capital and
margin requirements. Although it is not possible at this time to predict whether
or when Congress may act on derivatives legislation or how any climate change
bill approved by the Senate would be reconciled with ACESA, any laws or
regulations that may be adopted that subject us to additional capital or margin
requirements relating to, or to additional restrictions on, our trading and
commodity positions could have an adverse effect on our ability to hedge risks
associated with our business or on the cost of our hedging
activity.





Federal
and state legislation and regulatory initiatives relating to hydraulic
fracturing could result in increased costs and additional operating restrictions
or delays.





Congress
is currently considering legislation to amend the federal Safe Drinking Water
Act to require the disclosure of chemicals used by the oil and gas industry in
the hydraulic fracturing process. Hydraulic fracturing involves the injection of
water, sand and chemicals under pressure into rock formations to stimulate
natural gas production. Sponsors of bills currently pending before the Senate
and House of Representatives have asserted that chemicals used in the fracturing
process could adversely affect drinking water supplies. The proposed legislation
would require the reporting and public disclosure of chemicals used in the
fracturing process, which could make it easier for third parties opposing the
hydraulic fracturing process to initiate legal proceedings based on allegations
that specific chemicals used in the fracturing process could adversely affect
groundwater. In addition, these bills, if adopted, could establish an additional
level of regulation at the federal level that could lead to operational delays
or increased operating costs and could result in additional regulatory burdens
that could make it more difficult to perform hydraulic fracturing and increase
our costs of compliance and doing business.





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




None.




Item 3.  Defaults Upon Senior
Securities




None.




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




The
annual meeting of unitholders of Vanguard Natural Resources, LLC was held on May
12, 2009 in Houston, Texas. At the annual meeting, holders of 12,565,873 units
were entitled to vote on the specified unitholder matters, of which 10,774,720
units were present and voting, or 86% of the outstanding units, which
constituted a quorum.





Proposals
submitted to a vote of the unitholders were:





(1) The
      election of six directors of Vanguard Natural Resources, LLC for a
      one-year term expiring at the 2010 annual meeting of unitholders and until
      their respective successors are elected and
    qualified.





41


Number
      of Voting UnitsDirector’s
      Name
                
                For
                
                WithheldW.
      Richard Anderson
                
                
                10,610,227
                
                164,493Loren
      Singletary
                
                
                10,633,528
                
                141,192Bruce
      W. McCullough
                
                
                10,634,927
                
                139,793John
      R. McGoldrick
                
                
                10,634,927
                
                139,793Lasse
      Wagene
                
                
                10,633,428
                
                141,292Scott
      W. Smith
                
                
                10,634,827
                
                139,893





(2) The
      ratification of BDO Seidman, LLP as our independent registered public
      accountants for the fiscal year ended December 31,
  2009.





For
                    
                    Against
                    
                    Abstained10,739,534
                    
                    
                    33,543
                    
                    
                    1,643




Item 5.  OtherInformation




None.




Item 6.  Exhibits




EXHIBIT
INDEX


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




Exhibit
      No.
            
            Exhibit
      Title
            
            Incorporated
      by Reference to the 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)10.31
            
            Fourth
      Amendment to First Amended and Restated Credit Agreement, dated June 26,
      2009, by and between Vanguard Natural Gas, LLC, lenders party hereto, and
      Citibank, N.A., as administrative agent
            
            Filed
      herewith10.32
            
            Purchase
      and Sale Agreement, dated July 17, 2009, among Vanguard Permian, LLC and
      Segundo Navarro Drilling, Ltd.
            
            Form
      8-K, filed July 21, 2009 (File No. 001-33756)31.1
            
            Certification
      of Chief Executive Officer Pursuant to Rule 13a — 14 of the
      Securities and Exchange Act of 1934, as Adopted Pursuant to
      Section 302 of the Sarbanes-Oxley Act of 2002
            
            Filed
      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





42











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:
      July 31, 2009/s/ Richard
      A. RobertRichard
      A. RobertExecutive
      Vice President andChief
      Financial Officer(Principal
      Financial Officer and Principal Accounting
  Officer)