##### Table of Contents





UNITED STATES SECURITIES AND
    EXCHANGE COMMISSION
 Washington, D.C.
    20549
 Form 10-K
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
    SECURITIES EXCHANGE ACT OF 1934   For the fiscal year ended December 31, 2008
  Commission file number:
    001-33787
      QUEST ENERGY PARTNERS,
    L.P.
 (Exact Name of Registrant as
    Specified in Its Charter)
      Delaware

26-0518546(State or Other Jurisdiction
    of
    Incorporation or Organization)

(I.R.S. Employer
    Identification No.)210 Park Avenue, Suite 2750

73102Oklahoma City, Oklahoma(Address of Principal
    Executive
    Offices)

(Zip Code)   Registrants telephone number, including area code:
 405-600-7704
 Securities Registered Pursuant to Section 12(b) of the
    Exchange Act:
  Title of Each Class

Name of Each Exchange on Which RegisteredCommon Units representing limited partner interests

NASDAQ Global Market   Securities Registered Pursuant to Section 12(g) of the
    Exchange Act:
 None
  o þ
  o þ
  o þ
  Regulation S-T o o
  Regulation S-K Form 10-K Form 10-K. þ
  Rule 12b-2
  Large
    accelerated
    filer o
    Accelerated
    filer þ
    Non-accelerated
    filer o
    Smaller
    reporting
    company o   Rule 12b-2 o þ
    DOCUMENTS
    INCORPORATED BY REFERENCE




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##### 





TABLE OF
    CONTENTS
   
  PART IITEMS 1 AND 2.

BUSINESS AND PROPERTIES


8ITEM 1A.

RISK FACTORS


38ITEM 1B.

UNRESOLVED STAFF COMMENTS


68ITEM 3.

LEGAL PROCEEDINGS


68ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY
    HOLDERS


72PART IIITEM 5.

MARKET FOR REGISTRANTS COMMON EQUITY,
    RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
    SECURITIES


73ITEM 6.

SELECTED FINANCIAL DATA


76ITEM 7.

MANAGEMENTS DISCUSSION AND ANALYSIS OF
    FINANCIAL CONDITION AND RESULTS OF OPERATIONS


77ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
    MARKET RISK


100ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


102ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
    ACCOUNTING AND FINANCIAL DISCLOSURE


102ITEM 9A.

CONTROLS AND PROCEDURES


102ITEM 9B.

OTHER INFORMATION


105PART IIIITEM 10.

DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT
    AND CORPORATE GOVERNANCE


106ITEM 11.

EXECUTIVE COMPENSATION


110ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
    AND MANAGEMENT AND RELATED UNITHOLDER MATTERS


129ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
    AND DIRECTOR INDEPENDENCE


132ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES


135PART IVITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES


136SIGNATURES


137INDEX TO EXHIBITS


138EX-10.15EX-10.20EX-10.31EX-10.32EX-21.1EX-23.1EX-23.2EX-24.1EX-31.1EX-31.2EX-32.1EX-32.2   2




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GUIDE TO
    READING THIS REPORT
    
    when we use the terms Quest Energy,
    QELP, the Partnership,
    Successor, our, we,
    us and similar terms in a historical context prior
    to November 15, 2007, we are referring to Predecessor, and
    when we use such terms in a historical context on or after
    November 15, 2007, in the present tense or prospectively,
    we are referring to Quest Energy Partners, L.P. and its
    subsidiaries;
    when we use the term Predecessor, we are referring
    to the assets, liabilities and operations of QRCP located in the
    Cherokee Basin (other than its midstream assets), which QRCP
    contributed to us at the completion of our initial public
    offering on November 15, 2007;
    when we use the terms Quest Energy GP or our
    general partner, we are referring to Quest Energy GP, LLC,
    our general partner;
    when we use the term QRCP, we are referring to Quest
    Resource Corporation (NASDAQ: QRCP), the owner of our general
    partner;
    when we use the term Quest Midstream, or
    QMLP, we are referring to our affiliate Quest
    Midstream Partners, L.P. and its subsidiaries; and
    references to our consolidated financial statements
    and the Predecessors consolidated financial
    statements when used for any period prior to
    November 15, 2007 include or mean, respectively, the carve
    out financial statements of our Predecessor.   3




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EXPLANATORY
    NOTE
  Form 10-K Form 10-Q/A Form 10-Q/A Form 10-Q
    Investigation 
    Form 8-K
 4




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8-K
  Restatement and Reaudit 
  Form 10-K
  
    The Transfers, which were not approved expenditures, were not
    properly accounted for as losses.
    Hedge accounting was inappropriately applied for our commodity
    derivative instruments and the valuation of commodity derivative
    instruments was incorrectly computed.
    Errors were identified in the accounting for the formation of
    Quest Cherokee in December 2003 in which: (i) no value was
    ascribed to the Quest Cherokee Class A units that were
    issued to ArcLight Energy Partners Fund I, L.P.
    (ArcLight) in connection with the transaction,
    (ii) a debt discount (and related accretion) and minority
    interest were not recorded, (iii) transaction costs were
    inappropriately capitalized to oil and gas properties, and
    (iv) subsequent to December 2003, interest expense was
    improperly stated as a result of these errors. In 2005, the debt
    relating to this transaction was repaid and the Class A
    units were repurchased from ArcLight. Due to the errors that
    existed in the previous accounting, additional errors resulted
    in 2005 including: (i) a loss on extinguishment of debt was
    not recorded, and (ii) oil and gas properties and retained
    earnings were overstated. Subsequent to the 2005 transaction,
    depreciation, depletion and amortization expense was also
    overstated due to these errors.
    Certain general and administrative expenses unrelated to oil and
    gas production were inappropriately capitalized to oil and gas
    properties, and certain operating expenses were inappropriately
    capitalized to oil and gas properties being amortized. These
    items resulted in errors in valuation of the full cost pool, oil
    and gas production expenses and general and administrative
    expenses.
    Invoices were not properly accrued resulting in the
    understatement of accounts payable and numerous other balance
    sheet and income statement accounts.
    As a result of previously discussed errors and an additional
    error related to the methods used in calculating depreciation,
    depletion and amortization, errors existed in our depreciation,
    depletion and amortization expense and our accumulated
    depreciation, depletion and amortization.
    As a result of previously discussed errors relating to oil and
    gas properties and hedge accounting, and errors relating to the
    treatment of deferred taxes, errors existed in our ceiling test
    calculations. 5




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Successor


PredecessorAs of December 312007


2006


2005Partners equity as previously reported

$
228,760


$
51,091


$
69,547Effect of the Transfers


(9,500
)


(8,000
)


(2,000
)Reversal of hedge accounting


1,224



(2,389
)


(8,177
)Accounting for formation of Quest Cherokee


(15,102
)


(15,102
)


(15,102
)Capitalization of costs in full cost pool


(24,007
)


(12,671
)


(5,388
)Recognition of costs in proper periods


(1,540
)


(233
)


(272
)Depreciation, depletion and amortization


11,920



8,249



4,054Impairment of oil and gas properties


30,719



30,719



Other errors


(2,744
)


(4,910
)


(3,920
)Partners equity as restated

$
219,730


$
46,754


$
38,742   Successor


PredecessorNovember 15, 2007


January 1, 2007to


toDecember 31,


November 14,


Year Ended December 312007


2007


2006


2005Net loss as previously reported

$
(18,511
)

$
(19,191
)

$
(47,549
)

$
(25,192
)Effect of the Transfers






(1,500
)


(6,000
)


(2,000
)Reversal of hedge accounting


1,627



73



53,387



(42,854
)Accounting for formation of Quest Cherokee














(10,319
)Capitalization of costs in full cost pool


(1,839
)


(9,497
)


(7,283
)


(5,388
)Recognition of costs in proper periods






(1,307
)


39



(80
)Depreciation, depletion and amortization


335



3,336



4,195



1,448Impairment of oil and gas properties










30,719



Other errors


(818
)


(1,088
)


1,625



(922
)Net income (loss) as restated

$
(19,206
)

$
(29,174
)

$
29,133


$
(85,307
)     Other Matters 
  
    The theft of approximately $1.0 million by David E. Grose,
    the former chief financial officer, and Brent Mueller, the
    former purchasing manager. The evidence indicates that this
    theft occurred in the third quarter of 2008 and was uncovered
    prior to the preparation of the financial statements for such
    period, and therefore did not result in a restatement.
    A kickback scheme involving David E. Grose and Brent Mueller, in
    which each received kickbacks totaling approximately
    $0.9 million from several related suppliers beginning in
    2005. 6




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
    the necessary retention of numerous professionals, including
    consultants to perform the accounting and finance functions
    following the termination of the chief financial officer,
    independent legal counsel to conduct the internal investigation,
    investment bankers and financial advisors, and law firms to
    respond to the class action and derivative suits that have been
    filed against us and our affiliates and to pursue the claims
    against the former employees;
    costs associated with amending our credit agreements;
    preparing the restated consolidated financial
    statements; and
    conducting the reaudits of the restated consolidated financial
    statements.   7




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PART I ITEMS 1
    AND 2.  BUSINESS AND PROPERTIES.  Overview
          
    Cherokee Basin.  152.7 Bcfe of estimated
    net proved reserves as of December 31, 2008 and an average
    net daily production of 57.3 Mmcfe for the year ended
    December 31, 2008 throughout six counties in southeastern
    Kansas and northeastern Oklahoma;
    Appalachian Basin.  10.9 Bcfe of estimated
    net proved reserves as of December 31, 2008 and an average
    net daily production of 2.9 Mmcfe for the year ended
    December 31, 2008 predominantly in the Marcellus Shale and
    Devonian Sand formations in West Virginia and New York; and
    Seminole County.  588,800 Bbls of
    estimated net proved reserves as of December 31, 2008 and
    an average net daily production of approximately 148 Bbls
    for the year ended December 31, 2008 of oil producing
    properties in Seminole County, Oklahoma. 8




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Oil and
    Gas Production
  Cherokee Basin. reserve-to-production
  160-acre 80-acre 80-acre
    Appalachian Basin.
   9




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##### Table of Contents



reserve-to-production
      Seminole County, Oklahoma.
  Recent
    Developments
  PetroEdge
    Acquisition
   10




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Internal
    Investigation; Restatements and Reaudits
    and/or
      
    We had costs associated with the internal investigation and our
    responding to inquiries from the Oklahoma Department of
    Securities, the Federal Bureau of Investigation, the Department
    of Justice, the SEC and the IRS.
    As a result of the resignation of Jerry D. Cash and the
    termination of David E. Grose, consultants were immediately
    retained to perform the accounting and finance functions and to
    assist in the determination of the intercompany debt discussed
    below under  Intercompany Accounts. 11




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
    We retained law firms to respond to the class action and
    derivative suits that have been filed against us, our general
    partner and QRCP and to pursue the claims against the former
    employees.
    We had costs associated with amending our credit agreements and
    obtaining the necessary waivers from our lenders thereunder as
    well as incremental increased interest expense related thereto.
    See Item 7. Managements Discussion and Analysis
    of Financial Condition and Results of Operations 
    Liquidity and Capital Resources.
    We retained new external auditors, who completed reaudits of our
    restated consolidated financial statements as of
    December 31, 2007 and for the period from November 15,
    2007 to December 31, 2007, and of the Predecessors
    consolidated financial statements as of and for the years ended
    December 31, 2005 and 2006 and for the period from
    January 1, 2007 to November 14, 2007.
    We retained financial advisors to consider strategic options and
    retained outside legal counsel or increased the amount of work
    being performed by our previously engaged outside legal counsel.    Global
    Financial Crisis and Impact on Capital Markets and Commodity
    Prices
           12




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Management
    Personnel Changes
    NASDAQ
    Non-compliance
  Form 10-Q Form 10-Q. Form 10-Q
  Credit
    Agreement Amendments
  and/or
    Suspension
    of Distributions
    
    the decline in our cash flows from operations due to declines in
    oil and natural gas prices during the last half of 2008,
    the costs of the investigation and associated remedial actions,
    including the reaudit and restatement of our financial
    statements,
    concerns about a potential borrowing base redetermination in the
    second quarter of 2009, 13




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
    the need to conserve cash to properly conduct operations and
    maintain strategic options, and
    the need to repay or refinance our term loan by
    September 30, 2009.      Intercompany
    Accounts
    Cost-cutting
    Measures
    Decrease
    in Year-End Reserves; Impairment
    Seminole
    County Acreage Acquisition
   14




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Settlement
    Agreements
    2008
    Operating Results
    Outlook
    for 2009; Recombination
  and/or
  Our
    Relationship with QRCP and Quest Midstream
   15




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Form 10-K.
  Organizational
    Structure
    
    Omnibus Agreement.
  
    reimbursement of certain insurance, operating and general and
    administrative expenses incurred on our behalf;
    indemnification for certain environmental liabilities, tax
    liabilities, tax defects and other losses in connection with
    assets;
    a license for the use of the Quest name and mark; and
    our right to purchase from QRCP and its affiliates certain
    assets that they acquire within the Cherokee Basin.    Management Agreement. Sarbanes-Oxley
 16




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Description
    of Our Properties and Projects
  Cherokee
    Basin
            Cherokee
    Basin Projects
  160-acre 80-acre 80-acre
 17




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50-55 Mcf/d
    50-60 Bbls 30-50 Bbls
  Appalachian
    Basin
     18




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Appalachian
    Basin Projects
      Seminole
    County, Oklahoma
  on-site.
 19




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Oil and
    Gas Data
  Estimated
    Net Proved Reserves
  Form EIA-23. Form EIA-23 Form EIA-23
  Successor


PredecessorDecember 31,2008


2007


2006Proved reservesGas (Mcf)


162,984,141



210,923,406



198,040,000Oil (Bbls)


682,031



36,556



32,272Total (Mcfe)


167,076,327



211,142,742



198,233,632Proved developed gas reserves (Mcf)


134,837,100



140,966,300



122,390,400Proved undeveloped gas reserves (Mcf)


28,147,041



69,957,106



75,649,600Proved developed oil reserves (Bbls)(1)


682,031



36,556



32,272Proved developed reserves as a percentage of total proved
    reserves


83.2
%


66.9
%


61.8
%Standardized measure (in thousands)(2)

$
156,057


$
322,538


$
230,832     (1)
    
    Although we have proved undeveloped oil reserves, they are
    insignificant, so no effort was made to calculate such reserves.(2)
    
    Standardized measure is the present value of estimated future
    net revenue to be generated from the production of proved
    reserves, determined in accordance with the rules and
    regulations of the SEC (using prices and costs in effect as of
    the date of estimation), less future development, production and
    income tax expenses, and discounted at 10% per annum to reflect
    the timing of future net revenues. Our standardized measure does
    not reflect any future income tax expenses, for the successor
    period, because we are not subject to federal income taxes.
    Standardized measure does not give effect to commodity
    derivative transactions. For a description of our derivative
    transactions, see Note 7  Financial Instruments
    and Note 6  Derivative Financial Instruments, in
    the notes to the consolidated financial statements of this
    Form 10-K.
    The standardized measure shown should not be construed as the
    current market value of the reserves. The 10% discount factor
    used to calculate present value, which is required by Financial
    Accounting Standards Board (FASB) pronouncements, is
    not necessarily the most appropriate discount rate. The present
    value, no matter what discount rate is used, is materially
    affected by assumptions as to timing of future production, which
    may prove to be inaccurate.   20




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Production
    Volumes, Sales Prices and Production Costs
    Successor


PredecessorNovember 15


January 1Year Ended


to


to


Year EndedDecember 31,


December 31,


November 14,


December 31,2008


2007


2007


2006Net Production:Gas (Bcf)


21.33



2.43



14.55



12.30Oil (Bbls)


69,812



396



6,674



9,808Gas equivalent (Bcfe)


21.75



2.43



14.59



12.36Oil and Gas Sales ($ in thousands):Gas sales

$
141,482


$
15,314


$
89,539


$
71,836Oil sales


6,448



34



398



574Total oil and gas sales

$
147,930


$
15,348


$
89,937


$
72,410Avg Sales Price:Gas ($ per Mcf)

$
6.63


$
6.30


$
6.15


$
5.84Oil ($ per Bbl)

$
92.36


$
85.86


$
59.63


$
58.52Gas equivalent ($ per Mcfe)

$
6.80


$
6.32


$
6.16


$
5.86Oil and gas operating expenses ($ per Mcfe):Lifting

$
1.56


$
1.73


$
1.22


$
1.52Production and property tax


0.45



0.41



0.43



0.49Net Revenue ($ per Mcfe)

$
4.79


$
4.18


$
4.51


$
3.85   Producing
    Wells and Acreage
    Productive WellsGas(1)


Oil


TotalGross


Net


Gross


Net


Gross


NetPredecessor:December 31, 2006


1,653



1,635.0



29



28.1



1,682



1,663.1Successor:December 31, 2007


2,225



2,218.2



29



28.1



2,254



2,246.3December 31, 2008(2)


2,873



2,825.0



82



80.2



2,955



2,905.2     (1)
    
    At December 31, 2008, we had approximately 2,346 gross
    wells in the Cherokee Basin that were producing from multiple
    seams.(2)
    
    Includes approximately 500 gross productive Appalachian
    Basin wells acquired in the PetroEdge acquisition and
    55 gross productive oil wells acquired in Seminole County,
    Oklahoma.  21




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Leasehold AcreageProducing(1)


Nonproducing


TotalGross


Net


Gross


Net


Gross


NetPredecessor:December 31, 2006(2)


394,795



385,148



132,189



124,774



526,984



509,922Successor:December 31, 2007


402,888



393,320



179,524



164,870



582,412



558,190December 31, 2008


416,200



408,161



160,062



150,923



576,262



559,084     (1)
    
    Includes acreage held by production under the terms of the lease.(2)
    
    Approximately 45,000 net acres that were included in the
    2006 leasehold acreage amounts have expired.    Drilling
    Activities
    Successor


PredecessorNovember 15


January 1Year Ended


through


through


Year EndedDecember 31,


December 31,


November 14,


December 31,2008


2007


2007


2006Oil & Gas


Gas(1)


Gas(1)


Gas(1)Gross


Net


Gross


Net


Gross


Net


Gross


NetExploratory wells drilled:Capable of production






























Dry






























Development wells drilled:Capable of production


323



323



40



40



532



532



621



621Dry






























Wells plugged and abandoned


17



17























Wells acquired capable of production(2)


549



513























Net increase in capable wells


855



819



40



40



532



532



621



621Recompletion of old wells:Capable of production


14



14



3



3



47



46



125



122     (1)
    
    No change to oil wells for the years ended December 31,
    2007 and 2006.(2)
    
    Includes 53.5 net and 55 gross oil wells capable of
    production acquired in Seminole County, Oklahoma in February
    2008. The remainder of the acquired wells were acquired as part
    of the PetroEdge acquisition.  Operations
  General
   22




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Oil
    and Gas Leases
        Gas
    Gathering
  Midstream
    Services Agreement
       23




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and/or
        Appalachian
    Gathering Agreement
         24




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##### Table of Contents



Marketing
    and Major Customers
              Commodity
    Derivative Activities
     25




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Form 10-K.
  Competition
          Title to
    Properties
       26




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Seasonal
    Nature of Business
        Environmental
    Matters and Regulation
  General
    
    require the acquisition of various permits before drilling
    commences;
    enjoin some or all of the operations of facilities deemed in
    non-compliance with permits;
    restrict the types, quantities and concentration of various
    substances that can be released into the environment in
    connection with oil and gas drilling and production activities;
    limit or prohibit drilling activities on certain lands lying
    within wilderness, wetlands, areas inhabited by endangered or
    threatened species, and other protected areas; and
    require remedial measures to mitigate pollution from former and
    ongoing operations, such as requirements to close pits and plug
    abandoned wells.      Waste
    Handling
   27




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Comprehensive
    Environmental Response, Compensation and Liability
    Act
      Water
    Discharges
     28




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##### Table of Contents



Air
    Emissions
         29




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and/or
  Hydrogen
    Sulfide
    National
    Environmental Policy Act
    Endangered
    Species Act
    OSHA
    and Other Laws and Regulation
  and/or
   30




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Other
    Regulation of the Oil and Gas Industry
      Drilling
    and Production
    
    the location of wells;
    the method of drilling and casing wells;
    the surface use and restoration of properties upon which wells
    are drilled;
    the plugging and abandoning of wells; and
    notice to surface owners and other third parties.     31




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State
    Regulation
          Gas
    Marketing
       32




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##### Table of Contents



Sales
    of Natural Gas
    Other
    and/or
    Employees
    Administrative
    Facilities
   33




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Where To
    Find Additional Information
  Form 10-K, Form 10-Q, Form 8-K
 34




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##### Table of Contents



GLOSSARY
    OF SELECTED TERMS
  Form 10-K.
  Appalachian Basin.
  Bbl.
  Bcf.
  Bcfe.
  Btu or British Thermal Unit.
  CBM.
  Cherokee Basin.
  Completion.
  Developed acreage.
  Development well.
  Devonian Sands.
  Dry hole.
  Exploitation.
  Exploratory well.
  Field. and/or
  Frac/fracturing.
  Gas.
  Gathering system.
  Gross acres or gross wells.
  Horizon or formation.
  Marcellus Shale.
 35




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##### Table of Contents



Mcf.
  Mcf/d.
  Mcfe.
  Mmbtu.
  Mmcf.
  Mmcf/d.
  Mmcfe.
  Mmcfe/d.
  Net acres or net wells.
  Net production.
  Net revenue interest.
  NGLs.
  NYMEX.
  Oil.
  Permeability.
  Perforation.
  Productive well.
  Proved developed non-producing
    reserves.
  Proved developed reserves. Rule 4-10(a)(2-4) Regulation S-X.
  Proved reserves. Rule 4-10(a)(2-4) Regulation S-X.
  Proved undeveloped reserves. Rule 4-10(a)(2-4) Regulation S-X.
  Recompletion.
 36




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Reserve.
  Reserve-to-production ratio.
  Reservoir. and/or
  Royalty Interest.
  Shut in.
  Standardized measure.
  Unconventional resource development.
  Undeveloped acreage.
  Working interest.
 37




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##### Table of Contents



ITEM 1A.
    RISK
    FACTORS  Limited
    partner interests are inherently different from capital stock of
    a corporation, although many of the business risks to which we
    are subject are similar to those that would be faced by a
    corporation engaged in similar businesses. The following risk
    factors should be carefully considered together with all of the
    other information included in this report. If any of the
    following risks and uncertainties described below or elsewhere
    in this report were actually to occur, our business, financial
    condition or results of operations could be materially adversely
    affected. In that case, we may not be able to restart paying
    distributions on our common units, the trading price of our
    common units could decline, and unitholders could lose all or
    part of their investment.
  Risks
    Related to Our Business
  Our
    independent registered public accounting firm has expressed
    substantial doubt about our ability to continue as a going
    concern.
    The board of directors of our general partner suspended
    quarterly distributions and we are unable to estimate when
    distributions may be resumed.
    
    the decline in our cash flows from operations due to declines in
    oil and natural gas prices during the last half of 2008,
    the costs of the investigation and associated remedial actions,
    including the reaudit and restatement of our financial
    statements,
    concerns about a potential borrowing base redetermination in the
    second quarter of 2009,
    the need to conserve cash to properly conduct operations and
    maintain strategic options, and
    the need to repay or refinance our term loan by
    September 30, 2009.     38




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We
    have identified significant and pervasive material weaknesses in
    our internal controls, which have and could continue to affect
    our ability to ensure timely and reliable financial reports and
    the ability of our auditors to attest to the effectiveness of
    our internal controls.
    
    We did not maintain an effective control environment. The
    control environment, which is the responsibility of senior
    management, sets the tone of the organization, influences the
    control consciousness of its people, and is the foundation for
    all other components of internal control over financial
    reporting.
    We did not maintain effective monitoring controls to determine
    the adequacy of our internal control over financial reporting
    and related policies and procedures.
    We did not establish and maintain effective controls over
    certain of our period-end financial close and reporting
    processes, including the preparation and review of financial
    statements and schedules and journal entries.
    We did not establish and maintain effective controls to ensure
    the correct application of generally accepted accounting
    principles in the United States of America (GAAP)
    related to derivative instruments.
    We did not establish and maintain effective controls to ensure
    completeness and accuracy of depreciation, depletion and
    amortization expense.
    We did not establish and maintain effective controls to ensure
    the accuracy and application of GAAP related to the
    capitalization of costs related to oil and gas properties and
    the required evaluation of impairment of such costs.
    We did not establish and maintain effective controls to
    adequately segregate the duties over cash management.    Form 10-K.
    Events
    of default are anticipated under our credit agreements, which
    could expose our assets to foreclosure or other collection
    efforts.
   39




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Our
    borrowing base under our First Lien Credit Agreement could be
    redetermined to an amount that creates a deficiency that we do
    not have the ability to pay.
    Our
    credit agreements contain cross default provisions so a default
    under either of our credit agreements can cause a default under
    the other credit agreement, resulting in payment acceleration of
    both loans.
    The
    definitive agreement for Recombination, if entered into, is
    expected to be subject to closing conditions that could result
    in the completion of the Recombination being delayed or not
    consummated, which could lead to liquidation or
    bankruptcy.
    Failure
    to complete the proposed Recombination could negatively impact
    the market price of our common units and our future business and
    financial results because of, among other things, the disruption
    that would occur as a result of uncertainties relating to a
    failure to complete the Recombination.
   40




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
    the diversion of managements attention directed toward the
    Recombination and other affirmative and negative covenants in
    the definitive merger agreement that may restrict our business;
    the failure to pursue other beneficial opportunities as a result
    of managements focus on the Recombination without
    realizing any of the anticipated benefits of the Recombination;
    the market price of our common units may decline to the extent
    that the current market price reflects a market assumption that
    the Recombination will be completed; and
    incurring substantial transaction costs related to the
    Recombination, such as investment banking, legal and accounting
    fees, printing expenses and other related charges that must be
    paid even if the Recombination is not completed.    A
    default by QRCP under its credit agreement could result in a
    change of control of our general partner, which would be an
    event of default under our credit agreements and could adversely
    affect our operating results.
        The
    economic terms of the midstream services agreement may become
    unfavorable to us.
  and/or
 41




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Form 10-K.
  The
    gathering fees payable to Quest Midstream under the midstream
    services agreement in some cases could exceed the amount we are
    able to charge to royalty owners under our gas leases for
    gathering and compression.
  and/or
  The
    current financial crisis and economic conditions may have a
    material adverse impact on our business and financial condition
    that we cannot predict.
      
    our ability to obtain credit and access the capital markets has
    been and may continue to be restricted at a time when we would
    need to raise capital for our business, including for
    exploration or development of our reserves;
    our hedging arrangements could become ineffective if our
    counterparties are unable to perform their obligations or seek
    bankruptcy;
    the values we are able to realize in asset sales or other
    transactions we engage in to raise capital may be reduced, thus
    making these transactions more difficult to consummate and less
    economic; and
    the demand for oil and natural gas may decline due to
    deteriorating economic conditions, which could adversely affect
    our business, financial condition or results of operations.   42




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Energy
    prices are very volatile, and if commodity prices remain low or
    continue to decline for a temporary or prolonged period, our
    revenues, profitability and cash flows will decline. A sustained
    or further decline in oil and natural gas prices may adversely
    affect our business, financial condition or results of
    operations.
    
    the domestic and foreign supply of and demand for oil and
    natural gas;
    the price and level of foreign imports of oil and natural gas;
    the level of consumer product demand;
    weather conditions;
    overall domestic and global economic conditions;
    political and economic conditions in oil and gas producing
    countries, including embargoes and continued hostilities in the
    Middle East and other sustained military campaigns, acts of
    terrorism or sabotage;
    actions of the Organization of Petroleum Exporting Countries and
    other state-controlled oil companies relating to oil price and
    production controls;
    the impact of the U.S. dollar exchange rates on oil and gas
    prices;
    technological advances affecting energy consumption;
    domestic and foreign governmental regulations and taxation;
    the impact of energy conservation efforts;
    the costs, proximity and capacity of gas pipelines and other
    transportation facilities; and
    the price and availability of alternative fuels.      
    negatively impact the value of our reserves because declines in
    oil and natural gas prices would reduce the amount of oil and
    natural gas we can produce economically;
    reduce the amount of cash flow available for capital
    expenditures; and
    limit our ability to borrow money or raise additional capital. 43




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Future
    price declines may result in a write-down of our asset carrying
    values.
    Unless
    we replace the reserves that we produce, our existing reserves
    and production will decline, which would adversely affect our
    cash from operations and have a material adverse effect on our
    financial condition and results of operation.
      If
    QRCP fails to present us with, or successfully competes against
    us for, attractive acquisition opportunities, we may not be able
    to replace or increase our reserves, which would have a material
    adverse effect on our financial condition and results of
    operation.
    
    QRCP chooses to acquire oil and natural gas properties for
    itself instead of allowing us to acquire them;
    the board of directors of our general partner or its conflicts
    committee is unable to agree with QRCP and its affiliates on a
    purchase price or on acceptable purchase terms for QRCPs
    properties that are attractive to all parties; 44




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
    QRCP is unable or unwilling to identify attractive properties
    for us or is unable to negotiate acceptable purchase contracts;
    we are unable to obtain financing for acquisitions on
    economically acceptable terms; or
    we are outbid by competitors.    We
    face the risks of leverage.
      
    our ability to obtain additional debt or equity financing, if
    necessary, for drilling, expansion, working capital and other
    business needs may be impaired or such financing may not be
    available on favorable terms;
    a substantial decrease in our revenues as a result of lower oil
    and natural gas prices, decreased production or other factors
    could make it difficult for us to pay our liabilities or remain
    in compliance with the covenants in our credit agreements. Any
    failure by us to meet these obligations could result in
    litigation, non-performance by contract counterparties or
    bankruptcy;
    our funds available for operations and future business
    opportunities will be reduced by that portion of our cash flow
    required to make interest payments on our debt;
    we may be more vulnerable to competitive pressures or a downturn
    in our business or the economy generally; and
    our flexibility in responding to changing business and economic
    conditions may be limited.  and/or
  The
    credit agreements of our operating subsidiary, Quest Cherokee,
    (to which we are a guarantor) have substantial restrictions and
    financial covenants that may restrict our business and financing
    activities.
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
    incur indebtedness;
    grant liens;
    make certain investments;
    enter into certain hedging agreements;
    create certain lease obligations;
    dispose of property;
    enter into certain types of agreements;
    use the loan proceeds;
    make capital expenditures above specified amounts;
    make distributions to unitholders or repurchase units;
    enter into transactions with affiliates; and
    enter into a merger, consolidation or sale of assets.     46




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Our
    future debt levels may limit our flexibility to obtain
    additional financing and pursue other business
    opportunities.
    
    our ability to obtain additional financing, if necessary, for
    working capital, capital expenditures, acquisition or other
    purposes may be impaired or such financing may not be available
    on favorable terms;
    covenants contained in our existing and future debt arrangements
    will require us to meet financial tests that may affect our
    flexibility in planning for and reacting to changes in our
    business, including possible acquisition opportunities;
    we will need a substantial portion of our cash flow to make
    principal and interest payments on our indebtedness, reducing
    the funds that would otherwise be available for operations,
    future business opportunities and distributions to
    unitholders; and
    our debt level will make us more vulnerable than our competitors
    with less debt to competitive pressures or a downturn in our
    business or the economy generally.  and/or
  An
    increase in interest rates will cause our debt service
    obligations to increase.
    We are
    exposed to trade credit risk in the ordinary course of our
    business activities.
  and/or
  U.S.
    government and internal investigations could affect our results
    of operations.
  Form 10-K,
   47




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There
    is a significant delay between the time we drill and complete a
    CBM well and when the well reaches peak production. As a result,
    there will be a significant lag time between when we expend
    capital expenditures and when we will begin to recognize
    significant cash flow from those expenditures.
  50-55 Mcf/d
  Our
    estimated proved reserves are based on assumptions that may
    prove to be inaccurate. Any material inaccuracies in these
    reserve estimates or underlying assumptions will materially
    affect the quantities and present value of our
    reserves.
    
    a constant level of future oil and gas prices;
    geological conditions;
    production levels;
    capital expenditures;
    operating and development costs;
    the effects of governmental regulations and taxation; and
    availability of funds.        
    the actual prices we receive for oil and gas;
    our actual operating costs in producing oil and gas;
    the amount and timing of actual production; 48




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
    the amount and timing of our capital expenditures;
    supply of and demand for oil and gas; and
    changes in governmental regulations or taxation.  Disclosures about Oil and Gas Producing
    Activities
  Drilling
    for and producing oil and gas is a costly and high-risk activity
    with many uncertainties that could adversely affect our
    financial condition or results of operations, and as a
    result.
    
    high costs, shortages or delivery delays of drilling rigs,
    equipment, labor or other services;
    adverse weather conditions;
    difficulty disposing of water produced as part of the coal bed
    methane production process;
    equipment failures or accidents;
    title problems;
    pipe or cement failures or casing collapses;
    compliance with environmental and other governmental
    requirements;
    environmental hazards, such as gas leaks, oil spills, pipeline
    ruptures and discharges of toxic gases;
    lost or damaged oilfield drilling and service tools;
    loss of drilling fluid circulation;
    unexpected operational events and drilling conditions;
    increased risk of wellbore instability due to horizontal
    drilling;
    unusual or unexpected geological formations;
    natural disasters, such as fires;
    blowouts, surface craterings and explosions; and
    uncontrollable flows of oil, gas or well fluids.   49




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Our
    hedging activities could result in financial losses or reduce
    our income, which may adversely affect our liquidity, financial
    condition and borrowing base.
      
    a counterparty may not perform its obligation under the
    applicable derivative instrument;
    there may be a change in the expected differential between the
    underlying commodity price in the derivative instrument and the
    actual price received; and
    the steps we take to monitor our derivative financial
    instruments may not detect and prevent violations of our risk
    management policies and procedures.  Because
    of our lack of asset and geographic diversification, adverse
    developments in our operating area would adversely affect our
    results of operations.
    We may
    be unable to compete effectively with larger companies, which
    may adversely affect our results of operations.
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We may
    have difficulty managing growth in our business.
    Our
    business involves many hazards and operational risks, some of
    which may not be fully covered by insurance. If a significant
    accident or event occurs that is not fully insured, our
    operations and financial results could be adversely
    affected.
    
    damage to wells, pipelines, related equipment and surrounding
    properties caused by hurricanes, tornadoes, floods, fires and
    other natural disasters and acts of terrorism;
    inadvertent damage from construction, farm and utility equipment;
    leaks of gas or oil spills as a result of the malfunction of
    equipment or facilities;
    fires and explosions; and
    other hazards that could also result in personal injury and loss
    of life, pollution and suspension of operations.     51




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We
    have recently been named a defendant in a number of securities
    class action lawsuits and securityholder derivative lawsuits and
    we are a party to pending litigation arising out of the conduct
    of our business. These, and potential similar or related
    litigation, could result in significant expenses, monetary
    damages, penalties or injunctive relief against
    us.
    We may
    incur significant costs and liabilities in the future resulting
    from a failure to comply with new or existing environmental and
    operational safety regulations or an accidental release of
    hazardous substances into the environment.
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We may
    face unanticipated water disposal costs.
      
    we cannot obtain future permits from applicable regulatory
    agencies;
    water of lesser quality or requiring additional treatment is
    produced;
    our wells produce excess water;
    new laws and regulations require water to be disposed in a
    different manner; or
    costs to transport the produced water to the disposal wells
    increase.  Shortages
    of crews could delay our operations, adversely affect our
    ability to increase our reserves and production.
  and/or
  We
    depend on one customer to purchase our natural
    gas.
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The
    credit and risk profile of QRCP could adversely affect our
    credit ratings and risk profile, which could increase our
    borrowing costs or hinder our ability to raise
    capital.
    Form 10-K and/or
    Certain
    of our undeveloped leasehold acreage is subject to leases that
    may expire in the near future.
    Our
    identified drilling location inventories will be developed over
    several years, making them susceptible to uncertainties that
    could materially alter the occurrence or timing of their
    drilling, which could have an adverse effect on our financial
    condition and results of operation.
    We may
    incur losses as a result of title deficiencies in the properties
    in which we invest.
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We
    depend on a limited number of key management personnel, who
    would be difficult to replace.
    We
    rely on our general partner and Quest Energy Service for our
    management. If our general partner or Quest Energy Service fails
    to or inadequately performs, our costs will increase which will
    reduce our cash from operations and have a material adverse
    effect on our financial condition and results of
    operation.
    Any
    acquisitions we complete are subject to substantial risks that
    could have a material adverse effect on our financial condition
    and results of operation.
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
    mistaken assumptions about reserves, future production, volumes,
    revenues and costs, including synergies;
    an inability to integrate successfully the businesses we acquire;
    a decrease in our liquidity as a result of our using a
    significant portion of our available cash or borrowing capacity
    to finance the acquisition;
    a significant increase in our interest expense or financial
    leverage if we incur additional debt to finance the acquisition;
    the assumption of unknown liabilities for which we are not
    indemnified or for which our indemnity is inadequate;
    an inability to hire, train or retain qualified personnel to
    manage and operate our growing business and assets;
    limitations on rights to indemnity from the seller;
    mistaken assumptions about the overall costs of equity or debt;
    the diversion of managements and employees attention
    from other business concerns;
    the incurrence of other significant charges, such as impairment
    of goodwill or other intangible assets, asset devaluation or
    restructuring charges;
    unforeseen difficulties operating in new product areas or new
    geographic areas; and
    customer or key employee losses at the acquired businesses.      
    geology;
    well economics;
    availability of third party services;
    transportation charges;
    content, quantity and quality of oil and gas produced;
    volume of waste water produced;
    state and local regulations and permit requirements; and
    production, severance, ad valorem and other taxes.   56




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Risks
    Inherent in an Investment in Our Common Units
  We
    currently are not in compliance with NASDAQs continued
    listing requirements, and if our common units are delisted, it
    could negatively impact the price of our common units, our
    ability to access the capital markets and the liquidity of our
    common units.
  Form 10-Q Form 10-Q.
  Form 10-Q
    Our
    unit price may be volatile.
    
    the Recombination and the uncertainty whether it will be
    successful;
    our operating and financial performance and prospects;
    quarterly variations in the rate of growth of our financial
    indicators, such as net income per unit, net income and revenues;
    changes in revenue or earnings estimates or publication of
    research reports by analysts about us or the exploration and
    production industry;
    liquidity and registering our common units for public resale;
    material weaknesses in the control environment;
    actual or anticipated variations in our reserve estimates and
    quarterly operating results;
    changes in oil and natural gas prices;
    speculation in the press or investment community;
    sales of our common units by significant unitholders; 57




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
    short-selling of our common units by investors;
    pending litigation, including securities class action and
    derivative lawsuits;
    issuance of a significant number of units to raise additional
    capital to fund our operations;
    increases in our cost of capital;
    changes in applicable laws or regulations, court rulings and
    enforcement and legal actions;
    changes in market valuations of similar companies;
    adverse market reaction to any increased indebtedness we incur
    in the future;
    additions or departures of key management personnel;
    actions by our unitholders;
    general market conditions, including fluctuations in and the
    occurrence of events or trends affecting the price of oil and
    natural gas; and
    domestic and international economic, legal and regulatory
    factors unrelated to our performance.  Our
    common units are unsecured equity interests.
    QRCP
    controls our general partner, which conducts our business and
    manages our operations. QRCP and its affiliates have conflicts
    of interest with us and limited fiduciary duties to us, which
    may permit them to favor their own interests to your
    detriment.
    
    neither our partnership agreement nor any other agreement
    requires QRCP to pursue a business strategy that favors us.
    QRCPs directors and officers have a fiduciary duty to make
    decisions in the best interests of the owners of QRCP, who
    include public shareholders. These decisions may be contrary to
    our interests;
    our general partner is allowed to take into account the
    interests of parties other than us, such as QRCP, in resolving
    conflicts of interest, which has the effect of limiting its
    fiduciary duty to our unitholders;
    our general partner determines the amount and timing of
    operating expenditures, asset purchases and sales, capital
    expenditures, borrowings, repayments of indebtedness, issuance
    of additional partnership securities and reserves, each of which
    can affect the amount of cash that is distributed to unitholders
    and the general partner, including with respect to its incentive
    distribution rights, and the ability of the subordinated units
    to convert to common units;
    our general partner determines the amount and timing of any
    capital expenditures and whether a capital expenditure is a
    maintenance capital expenditure, which reduces operating
    surplus, or an expansion capital expenditure, which does not
    reduce operating surplus. This determination can affect the
    amount of cash that is distributed to our unitholders;
    subject to the limitations in our omnibus agreement, our general
    partner determines which costs incurred by it and its affiliates
    are reimbursable by us; 58




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
    our general partner has the ability in certain circumstances to
    cause us to borrow funds to pay distributions on its
    subordinated units and incentive distribution rights; and
    our general partner controls the interpretation and enforcement
    of obligations owed to us by our general partner and its
    affiliates, including our omnibus agreement with QRCP, the
    midstream services agreement between us and Quest Midstream and
    Quest Midstreams midstream omnibus agreement with QRCP.  Our
    partnership agreement limits our general partners
    fiduciary duties to unitholders and restricts the remedies
    available to holders of our common units and subordinated units
    for actions taken by our general partner that might otherwise
    constitute breaches of fiduciary duty.
    
    permits our general partner to make a number of decisions either
    in its individual capacity, as opposed to in its capacity as our
    general partner. This entitles our general partner to consider
    only the interests and factors that it desires, and it has no
    duty or obligation to give any consideration to any interest of,
    or factors affecting, us, our affiliates or any limited partner;
    provides that our general partner will not have any liability to
    us or our unitholders for decisions made in its capacity as a
    general partner so long as it acted in good faith, meaning it
    believed the decision was in the best interests of our
    partnership;
    generally provides that affiliated transactions and resolutions
    of conflicts of interest not approved by the conflicts committee
    of the board of directors of our general partner and not
    involving a vote of unitholders must be on terms no less
    favorable to us than those generally being provided to or
    available from unrelated third parties or must be fair and
    reasonable to us, as determined by our general partner in
    good faith and that, in determining whether a transaction or
    resolution is fair and reasonable, our general
    partner may consider the totality of the relationships between
    the parties involved, including other transactions that may be
    particularly advantageous or beneficial to us;
    provides that in resolving conflicts of interest, it will be
    presumed that in making its decision our general partner or its
    conflicts committee acted in good faith, and in any proceeding
    brought by or on behalf of any limited partner or us, the person
    bringing or prosecuting such proceeding will have the burden of
    overcoming such presumption; and
    provides that our general partner and its officers and directors
    will not be liable for monetary damages to us, our limited
    partners or assignees for any acts or omissions, unless there
    has been a final and non-appealable judgment entered by a court
    of competent jurisdiction determining that the general partner
    or those other persons acted in bad faith or engaged in fraud or
    willful misconduct or, in the case of a criminal matter, acted
    with knowledge that the conduct was criminal.    We do
    not have any officers and rely solely on officers of our general
    partner and employees of QRCP and its affiliates for the
    management of our business.
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Unitholders
    have limited voting rights and are not entitled to elect our
    general partner or the directors of our general
    partner.
    Even
    if holders of our common units are dissatisfied, they cannot
    initially remove our general partner without its
    consent.
  2 3
      QRCP
    may engage in competition with us.
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We are
    restricted from engaging in businesses other than the
    exploration and development of oil and gas.
    
    the gathering, treating, processing and transporting of gas in
    North America;
    the transporting and fractionating of gas liquids in North
    America;
    any other midstream activities, including but not limited to
    crude oil storage, transportation, gathering and terminaling;
    constructing, buying or selling any assets related to the
    foregoing businesses; and
    any line of business other than those described in the preceding
    bullet points that generates qualifying income,
    within the meaning of Section 7704(d) of the Internal Revenue
    Code of 1986, as amended, other than any business that is
    primarily engaged in the exploration for and production of oil
    or gas and the sale and marketing of gas and oil derived from
    such exploration and production activities.    Our
    general partner has incentive distribution rights, which may
    incentivize it to cause us to distribute cash needed to develop
    our properties.
    Each
    quarter our general partner is required to deduct estimated
    maintenance capital expenditures from operating surplus, which
    may result in less cash available to unitholders than if actual
    maintenance capital expenditures were deducted.
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Cost
    reimbursements due our general partner and its affiliates for
    services provided, which will be determined by our general
    partner, will be substantial and will reduce our cash available
    for distribution to you.
    Our
    general partners interest in us and control of our general
    partner may be transferred to a third party without unitholder
    consent.
    We may
    issue additional units, including units that are senior to the
    common units, without approval of our unitholders, which would
    dilute the existing ownership interests of our
    unitholders.
    
    our unitholders proportionate ownership interest in us
    will decrease;
    the amount of cash available for distribution on each unit may
    decrease;
    because a lower percentage of total outstanding units will be
    subordinated units, the risks that a shortfall in the payment of
    the minimum quarterly distribution will be borne by our common
    unitholders will increase;
    the ratio of taxable income to distributions may increase;
    the relative voting strength of each previously outstanding unit
    may be diminished; and
    the market price of the common units may decline.  Our
    general partner may elect to cause us to issue Class B
    units to it in connection with a resetting of the target
    distribution levels related to our general partners
    incentive distribution rights without the approval of the
    conflicts committee of our general partner or holders of our
    common units and subordinated units. This may result in lower
    distributions to holders of our common units in certain
    situations.
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Our
    partnership agreement restricts the voting rights of unitholders
    owning 20% or more of our common units.
    The
    NASDAQ Global Market does not require a listed limited
    partnership like us to comply with some of its listing
    requirements with respect to corporate governance
    requirements.
    Our
    general partner has a limited call right that may require you to
    sell your units at an undesirable time or price.
    The
    liability of our unitholders may not be limited if a court finds
    that unitholder action constitutes control of our
    business.
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
    we were conducting business in a state but had not complied with
    that particular states partnership statute; or
    a unitholders right to act with other unitholders to
    remove or replace the general partner, to approve some
    amendments to our partnership agreement or to take other actions
    under our partnership agreement constitute control
    of our business.  Unitholders
    may have liability to repay distributions.
  Sections 17-607 17-804
  Common
    units held by persons who are not Eligible Holders will be
    subject to the possibility of redemption.
    An
    increase in interest rates may cause the market price of our
    common units to decline.
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Tax Risks
    to Common Unitholders
  Our
    tax treatment depends on our status as a partnership for federal
    income tax purposes, as well as our not being subject to a
    material amount of entity-level taxation by individual states.
    If the IRS were to treat us as a corporation or if we were to
    become subject to a material amount of entity-level taxation for
    state tax purposes, then our cash available for distribution to
    unitholders would be substantially reduced.
        We
    prorate our items of income, gain, loss and deduction between
    transferors and transferees of our units each month based upon
    the ownership of our units on the first day of each month,
    instead of on the basis of the date a particular unit is
    transferred. The IRS may challenge this treatment, which could
    change the allocation of items of income, gain, loss and
    deduction among our unitholders.
    Our
    unitholders may be required to pay taxes on their share of our
    income even if they do not receive any cash distributions from
    us.
   65




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##### Table of Contents



If the
    IRS contests the federal income tax positions we take, the
    market for our common units may be adversely affected, and the
    cost of any contest will reduce our cash available for
    distribution to unitholders.
    Tax
    gain or loss on disposition of our common units could be more or
    less than expected.
    Tax-exempt
    entities and foreign persons face unique tax issues from owning
    our common units that may result in adverse tax consequences to
    them.
  non-U.S. persons non-U.S. persons non-U.S. persons
  We
    will treat each purchaser of our common units as having the same
    tax benefits without regard to the actual common units
    purchased. The IRS may challenge this treatment, which could
    adversely affect the value of the common units.
    The
    sale or exchange of 50% or more of our capital and profits
    interests during any twelve-month period will result in the
    termination of our partnership for federal income tax
    purposes.
  Schedule K-1s)
 66




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##### Table of Contents



We may
    adopt certain valuation methodologies that may result in a shift
    of income, gain, loss and deduction between the holders of
    incentive distribution rights and the unitholders. The IRS may
    challenge this treatment, which could adversely affect the value
    of our common units.
      Unitholders
    likely will be subject to state and local taxes and return
    filing requirements.
    A
    unitholder whose units are loaned to a short seller
    to cover a short sale of units may be considered as having
    disposed of those units. If so, he would no longer be treated
    for tax purposes as a partner with respect to those units during
    the period of the loan and may recognize gain or loss from the
    disposition.
   67




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##### Table of Contents



ITEM 1B.
    UNRESOLVED
    STAFF COMMENTS.    ITEM 3.
    LEGAL
    PROCEEDINGS.    Federal
    Securities Class Actions
  Michael Friedman, individually and on behalf of all others
    similarly situated v. Quest Energy Partners LP, Quest
    Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
    E. Grose, Case
    No. 08-cv-936-M
    U.S., District Court for the Western District of Oklahoma, filed
    September 5, 2008
  James Jents, individually and on behalf of all others
    similarly situated v. Quest Resource Corporation,
    Jerry Cash, David E. Grose, and John Garrison, Case
    No. 08-cv-968-M,
    U.S. District Court for the Western District of Oklahoma,
    filed September 12, 2008
  J. Braxton Kyzer and Bapui Rao, individually and on
    behalf of all others similarly situated v. Quest Energy
    Partners LP, Quest Energy GP LLC, Quest Resource Corporation and
    David E. Grose, Case
    No. 08-cv-1066-M,
    U.S. District Court for the Western District of Oklahoma,
    filed October 6, 2008
  Paul Rosen, individually and on behalf of all others
    similarly situated v. Quest Energy Partners LP, Quest
    Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
    E. Grose, Case
    No. 08-cv-978-M,
    U.S. District Court for the Western District of Oklahoma,
    filed September 17, 2008
  Rule 10b-5 and/or Michael Friedman,
    individually and on behalf of all others similarly
    situated v. Quest Energy Partners LP, Quest Energy GP LLC,
    Quest Resource Corporation, Jerry Cash, and David E. Grose No. 08-cv-936-M,
 68




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##### Table of Contents



Royalty
    Owner Class Action
  Hugo Spieker, et al. v. Quest Cherokee, LLCCase
    No. 07-1225-MLB
    in the U.S. District Court, District of Kansas, filed
    August 6, 2007
    Personal
    Injury Litigation
  Segundo Francisco Trigoso and Dana Jara De Trigoso v.
    Quest Cherokee Oilfield Service, LLC,CJ-2007-11079,
    in the District Court of Oklahoma County, State of Oklahoma,
    filed December 27, 2007
    St. Paul Surplus Lines Insurance Company v.
    Quest Cherokee Oilfield Service, LLC, et al, CJ-2009-1078, in the District Court of Tulsa County, State of
    Oklahoma, filed February 11, 2009
  Trigoso Trigoso
  Billy Bob Willis, et al. v. Quest Resource
    Corporation, et al.,Case
    No. CJ-09-00063,
    District Court of Nowata County, State of Oklahoma, filed
    April 28, 2009
    Berenice Urias v. Quest Cherokee, LLC, et al.,
    CV-2008-238C in the Fifth Judicial District, County of Lea,
    State of New Mexico (Second Amended Complaint filed
    September 24, 2008)
    Juana Huerter v. Quest Cherokee Oilfield Services,
    LLC, et al.,Case No. 2008 CV-50, District Court of
    Neosho County, State of Kansas, filed May 5, 2008
  et al.
  Bradley Haviland, Jr., v. Quest Cherokee
    Oilfield Services, LLC, et al.,Case No. 2008 CV-78,
    District Court of Neosho County, State of Kansas, filed
    July 25, 2008
  et al.
 69




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##### Table of Contents



Litigation
    Related to Oil and Gas Leases
    Roger Dean Daniels v. Quest Cherokee, LLC,Case
    No. 06-CV-61,
    in the District Court of Montgomery County, State of Kansas,
    filed May 5, 2006
  Carol R. Knisely, et al. v. Quest Cherokee, LLC,Case
    No. 07-CV-58-I,
    in the District Court of Montgomery County, State of Kansas,
    filed April 16, 2007
  Quest Cherokee, LLC v. David W. Hinkle, et al.,Case
    No. 2006-CV-74,
    in the District Court of Labette County, State of Kansas, filed
    September 5, 2006
  Scott Tomlinson, et al. v. Quest Cherokee, LLC,Case
    No. 2007-CV-45,
    in the District Court of Wilson County, State of Kansas, filed
    August 29, 2007
  Ilene T. Bussman et al. v. Quest Cherokee, LLC,Case
    No. 07-CV-106-PA,
    in the District Court of Labette County, State of Kansas, filed
    November 26, 2007
  Gary Dale Palmer, et al. v. Quest Cherokee, LLC,Case
    No. 07-CV-107-PA,
    in the District Court of Labette County, State of Kansas, filed
    November 26, 2007
  Richard L. Bradford, et al. v. Quest Cherokee, LLC,Case
    No. 2008-CV-67,
    in the District Court of Wilson County, Kansas, filed
    September 18, 2008
    Richard Winder v. Quest Cherokee, LLC,Case Nos.
    07-CV-141 and 08-CV-20, in the District Court of Wilson County,
    Kansas, filed December 7, 2007, and February 27,
    2008
  Housel v. Quest Cherokee, LLC, 06-CV-26-I, in the
    District Court of Montgomery County, State of Kansas, filed
    March 2, 2006
  and/or
  Central Natural Resources, Inc. v. Quest Cherokee,
    LLC, et al.,Case
    No. 04-C-100-PA
    in the District Court of Labette County, State of Kansas, filed
    on September 1, 2004
   70




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##### Table of Contents



Central Natural Resources, Inc. v. Quest Cherokee,
    LLC, et al., Case
    No. CJ-06-07
    in the District Court of Craig County, State of Oklahoma, filed
    January 17, 2006
    Edward E. Birk, et ux., and Brian L. Birk, et ux., v.
    Quest Cherokee, LLC, Case
    No. 09-CV-27,
    in the District Court of Neosho County, State of Kansas, filed
    April 23, 2009
  and/or
  Robert C. Aker, et al. v. Quest Cherokee, LLC, et al.,U.S. District Court for the Western District of
    Pennsylvania, Case
    No. 3-09CV101,
    filed April 16, 2009
    Other
  Well Refined Drilling Co. v. Quest Cherokee, LLC,Case
    No. 2007-CV-91,
    in the District Court of Neosho County, State of Kansas, filed
    July 19, 2007; and Well Refined Drilling Co. v.
    Quest Cherokee, LLC,Case
    No. 2007-CV-46,
    in the District Court of Wilson County, State of Kansas, filed
    September 4, 2007
   71




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##### Table of Contents



Neosho Natural, LLC, Jeffrey D. Kephart and Randall L.
    Cox v. Quest Cherokee, LLC,Case
    No. 2008-CV-23,
    in the District Court of Neosho County, State of Kansas, filed
    March 7, 2008.
  Well Refined Drilling
  Barbara Cox v. Quest Cherokee, LLC,
    U.S. District Court for the District of New Mexico, Case
    No. CIV-08-0546,
    filed April 18, 2008
    Larry Reitz, et al. v. Quest Resource Corporation, et al.,Case
    No. CJ-09-00076,
    District Court of Nowata County, State of Oklahoma, filed
    May 15, 2009
    Quest Resource Corporation, et al. v. David E. Grose, et
    al.,Case No. CJ-2009-2078, in the District Court of
    Oklahoma County, State of Oklahoma, filed March 3, 2009
  et al.
  ITEM 4.
    SUBMISSION
    OF MATTERS TO A VOTE OF SECURITY HOLDERS.   72




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##### Table of Contents



PART II  ITEM 5.
    MARKET
    FOR REGISTRANTS COMMON EQUITY, RELATED UNITHOLDER MATTERS
    AND ISSUER PURCHASES OF EQUITY SECURITIES.  Market
    Information
    Price Range


Cash DistributionFiscal Quarter and Period Ended

High Price


Low Price


per Common UnitDecember 31, 2008

$
6.84


$
1.87


$
0September 30, 2008

$
16.97


$
6.32


$
0.4000June 30, 2008

$
17.04


$
14.04


$
0.4300March 31, 2008

$
16.15


$
13.71


$
0.4100December 31, 2007

$
16.50


$
14.18


$
0.2043
(a)     (a)
    
    On January 21, 2008, the board of directors of our general
    partner declared a cash distribution for the fourth quarter of
    2007. The distribution was based on an initial quarterly
    distribution of $0.40 per unit, prorated for the period from and
    including November 15, 2007, the closing date of our
    initial public offering, through December 31, 2007. The
    distribution was paid on February 14, 2008 to unitholders
    of record at the close of business on February 7, 2008.  Record
    Holders
    Cash
    Distributions to Unitholders
       73




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##### Table of Contents




    less the amount of cash reserves established by our general
    partner to:  
    provide for the proper conduct of our business, including
    reserves for future capital expenditures and our anticipated
    future credit needs;
    comply with applicable law, any of our debt instruments or other
    agreements; or
    provide funds for distributions to our unitholders and to our
    general partner for any one or more of the next four quarters;  
    plus, all additional cash and cash equivalents on hand on the
    date of determination of available cash for the quarter
    resulting from working capital borrowings made after the end of
    the quarter. Working capital borrowings are generally borrowings
    that are made under a credit facility, commercial paper facility
    or similar financing arrangement, and in all cases are used
    solely for working capital purposes or to pay distributions to
    partners and with the intent of the borrower to repay such
    borrowings within 12 months other than from additional
    working capital borrowings.        
    distributions of available cash from operating surplus on each
    of the outstanding common units, subordinated units and general
    partner units equaled or exceeded the minimum quarterly
    distribution for each of the three consecutive, non-overlapping
    four-quarter periods immediately preceding that date;
    the adjusted operating surplus (as defined in our partnership
    agreement) generated during each of the three consecutive,
    non-overlapping four-quarter periods immediately preceding that
    date equaled or exceeded the sum of the minimum quarterly
    distributions on all of the outstanding common units,
    subordinated units and general partner units during those
    periods on a fully diluted basis; and
    there are no arrearages in payment of the minimum quarterly
    distribution on the common units.    
    the subordination period will end and each subordinated unit
    will immediately convert into one common unit; 74




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##### Table of Contents




    any existing arrearages in payment of the minimum quarterly
    distribution on the common units will be extinguished; and
    the general partner will have the right to convert its general
    partner interest and its incentive distribution rights into
    common units or to receive cash in exchange for those interests.      
    distributions of available cash from operating surplus on each
    outstanding common unit, subordinated unit and the 2% general
    partner interest equaled or exceeded $2.00 (125% of the
    annualized minimum quarterly distribution) for each of the two
    consecutive, non-overlapping four-quarter periods immediately
    preceding that date;
    the adjusted operating surplus generated during each of the two
    consecutive, non-overlapping four-quarter periods immediately
    preceding that date equaled or exceeded the sum of a
    distribution of $2.00 per common unit (125% of the annualized
    minimum quarterly distribution) on all of the outstanding common
    and subordinated units and the 2% general partner interest
    during those periods on a fully diluted basis; and
    there are no arrearages in payment of the minimum quarterly
    distribution on the common units.    
    first, 98% to the common unitholders, pro rata, and 2% to the
    general partner, until we distribute for each outstanding common
    unit an amount equal to the minimum quarterly distribution for
    that quarter;
    second, 98% to the common unitholders, pro rata, and 2% to the
    general partner, until we distribute for each outstanding common
    unit an amount equal to any arrearages in payment of the minimum
    quarterly distribution on the common units for any prior
    quarters during the subordination period;
    third, 98% to the subordinated unitholders, pro rata, and 2% to
    the general partner, until we distribute for each subordinated
    unit an amount equal to the minimum quarterly distribution for
    that quarter; and
    thereafter, cash in excess of the minimum quarterly
    distributions is distributed to the unitholders and the general
    partner based on the percentages below (which results in our
    general partner receiving incentive distributions if the amount
    we distribute with respect to one quarter exceeds specified
    target levels shown below):  Marginal PercentageTotal Quarterly

Interest inDistributions Target

DistributionsAmount

Limited Partner


General PartnerMinimum quarterly distribution

$0.40


98
%


2
%First target distribution

Up to $0.46
    Above $0.46, up to


98
%


2
%Second target distribution

$0.50


85
%


15
%Thereafter

Above $0.50


75
%


25
%   Recent
    Sales of Unregistered Securities
    Purchases
    of Equity Securities
   75




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##### Table of Contents



ITEM 6.
    SELECTED
    FINANCIAL DATA.    Successor


PredecessorNovember 15,


January 1,





7 MonthsYear Ended


2007 to


2007 to


Year Ended


Ended


Fiscal YearDecember 31,


December 31,


November 14,


December 31,


December 31,


Ended May 31,2008


2007


2007


2006


2005


2004


2004(Consolidated)


(Restated)


(Restated)


(Restated)


(Restated)


(Unaudited)


(Unaudited)(Consolidated)


(Carve out)


(Carve out)


(Carve out)


(Restated)


(Restated)(Carve out)


(Carve out)($ in thousands, except per unit data)Statement of Operations Data:Revenues:Oil and gas sales

$
147,930


$
15,348


$
89,937


$
72,410


$
70,628


$
28,593


$
2,560Costs and expenses:Oil and gas production


43,490



3,970



31,436



24,886



19,152



5,571Transportation expense


35,546



4,342



24,837



17,278



7,038



3,196General and administrative


13,647



2,872



11,040



7,853



5,353



2,365



370Depreciation, depletion and amortization


50,988



5,045



29,568



24,760



19,037



6,738



(2,162
)Impairment of oil and gas properties


245,587























Misappropriation of funds










1,500



6,000



2,000







Loss on early extinguishment of debt


















8,255



1,834



Total costs and expenses


389,258



16,229



98,381



80,777



60,835



19,704



(1,792
)Operating income (loss)


(241,328
)


(881
)


(8,444
)


(8,367
)


9,793



8,889



4,352Other income (expense):Gain (loss) from derivative financial instruments


80,707



(4,583
)


6,544



52,690



(73,566
)


(6,085
)


(17,775
)Other income (expense)


301



4



(355
)


(90
)


399



37



Interest expense, net


(13,612
)


(13,746
)


(26,919
)


(15,100
)


(21,933
)


(9,233
)


(332
)Total other income and (expense)


67,396



(18,325
)


(20,730
)


37,500



(95,100
)


(15,281
)


(18,107
)Net income (loss)

$
(173,932
)

$
(19,206
)

$
(29,174
)

$
29,133


$
(85,307
)

$
(6,392
)

$
(13,755
) 76




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##### Table of Contents



Successor


PredecessorNovember 15,


January 1,





7 MonthsYear Ended


2007 to


2007 to


Year Ended


Ended


Fiscal YearDecember 31,


December 31,


November 14,


December 31,


December 31,


Ended May 31,2008


2007


2007


2006


2005


2004


2004(Consolidated)


(Restated)


(Restated)


(Restated)


(Restated)


(Unaudited)


(Unaudited)(Consolidated)


(Carve out)


(Carve out)


(Carve out)


(Restated)


(Restated)(Carve out)


(Carve out)($ in thousands, except per unit data)General partners interest in net (loss)

$
(3,479
)

$
(384
)


*



*



*



*



*Limited partners interest in net (loss)

$
(170,453
)

$
(18,822
)


*



*



*



*



*Net income (loss) per limited partner unit:

$
(8.05
)

$
(0.89
)


*



*



*



*



*Weighted average limited partner units:Common


12,309,432



12,301,521



*



*



*



*



*Subordinated


8,857,981



8,857,981



*



*



*



*



*Cash distribution per unit:Common

$
1.44


$




*



*



*



*



*Subordinated

$
1.04


$




*



*



*



*



*General partner

$
1.44


$




*



*



*



*



*Balance Sheet Data (at end of period):Total assets

$
278,221


$
351,577



*


$
314,673


$
195,618


$
177,646


$
(191
)Long-term debt, net of current maturities

$
189,090


$
94,042



*


$
225,245


$
75,889


$
101,616


$
     *
    
    Not applicable    ITEM 7.
    MANAGEMENTS
    DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
    OPERATIONS.  Restatement
  Form 10-K Form 10-K
  Form 10-K,
 77




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##### Table of Contents



Overview
           
    Cherokee Basin.  152.7 Bcfe of estimated
    net proved reserves as of December 31, 2008 and an average
    net daily production of 57.3 Mmcfe for the year ended
    December 31, 2008 in the Cherokee Basin;
    Appalachian Basin.  10.9 Bcfe of estimated
    net proved reserves as of December 31, 2008 and an average
    net daily production of 2.9 Mmcfe for the year ended
    December 31, 2008 predominantly in the Marcellus Shale and
    Devonian Sand formations in West Virginia and New York; and
    Seminole County.  588,800 Bbls of
    estimated net proved reserves as of December 31, 2008 and
    an average net daily production of approximately 148 Bbls
    for the year ended December 31, 2008 of oil producing
    properties in Seminole County, Oklahoma.  Recent
    Developments
    PetroEdge
    Acquisition
   78




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##### Table of Contents



Internal
    Investigation; Restatements and Reaudits
    and/or
    
    We had costs associated with the internal investigation and our
    responding to inquiries from the Oklahoma Department of
    Securities, the Federal Bureau of Investigation, the Department
    of Justice, the SEC and the IRS.
    As a result of the resignation of Jerry D. Cash and the
    termination of David E. Grose, consultants were immediately
    retained to perform the accounting and finance functions and to
    assist in the determination of the intercompany debt discussed
    under Items 1 and 2. Business and
    Properties  Recent Developments 
    Intercompany Accounts.
    We retained law firms to respond to the class action and
    derivative suits that have been filed against us, our general
    partner and QRCP and to pursue the claims against the former
    employees.
    We had costs associated with amending our credit agreements and
    obtaining the necessary waivers from our lenders thereunder as
    well as incremental increased interest expense related thereto.
    See  Liquidity and Capital Resources.
    We retained new external auditors, who completed reaudits of our
    restated consolidated financial statements as of
    December 31, 2007 and for the period from November 15,
    2007 to December 31, 2007 and of the Predecessors
    consolidated financial statements as of and for the years ended
    December 31, 2005 and 2006, and for the period from
    January 1, 2007 to November 14, 2007.
    We retained financial advisors to consider strategic options and
    retained outside legal counsel or increased the amount of work
    being performed by our previously engaged outside legal counsel.    Global
    Financial Crisis and Impact on Capital Markets and Commodity
    Prices
   79




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##### Table of Contents



Credit
    Agreement Amendments
  and/or
    Suspension
    of Distributions
    
    the decline in our cash flows from operations due to declines in
    oil and natural gas prices during the last half of 2008,
    the costs of the investigation and associated remedial actions,
    including the reaudit and restatement of our financial
    statements,
    concerns about a potential borrowing base redetermination in the
    second quarter of 2009, 80




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##### Table of Contents




    the need to conserve cash to properly conduct operations and
    maintain strategic options, and
    the need to repay or refinance our term loan by
    September 30, 2009.      Decrease
    in Year-End Reserves; Impairment
      Settlement
    Agreements
    Outlook
    for 2009; Recombination
  and/or
 81




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##### Table of Contents



Cherokee Basin.
    Appalachian Basin.
  Capital Expenditures for 2009.
    
    the domestic and foreign supply of oil and gas;
    the price and quantity of imports of foreign oil and natural gas;
    overall domestic and global economic conditions;
    the consumption pattern of industrial consumers, electricity
    generators and residential users;
    weather conditions;
    the level of domestic oil and natural gas inventories;
    technological advances affecting energy consumption;
    domestic and foreign governmental regulations;
    proximity and capacity of oil and gas pipelines and other
    transportation facilities; and
    the price and availability of alternative fuels.    Factors
    That Significantly Affect Comparability of Our Results
    Outstanding Indebtedness.
  Midstream Services Agreement.
 82




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##### Table of Contents



Results
    of Operations
    Year
    ended December 31, 2008 compared to the year ended
    December 31, 2007
    Overview.
  Year EndedDecember 31,


Increase/2008


2007**


(Decrease)($ in thousands)Oil and gas sales

$
147,930


$
105,285


$
42,645



40.5
%Oil and gas production costs

$
43,490


$
35,406


$
8,084



22.8
%Transportation expense

$
35,546


$
29,179


$
6,367



21.8
%Depreciation, depletion and amortization

$
50,988


$
34,613


$
16,375



47.3
%General and administrative expenses

$
13,647


$
13,912


$
(265
)


(1.9
)%Gain from derivative financial instruments

$
80,707


$
1,961


$
78,746



4,015.6
%Impairment of oil and gas properties

$
245,587


$



$
245,587



*Misappropriation of funds

$



$
1,500


$
(1,500
)


(100
)%Interest expense, net

$
13,612


$
40,665


$
(27,053
)


(66.5
)%     *
    
    Not meaningful**
    
    2007 amounts represent combined predecessor and successor. 83




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##### Table of Contents



Production.
  Year EndedDecember 31,


Increase/2008


2007*


(Decrease)Production Data:Total production (Mmcfe)


21,747



17,017



4,730



27.8
%Average daily production (Mmcfe/d)


59.6



46.6



13.0



27.9
%Average Sales Price per Unit (Mcfe):Excluding hedges

$
6.83


$
6.19


$
0.64



10.3
%Average Unit Costs per Mcfe:Production costs

$
2.00


$
2.08


$
(0.08
)


(3.8
)%Transportation expense

$
1.63


$
1.71


$
(0.08
)


(4.7
)%Depreciation, depletion and amortization

$
2.34


$
2.03


$
0.31



15.3
%     *
    
    2007 amounts represent combined predecessor and successor.  Oil and Gas Sales.
  Oil and Gas Operating Expenses.
      Depreciation, Depletion and Amortization.
  General and Administrative Expense.
 84




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##### Table of Contents



Gain from Derivative Financial
    Instruments.
  Impairment of Oil and Gas Properties.
  Misappropriation of Funds.
  Interest Expense, net.
  Year
    ended December 31, 2007 compared to the year ended
    December 31, 2006
    Overview.
  Year EndedDecember 31,


Increase/2007*


2006


(Decrease)($ in thousands)Oil and gas sales

$
105,285


$
72,410


$
32,875



45.4
%Oil and gas production costs

$
35,406


$
24,886


$
10,520



42.3
%Transportation expense

$
29,179


$
17,278


$
11,901



68.9
%Depreciation, depletion and amortization

$
34,613


$
24,760


$
9,853



39.8
%General and administrative expenses

$
13,912


$
7,853


$
6,059



77.2
%Gain from derivative financial instruments

$
1,961


$
52,690


$
(50,729
)


(96.3
)%Misappropriation of funds

$
1,500


$
6,000


$
(4,500
)


(75.0
)%Interest expense, net

$
40,665


$
15,100


$
25,565



169.3
%     *
    
    2007 amounts represent combined predecessor and successor. 85




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##### Table of Contents



Production.
  Year EndedDecember 31,


Increase/2007*


2006


(Decrease)Production Data:Total production (Mmcfe)


17,017



12,364



4,653



37.6
%Average daily production (Mmcfe/d)


46.6



33.9



12.7



37.5
%Average Sales Price per Unit (Mcfe):Excluding hedges

$
6.19


$
5.86


$
0.33



5.6
%Average Unit Costs per Mcfe:Production costs

$
2.08


$
2.01


$
0.07



3.5
%Transportation expense

$
1.71


$
1.40


$
0.31



22.1
%Depreciation, depletion and amortization

$
2.03


$
2.00


$
0.03



1.5
%     *
    
    2007 amounts represent combined predecessor and successor.  Oil and Gas Sales.
  Oil and Gas Operating Expenses.
      Depreciation, Depletion and Amortization.
  General and Administrative Expenses.
 86




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##### Table of Contents



Gain from Derivative Financial
    Instruments.
  Misappropriation of Funds.
  Interest Expense, net.
  Year
    ended December 31, 2006 compared to the year ended
    December 31, 2005
  Overview.
  Year EndedDecember 31,


Increase/2006


2005


(Decrease)($ in thousands)Oil and gas sales

$
72,410


$
70,628


$
1,782



2.5
%Oil and gas production costs

$
24,886


$
19,152


$
5,734



29.9
%Transportation expense

$
17,278


$
7,038


$
10,240



145.5
%Depreciation, depletion and amortization

$
24,760


$
19,037


$
5,723



30.1
%General and administrative expense

$
7,853


$
5,353


$
2,500



46.7
%Loss on extinguishment of debt





$
8,255


$
(8,255
)


(100
)%Gain (loss) from derivative financial instruments

$
52,690


$
(73,566
)

$
126,256



171.6
%Misappropriation of funds

$
6,000


$
2,000


$
4,000



200.0
%Interest expense, net

$
15,100


$
21,933


$
(6,833
)


(31.2
)%  87




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##### Table of Contents



Production.
  Year EndedDecember 31,


Increase/2006


2005


(Decrease)Production Data:Total production (Mmcfe)


12,364



9,629



2,735



28.4
%Average daily production (Mmcfe/d)


33.9



26.4



7.5



28.4
%Average Sales Price per Unit (Mcfe):Excluding hedges

$
5.86


$
7.33


$
(1.47
)


(20.1
)%Average Unit Costs per Mcfe:Production costs

$
2.01


$
1.99


$
0.02



1.0
%Transportation expense

$
1.40


$
0.73


$
0.67



91.8
%Depreciation, depletion and amortization

$
2.00


$
1.98


$
0.02



1.0
%   Oil and Gas Sales.
  Oil and Gas Operating Expenses.
      Depreciation, Depletion and Amortization.
  General and Administrative Expenses.
 88




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##### Table of Contents



Loss on Extinguishment of Debt.
  Gain (loss) from Derivative Financial
    Instruments.
  Misappropriation of Funds.
  Interest Expense.
  Liquidity
    and Capital Resources
  Liquidity
          Historical
    Cash Flows and Liquidity
  Cash Flows from Operating Activities.
 89




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##### Table of Contents



Cash Flows Used in Investing Activities.
  Year Ended December 31,2008


2007(In thousands)Capital expenditures:Leasehold acquisition

$
9,860


$
13,345Development


50,609



67,197Acquisition of PetroEdge assets


71,213



Acquisition of Seminole County, Oklahoma property


9,500



Other items (primarily capitalized overhead and interest)


14,204



15,663Total capital expenditures

$
155,386


$
96,205   Cash Flows from Financing Activities.
  Working Capital.
  Credit
    Agreements
   90




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##### Table of Contents



and/or and/or
       91




---



##### Table of Contents



pari passu
      
    permitting the ratio (calculated based on the most recently
    delivered compliance certificate) of our consolidated current
    assets (including the unused availability under the revolving
    credit facility, but excluding non-cash assets under
    FAS 133) to consolidated current liabilities
    (excluding non-cash obligations under FAS 133, asset and
    asset retirement obligations and current maturities of
    indebtedness under the First Lien Credit Agreement) at any
    fiscal quarter-end to be less than 1.0 to 1.0; provided,
    however, that current assets and current liabilities will
    exclude mark-to-market values of swap contracts, to the extent
    such values are included in current assets and current
    liabilities;
    permitting the interest coverage ratio (calculated on the most
    recently delivered compliance certificate) of adjusted
    consolidated EBITDA to consolidated interest charges at any
    fiscal quarter-end to be less than 2.5 to 1.0 measured on a
    rolling four quarter basis; and
    permitting the leverage ratio (calculated based on the most
    recently delivered compliance certificate) of consolidated
    funded debt to adjusted consolidated EBITDA at any fiscal
    quarter-end to be greater than 3.5 to 1.0 measured on a rolling
    four quarter basis.     92




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##### Table of Contents



and/or
        30-day
  Sources
    of Liquidity in 2009 and Capital Requirements
    Form 10-K,
 93




---



##### Table of Contents



and/or
     94




---



##### Table of Contents



Contractual
    Obligations
    Payments Due by PeriodLess Than


1-3


4-5


More ThanTotal


1 Year


Years


Years


5 Years(In thousands)First Lien Credit Agreement

$
189,000


$



$
189,000


$



$
Second Lien Loan Agreement


41,200



41,200











Other note obligations


772



682



76



14



Interest expense on credit agreements(1)


17,326



10,167



7,159







Operating lease obligations


696



174



296



226



Total commitments

$
248,994


$
52,223


$
196,531


$
240


$
     (1)
    
    The interest payment obligation was computed using the LIBOR
    interest rate as of December 31, 2008. Assumes no reduction
    in the outstanding principal amount borrowed under the First
    Lien Credit Agreement prior to maturity.    Off-balance
    Sheet Arrangements
    Critical
    Accounting Policies
  Form 10-K.
  Oil
    and Gas Reserves
   95




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12-month Form 10-K
  Oil
    and Gas Properties
       96




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##### Table of Contents



Accounting for Asset Retirement
    Obligations
  Unevaluated
    Properties
    Future
    Abandonment Costs
      Derivative
    Instruments
  Derivative Instruments and Hedging
    Activities
 97




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##### Table of Contents



Revenue
    Recognition
      Recent
    Accounting Pronouncements
  No. 07-4, Application of the Two-Class Method under FASB Statement
    No. 128, Earnings per Share, to Master Limited
    Partnerships No. 07-4
  FAS 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2). FSP 157-2 FSP 157-2
  FAS 157-3, Determining the Fair Value of a Financial Asset When the
    Market for That Asset is Not Active (FSP 157-3) FSP 157-3 FSP 157-3
    Business Combinations
  Disclosures about Derivative Instruments and Hedging
    Activities-an amendment of FASB Statement No. 133
 98




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##### Table of Contents



No. 33-8995, Modernization of Oil and Gas Reporting Form 10-K Form 10-K
  Forward-Looking
    Statements
      
    current financial instability and deteriorating economic
    conditions;
    our current financial instability;
    volatility of oil and gas prices;
    completion of the Recombination;
    increases in the cost of drilling, completion and gas gathering
    or other costs of developing and producing our reserves;
    our restrictive debt covenants;
    results of our hedging activities;
    developments in oil and gas producing countries;
    the impact of weather and the occurrence of natural disasters
    such as fires;
    competition in the oil and gas industry;
    availability of drilling and production equipment, labor and
    other services; 99




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##### Table of Contents




    drilling, operational and environmental risks; and
    regulatory changes and litigation risks.      ITEM 7A.
    QUANTITATIVE
    AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.  Quantitative
    and Qualitative Disclosures about Market Risk
    Commodity
    Price Risk
         100




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##### Table of Contents



2008


2007


2006Realized gains (losses)

$
8,174


$
7,279


$
(17,712
)Unrealized gains (losses)


72,533



(5,318
)


70,402Total

$
80,707


$
1,961


$
52,690     Year Ending December 31,2009


2010


2011


Thereafter


Total($ in thousands, except volumes and per unit data)Natural Gas Swaps:Contract volumes (Mmbtu)


14,629,200



12,499,060



2,000,004



2,000,004



31,128,268Weighted-average fixed price per Mmbtu(1)

$
7.78


$
7.42


$
8.00


$
8.11


$
7.67Fair value, net

$
38,107


$
14,071


$
2,441


$
2,335


$
56,954Natural Gas Collars:Contract volumes (Mmbtu):Floor


750,000



630,000



3,549,996



3,000,000



7,929,996Ceiling


750,000



630,000



3,549,996



3,000,000



7,929,996Weighted-average fixed price per Mmbtu(1):Floor

$
11.00


$
10.00


$
7.39


$
7.03


$
7.79Ceiling

$
15.00


$
13.11


$
9.88


$
7.39


$
9.52Fair value, net

$
3,630


$
1,875


$
3,144


$
2,074


$
10,723Total Natural Gas Contracts:Contract volumes (Mmbtu)


15,379,200



13,129,060



5,550,000



5,000,004



39,058,264Weighted-average fixed price per Mmbtu(1)

$
7.94


$
7.55


$
7.61



7.44


$
7.70Fair value, net

$
41,737


$
15,946


$
5,585



4,409


$
67,677Crude Oil Swaps:Contract volumes (Bbl)


36,000



30,000











66,000Weighted-average fixed per Bbl(1)

$
90.07


$
87.50










$
88.90Fair value, net

$
1,246


$
666










$
1,912     (1)
    
    The prices to be realized for hedged production are expected to
    vary from the prices shown due to basis.  Interest
    Rate Risk
   101




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ITEM 8.
    FINANCIAL
    STATEMENTS AND SUPPLEMENTARY DATA.  page F-1.
  ITEM 9.
    CHANGES
    IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
    FINANCIAL DISCLOSURE.    ITEM 9A.
    CONTROLS
    AND PROCEDURES.  Conclusion
    Regarding the Effectiveness of Disclosure Controls and
    Procedures
  Rules 13a-15(e) 15d-15(e)
  Form 10-K, Form 10-K
  Managements
    Annual Report on Internal Control Over Financial
    Reporting
  Rules 13a-15(f) 15d-15(f)
 102




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##### Table of Contents



Form 10-K,
  (1)
    Control environment We did not maintain an
    effective control environment. The control environment, which is
    the responsibility of senior management, sets the tone of the
    organization, influences the control consciousness of its
    people, and is the foundation for all other components of
    internal control over financial reporting. Each of these control
    environment material weaknesses contributed to the material
    weaknesses discussed in items (2) through (7) below.
    We did not maintain an effective control environment because of
    the following material weaknesses:  (a)
    We did not maintain a tone and control consciousness that
    consistently emphasized adherence to accurate financial
    reporting and enforcement of our policies and procedures. This
    control deficiency fostered a lack of sufficient appreciation
    for internal controls over financial reporting, allowed for
    management override of internal controls in certain
    circumstances and resulted in an ineffective process for
    monitoring the adherence to our policies and procedures.  (b)
    In addition, we did not maintain a sufficient complement of
    personnel with an appropriate level of accounting knowledge,
    experience, and training in the application of GAAP commensurate
    with our financial reporting requirements and business
    environment.  (c)
    We did not maintain an effective anti-fraud program designed to
    detect and prevent fraud relating to (i) an effective
    whistle-blower program, (ii) consistent background checks
    of personnel in positions of responsibility, and (iii) an
    ongoing program to manage identified fraud risks.    (2)
    Internal control over financial reporting  We
    did not maintain effective monitoring controls to determine the
    adequacy of our internal control over financial reporting and
    related policies and procedures because of the following
    material weaknesses:  (a)
    Our policies and procedures with respect to the review,
    supervision and monitoring of our accounting operations
    throughout the organization were either not designed and in
    place or not operating effectively.  (b)
    We did not maintain an effective internal control monitoring
    function. Specifically, there were insufficient policies and
    procedures to effectively determine the adequacy of our internal
    control over financial reporting and monitoring the ongoing
    effectiveness thereof.    (3)
    Period end financial close and reporting We
    did not establish and maintain effective controls over certain
    of our period-end financial close and reporting processes
    because of the following material weaknesses:  (a)
    We did not maintain effective controls over the preparation and
    review of the interim and annual consolidated financial
    statements and to ensure that we identified and accumulated all
    required supporting information to ensure the completeness and
    accuracy of the consolidated financial 103




---



##### Table of Contents



statements and that balances and disclosures reported in the
    consolidated financial statements reconciled to the underlying
    supporting schedules and accounting records.  (b)
    We did not maintain effective controls to ensure that we
    identified and accumulated all required supporting information
    to ensure the completeness and accuracy of the accounting
    records.  (c)
    We did not maintain effective controls over the preparation,
    review and approval of account reconciliations. Specifically, we
    did not have effective controls over the completeness and
    accuracy of supporting schedules for substantially all financial
    statement account reconciliations.  (d)
    We did not maintain effective controls over the complete and
    accurate recording and monitoring of intercompany accounts.
    Specifically, effective controls were not designed and in place
    to ensure that intercompany balances were completely and
    accurately classified and reported in our underlying accounting
    records and to ensure proper elimination as part of the
    consolidation process.  (e)
    We did not maintain effective controls over the recording of
    journal entries, both recurring and non-recurring. Specifically,
    effective controls were not designed and in place to ensure that
    journal entries were properly prepared with sufficient support
    or documentation or were reviewed and approved to ensure the
    accuracy and completeness of the journal entries recorded.  (4)
    Derivative instruments We did not establish
    and maintain effective controls to ensure the correct
    application of GAAP related to derivative instruments.
    Specifically, we did not adequately document the criteria for
    measuring hedge effectiveness at the inception of certain
    derivative transactions and did not subsequently value those
    derivatives appropriately.(5)
    Depreciation, depletion and amortization We
    did not establish and maintain effective controls to ensure
    completeness and accuracy of depreciation, depletion and
    amortization expense. Specifically, effective controls were not
    designed and in place to calculate and review the depletion of
    oil and gas properties.(6)
    Impairment of oil and gas properties We did
    not establish and maintain effective controls to ensure the
    accuracy and application of GAAP related to the capitalization
    of costs related to oil and gas properties and the required
    evaluation of impairment of such costs. Specifically, effective
    controls were not designed and in place to determine, review and
    record the nature of items recorded to oil and gas properties
    and the calculation of oil and gas property impairments.(7)
    Cash management We did not establish and
    maintain effective controls to adequately segregate the duties
    over cash management. Specifically, effective controls were not
    designed to prevent the misappropriation of cash.    Form 10-K.
 104




---



##### Table of Contents



Remediation
    Plan
        and/or
      Changes
    in Internal Control Over Financial Reporting
    ITEM 9B.
    OTHER
    INFORMATION.   105




---



##### Table of Contents



PART III  ITEM 10.
    DIRECTORS,
    EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE
    GOVERNANCE.  Management
        Directors
    and Executive Officers
    Name

Age

Positions Held

Term of Office SinceDavid C. Lawler


41


Chief Executive Officer, President and Director


2007Eddie M. LeBlanc, III


60


Chief Financial Officer


2009Gary M. Pittman(1)


45


Chairman of the Board and Director


2007Mark A. Stansberry(1)


53


Director


2007J. Philip McCormick(1)


67


Director


2008Richard Marlin


56


Executive Vice President, Engineering


2007David W. Bolton


40


Executive Vice President, Land


2007Jack T. Collins


33


Executive Vice President, Finance/Corporate Development


2007Thomas A. Lopus


50


Executive Vice President, Appalachia


2008     (1)
    
    Member of the audit committee, nominating committee and the
    conflicts committee.     106




---



##### Table of Contents



107




---



##### Table of Contents



Corporate
    Governance
  Committees
    of the Board of Directors
   108




---



##### Table of Contents



Audit Committee.
    Conflicts Committee.
    Unitholder
    Communications and Other Information
      Reimbursement
    of Expenses of Our General Partner
   109




---



##### Table of Contents



Code
    of Ethics
    Form 8-K.
  Section 16(a)
    Beneficial Ownership Reporting Compliance
      ITEM 11.
    EXECUTIVE
    COMPENSATION.  Compensation
    Discussion and Analysis
     110




---



##### Table of Contents



Percentage of TimePercentage of Time

Devoted to Business ofDevoted to Our

QRCP and Its OtherName

Business

AffiliatesJerry D. Cash


33
%


67
%David C. Lawler


50
%


50
%David E. Grose


33
%


67
%Jack T. Collins


40
%


60
%Richard Marlin


60
%


40
%David W. Bolton


80
%


20
%Thomas A. Lopus


40
%


60
%   QRCPs
    Compensation Philosophy
      Role
    of the Compensation Committee
    
    attract and retain well-qualified executives who will lead us
    and achieve superior performance;
    tie annual incentives to achievement of specific, measurable
    short-term corporate goals; and
    align the interests of management with those of the equity
    holders to encourage achievement of increases in equityholder
    value.     111




---



##### Table of Contents



Role
    of Management in Compensation Process
           112




---



##### Table of Contents



Performance
    Peer Groups
      Elements
    of QRCPs Executive Compensation Program
    Base Salary:
      Management Annual Incentive Plan:
   113




---



##### Table of Contents



114




---



##### Table of Contents



Percentage of Goal Achieved50%


100%


150%Performance Measure and % WeightCost reduction in savings  health, safety and
    environment (20% in the aggregate)Number of OSHA recordable injuries (5%)


33



30



26Number of vehicle incidents > $1,000 (5%)


20



18



15Salt water spills (Bbls) (5%)


14,760



13,120



11,480Number of spills (5%)


338



301



263EBITDA (earnings before interest, taxes, depreciation and
    amortization) (20%)

$
69,300,000


$
72,400,000


$
78,800,000Lease operating expense (excluding gross production taxes and ad
    valorem taxes) (20%)

$
28,246,660


$
25,700,000


$
23,153,000Finding and development cost (20%)

$
1.52/Mcf


$
1.39/Mcf


$
1.25/McfProduction (20%)


22.5 Bcfe



23.1 Bcfe



24.5 Bcfe         Discretionary Bonuses:
 115




---



##### Table of Contents



gross-up
  Productivity Gain Sharing Payments:
  Equity Awards:
  Omnibus Stock Award Plan.
 116




---



##### Table of Contents



QRCPs Long-Term Incentive
    Plan.
    
    enhance the link between the creation of stockholder value and
    long-term incentive compensation;
    provide an opportunity for increased equity ownership by
    executive officers; and
    maintain a competitive level of total compensation.    Our Long Term Incentive Plan.
 117




---



##### Table of Contents



Restricted Units.
  Phantom Units.
  Unit Options.
  Unit Appreciation Rights.
  Distribution Equivalent Rights.
  Other Unit-Based Awards.
  Unit Awards.
  Change in Control; Termination of
    Service. and/or
 118




---



##### Table of Contents



Source of Units.
  Benefits
    Perquisites
    Policy
    Regarding Hedging Equity Ownership
    Compensation
    Recovery Policies
   119




---



##### Table of Contents



Executive
    Compensation and Other Information
    Summary
    Compensation Table
  Non-Equity


AllStock


Option


Incentive Plan


OtherName and Principal Position

Year


Salary


Bonus (1)


Awards (2)


Awards (3)


Compensation (4)


Compensation (5)


TotalJerry D. Cash


2008


$
349,731


$
100


$
(637,113
)





$
22,225


$
11,534


$
(253,523
)Chairman of the Board,


2007


$
491,346


$
1,200


$
2,048,169






$
289,667


$
11,300


$
2,841,682President and Chief


2006


$
400,000


$
1,300


$
14,000






$
165,333


$
11,054


$
591,687Executive OfficerDavid C. Lawler(6)


2008


$
344,616


$
390,244


$
280,735


$
48,000


$
104,917


$
50,205


$
1,218,717President, Chief Operating


2007


$
180,692


$
1,200


$
515,264






$
107,672


$
96,040


$
900,868Officer and DirectorDavid E. Grose


2008


$
275,154


$
100


$
(140,993
)





$
17,850


$
11,538


$
163,649Chief Financial Officer


2007


$
329,808


$
1,200


$
1,129,900






$
193,458


$
11,300


$
1,665,6662006


$
270,240


$
1,200


$
203,890






$
113,667


$
11,054


$
600,051Jack T. Collins(7)


2008


$
152,500


$
28,600


$
289,363


$
19,619


$
52,042


$
49,994
(8)

$
592,118Interim Chief FinancialOfficer and Executive VPFinance/CorporateDevelopmentRichard Marlin


2008


$
254,486


$
17,990


$
154,302






$
32,851


$
11,550


$
471,179Executive VP Engineering


2007


$
247,865


$
1,500


$
270,421






$
102,073


$
11,300


$
633,1592006


$
247,500


$
1,000


$
195,066






$
77,550


$
11,054


$
532,170David W. Bolton


2008


$
230,885


$
57,848


$
196,108






$
29,805


$
24,542


$
539,188Executive VP Land


2007


$
228,461


$
1,200


$
414,205






$
92,625


$
11,300


$
747,7912006


$
100,961


$
1,000


$
65,856






$
39,588


$
2,746


$
210,151Thomas A. Lopus(9)


2008


$
95,192


$
26,156


$
126,131






$
10,313


$
8


$
257,800Executive Vice PresidentAppalachia     (1)
    
    See Compensation Discussion and Analysis 
    Elements of QRCPs Executive Compensation
    Program  Discretionary Bonuses, exclusive of
    the portion constituting a tax
    gross-up.
    Also includes other miscellaneous bonuses available to all
    employees totaling less than $1,500 per named executive officer.(2)
    
    Includes expense related to bonus shares and restricted stock
    granted under employment agreements. Expense for the bonus
    shares and restricted stock is computed in accordance with the
    provisions of Statement of Financial Accounting Standards
    No. 123 (Revised) (SFAS No. 123R) and
    represents the grant date fair value, which for QRCP common
    stock was determined by utilizing the closing stock price on the
    date of grant, with expense being recognized ratably over the
    requisite service period. Also includes equity portion of the
    QRCP Bonus Plan award earned for 2006. Twenty-five percent of
    the bonus shares vested in March 2007 at the time the Committee
    determined the amount of the awards based upon 2006 performance,
    twenty-five percent of the bonus shares vested in March 2008 and
    the remaining portion vests and will be paid in March of each of
    the next two years. Amounts for Messrs. Cash and Grose in
    2008 are negative due to forfeiture of unvested equity awards in
    connection with the termination of their employment during the
    year.(3)
    
    Includes expense related to stock options granted to
    Mr. Lawler and Mr. Collins during 2008. Expense for
    the stock options is computed in accordance with the provisions
    of Statement of Financial Accounting Standards 120




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##### Table of Contents



No. 123 (Revised) (SFAS No. 123R) and
    represents the grant date fair value, which is calculated using
    the Black-Scholes Option Pricing Model, with expense being
    recognized ratably over the requisite service period. The
    expected life of the stock option is estimated based upon
    historical exercise behavior. The expected forfeiture rate was
    estimated based upon historical forfeiture experience. The
    volatility assumption was estimated based upon expectations of
    volatility over the life of the option as measured by historical
    and implied volatility. The risk-free interest rate was based on
    the U.S. Treasury rate for a term commensurate with the
    expected life of the option. The dividend yield was based upon a
    12-month
    average dividend yield. QRCP used the following weighted-average
    assumptions to estimate the fair value of stock options granted
    during the year ended December 31, 2008:  2008Expected option life  years

10Volatility

69.8%Risk-free interest rate

5.42%Dividend yield

Fair value

$0.41-$0.61   (4)
    
    Represents the QRCP Bonus Plan awards earned for 2007 and 2008
    and paid in 2008 and 2009, as applicable, the cash portion of
    the QRCP Bonus Plan awards earned for 2006 and paid in 2007 and
    productivity gain sharing bonus payments earned and paid in
    2006, 2007 and 2008.(5)
    
    QRCP matching contribution under the 401(k) savings plan, life
    insurance premiums, perquisites and personal benefits if $10,000
    or more for the year and, for Messrs. Lawler and Bolton,
    tax withholding
    gross-ups
    related to discretionary bonuses paid in 2008 relating to the
    failure of our former chief financial officer to execute on
    10b-5(1)(c)
    trading plans. See Compensation Discussion and
    Analysis  Elements of Executive Compensation
    Program  Discretionary Bonuses. Salary shown
    above has not been reduced by pre-tax contributions to the
    company-sponsored 401(k) savings plan. For 2008, QRCP matching
    contributions were as follows: Mr. Cash 
    $11,500, Mr. Lawler  $10,193,
    Mr. Grose  $11,500, Mr. Collins 
    $6,245, Mr. Marlin  $11,500,
    Mr. Bolton  $9,437 and
    Mr. Lopus  $0. Tax withholding
    gross-up in
    2008 for Mr. Lawler was $39,962 and for Mr. Bolton was
    $15,055.(6)
    
    Mr. Lawlers employment as our general partners
    chief operating officer commenced on April 10, 2007 and as
    our general partners president effective as of
    August 23, 2008.(7)
    
    Mr. Collinss employment as our general partners
    executive vice president of investor relations commenced on
    December 3, 2007 and as our general partners interim
    chief financial officer and executive vice president of
    finance/corporate development effective as of August 23,
    2008.(8)
    
    Perquisites and personal benefits for 2008 consist of expenses
    related to relocation expenses ($40,782), benefits for gym
    services, parking and social club membership.(9)
    
    Mr. Lopuss employment as our general partners
    Executive Vice President Appalachia commenced on July 16,
    2008. 121




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##### Table of Contents



Grants
    of Plan-Based Awards in 2008
      Grants of
    Plan-Based Awards in 2008
  Estimatedfuturepayouts

All other

All otherunder

stock

option



Grant dateequity

awards:

awards:

Exercise

fair valueEstimated future payouts under

incentive

Number of

Number of

or base

of stocknon-equity incentive plan awards

plan awards

shares of

securities

price of

andApproval

Grant

Threshold

Target

Maximum

Target

stock or

underlying

option

optionName

Date

Date

($)

($)

($)

($)

units (#)

options (#)

awards ($/Sh)

awards(1)Jerry D. Cash






(2
)

$
115,500


$
220,500


$
519,7505/19/08(3
)














(3
)(4
)





$
22,225David C. Lawler






(2
)

$
75,816


$
144,739


$
341,1705/19/08(3
)













$
24,166(4
)





$
16,91710/20/08



10/20/08























200,000
(5)

$
0.71


$
122,000David E. Grose






(2
)

$
77,000


$
147,000


$
346,5005/19/08
(3)













$
25,133(4
)





$
17,850Jack T. Collins






(2
)

$
33,550


$
64,050


$
150,9755/19/08
(3)













$
8,976(4
)





$
8,04210/20/08



10/23/08























100,000
(6)

$
0.48


$
41,000Richard Marlin






(2
)

$
17,814


$
68,711


$
187,0475/19/08
(3)













$
17,808(4
)





$
14,797David W. Bolton






(2
)

$
16,162


$
62,339


$
169,7005/19/08
(3)













$
16,517(4
)





$
13,425Thomas A. Lopus






(2
)

$
6,663


$
25,696


$
69,937(4
)





$
3,7506/30/08



7/14/08
(7)


















45,000










$
441,450     (1)
    
    The amounts included in the Grant date fair value of stock
    and option awards column represents the grant date fair
    value of the awards made to Named Executive Officers in 2008
    computed in accordance with SFAS No. 123(R). The value
    ultimately realized by the executive upon the actual vesting of
    the award(s) or the exercise of the stock option(s) may or may
    not be equal to the SFAS No. 123(R) determined value.
    The expected life of the stock option is estimated based upon
    historical exercise behavior. The expected forfeiture rate was
    estimated based upon historical forfeiture experience. The
    volatility assumption was estimated based upon expectations of
    volatility over the life of the option as measured by historical
    and implied volatility. The risk-free interest rate was based on
    the U.S. Treasury rate for a term commensurate with the
    expected life of the option. The dividend yield was based upon a
    12-month
    average dividend yield. QRCP used the following 122




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##### Table of Contents



weighted-average assumptions to estimate the fair value of stock
    options granted during the year ended December 31, 2008:  2008Expected option life  years

10Volatility

69.8%Risk-free interest rate

5.42%Dividend yield

Fair value

$0.41-$0.61   (2)
    
    Represents an award under the QRCP Bonus Plan for 2008. On
    March 26, 2009, the Committee determined the amount of the
    award payable for 2008 based upon 2008 performance. The amounts
    for Messrs. Lawler, Collins, Marlin, Bolton and Lopus are
    based upon their actual base salary paid during the year. The
    amounts for Messrs. Cash and Grose represents the amounts
    they would have been entitled to receive if they had remained
    employed with the Company for the entire year at the salaries
    provided for in their employment agreements. See
    Compensation Discussion and Analysis  Elements
    of QRCPs Executive Compensation Program 
    Management Annual Incentive Plan for a discussion of the
    performance criteria applicable to these awards.(3)
    
    Represents amounts payable under the LTIP adopted by the QRCP
    Board of Directors on May 19, 2008. The award for
    Mr. Cash was an indeterminate number of shares based on the
    increase in our adjusted average share price for 2008 over
    $9.74. As such, a target amount for the award was not
    determinable. The amount of Mr. Cashs award was
    capped at $3.0 million. For the other Named Executive
    Officers, a bonus pool equal to three percent of our
    consolidated income before income taxes, adjusted to
    (1) add back depreciation, depletion and amortization
    expenses and (2) exclude the effect of non-cash derivative
    fair value gains or losses, for the applicable calendar year or
    period (Measured Income) was to be divided among
    plan participants based on their relative base salaries. Each
    individual would then be issued that number of shares equal to
    the dollar amount of their award divided by the stock price as
    of the day the Compensation Committee finalized the awards. For
    purposes of this table, the target amount is based on the base
    salaries of all participants as of May 19, 2008 and assumes
    QRCPs Measured Income was equal to the budgeted amount.
    The LTIP program for 2008 was terminated in January 2009 and no
    awards were paid to the Named Executive Officers for 2008.(4)
    
    Represents amount payable under QRCPs productivity gain
    sharing bonus program.(5)
    
    100,000 shares subject to the stock option were immediately
    vested.(6)
    
    50,000 shares subject to the stock option were immediately
    vested.(7)
    
    Represents an equity award granted in connection with the
    execution of Mr. Lopuss employment agreement in 2008.
    Grant date is the date the employment agreement was executed.
    One-third of the award vests on July 16, 2009, 2010 and
    2011. 123




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##### Table of Contents



Equity
    Awards Outstanding at Fiscal Year-End 2008
    Option Awards


Stock AwardsNumber of


Number of











Market valueSecurities


Securities








Number of


of shares orUnderlying


Underlying








shares or


units of stockUnexercised


Unexercised


Option


Option


units that


thatOptions


Options (#)


Exercise


Expiration


have not


have not(#) Exercisable


Unexercisable


Price ($)


Date


vested


vestedJerry D. Cash(1)






















David C. Lawler


100,000



100,000
(2)

$
0.71



10/20/18



60,000
(3)

$
26,400David E. Grose(4)






















Jack T. Collins


50,000



50,000
(5)

$
0.48



10/23/18



40,000
(6)

$
17,600Richard Marlin


















31,376
(7)

$
13,805Dave W. Bolton


















30,740
(8)

$
13,526Thomas A. Lopus


















45,000
(9)

$
19,800     (1)
    
    Mr. Cash forfeited all of his unvested stock awards when he
    resigned all of his positions with QRCP on August 23, 2008.(2)
    
    Option vests on October 20, 2009.(3)
    
    30,000 shares vest on each of May 1, 2009 and 2010.(4)
    
    All of Mr. Groses unvested stock awards were
    forfeited in connection with the termination of his employment
    on September 13, 2008.(5)
    
    Option vests on October 23, 2009.(6)
    
    20,000 shares vest on each of December 3, 2009 and
    2010.(7)
    
    15,688 shares vest on each of March 16, 2009 and 2010.(8)
    
    15,370 shares vest on each of March 16, 2009 and 2010.(9)
    
    15,000 shares vest on each of July 16, 2009, 2010 and
    2011.  Stock
    Vested in 2008
    Stock AwardsNumber of shares ofcommon stock acquired

Value realized onName

on vesting (#)

vesting ($)Jerry D. Cash


166,088


$
1,077,625David C. Lawler


30,000


$
266,400David E. Grose


36,188


$
231,544Jack T. Collins


20,000


$
7,200Richard Marlin


27,688


$
129,924David W. Bolton


35,370


$
149,282Thomas A. Lopus






    124




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##### Table of Contents



Director
    Compensation for 2008
    Fees earned orName

paid in cash ($)

Unit Awards ($)(1)

Total ($)Gary M. Pittman

$
67,614


$
34,900
(2)

$
102,514Mark A. Stansberry

$
61,979


$
34,900
(2)

$
96,879J. Philip McCormick

$
4,125






$
4,125     (1)
    
    Represents the dollar amount recognized for financial reporting
    purposes for 2008 in accordance with FAS 123R.(2)
    
    On January 28, 2008, the Board of Directors of our general
    partner approved a grant of 15,000 common units each for the
    non-employee directors, Messrs. Pittman and Stansberry,
    with 25% of the units immediately vested and 25% of the units
    vesting on each of the first three anniversaries of the vesting
    date. Messrs. Pittman and Stansberry each received
    distributions and distribution equivalents with respect to the
    vested and unvested units totaling $21,665 for 2008.    
    from January 1, 2008 to August 22, 2008:  
    a pro rated annual director fee of $32,000 per year;
    a pro rated annual fee of $7,500 per year for the Audit
    Committee chairperson;
    a pro rated annual fee of $2,500 per year for any other
    committee chairperson;  
    from August 23, 2008 to December 31, 2008:  
    a pro rated annual director fee of $42,000 per year (the fees
    for Mr. McCormick were pro rated for the fourth quarter of
    2008 based on his length of service);
    a pro rated annual fee of $30,000 per year for the Chairman of
    the Board;
    a pro rated annual fee of $7,500 per year for the Audit
    Committee chairperson; and
    a pro rated annual fee of $2,500 per year for any other
    committee chairperson.      Employment
    Contracts
   125




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##### Table of Contents



Number of

Number of SharesShares of

for PurchaseExpiration of



QRCP

Pursuant toInitial



Restricted

QRCPName

Position

Term

Base Salary

Stock

Stock OptionsJerry D. Cash

Chief Executive Officer

(1)

$
525,000



493,080
(2)


David C. Lawler

Chief Operating Officer and President

August 2011

$
400,000



90,000



200,000David E. Grose

Chief Financial Officer

(1)

$
350,000



105,000
(3)


Jack T. Collins

Interim Chief Financial

August 2011

$
200,000



60,000



100,000Officer and Executive Vice President  Finance/
    Corporate DevelopmentDavid W. Bolton

Executive Vice President  Land

March 2010

$
225,000



45,000



Richard Marlin

Executive Vice

March 2010

$
248,000



45,000



President  EngineeringThomas A. Lopus

Executive Vice President  Appalachia

July 2011

$
225,000



45,000



     (1)
    
    Agreement has been terminated.(2)
    
    328,720 of these shares were forfeited at the time the agreement
    was terminated.(3)
    
    All of these shares were cancelled at the time the agreement was
    terminated.        
    the executive will receive his base salary for the remainder of
    the term,
    QRCP will pay the executives health insurance premium
    payments for the duration of the COBRA continuation period
    (18 months) or until he becomes eligible for health
    insurance with a different employer,
    the executive will receive his pro rata portion of any annual
    bonus and other incentive compensation to which he would have
    been entitled; and
    his unvested shares of restricted stock will vest (which vesting
    may be deferred for six months if necessary to comply with
    Section 409A of the Internal Revenue Code). 126




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##### Table of Contents




    QRCPs failure to pay the executives salary or annual
    bonus in accordance with the terms of the agreement (unless the
    payment is not material and is being contested by QRCP in good
    faith);
    if QRCP requires the executive to be based anywhere other than
    Oklahoma City, Oklahoma (or, in the case of Mr. Lopus,
    Pittsburgh, Pennsylvania);
    a substantial or material reduction in the executives
    duties or responsibilities; or
    the executive no longer has the title specified above (though
    this does not apply to Mr. Lopus and in the case of
    Mr. Collins, Good Reason does not apply in the situation
    where he no longer holds the interim chief financial officer
    position as long as he continues to have a title, position and
    duties not materially less than those of executive vice
    president finance/corporate development).    
    any act or omission by the executive that constitutes gross
    negligence or willful misconduct;
    theft, dishonest acts or breach of fiduciary duty that
    materially enrich the executive or materially damage QRCP or
    conviction of a felony,
    any conflict of interest, except those consented to in writing
    by QRCP;
    any material failure by the executive to observe QRCPs
    work rules, policies or procedures;
    failure or refusal by the executive to perform his duties and
    responsibilities required under the employment agreements, or to
    carry out reasonable instruction, to QRCPs satisfaction;
    any conduct that is materially detrimental to QRCPs
    operations, financial condition or reputation; or
    any material breach of the employment agreement by the executive.    Unvested EquityName

Base Salary(1)

Compensation(2)

Bonus(3)

Benefits(4)

TotalDavid C. Lawler

$
1,057,534


$
53,400


$
336,000


$
21,522


$
1,468,456Jack T. Collins

$
528,767


$
19,600


$
84,000


$
25,461


$
657,828Richard Marlin

$
302,356


$
13,805


$
66,960


$
9,703


$
392,824David W. Bolton

$
265,685


$
13,526


$
60,750


$
17,582


$
357,543Thomas A. Lopus

$
570,205


$
19,800


$
60,750


$
17,582


$
668,337     (1)
    
    Assumes full amount of remaining base salary payable under the
    agreement as of December 31, 2008 is paid (with no renewal
    of the term of the agreement). Actual amounts may be less.(2)
    
    For purposes of this table, we have used the number of unvested
    equity awards and stock options as of December 31, 2008 and
    the closing price of QRCPs common stock on that date
    ($0.44). Assumes all such equity awards remain unvested on the
    date of termination. No value was assigned to unvested stock
    options since the exercise price exceeded the stock price on
    December 31, 2008.(3)
    
    Represents target amounts payable under the QRCP Bonus Plan for
    2009. Assumes a full years bonus (i.e., if employment were
    terminated on December 31 of a year). Actual payment would be
    pro-rated based on the number of days in the year during which
    the executive was employed. For Mr. Lawler, also assumes he
    will be granted (i) a number of performance shares under
    the Omnibus Plan having a value equal to 50% of the payment he
    would have been paid under the QRCP Bonus Plan and (ii) a
    number of restricted shares under the Omnibus Plan having a
    value equal to 50% of the payment he would have been paid under
    the QRCP Bonus Plan.(4)
    
    Represents 18 months of insurance premiums at current rates.   127




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##### Table of Contents




    the acquisition by any person or group of QRCPs common
    stock that, together with shares of common stock held by such
    person or group, constitutes more than 50% of the total voting
    power of QRCPs common stock;
    any person or group acquires (or has acquired during the
    12-month
    period ending on the date of the most recent acquisition by such
    person or group) ownership of QRCPs common stock
    possessing 35% or more of the total voting power of QRCPs
    common stock;
    a majority of members of QRCPs board of directors being
    replaced during any
    12-month
    period by directors whose appointment or election is not
    endorsed by a majority of the members of QRCPs board of
    directors prior to the date of the appointment or
    election; or
    any person or group acquires (or has acquired during the
    12-month
    period ending on the date of the most recent acquisition by such
    person or group) assets from QRCP that have a total gross fair
    market value equal to or more than 40% of the total gross fair
    market value of all of QRCPs assets immediately prior to
    the acquisition or acquisitions.        Compensation
    Committee Report
  Regulation S-K Form 10-K.
  
 128




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##### Table of Contents



Compensation
    Committee Interlocks and Insider Participation
    Form 10-K,
  ITEM 12.
    SECURITY
    OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
    RELATED UNITHOLDER MATTERS.    
    each person known by us to beneficially own 5% or more of our
    common or subordinated units;
    each director of our general partner;
    each Named Executive Officer of our general partner; and
    all current directors and officers of our general partner as a
    group.    129




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##### Table of Contents



Percentage ofCommonPercentage of





Percentage of


Units andCommon


Common


Subordinated


Subordinated


SubordinatedUnits


Units


Units


Units


UnitsBeneficially


Beneficially


Beneficially


Beneficially


BeneficiallyName and Address of Beneficial Owner

Owned


Owned


Owned


Owned


Owned5% Beneficial Owners:Quest Resource Corporation 210 Park Avenue, Suite 2750
    Oklahoma City, OK 73102


3,201,521



26.0
%


8,857,981



100
%


57.0
%Officers and Directors:Gary M. Pittman(1)


7,500




*











*Mark A. Stansberry(2)


7,500




*











*J. Philip McCormick


















Thomas A. Lopus


















Jack T. Collins


















David C. Lawler


















David E. Grose


















Jerry D. Cash


















David W. Bolton


















Richard Marlin


















All directors and executive officers as a group (9 persons)


15,000




*











*     *
    
    Signifies less than 1%(1)
    
    In addition, Mr. Pittman is entitled to receive 7,500 bonus
    units upon satisfaction of certain vesting requirements.
    Mr. Pittman does not have the ability to vote these bonus
    units.(2)
    
    In addition, Mr. Stansberry is entitled to receive 7,500
    bonus units upon satisfaction of certain vesting requirements.
    Mr. Stansberry does not have the ability to vote these
    bonus units.    Number of Shares ofQuest ResourceCorporation Common


PercentStock


of Class of QuestBeneficially


Resource CorporationName and Address of Beneficial Owner

Owned(1)


Common StockJerry D. Cash(2)


1,463,270



4.6
%David C. Lawler(3)


183,415




*Jack T. Collins(4)


113,000




*Richard Marlin(5)


61,012




*David E. Grose(6)


56,080




*David W. Bolton(7)


47,776




*Thomas A. Lopus(8)


45,000




*Gary M. Pittman






Mark A. Stansberry






J. Philip McCormick






All Current Directors and Executive Officers as a Group
    (9 Persons)


450,203



1.4
%  130




---



##### Table of Contents



(1)
    
    The number of securities beneficially owned by the persons or
    entities above is determined under rules promulgated by the SEC
    and the information is not necessarily indicative of beneficial
    ownership for any other purpose. Under such rules, beneficial
    ownership includes any securities as to which the person or
    entity has sole or shared voting power or investment power and
    also any securities that the person or entity has the right to
    acquire within 60 days through the exercise of any option
    or other right. The inclusion herein of such securities,
    however, does not constitute an admission that the named
    equityholder is a direct or indirect beneficial owner of such
    securities. Unless otherwise indicated, each person or entity
    named in the table has sole voting power and investment power
    (or shares such power with his or her spouse) with respect to
    all securities listed as owned by such person or entity.(2)
    
    Includes (i) 1,200 shares of QRCPs common stock
    owned by Mr. Cashs wife, Sherry J. Cash and
    (ii) 7,678 shares held in Mr. Cashs
    retirement account (Mr. Cash does not have voting rights
    with respect to the shares held in his profit sharing retirement
    account). Mr. Cash disclaims beneficial ownership of the
    shares owned by Sherry J. Cash. Mr. Cash did not respond to
    QRCPs request to confirm the exact beneficial ownership
    information and, as a result, it is based on his most recent
    Form 4 adjusted for forfeitures; however, he has advised
    QRCP that all of the shares of QRCP common stock beneficially
    owned by him have been pledged to secure a personal loan.(3)
    
    Includes 30,000 restricted shares, which are subject to vesting,
    and options to acquire 100,000 shares of QRCPs common
    stock that are immediately exercisable.(4)
    
    Includes 40,000 restricted shares, which are subject to vesting,
    and options to acquire 50,000 shares of QRCPs common
    stock that are immediately exercisable.(5)
    
    Includes 15,000 restricted shares, which are subject to vesting.
    In addition, Mr. Marlin is entitled to receive
    688 bonus shares upon satisfaction of certain vesting
    requirements. Mr. Marlin does not have the ability to vote
    these bonus shares.(6)
    
    Includes 3,281 shares of QRCPs common stock held in
    Mr. Groses retirement account (Mr. Grose does
    not have voting rights with respect to these shares).
    Mr. Grose did not respond to QRCPs request to confirm
    the exact beneficial ownership information and, as a result it
    is based on his most recent Form 4 adjusted for shares
    cancelled in connection with the termination of his employment.(7)
    
    Includes 15,000 restricted shares, which are subject to vesting.
    In addition, Mr. Bolton is entitled to receive 370 bonus
    shares upon satisfaction of certain vesting requirements.
    Mr. Bolton does not have the ability to vote these bonus
    shares.(8)
    
    Consists of 45,000 restricted shares, which are subject to
    vesting.  Equity
    Compensation Plans
   131




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##### Table of Contents



Equity
    Compensation Plan Information
  Number of securitiesNumber of securities to


Weighted-average


remaining available forbe issued upon exercise


exercise price of


future issuance underof outstanding options,


outstanding options,


equity compensationPlan category

warrants and rights


warrants and rights


plansEquity compensation plans approved by security holders





$




Equity compensation plans not approved by security holders





$




2,085,950
(1)Total





$




2,085,950     (1)
    
    Excludes securities to be issued upon vesting of bonus units
    that have been granted.  ITEM 13.
    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
    INDEPENDENCE.  Related
    Transactions
      Distributions
    and Payments to Our General Partner and its Affiliates
    Operational StageDistribution of available cash to our general partner and its
    affiliates
    
    We will generally distribute 98% of our available cash to all
    unitholders, including QRCP (as the holder of an aggregate of
    3,201,521 common units and 8,857,981 subordinated units), and
    the independent directors of our general partner (as the owners
    of an aggregate of 15,000 common units), and 2% of our available
    cash to our general partner. In addition, if distributions
    exceed the minimum quarterly distribution and other higher
    target distribution levels, our general partner will be entitled
    to increasing percentages of the distributions, up to 23% of the
    distributions above the highest target distribution level.For 2008, our general partner and its affiliates received a
    distribution of approximately $0.6 million on their 2%
    general partner interest and $13.9 million on their common
    units and subordinated units.Payments to our general partner and its affiliates
    
    Our partnership agreement requires us to reimburse our general
    partner for all actual direct and indirect expenses it incurs or
    actual payments it makes on our behalf and all other expenses
    allocable to us or otherwise 132




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##### Table of Contents



incurred by our general partner in connection with operating our
    business, including overhead allocated to our general partner by
    its affiliates. These expenses include salary, bonus, incentive
    compensation and other amounts paid to persons who perform
    services for us or on our behalf, and expenses allocated to our
    general partner by its affiliates. Our general partner is
    entitled to determine in good faith the expenses that are
    allocable to us. Our management services agreement requires us
    to reimburse Quest Energy Service for its expenses incurred on
    our behalf. For 2008, we reimbursed our general partner and
    Quest Energy Service for expenses of $10.5 million in the
    aggregate.Withdrawal or removal of the general partner
    
    If our general partner withdraws or is removed, its general
    partner interest and its incentive distribution rights will
    either be sold to the new general partner for cash or converted
    into common units, in each case for an amount equal to the fair
    market value of that interest.Liquidation StageLiquidation
    
    Upon our liquidation, the partners, including our general
    partner, will be entitled to receive liquidating distributions
    according to their respective capital account balances.  Agreements
    Governing the Transactions
    Omnibus Agreement.
       133




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Midstream Services Agreement.
  Management Services Agreement.
          Midstream Omnibus Agreement.
    
    the gathering, treating, processing and transporting of gas in
    North America;
    the transporting and fractionating of gas liquids in North
    America;
    any other midstream activities, including but not limited to
    crude oil storage, transportation, gathering and terminaling;
    constructing, buying or selling any assets related to the
    foregoing businesses; and
    any line of business other than those described in the preceding
    bullet points that generates qualifying income,
    within the meaning of Section 7704(d) of the Code, other than
    any business that is primarily 134




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engaged in the exploration for and production of oil or gas and
    the sale and marketing of gas and oil derived from such
    exploration and production activities.      
    the ownership of a passive investment of less than 5% in an
    entity engaged in a Restricted Business;
    any business in which Quest Midstream permits us to engage;
    the ownership or operation of assets used in a Restricted
    Business if the value of the assets is less than
    $4 million; and
    any business that we have given Quest Midstream the option to
    acquire and it has elected not to purchase.      Contribution, Conveyance and Assumption
    Agreement.
  Policy
    Regarding Transactions with Related Persons
  Regulation S-K.
  Director
    Independence
    ITEM 14.
    PRINCIPAL
    ACCOUNTING FEES AND SERVICES.  Audit and
    Non-Audit Fees
  Form 10-Q
 135




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##### Table of Contents



Successor


PredecessorNovember 15,


January 1,Year Ended


to


toDecember 31,


December 31,


November 14,2008


2007


2007Audit Fees(1)

$
162,054


$
9,300


$
105,833Audit-Related Fees(2)


78,051







2,328Tax Fees(3)


114,725



4,353



15,374All Other Fees










Total Fees

$
354,830


$
13,653


$
123,535   1.
    Audit Fees include fees billed for services performed to comply
    with Generally Accepted Auditing Standards (GAAS), including the
    recurring audit of our consolidated financial statements for
    such period included in the Annual Report on
    Form 10-K
    and for the reviews of the consolidated quarterly financial
    statements included in the Quarterly Reports on Form
    10-Q filed
    with the SEC. This category also includes fees for audits
    provided in connection with statutory filings or procedures
    related to the audit of income tax provisions and related
    reserves, consents and assistance with and review of documents
    filed with the SEC. During 2008, UHY billed us $49,306 for audit
    fees.2.
    Audit-Related Fees include fees for services associated with
    assurance and reasonably related to the performance of the audit
    or review of our financial statements. This category includes
    fees related to assistance in financial due diligence related to
    mergers and acquisitions, consultations regarding GAAP, reviews
    and evaluations of the impact of new regulatory pronouncements,
    general assistance with implementation of Sarbanes-Oxley Act of
    2002 requirements and audit services not required by statute or
    regulation. This category also includes audits of pension and
    other employee benefit plans, as well as the review of
    information systems and general internal controls unrelated to
    the audit of the financial statements. During 2008, UHY did not
    bill us any amount for audit-related fees.3.
    Tax fees consist of fees related to the preparation and review
    of our federal and state income tax returns and tax consulting
    services. During 2008, UHY did not bill us any amount for tax
    fees.     PART IV  ITEM 15.
    EXHIBITS,
    FINANCIAL STATEMENT SCHEDULES.  (a)(1) and (2) Financial
    Statements. page F-1 Form 10-K.
  (a)(3) Index to Exhibits. Regulation S-K Form 10-K
 136




---



##### 



QUEST
    ENERGY PARTNERS, L.P.
    Index To Financial Statements
   
 Report of Independent Registered Public
    Accounting Firm on Consolidated Financial Statements


F-2Report of Independent Registered Public
    Accounting Firm on Internal Control Over Financial Reporting


F-3Balance Sheets


F-6Statements of Operations


F-7Statements of Cash Flows


F-8Statements of Partners Equity


F-9Notes to Consolidated/Carve-Out Financial
    Statements


F-10   F-1




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM              Internal Control  Integrated Framework
     F-2




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM              Control environment
 F-3




---



##### Table of Contents



Internal control over financial
    reporting 
        Period end financial close and reporting 
         F-4




---



##### Table of Contents



Derivative instruments 
  Depreciation, depletion and amortization 
  Impairment of oil and gas properties 
  Cash management 
    Internal Control  Integrated Framework
       F-5




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  BALANCE SHEETS
 ($ in thousands except unit data)
  Successor


PredecessorDecember 312008


2007


2006(Consolidated)


(Consolidated)


(Carve out)(Restated)


(Restated)ASSETSCurrent assetsCash and cash equivalents

$
3,706


$
169


$
13,334Restricted cash


112



1,205



1,150Accounts receivable  trade, net


11,696



86



10,022Other receivables


2,590







Due from affiliates


2,819



15,624



607Other current assets


2,031



3,091



1,053Inventory


8,782



4,956



3,378Current derivative financial instrument assets


42,995



8,008



14,109Total current assets


74,731



33,139



43,653Property and equipment, net


17,367



17,116



16,706Oil and gas properties under full cost method of accounting, net


151,120



294,329



236,826Other assets, net


4,167



3,526



9,466Long-term derivative financial instrument assets


30,836



3,467



8,022Total assets

$
278,221


$
351,577


$
314,673LIABILITIES AND PARTNERS EQUITYCurrent liabilities:Accounts payable

$
7,380


$
17,754


$
14,845Revenue payable


3,221



919



4,989Accrued expenses


1,770



639



964Due to affiliates


7,516



1,708



385Current portion of notes payable


41,882



666



324Current derivative financial instrument liabilities


12



8,108



8,879Total current liabilities


61,781



29,794



30,386Non-current liabilities:Long-term derivative financial instrument liabilities


4,230



6,311



10,878Asset retirement obligations


4,592



1,700



1,410Notes payable


189,090



94,042



225,245Non-current liabilities


197,912



102,053



237,533Total liabilities


259,693



131,847



267,919Commitments and contingenciesPartners equity:Predecessor










46,754Common unitholders  Issued  12,331,521 and
    12,301,521 at December 31, 2008 and 2007, respectively
    (9,100,000  public; 3,231,521 and
    3,201,521  affiliate); outstanding 
    12,316,521 and 12,301,521 at December 31, 2008 and 2007;
    respectively (9,100,000  public; 3,216,521 and
    3,201,521  affiliates)


45,832



162,610



Subordinated unitholder  affiliate;
    8,857,981 units issued and outstanding at December 31,
    2008 and 2007


(25,857
)


54,465



General Partner  affiliate; 431,827 units issued
    and outstanding at December 31, 2008 and 2007


(1,447
)


2,655



Total partners equity


18,528



219,730



46,754Total liabilities and partners equity

$
278,221


$
351,577


$
314,673    F-6




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  STATEMENTS OF OPERATIONS
 ($ in thousands, except unit and per unit data)
   Successor


PredecessorNovember 15,


January 1,2007


2007Year Ended


to


to


Years EndedDecember 31,


December 31,


November 14,


December 31,


December 31,2008


2007


2007


2006


2005(Consolidated)


(Consolidated)


(Carve out)


(Carve out)


(Carve out)(Restated)


(Restated)


(Restated)


(Restated)Revenue:Oil and gas sales

$
147,930


$
15,348


$
89,937


$
72,410


$
70,628Total revenues


147,930



15,348



89,937



72,410



70,628Costs and expenses:Oil and gas production


43,490



3,970



31,436



24,886



19,152Transportation expense


35,546



4,342



24,837



17,278



7,038General and administrative expenses


13,647



2,872



11,040



7,853



5,353Impairment of oil and gas properties


245,587















Loss on early extinguishment of debt


















8,255Depreciation, depletion and amortization


50,988



5,045



29,568



24,760



19,037Misappropriation of funds










1,500



6,000



2,000Total costs and expenses


389,258



16,229



98,381



80,777



60,835Operating income (loss)


(241,328
)


(881
)


(8,444
)


(8,367
)


9,793Other income (expense):Gain (loss) from derivative financial instruments


80,707



(4,583
)


6,544



52,690



(73,566
)Other income (expense)


301



4



(355
)


(90
)


399Interest expense


(13,744
)


(13,760
)


(27,321
)


(15,490
)


(21,979
)Interest income


132



14



402



390



46Total other income (expense)

$
67,396


$
(18,325
)

$
(20,730
)

$
37,500


$
(95,100
)Net income (loss)

$
(173,932
)

$
(19,206
)

$
(29,174
)

$
29,133


$
(85,307
)General partners interest in net loss

$
(3,479
)

$
(384
)Limited partners interest in net loss

$
(170,453
)

$
(18,822
)Net loss per limited partner unit: (basic and diluted)


(8.05
)


(0.89
)Weighted average limited partner units outstanding:Common units (basic and diluted)


12,309,432



12,301,521Subordinated units (basic and diluted)


8,857,981



8,857,981    F-7




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  STATEMENTS OF CASH FLOWS
 ($ in thousands)
  Successor


PredecessorNovember 15,


January 1,2007


2007Year Ended


to


to


Years EndedDecember 31,


December 31,


November 14,


December 31,2008


2007


2007


2006


2005(Consolidated)


(Consolidated)


(Carve out)


(Carve out)


(Carve out)(Restated)


(Restated)


(Restated)


(Restated)Cash flows from operating activities:Net income (loss)

$
(173,932
)

$
(19,206
)

$
(29,174
)

$
29,133


$
(85,307
)Adjustments to reconcile net income (loss) to cash provided by
    (used in) operations:Depreciation, depletion and amortization


50,988



5,045



29,568



24,760



19,037Impairment of oil and gas properties


245,587















Accretion of debt discount


















9,656Unit-based compensation


35















Change in fair value of derivative financial instruments


(72,533
)


4,972



346



(70,402
)


46,602Capital contributions for retirement plan and services


















559Contributions for consideration for compensation to employees










5,322



1,037



1,217Amortization of deferred loan costs


1,254



9,063



1,599



1,204



4,497Bad debt expense










22



85



302Loss on early extinguishment of debt


















8,255Change in assets and liabilities:Accounts receivable


(11,610
)


(316
)


10,230



(590
)


(3,646
)Other receivables


(2,590
)


280



(280
)


343



180Other current assets


1,060



(1,489
)


(549
)


674



(1,483
)Other assets


(2
)


(3
)


514



90



790Due from affiliates


18,613



(11,007
)


(572
)


(6,791
)


2,646Accounts payable


(9,942
)


(6,236
)


9,250



5,800



119Revenue payable


2,302



(5,567
)


1,497



4,788



(19
)Accrued expenses


1,825



113



(438
)


315



63Other long-term liabilities


403



31



140



168



211Other






1



(1
)


1



(239
)Net cash provided by (used in) operating activities


51,458



(24,319
)


27,474



(9,385
)


3,440Cash flows from investing activities:Restricted cash


1,093







(55
)


3,168



(4,318
)Acquisition of business  PetroEdge


(71,213
)














Equipment, development and leasehold


(84,173
)


(7,341
)


(88,864
)


(103,523
)


(32,551
)Acquisition of minority interest  ArcLight


















(7,800
)Net cash used in investing activities


(154,293
)


(7,341
)


(88,919
)


(100,355
)


(44,669
)Cash flows from financing activities:Proceeds from bank borrowings


45,064



580







149,862



75,892Repayments of note borrowings


(3,800
)


(260,013
)


(428
)


(589
)


(102,777
)Proceeds from revolver note


95,000



94,000



35,000



75,000



Repayment of revolver note














(75,000
)


Contributions(distributions)


626



49,783



15,226



(22,158
)


121,568Distributions to unitholders


(28,360
)


Proceeds from issuance of common units






163,800











Syndication costs


(265
)


(12,775
)










Equity offering costs


















13,297Repayment of subordinated debt


















(66,390
)Refinancing costs


(1,893
)


(3,546
)


(1,687
)


(4,568
)


(6,281
)Net cash provided by financing activities


106,372



31,829



48,111



122,547



35,309Net increase (decrease) in cash and cash equivalents


3,537



169



(13,334
)


12,807



(5,920
)Cash and cash equivalents, beginning of period


169







13,334



527



6,447Cash and cash equivalents, end of period

$
3,706


$
169


$



$
13,334


$
527    F-8




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
 STATEMENTS
    OF PARTNERS EQUITY

(amounts as of and prior to December 31, 2007 are
    restated)

($ in thousands) Predecessor (Carve out):Balance, December 31, 2004

$
705Net Loss


(85,307
)Partner contributions


121,568Contributions for consideration for compensation to employees


1,217Contributions for retirement plan


495Contributions for consideration of services


64Balance, December, 2005


38,742Net income


29,133Contributions for consideration for compensation to employees


1,037Partners distributions


(22,158
)Balance, December 31, 2006


46,754Net loss


(29,174
)Contributions for consideration for compensation to employees


5,322Partner contributions


15,226Balance, November 14, 2007

$
38,128   Common











General


General


TotalUnits


Common


Subordinated


Subordinated


Partner


Partner


PartnersIssued


Unitholders


Units


Unitholders


Units


Interest


EquitySuccessor (Consolidated):Balance, November 14, 2007





$







$







$



$
Proceeds from initial public offering, net of underwriting
    discount


9,100,000



153,153



















153,153Offering costs






(2,128
)


















(2,128
)Acquisition of the Predecessor


3,201,521



22,532



8,857,981



62,340



431,827



3,039



87,911Net loss






(10,947
)






(7,875
)






(384
)


(19,206
)Balance, December 31, 2007


12,301,521



162,610



8,857,981



54,465



431,827



2,655



219,730Net loss






(99,097
)






(71,356
)






(3,479
)


(173,932
)Offering costs






(265
)


















(265
)Contributions






341







285











626Unit-based compensation


30,000



35



















35Distributions






(17,792
)






(9,251
)






(623
)


(27,666
)Balance, December 31, 2008


12,331,521


$
45,832



8,857,981


$
(25,857
)


431,827


$
(1,447
)

$
18,528    F-9




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES



NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS  Note 1 
    Organization,
    Basis of Presentation, Misappropriation, Reaudit and
    Restatement, Going Concern and Business  Organization
      Basis
    of Presentation
  Regulation S-X,
  Misappropriation,
    Reaudit and Restatement
  Form 10-Q/A Form 10-Q/A Form 10-Q
  Investigation 
 F-10




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Form 8-K
  8-K
    Going
    Concern
     F-11




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
      Form 10-K and/or
      and/or
  Business
    
    Cherokee Basin.  152.7 Bcfe of estimated
    net proved reserves as of December 31, 2008 and an average
    net daily production of 57.3 Mmcfe for the year ended
    December 31, 2008 in the Cherokee Basin; F-12




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
   
    Appalachian Basin.  10.9 Bcfe of estimated
    net proved reserves as of December 31, 2008 and an average
    net daily production of 2.9 Mmcfe for the year ended
    December 31, 2008 in the Marcellus Shale and Devonian Sand
    formations in West Virginia and New York; and
    Seminole County.  588,800 Bbls of
    estimated net proved reserves as of December 31, 2008 and
    an average net daily production of approximately 148 Bbls
    for the year ended December 31, 2008 of oil producing
    properties in Seminole County, Oklahoma.        
    the contribution of Quest Cherokee and its subsidiary, QCOS, to
    us. Quest Cherokee owns all of QRCPs oil and gas leases in
    the Cherokee Basin;
    the issuance of 431,827 General Partner Units and the incentive
    distribution rights to Quest Energy GP and the continuation of
    its 2.0% general partner interest in us; and
    the issuance of 3,201,521 common and
    8,857,981 subordinated units to QRC
    QRCP and its affiliates on the one hand, and we and Quest
    Cherokee on the other, agreed to indemnify the other parties
    from and against all losses suffered or incurred by reason of or
    arising out of certain existing legal proceedings.    
    reimbursement of certain insurance, operating and general and
    administrative expenses incurred on behalf of us;
    indemnification for certain environmental liabilities, tax
    liabilities, title defects and other losses in connection with
    assets;
    a license for the use of the Quest name and mark; and
    our right to purchase from QRCP and its affiliates certain
    assets that QRCP and its affiliates acquire within the Cherokee
    Basin.     F-13




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
      
    the gathering, treating, processing and transporting of gas in
    North America;
    the transporting and fractionating of gas liquids in North
    America;
    any other midstream activities, including but not limited to
    crude oil storage, transportation, gathering and terminaling;
    constructing, buying or selling any assets related to the
    foregoing businesses; and
    any line of business other than those described in the preceding
    bullet points that generates qualifying income,
    within the meaning of Section 7704(d) of the Internal
    Revenue Code of 1986, as amended, other than any business that
    is primarily engaged in the exploration for and production of
    oil or gas and the sale and marketing of gas and oil derived
    from such exploration and production activities.    Note 2 
    Summary
    of Significant Accounting Policies  Principles of Consolidation
  Use of Estimates in the Preparation of Financial
    Statements
  Revenue Recognition
 F-14




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Cash and Cash Equivalents
  Accounts Receivable
  Inventory
  Oil and Gas Properties
      Unevaluated Properties
 F-15




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Capitalized General and Administrative
    Expenses
  Other Property and Equipment
    Impairment 
  Other Assets
  Asset Retirement Obligations
    Derivative Instruments
 F-16




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
          Legal
  Environmental Costs  and/or
  Unit-Based Compensation
  Share-Based Payment
  Income Taxes
  Net Income (Loss) per Unit 03-06, Participating Securities and the Two 
    Class Method under FASB Statement No. 128
 F-17




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  (EITF 03-06). EITF 03-06
  Concentrations of Market Risk
  Concentration of Credit Risk
    Fair Value Fair Value Measurements FSP 157-2,
    
    Level 1  Quoted prices available in active
    markets for identical assets or liabilities as of the reporting
    date.
    Level 2  Pricing inputs other than quoted prices
    in active markets included in Level 1 which are either
    directly or indirectly observable as of the reporting date.
    Level 2 consists primarily of non-exchange traded commodity
    derivatives.
    Level 3  Pricing inputs include significant
    inputs that are generally less observable from objective sources.   F-18




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Recently
    Adopted Accounting Principles
  FAS No. 157-2 FAS 157-3, Determining the Fair Value of a Financial Asset When the
    Market for That Asset is Not Active FAS 157-3), FAS 157-3
    Exchanges of
    Nonmonetary Assets
  No. 04-13, Accounting for Purchases and Sales of Inventory with the Same
    Counterparty (EITF 04-13), EITF 04-13
  Recent
    Accounting Pronouncements
  FIN 39-1, Amendment of FASB Interpretation No. 39 FIN 39-1), Offsetting of Amounts Related to
    Certain Contracts FIN 39-1 FIN 39-1 FIN 39-1.
 F-19




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Business Combinations
  The Fair
    Value Option for Financial Assets and Financial Liabilities contract-by-contract
  Non-controlling Interests in Consolidated Financial
    Statements  An Amendment of ARB No. 51
  No. 07-4, Application of the Two-Class Method under FASB Statement
    No. 128, Earnings per Share, to Master Limited
    Partnerships No. 07-4
  Disclosures about Derivative Instruments and Hedging
    Activities  an amendment of FASB Statement
    No. 133
  No. 03-6-1, Determining Whether Instruments Granted in
    Share-Based
    Payment Transactions Are Participating Securities EITF 03-6-1). EITF 03-6-1 Earnings per Share. EITF 03-6-1
 F-20




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  EITF 03-6-1 EITF 03-6-1 EITF 03-6-1
  No. 33-8995, Modernization of Oil and Gas Reporting Form 10-K Form 10-K
  Note 3 
    Acquisitions
    and Divestitures  Acquisitions
  PetroEdge 
    Business Combinations.
  Proved oil and gas properties

$
73,406Asset retirement obligations


(2,193
)Purchase price

$
71,213  F-21




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Pro Forma
    Summary Data related to acquisitions (unaudited)
    Successor


PredecessorNovember 15, 2007


January 1, 2007Year Ended


to


toDecember 31,


December 31,


November 14,2008


2007


2007(Consolidated)


(Consolidated)


(Carve-out)Pro forma revenue

$
154,630


$
16,879


$
100,554Pro forma net income (loss)

$
(185,616
)

$
(20,397
)

$
(43,380
)Pro forma net income (loss) per limited partner unit 
    basic and diluted

$
(8.58
)

$
(0.94
)       Seminole County 
  Note 4 
    Long-Term
    Debt    Successor


PredecessorDecember 31


December 31


December 312008


2007


2006Borrowings under bank senior credit facilitiesFirst Lien Credit Agreement

$
189,000


$
94,000


$
225,000Second Lien Loan Agreement


41,200







Notes payable to banks and finance companies, secured by
    equipment and vehicles, due in installments through October 2013
    with interest ranging from 2.9% to 9.8% per annum


772



708



569Total debt


230,972



94,708



225,569Less current maturities included in current liabilities


41,882



666



324Total long-term debt

$
189,090


$
94,042


$
225,245  F-22




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    2009

$
41,8822010


189,0502011


262012


72013 and thereafter


7Total

$
230,972   Other
    Long-Term Indebtedness
    Credit
    Facilities
       F-23




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
      and/or and/or
           F-24




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    pari passu
      
    permitting the ratio (calculated based on the most recently
    delivered compliance certificate) of our consolidated current
    assets (including the unused availability under the revolving
    credit facility, but excluding non-cash assets under
    FAS 133) to consolidated current liabilities
    (excluding non-cash obligations under FAS 133, asset and
    asset retirement obligations and current maturities of
    indebtedness under the First Lien Credit Agreement) at any
    fiscal quarter-end to be less than 1.0 to 1.0; provided,
    however, that current assets and current liabilities will
    exclude mark-to-market values of swap contracts, to the extent
    such values are included in current assets and current
    liabilities;
    permitting the interest coverage ratio (calculated on the most
    recently delivered compliance certificate) of adjusted
    consolidated EBITDA to consolidated interest charges at any
    fiscal quarter-end to be less than 2.5 to 1.0 measured on a
    rolling four quarter basis; and
    permitting the leverage ratio (calculated based on the most
    recently delivered compliance certificate) of consolidated
    funded debt to adjusted consolidated EBITDA at any fiscal
    quarter-end to be greater than 3.5 to 1.0 measured on a rolling
    four quarter basis.    and/or
   F-25




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
        30-day
    Subordinated Notes 
   F-26




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Note 5 
    Property    Successor


Predecessor2008


2007


2006Oil and gas properties under the full cost method of accounting:Properties being amortized

$
283,001


$
374,631


$
283,420Properties not being amortized


1,282



5,294



7,843Total oil and gas properties, at cost


284,283



379,925



291,263Less: accumulated depletion, depreciation and amortization


(133,163
)


(85,596
)


(54,437
)Oil and gas properties, net

$
151,120


$
294,329


$
236,826Other property and equipment at cost

$
26,133


$
22,589


$
21,079Less: accumulated depreciation


(8,766
)


(5,473
)


(4,373
)Other property and equipment, net

$
17,367


$
17,116


$
16,706       Buildings


25 yearsMachinery and equipment


10 yearsSoftware and computer equipment


3 to 5 yearsFurniture and fixtures


10 yearsVehicles


7 years    F-27




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Note 6 
    Derivative
    Financial Instruments      Interest Rate Derivatives
  Commodity Derivatives
    Successor


PredecessorNovember 15,


January 1,2007


2007Year Ended


to


to


Years EndedDecember 31,


December 31,


November 14,


December 31,2008


2007


2007


2006


2005(Consolidated)


(Consolidated)


(Carve out)


(Carve out)


(Carve out)Realized gains (losses)

$
8,174


$
389


$
6,890


$
(17,712
)

$
(26,964
)Unrealized gains (losses)


72,533



(4,972
)


(346
)


70,402



(46,602
)Total

$
80,707


$
(4,583
)

$
6,544


$
52,690


$
(73,566
)  F-28




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Year Ending December 31,2009


2010


2011


Thereafter


Total($ in thousands, except volumes and per unit data)Natural Gas Swaps:Contract volumes (Mmbtu)


14,629,200



12,499,060



2,000,004



2,000,004



31,128,268Weighted-average fixed price per Mmbtu

$
7.78


$
7.42


$
8.00


$
8.11


$
7.67Fair value, net

$
38,107


$
14,071


$
2,441


$
2,335


$
56,954Natural Gas Collars:Contract volumes (Mmbtu):Floor


750,000



630,000



3,549,996



3,000,000



7,929,996Ceiling


750,000



630,000



3,549,996



3,000,000



7,929,996Weighted-average fixed price per Mmbtu:Floor

$
11.00


$
10.00


$
7.39


$
7.03


$
7.79Ceiling

$
15.00


$
13.11


$
9.88


$
7.39


$
9.52Fair value, net

$
3,630


$
1,875


$
3,144


$
2,074


$
10,723Total Natural Gas Contracts:Contract volumes (Mmbtu)


15,379,200



13,129,060



5,550,000



5,000,004



39,058,264Weighted-average fixed price per Mmbtu

$
7.94


$
7.55


$
7.61


$
7.44


$
7.70Fair value, net

$
41,737


$
15,946


$
5,585


$
4,409


$
67,677Crude Oil Swaps:Contract volumes (Bbl)


36,000



30,000











66,000Weighted-average fixed per Bbl

$
90.07


$
87.50


$



$



$
88.90Fair value, net

$
1,246


$
666


$



$



$
1,912  F-29




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Years Ending December 31,2008


2009


2010


Thereafter


Total($ in thousands, except volumes and per unit data)Natural Gas Swaps:Contract volumes (Mmbtu)


8,595,876



12,629,365



10,499,225







31,724,466Weighted-average fixed price per Mmbtu

$
6.39


$
7.70


$
7.31


$



$
7.22Fair value, net

$
1,517


$
1,721


$
(4,565
)

$



$
(1,327
)Natural Gas Collars:Contract volumes (Mmbtu):


7,027,566















7,027,566Floor


7,027,566















7,027,566CeilingWeighted-average fixed price per Mmbtu:Floor

$
6.54


$



$



$



$
6.54Ceiling

$
7.53


$



$



$



$
7.53Fair value, net

$
(1,617
)

$



$



$



$
(1,617
)Total Natural Gas Contracts:Contract volumes (Mmbtu)


15,623,442



12,629,365



10,499,225







38,752,032Weighted-average fixed price per Mmbtu

$
6.46


$
7.70


$
7.31


$



$
7.09Fair value, net

$
(100
)

$
1,721


$
(4,565
)

$



$
(2,944
)  F-30




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Years Ending December 31,2007


2008


2009


Thereafter


Total($ in thousands, except volumes and per unit data)Natural Gas Swaps:Contract volumes (Mmbtu)


2,353,885















2,353,885Weighted-average fixed price per Mmbtu

$
7.20


$



$



$



$
7.20Fair value, net

$
2,107


$



$



$



$
2,107Natural Gas Collars:Contract volumes (Mmbtu):Floor


8,432,595



7,027,566











15,460,161Ceiling


8,432,595



7,027,566











15,460,161Weighted-average fixed price per Mmbtu:Floor

$
6.63


$
6.54


$



$



$
6.59Ceiling

$
7.54


$
7.53


$



$



$
7.54Fair value, net

$
3,512


$
(2,856
)

$



$



$
656Natural Gas Basis Swaps:Contract volumes (Mmbtu)


1,825,000



1,464,000











3,289,000Weighted-average fixed price per Mmbtu


(1.15
)


(1.03
)










(1.10
)Fair value, net


(389
)














(389
)Total Natural Gas Contracts:Contract volumes (Mmbtu)


10,786,480



7,027,566











17,814,046Weighted-average fixed price per Mmbtu

$
6.75


$
6.54


$



$



$
6.67Fair value, net

$
5,230


$
(2,856
)

$



$



$
2,374   Note 7 
    Financial
    Instruments    Fair Value 
  Netting andLevel


Level


Level


Cash


Total Net FairAt December 31, 2008

1


2


3


Collateral*


ValueDerivative financial instruments  assets

$



$
8,866


$
64,883


$
(4,160
)

$
69,589Derivative financial instruments  liabilities

$



$
(224
)

$
(3,936
)

$
4,160


$
Total

$



$
8,642


$
60,947


$



$
69,589     *
    
    Amounts represent the effect of legally enforceable master
    netting agreements between us and our counterparties and the
    payable or receivable for cash collateral held or placed with
    the same counterparties.   F-31




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
        Year EndedDecember 31,2008Balance at beginning of year

$
3,444Realized and unrealized gains included in earnings


68,038Purchases, sales, issuances, and settlements


(10,535
)Transfers into and out of Level 3


Balance as of December 31, 2008

$
60,947   Note 8 
    Asset
    Retirement Obligations    Successor


PredecessorNovember 15,


January 1,2007


2007Year Ended


to


to


Year EndedDecember 31,


December 31,


November 14,


December 31,2008


2007


2007


2006(Consolidated)


(Consolidated)


(Carve out)


(Carve out)Asset retirement obligations at beginning of year

$
1,700


$
1,657


$
1,410


$
1,150Liabilities incurred


134



31



147



175Liabilities settled


(22
)






(7
)


(7
)Acquisition of PetroEdge


2,193











Accretion


297



12



107



92Revisions in estimated cash flows


290











Asset retirement obligations at end of year

$
4,592


$
1,700


$
1,657


$
1,410  F-32




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Note 9 
    Partners
    Equity  Issuance
    of Units
    Common
    Units
      
    distributions of available cash from operating surplus on each
    of the outstanding common units and subordinated units equaled
    or exceeded the minimum quarterly distribution for each of the
    three consecutive, non-overlapping four quarter periods
    immediately preceding that date;
    the adjusted operating surplus (as defined in our partnership
    agreement) generated during each of the three consecutive,
    non-overlapping four quarter periods immediately preceding that
    date equaled or exceeded the sum of the minimum quarterly
    distributions on all of the outstanding common and subordinated
    units during those periods on a fully diluted basis during those
    periods; and
    there are no arrearages in payment of the minimum quarterly
    distribution on the common units.    
    the subordination period will end and each subordinated unit
    will immediately convert into one common unit;
    any existing arrearages in payment of the minimum quarterly
    distribution on the common units will be extinguished; and
    Quest Energy GP will have the right to convert its 2% general
    partner interest and its incentive distribution rights into
    common units or to receive cash in exchange for those interests.     F-33




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Subordinated
    Units
        General
    Partner Interest
      Allocations
    of Net Income
    Cash
    Distributions
        
    first, 98% to the holders of common units and 2% to Quest
    Energy GP, until each common unit has received a minimum
    quarterly distribution of $0.40 plus any arrearages from prior
    quarters; F-34




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
   
    second, 98% to the holders of subordinated units and 2%
    to Quest Energy GP, until each subordinated unit has received a
    minimum quarterly distribution of $0.40;
    third, 98% to all unitholders, pro rata, and 2% to Quest
    Energy GP, until each unit has received a distribution of $0.46;
    fourth, 85% to all unitholders, pro rata, and 15% to
    Quest Energy GP, until each unit has received a distribution of
    $0.50; and
    thereafter, 75% to all unitholders, pro rata, and 25% to
    Quest Energy GP.    Marginal PercentageInterest inTotal Quarterly

DistributionsDistributions

Limited


GeneralTarget Amount

Partner


PartnerMinimum quarterly distribution

$0.40


98
%


2
%First target distribution

Up to $0.46


98
%


2
%Second target distribution

Above $0.46, up to $0.50


85
%


15
%Thereafter

Above $0.50


75
%


25
%   Equity
    Compensation Plans
    Note 10 
    Net
    Income Per Limited Partner Unit  No. 03-06 (EITF 03-06), Participating Securities and the Two-Class Method under
    Financial Accounting Standards Board (FASB)
    Statement No. 128,
  EITF 03-06 EITF 03-06,
 F-35




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    November 15,2007Year Ended


toDecember 31,


December 31,2008


2007Net loss

$
(173,932
)

$
(19,206
)Less: General partner 2.0% ownership


(3,479
)


(384
)Net loss available to limited and subordinated partners

$
(170,453
)

$
(18,822
)Basic and diluted weighted average number of units:Common units


12,309,432



12,301,521Subordinated units


8,857,981



8,857,981Basic and diluted net loss per limited partner unit

$
(8.05
)

$
(0.89
)   Note 11 
    Commitments
    and Contingencies  Litigation
    Federal
    Securities Class Actions
  Michael Friedman, individually and on behalf of all others
    similarly situated v. Quest Energy Partners LP, Quest
    Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
    E. Grose, Case
    No. 08-cv-936-M
    U.S., District Court for the Western District of Oklahoma, filed
    September 5, 2008
  James Jents, individually and on behalf of all others
    similarly situated v. Quest Resource Corporation, Jerry
    Cash, David E. Grose, and John Garrison, Case
    No. 08-cv-968-M,
    U.S. District Court for the Western District of Oklahoma,
    filed September 12, 2008
  J. Braxton Kyzer and Bapui Rao, individually and on behalf
    of all others similarly situated v. Quest Energy Partners
    LP, Quest Energy GP LLC, Quest Resource Corporation and David E.
    Grose, Case
    No. 08-cv-1066-M,
    U.S. District Court for the Western District of Oklahoma,
    filed October 6, 2008
  Paul Rosen, individually and on behalf of all others
    similarly situated v. Quest Energy Partners LP, Quest
    Energy GP LLC, Quest Resource Corporation, Jerry Cash, and David
    E. Grose, Case
    No. 08-cv-978-M,
    U.S. District Court for the Western District of Oklahoma,
    filed September 17, 2008
 F-36




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Rule 10b-5 and/or Michael Friedman,
    individually and on behalf of all others similarly
    situated v. Quest Energy Partners LP, Quest Energy GP LLC,
    Quest Resource Corporation, Jerry Cash, and David E. Grose No. 08-cv-936-M,
  Royalty
    Owner Class Action
  Hugo Spieker, et al. v. Quest Cherokee, LLCCase
    No. 07-1225-MLB
    in the U.S. District Court, District of Kansas, filed
    August 6, 2007
    Personal
    Injury Litigation
  Segundo Francisco Trigoso and Dana Jara De Trigoso v.
    Quest Cherokee Oilfield Service, LLC,CJ-2007-11079,
    in the District Court of Oklahoma County, State of Oklahoma,
    filed December 27, 2007
    St. Paul Surplus Lines Insurance Company v.
    Quest Cherokee Oilfield Service, LLC, et al, CJ-2009-1078, in the District Court of Tulsa County, State of
    Oklahoma, filed February 11, 2009
 F-37




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Trigoso Trigoso
  Billy Bob Willis, et al. v. Quest Resource
    Corporation, et al.,Case
    No. CJ-09-00063,
    District Court of Nowata County, State of Oklahoma, filed
    April 28, 2009.
    Berenice Urias v. Quest Cherokee, LLC, et al.,
    CV-2008-238C in the Fifth Judicial District, County of Lea,
    State of New Mexico (Second Amended Complaint filed
    September 24, 2008)
    Juana Huerter v. Quest Cherokee Oilfield Services,
    LLC, et al.,Case No. 2008 CV-50, District Court of
    Neosho County, State of Kansas, filed May 5, 2008
  et al.
  Bradley Haviland, Jr., v. Quest Cherokee
    Oilfield Services, LLC, et al.,Case No. 2008 CV-78,
    District Court of Neosho County, State of Kansas, filed
    July 25, 2008
  et al.
  Litigation
    Related to Oil and Gas Leases
    Roger Dean Daniels v. Quest Cherokee, LLC,Case
    No. 06-CV-61,
    in the District Court of Montgomery County, State of Kansas,
    filed May 5, 2006
  Carol R. Knisely, et al. v. Quest Cherokee, LLC,Case
    No. 07-CV-58-I,
    in the District Court of Montgomery County, State of Kansas,
    filed April 16, 2007
  Quest Cherokee, LLC v. David W. Hinkle, et al.,Case
    No. 2006-CV-74,
    in the District Court of Labette County, State of Kansas, filed
    September 5, 2006
  Scott Tomlinson, et al. v. Quest Cherokee, LLC,Case
    No. 2007-CV-45,
    in the District Court of Wilson County, State of Kansas, filed
    August 29, 2007
 F-38




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Ilene T. Bussman et al. v. Quest Cherokee, LLC,Case
    No. 07-CV-106-PA,
    in the District Court of Labette County, State of Kansas, filed
    November 26, 2007
  Gary Dale Palmer, et al. v. Quest Cherokee, LLC,Case
    No. 07-CV-107-PA,
    in the District Court of Labette County, State of Kansas, filed
    November 26, 2007
  Richard L. Bradford, et al. v. Quest Cherokee, LLC,Case
    No. 2008-CV-67,
    in the District Court of Wilson County, Kansas, filed
    September 18, 2008
    Richard Winder v. Quest Cherokee, LLC,Case Nos.
    07-CV-141 and 08-CV-20, in the District Court of Wilson County,
    Kansas, filed December 7, 2007, and February 27,
    2008
  Housel v. Quest Cherokee, LLC, 06-CV-26-I, in the
    District Court of Montgomery County, State of Kansas, filed
    March 2, 2006
  and/or
  Central Natural Resources, Inc. v. Quest Cherokee,
    LLC, et al.,Case
    No. 04-C-100-PA
    in the District Court of Labette County, State of Kansas, filed
    on September 1, 2004
    Central Natural Resources, Inc. v. Quest Cherokee,
    LLC, et al., Case
    No. CJ-06-07
    in the District Court of Craig County, State of Oklahoma, filed
    January 17, 2006
 F-39




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Edward E. Birk, et ux., and Brian L. Birk, et ux., v.
    Quest Cherokee, LLC, Case
    No. 09-CV-27,
    in the District Court of Neosho County, State of Kansas, filed
    April 23, 2009
  and/or
  Robert C. Aker, et al. v. Quest Cherokee, LLC, et
    al., U.S. District Court for the Western District of
    Pennsylvania, Case
    No. 3-09CV101,
    filed April 16, 2009
    Other
  Well Refined Drilling Co. v. Quest Cherokee, LLC,Case
    No. 2007-CV-91,
    in the District Court of Neosho County, State of Kansas, filed
    July 19, 2007; and Well Refined Drilling Co. v.
    Quest Cherokee, LLC,Case
    No. 2007-CV-46,
    in the District Court of Wilson County, State of Kansas, filed
    September 4, 2007
    Larry Reitz, et al. v. Quest Resource Corporation, et
    al.,Case
    No. CJ-09-00076,
    District Court of Nowata County, State of Oklahoma, filed
    May 15, 2009.
   F-40




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Barbara Cox v. Quest Cherokee, LLC,
    U.S. District Court for the District of New Mexico, Case
    No. CIV-08-0546,
    filed April 18, 2008
    Environmental Matters 
  Operating Lease Commitments 
    Year ending December 31,2009

$
1742010


1492011


1472012


1442013


82Thereafter


Total minimum lease obligations

$
696     Financial Advisor Contract 
  Note 12 
    Other
    Assets  Deferred Financing Costs 
 F-41




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Note 13 
    Supplemental
    Cash Flow Information  Successor


PredecessorNovember 15,


January 1,2007


2007Year Ended


to


toDecember 31,


December 31,


November 14,


Year Ended December 31,2008


2007


2007


2006


2005(Consolidated)


(Consolidated)


(Carve out)


(Carve out)


(Carve out)Cash paid for interest

$
11,526


$
4,714


$
23,828


$
20,913


$
10,315Cash paid for income taxes

$



$



$



$



$
   Note 14 
    Related
    Party Transactions    Omnibus Agreement.
        Midstream Services Agreement.
 F-42




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    and/or
          Management Services Agreement.
 F-43




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
            Midstream Omnibus Agreement.
    
    the gathering, treating, processing and transporting of gas in
    North America;
    the transporting and fractionating of gas liquids in North
    America;
    any other midstream activities, including but not limited to
    crude oil storage, transportation, gathering and terminaling;
    constructing, buying or selling any assets related to the
    foregoing businesses; and
    any line of business other than those described in the preceding
    bullet points that generates qualifying income,
    within the meaning of Section 7704(d) of the Code, other
    than any business that is primarily engaged in the exploration
    for and production of oil or gas and the sale and marketing of
    gas and oil derived from such exploration and production
    activities.      
    the ownership of a passive investment of less than 5% in an
    entity engaged in a Restricted Business;
    any business in which Quest Midstream permits us to engage; F-44




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
   
    the ownership or operation of assets used in a Restricted
    Business if the value of the assets is less than
    $4 million; and
    any business that we have given Quest Midstream the option to
    acquire and it has elected not to purchase.      Contribution, Conveyance and Assumption
    Agreement.
  Note 15 
    Employee
    Benefit Plan and Stock-Based Awards with Related Party        Note 16 
    Restatement  Form 8-K 8-K
 F-45




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
      Form 10-K Form 10-K, Form 10-Q/A, Form 10-Q
     F-46




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Successor


PredecessorAs of December 31,2007


2006


2005Partners equity as previously reported

$
228,760


$
51,091


$
69,547A  Effects of the transfers


(9,500
)


(8,000
)


(2,000
)B  Reversal of hedge accounting


707



(2,389
)


(8,177
)C  Accounting for formation of Quest Cherokee


(15,102
)


(15,102
)


(15,102
)D  Capitalization of costs in full cost pool


(24,007
)


(12,671
)


(5,388
)E  Recognition of costs in proper periods


(1,540
)


(233
)


(272
)F  Depreciation, depletion and amortization


11,920



8,249



4,054G  Impairment of oil and gas properties


30,719



30,719



H  Other errors


(2,227
)


(4,910
)


(3,920
)Partners equity as restated

$
219,730


$
46,754


$
38,742   Successor


PredecessorNovember 15,


January 1,2007 to


2007 to


Year Ended


Year EndedDecember 31,


November 14,


December 31,


December 31,2007


2007


2006


2005Net income (loss) as previously reported

$
(18,511
)

$
(19,191
)

$
(47,549
)

$
(25,192
)A  Effects of the transfers






(1,500
)


(6,000
)


(2,000
)B  Reversal of hedge accounting


1,110



73



53,387



(42,854
)C  Accounting for formation of Quest Cherokee














(10,319
)D  Capitalization of costs in full cost pool


(1,839
)


(9,497
)


(7,283
)


(5,388
)E  Recognition of costs in proper periods






(1,307
)


39



(80
)F  Depreciation, depletion and amortization


335



3,336



4,195



1,448G  Impairment of oil and gas properties










30,719



H  Other errors


(301
)


(1,088
)


1,625



(922
)Net income (loss) as restated

$
(19,206
)

$
(29,174
)

$
29,133


$
(85,307
)     (A)
  (B)
 F-47




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    (C)
  (D)
  (E)
  (F)
  (G)
  (H)
    F-48




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Predecessor (carve out)


SuccessorJanuary 1, 2007 to


November 15, 2007 toNovember 14, 2007


December 31, 2007As Previously


Restatement


As


As Previously


Restatement


AsReported


Adjustments


Restated


Reported


Adjustments


RestatedRevenues:Oil and gas sales

$
97,193


$
(7,256
)

$
89,937


$
15,842


$
(494
)

$
15,348Other revenue and expenses


(45
)


45







22



(22
)


Total revenues


97,148


$
(7,211
)

$
89,937


$
15,864


$
(516
)

$
15,348Costs and expenses:Oil and gas production


24,416



7,020



31,436



3,579



391



3,970Transportation expense


24,836



1



24,837



4,342







4,342General and administrative expenses


10,272



768



11,040



1,562



1,310



2,872Impairment of oil and gas properties






















Depreciation, depletion and amortization


30,672



(1,104
)


29,568



5,046



(1
)


5,045Misappropriation of funds






1,500



1,500











Total costs and expenses


90,196



8,185



98,381



14,529



(1,700
)


16,229Operating income (loss)


6,952



(15,396
)


(8,444
)


1,335



(2,216
)


(881
)Other income (expense):Gain (loss) from derivative financial instruments


(420
)


6,964



6,544



(6,082
)


1,499



(4,583
)Sale of assets


(310
)






(310
)


(18
)






(18
)Other income (expense)






(45
)


(45
)






22



22Interest expense


(25,815
)


(1,506
)


(27,321
)


(13,760
)






(13,760
)Interest income


402







402



14







14Total other income (expense)


(26,143
)


5,413



(20,730
)


(19,846
)


1,521



(18,325
)Net loss

$
(19,191
)

$
(9,983
)

$
(29,174
)

$
(18,511
)

$
(695
)

$
(19,206
)General Partners interest in net loss













$
(370
)

$
(14
)

$
(384
)Limited partners interest in net loss













$
(18,141
)

$
(681
)

$
(18,822
)Basic and diluted net loss per limited partner unit













$
(6.80
)

$
5.91


$
(0.89
)Weighted average limited partner units outstanding:Common














1,150,329



11,151,192



12,301,521Subordinated














1,116,348



7,741,633



8,857,981  F-49




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    SuccessorDecember 31, 2007As Previously


Restatement


AsReported


Adjustments


RestatedASSETSCurrent assets:Cash

$
10,170


$
(10,001
)

$
169Restricted cash


1,205







1,205Accounts receivable, trade, net


297



(211
)


86Other receivables










Due from affiliates


12,788



2,836



15,624Other current assets


2,923



168



3,091Inventory


4,956







4,956Current derivative financial instrument assets


6,729



1,279



8,008Total current assets


39,068



(5,929
)


33,139Property and equipment, net


17,063



53



17,116Oil and gas properties under full cost method of accounting, net


298,021



(3,692
)


294,329Other assets, net


3,526







3,526Long-term derivatives financial instrument assets


1,568



1,899



3,467Total assets

$
359,246


$
(7,669
)

$
351,577LIABILITIES AND PARTNERS EQUITYCurrent liabilities:Accounts payable

$
15,195


$
2,559


$
17,754Revenue payable






919



919Accrued expenses


5,056



(4,417
)


639Due to affiliates






1,708



1,708Current portion of notes payable


666







666Current derivative financial instrument liabilities


8,241



(133
)


8,108Total current liabilities


29,158



636



29,794Non-current liabilities:Long-term derivative financial instrument liabilities


5,586



725



6,311Asset retirement obligation


1,700







1,700Notes payable


94,042







94,042Non-current liabilities


101,328



725



102,053Total liabilities


130,486



1,361



131,847Commitments and contingenciesPartners equity:Common unitholders


163,962



(1,352
)


162,610Subordinated unitholder


63,235



(8,770
)


54,465General partner


3,048



(393
)


2,655Accumulated other comprehensive income (loss)


(1,485
)


1,485



Total partners equity


228,760



(9,030
)


219,730Total liabilities and partners equity

$
359,246


$
(7,669
)

$
351,577  F-50




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Predecessor (carve out)


SuccessorJanuary 1, 2007 to


November 15, 2007 toNovember 14, 2007


December 31, 2007As Previously


Restatement


As


As Previously


Restatement


AsReported


Adjustments


Restated


Reported


Adjustments


RestatedCash flows from operating activities:Net income (loss)

$
(19,191
)

$
(9,983
)

$
(29,174
)

$
(18,511
)

$
(695
)

$
(19,206
)Adjustments to reconcile net income (loss) to cash provided by
    operations:Depreciation, depletion and amortization


32,904



(3,336
)


29,568



5,391



(346
)


5,045Change in fair value of derivative financial instruments


420



(74
)


346



6,082



(1,110
)


4,972Contributions for consideration for compensation to employees


12



5,310



5,322



1



(1
)


Amortization of deferred loan costs


1,918



(319
)


1,599



9,042



21



9,063Amortization of gas swap fees


187



(187
)














Bad debt expense






22



22











Loss on disposal of property and equipment


328



(328
)














Change in assets and liabilities:Restricted cash


(55
)


55















Accounts receivable


9,840



390



10,230







(316
)


(316
)Other receivables


110



(390
)


(280
)


(36
)


316



280Other current assets


(108
)


(441
)


(549
)


(1,762
)


273



(1,489
)Inventory


(755
)


755







(823
)


823



Other assets






514



514







(3
)


(3
)Due from affiliates






(572
)


(572
)


(10,830
)


(177
)


(11,007
)Accounts payable


3,719



5,531



9,250



(2,405
)


(3,831
)


(6,236
)Revenue payable


(4,540
)


6,037



1,497







(5,567
)


(5,567
)Accrued expenses


(1,960
)


1,522



(438
)


119



(6
)


113Other long-term liabilities






140



140







31



31Other






(1
)


(1
)






1



1Net cash provided by (used in) operating activities


22,829



4,645



27,474



(13,732
)


(10,587
)


(24,319
)Cash flows from investing activities:Restricted cash






(55
)


(55
)










Equipment, development and leasehold


(98,743
)


9,879



(88,864
)


(7,603
)


262



(7,341
)Proceeds from sale of property and equipment


253



(253
)














 F-51




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Predecessor (carve out)


SuccessorJanuary 1, 2007 to


November 15, 2007 toNovember 14, 2007


December 31, 2007As Previously


Restatement


As


As Previously


Restatement


AsReported


Adjustments


Restated


Reported


Adjustments


RestatedNet cash used in investing activities


(98,490
)


9,571



(88,919
)


(7,603
)


262



(7,341
)Cash flows from financing activities:Proceeds from bank borrowings


35,000



(35,000
)






94,580



(94,000
)


580Repayments of note borrowings


(428
)






(428
)


(260,014
)


1



(260,013
)Proceeds from revolver note






35,000



35,000







94,000



94,000Contributions (distributions)  QRCP


21,298



(6,072
)


15,226



49,415



368



49,783Proceeds from issuance of common units














163,800







163,800Syndication costs of common units














(12,775
)






(12,775
)Refinancing costs


(1,688
)


1



(1,687
)


(3,527
)


(19
)


(3,546
)Change in other long-term liabilities


145



(145
)






26



(26
)


Net cash provided by (used in) financing activities


54,327



(6,216
)


48,111



31,505



324



31,829Net increase (decrease) in cash


(21,334
)


8,000



(13,334
)


10,170



(10,001
)


169Cash, beginning of period


21,334



(8,000
)


13,334











Cash, end of period

$



$



$



$
10,170


$
(10,001
)

$
169  F-52




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Predecessor (carve out)Year Ended December 31, 2006As Previously


Restatement


AsReported


Adjustments


RestatedRevenues:Oil and gas sales

$
65,551


$
6,859


$
72,410Other revenue (expense)


(83
)


83



Total revenues


65,468



6,942



72,410Costs and expenses:Oil and gas production


21,208



3,678



24,886Transportation expense


17,278







17,278General and administrative expenses


8,149



(296
)


7,853Depreciation, depletion and amortization


25,521



(761
)


24,760Impairment of oil and gas properties


30,719



(30,719
)


Misappropriation of funds






6,000



6,000Total costs and expenses


102,875



(22,098
)


80,777Operating income (loss)


(37,407
)


29,040



(8,367
)Other income (expense):Gain (loss) from derivative financial instruments


6,410



46,280



52,690Other income (expense)


(7
)


(83
)


(90
)Interest income (expense)


(16,935
)


1,445



(15,490
)Interest income


390







390Total other income (expense)


(10,142
)


47,642



37,500Net income (loss)

$
(47,549
)

$
76,682


$
29,133  F-53




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Predecessor (carve out)December 31, 2006As Previously


Restatement


AsReported


Adjustments


RestatedASSETSCurrent assets:Cash

$
21,334


$
(8,000
)

$
13,334Restricted cash


1,150







1,150Accounts receivable, trade, net


10,211



(189
)


10,022Due from affiliates






607



607Other current assets


1,053







1,053Inventory


3,378







3,378Current derivative financial instrument assets


10,795



3,314



14,109Total current assets


47,921



(4,268
)


43,653Property and equipment, net


16,054



652



16,706Oil and gas properties under full cost method of accounting:


233,495



3,331



236,826Other assets, net


9,466







9,466Long-term derivative financial instrument assets


4,782



3,240



8,022Total assets

$
311,718


$
2,955


$
314,673LIABILITIES AND PARTNERS EQUITYCurrent liabilities:Accounts payable

$
13,929


$
916


$
14,845Revenue payable


4,540



449



4,989Accrued expenses


2,486



(1,522
)


964Due to affiliates






385



385Current portion of notes payable


324







324Current derivative financial instrument liabilities


5,244



3,635



8,879Total current liabilities


26,523



3,863



30,386Non  current liabilities:Long-term derivative financial instrument liabilities


7,449



3,429



10,878Asset retirement obligation


1,410







1,410Notes payable


225,245







225,245Non-current liabilities


234,104



3,429



237,533Total liabilities


260,627



7,292



267,919Commitments and contingenciesPartners equity:Predecessor capital


50,663



(3,909
)


46,754Accumulated other comprehensive income (loss)


428



(428
)


Total partners equity


51,091



(4,337
)


46,754Total liabilities and partners equity

$
311,718


$
2,955


$
314,673  F-54




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Predecessor (carve out)Year Ended December 31, 2006As Previously


Restatement


AsReported


Adjustments


RestatedCash flows from operating activities:Net income (loss)

$
(47,549
)

$
76,682


$
29,133Adjustments to reconcile net income (loss) to cash provided by
    operations:Depreciation, depletion and amortization


28,339



(3,579
)


24,760Impairment of oil and gas properties


30,719



(30,719
)


Change in fair value of derivative financial instruments


(16,917
)


(53,485
)


(70,402
)Capital contributions for retirement plan


428



(428
)


Capital contributions for director fees


429



(429
)


Contributions for consideration for compensation to employees


779



258



1,037Amortization of deferred loan costs


1,202



2



1,204Amortization of gas swap fees


208



(208
)


Amortization of deferred hedging gains


(328
)


328



Bad debt expense


37



48



85Other


(3
)


3



Change in assets and liabilities:Restricted cash


3,167



(3,167
)


Accounts receivable


(219
)


(371
)


(590
)Other receivables


(28
)


371



343Other current assets






674



674Inventory


(1,970
)


1,970



Other assets


675



(585
)


90Due from affiliates






(6,791
)


(6,791
)Accounts payable


5,836



(36
)


5,800Revenue payable


4,540



248



4,788Accrued expenses


1,838



(1,523
)


315Other long-term liabilities






168



168Other






1



1Net cash provided by (used in) operating activities


11,183



(20,568
)


(9,385
)Cash flows from investing activities:Restricted cash






3,168



3,168Equipment, development and leasehold


(117,387
)


13,864



(103,523
)Proceeds from sale of property and equipment


193



(193
)


Net cash used in investing activities


(117,194
)


16,839



(100,355
) F-55




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Predecessor (carve out)Year Ended December 31, 2006As Previously


Restatement


AsReported


Adjustments


RestatedCash flows from financing activities:Proceeds from bank borrowings


203,696



(53,834
)


149,862Repayments of note borrowings


(54,424
)


53,835



(589
)Proceeds from revolver note






75,000



75,000Repayment of revolver note






(75,000
)


(75,000
)Contributions/(distributions)  QRCP


(20,142
)


(2,016
)


(22,158
)Refinancing costs


(4,479
)


(89
)


(4,568
)Change in other long  term liabilities


167



(167
)


Net cash provided by (used in) financing activities


124,818



(2,271
)


122,547Net increase (decrease) in cash


18,807



(6,000
)


12,807Cash, beginning of period


2,527



(2,000
)


527Cash, end of period

$
21,334


$
(8,000
)

$
13,334     Predecessor (carve out)Year Ended December 31, 2005As Previously


Restatement


AsReported


Adjustments


RestatedRevenues:Oil and gas sales

$
44,565


$
26,063


$
70,628Other revenue and expenses


387



(387
)


Total revenues


44,952



25,676



70,628Costs and expenses:Oil and gas production


14,388



4,764



19,152Transportation expense


7,038







7,038General and administrative expenses


4,068



1,285



5,353Depreciation, depletion and amortization


20,121



(1,084
)


19,037Loss on early extinguishment of debt






8,255



8,255Misappropriation of funds






2,000



2,000Total costs and expenses


45,615



15,220



60,835Operating income (loss)


(663
)


10,456



9,793Other income (expense):Gain (loss) from derivative financial instruments


(4,668
)


(68,898
)


(73,566
)Other income (expense)


12



387



399Interest expense


(19,919
)


(2,060
)


(21,979
)Interest income


46







46Total other income (expense)


(24,529
)


(70,571
)


(95,100
)Net loss

$
(25,192
)

$
(60,115
)

$
(85,307
)  F-56




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Predecessor (carve out)December 31, 2005As Previously


Restatement


AsReported


Adjustments


RestatedASSETSCurrent assets:Cash

$
2,527


$
(2,000
)

$
527Restricted cash


4,318







4,318Accounts receivable, trade, net


9,658



(141
)


9,517Other receivables


343







343Other current assets


1,727







1,727Inventory


1,407







1,407Current derivative financial instrument assets


95



(47
)


48Total current assets


20,075



(2,188
)


17,887Property and equipment, net


13,490



665



14,155Oil and gas properties under full cost method of accounting:


177,800



(20,948
)


156,852Other assets, net


6,192







6,192Long  term derivative financial instrument assets


93



439



532Total assets

$
217,650


$
(22,032
)

$
195,618LIABILITIES AND PARTNERS EQUITYCurrent liabilities:Accounts payable

$
8,090


$
1,092


$
9,182Revenue payable






201



201Accrued expenses


649







649Due to affiliates






790



790Current portion of notes payable


407







407Current derivative financial instrument liabilities


38,195



4,098



42,293Total current liabilities


47,341



6,181



53,522Non  current liabilities:Long  term derivative financial instrument liabilities


23,723



2,592



26,315Asset retirement obligation


1,150







1,150Notes payable


75,889







75,889Non  current liabilities


100,762



2,592



103,354Total liabilities


148,103



8,773



156,876Commitments and contingenciesPartners equity:Predecessor capital


116,718



(77,976
)


38,742Accumulated other comprehensive income (loss)


(47,171
)


47,171



Total partners equity


69,547



(30,805
)


38,742Total liabilities and partners equity

$
217,650


$
(22,032
)

$
195,618  F-57




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Predecessor (carve out)Year Ended December 31, 2005As Previously


Restatement


AsReported


Adjustments


RestatedCash flows from operating activities:Net loss

$
(25,192
)

$
(60,115
)

$
(85,307
)Adjustments to reconcile net loss to cash provided by operations:Depreciation, depletion and amortization


20,121



(1,084
)


19,037Accretion of debt discount


7,765



1,891



9,656Change in fair value derivative financial instruments


4,580



42,022



46,602Capital contributions for retirement plan and services


285



274



559Contributions for consideration for compensation to employees


352



865



1,217Amortization of deferred loan costs


5,108



(611
)


4,497Amortization of deferred hedging gains


(831
)


831



Bad debt expense


192



110



302(Gain) loss on sale of assets


(12
)


12



Loss on early extinguishment of debt






8,255



8,255Change in assets and liabilities:Restricted cash


(4,318
)


4,318



Accounts receivable


(3,455
)


(191
)


(3,646
)Other receivables


(15
)


195



180Other current assets


(1,495
)


12



(1,483
)Inventory


(1,124
)


1,124



Other assets






790



790Due from affiliates






2,646



2,646Accounts payable


(1,440
)


1,559



119Revenue payable






(19
)


(19
)Accrued expenses


63







63Other long-term liabilities






211



211Other






(239
)


(239
)Net cash provided by (used in) operating activities


584



2,856



3,440Cash flows from investing activities:Restricted cash






(4,318
)


(4,318
)Equipment, development and leasehold


(51,682
)


19,131



(32,551
)Proceeds from sale of property and equipment


37



(37
)


Acquisition of minority interest  Arclight






(7,800
)


(7,800
)Net cash used in investing activities


(51,645
)


6,976



(44,669
)Cash flows from financing activities:Proceeds from bank borrowings


59,584



16,308



75,892Repayments of note borrowings


(86,728
)


(16,049
)


(102,777
)Proceeds from subordinated debt


13,297







13,297Repayment of subordinated debt


(66,398
)


8



(66,390
)Contributions/distributions


133,658



(12,090
)


121,568 F-58




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Predecessor (carve out)Year Ended December 31, 2005As Previously


Restatement


AsReported


Adjustments


RestatedRefinancing costs


(6,272
)


(9
)


(6,281
)Net cash provided by (used in) financing activities


47,141



(11,832
)


35,309Net increase (decrease) in cash


(3,920
)


(2,000
)


(5,920
)Cash, beginning of period


6,447







6,447Cash, end of period

$
2,527


$
(2,000
)

$
527   Note 17 
    Subsequent
    Events  Impairment
    of oil and gas properties
    Settlement
    Agreements
    Note 18 
    Supplemental
    Financial Information  Quarterly Financial Data
    (Unaudited)    SuccessorQuarters2008

4th


3rd


2nd


1st(Restated)


(Restated)Total revenues

$
46,276


$
34,404


$
31,360


$
35,890Operating income (loss)(1)


(242,705
)


2,070



(3,736
)


3,043Net income (loss)


(197,489
)


157,938



(93,616
)


(40,765
)Basic and diluted net income (loss) per limited partner unit

$
(9.14
)

$
7.31


$
(4.33
)

$
(1.89
)   F-59




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  QuarterPredecessorSuccessorNovember 15,


October 1, 20072007 to December


to November 14,31, 2007


20074th


3rd


2nd


1st(Restated)


(Restated)


(Restated)


(Restated)


(Restated)2007Total revenues

$
15,348


$
13,541


$
23,852


$
27,570


$
24,974Operating income (loss)(1)


(881
)


(110
)


(5,078
)


(2,185
)


(1,071
)Net income (loss)


(19,206
)


(5,999
)


791



(1,203
)


(22,763
)Basic and diluted net income (loss) per limited partner unit

$
0.89     (1)
    
    Total revenue less total costs and expenses.      SuccessorQuarter Ended March 31, 2008As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
37,403


$
(1,513
)

$
35,890Operating income (loss)


8,589



(5,546
)


3,043Net income (loss)


(17,346
)


(23,419
)


(40,765
)Basic and diluted net income (loss) per limited partner unit

$
(0.80
)

$
(1.09
)

$
(1.89
)   SuccessorQuarter Ended June 30, 2008As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
39,972


$
(8,612
)

$
31,360Operating income (loss)


9,877



(13,613
)


(3,736
)Net income (loss)


16,221



(109,837
)


(93,616
)Basic and diluted net income (loss) per limited partner unit

$
0.75


$
(5.08
)

$
(4.33
)   F-60




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  PredecessorQuarter Ended March 31, 2007As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
25,536


$
(562
)

$
24,974Operating income (loss)


3,501



(4,572
)


(1,071
)Net income (loss)


(3,650
)


(19,113
)


(22,763
)   PredecessorQuarter Ended June 30, 2007As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
27,848


$
(278
)

$
27,570Operating income (loss)


1,880



(4,065
)


(2,185
)Net income (loss)


(5,231
)


4,028



(1,203
)   PredecessorQuarter Ended September 30, 2007As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
28,489


$
(4,637
)

$
23,852Operating income (loss)


3,347



(8,425
)


(5,078
)Net income (loss)


1,372



(581
)


791   PredecessorOctober 1, 2007 to November 14, 2007As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
15,275


$
(1,734
)

$
13,541Operating income (loss)


(1,776
)


1,666



(110
)Net income (loss)


(11,682
)


5,683



(5,999
)   SuccessorNovember 15, 2007 to December 31, 2007As Previously


Restatement


AsReported


Adjustments


RestatedTotal revenues

$
15,864


$
(516
)

$
15,348Operating income (loss)


1,335



(2,216
)


(881
)Net income (loss)


(18,511
)


(695
)


(19,206
)Basic and diluted net income (loss) per limited partner unit

$
(6.80
)

$
5.91


$
(0.89
)   Note 19 
    Supplemental
    Information on Oil and Gas Producing Activities
    (Unaudited)  Disclosures about Oil
    and Gas Producing Activities
 F-61




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Net
    Capitalized Costs
    Successor


PredecessorAs of December 31,2008


2007


2006


2005Oil and gas properties and related leasehold costs:Proved

$
283,001


$
374,631


$
283,420


$
170,968Unproved


1,282



5,294



7,843



16,521284,283



379,925



291,263



187,489Accumulated depreciation, depletion and amortization


(133,163
)


(85,596
)


(54,437
)


(30,637
)Net capitalized costs

$
151,120


$
294,329


$
236,826


$
156,852     Costs
    Incurred
    As of December 31,2008


2007


2006


2005Acquisition of proved and unproved properties

$
92,765


$



$



$
Exploration costs














Development costs


268,931



217,539



143,229



49,833$
361,696


$
217,539


$
143,229


$
49,833   Results
    of Operations for Oil and Gas Producing Activities
   F-62




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Successor


PredecessorNovember 15, 2007


January 1, 2007Year Ended


to


to


Year Ended


Year EndedDecember 31,


December 31,


November 14,


December 31,


December 31,2008


2007


2007


2006


2005(Consolidated)


(Consolidated)


(Carve out)


(Carve out)


(Carve out)Production revenues

$
147,930


$
15,348


$
89,937


$
72,410


$
70,628Production costs


(43,490
)


(3,970
)


(31,436
)


(24,886
)


(19,152
)Depreciation, depletion and amortization


(50,988
)


(5,045
)


(29,568
)


(24,760
)


(19,037
)Impairment of oil and gas properties


(245,587
)














(192,135
)


6,333



28,933



22,764



32,439Imputed income tax provision(1)










(10,995
)


(8,650
)


(12,327
)$
(192,135
)

$
6,333


$
17,938


$
14,114


$
20,112     (1)
    
    There are no imputed income tax provisions as we are not a
    taxable entity for the Successor periods.  Oil and
    Gas Reserve Quantities
   F-63




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
    Gas  Mcf


Oil  BblsProved reserves:Balance, December 31, 2004 (Predecessor)


149,843,900



47,834Purchase of reserves in place






Extensions, discoveries, and other additions


390,468



Sale of reserves






Revisions of previous estimates(1)


(6,342,690
)


(6,054
)Production


(9,572,378
)


(9,480
)Balance, December 31, 2005 (Predecessor)


134,319,300



32,300Purchase of reserves in place






Extensions, discoveries, and other additions


27,696,254



Sale of reserves






Revisions of previous estimates(2)


48,329,663



9,780Production


(12,305,217
)


(9,808
)Balance, December 31, 2006 (Predecessor)


198,040,000



32,272Purchase of reserves in place






Extensions, discoveries, and other additions


26,368,000



Contributions to successor


(213,363,596
)


(36,952
)Revisions of previous estimates(3)


3,490,473



11,354Production


(14,534,877
)


(6,674
)Balance, November 14, 2007 (Predecessor)






Contributions from predecessor


213,363,596



36,952Extensions, discoveries, and other additions






Sale of reserves






Revision of previous estimates






Production(4)


(2,440,190
)


(396
)Balance, December 31, 2007 (Successor)


210,923,406



36,556Purchase of reserves in place


87,082,455



1,548,357Extensions, discoveries, and other additions


13,897,600



Sale of reserves


(4,386,200
)


Revisions of previous estimates(5)


(123,204,433
)


(833,070
)Production


(21,328,687
)


(69,812
)Balance, December 31, 2008 (Successor)


162,984,141



682,031 F-64




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  Gas  Mcf


Oil  BblsProved developed reserves:Balance, December 31, 2005 (Predecessor)


71,638,300



32,300Balance, December 31, 2006 (Predecessor)


122,390,400



32,272Balance, December 31, 2007 (Successor)


140,966,300



36,556Balance, December 31, 2008 (Successor)


134,837,100



682,031     (1)
    
    The downward revision was due to a change in performance of
    wells on a portion of Quest Cherokees acreage.(2)
    
    During 2006, there were 530 additional producing wells resulting
    in increased estimated future reserves.(3)
    
    During 2007, higher prices increased the economic lives of the
    underlying oil and natural gas properties and thereby increased
    the estimated future reserves.(4)
    
    2007 production for Successor is from November 15, 2007 to
    December 31, 2007 for contributed properties.(5)
    
    Lower prices at December 31, 2008 as compared to
    December 31, 2007 reduced the economic lives of the
    underlying oil and gas properties and thereby decreased the
    estimated future reserves.  Standardized
    Measure of Discounted Future Net Cash Flows
  Disclosures About Oil and Gas
    Producing Activities
  Successor


PredecessorDecember 31,


December 31,


December 31,


December 31,2008


2007


2006


2005Future cash inflows

$
844,130


$
1,351,980


$
1,197,198


$
1,258,580Future production costs


552,906



732,488



638,844



366,475Future development costs


50,363



119,448



126,272



122,428Future income tax expense










60,024



230,651Future net cash flows


240,861



500,044



372,058



539,02610% annual discount for estimated timing of cash flows


84,804



177,506



141,226



201,087Standardized measure of discounted future net cash flows related
    to proved reserves

$
156,057


$
322,538


$
230,832


$
337,939     (1)
    
    Future cash inflows are computed by applying year-end prices,
    adjusted for location and quality differentials on a
    property-by-property basis, to year-end quantities of proved
    reserves, except in those instances where fixed and determinable
    price changes are provided by contractual arrangements at
    year-end. The discounted future cash flow estimates do not
    include the effects of our derivative instruments. There is no
    future income tax expense for Successor periods because we are
    not a taxable entity. See the following table for oil and gas
    prices as of the periods indicated.  F-65




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE-OUT FINANCIAL STATEMENTS 
    (Continued)
  As of December 31,2008


2007


2006


2005Crude oil price per Bbl

$
44.60


$
96.10


$
61.06


$
55.63Natural gas price per Mcf

$
5.71


$
6.43


$
6.03


$
9.27     Successor


PredecessorDecember 31,


December 31,


December 31,


December 31,2008


2007


2006


2005Present value, beginning of period

$
322,538


$



$
337,939


$
280,482Contributions from Predecessor






333,916







Net changes in prices and production costs


(146,141
)






(289,149
)


181,950Net changes in future development costs


6,712







(60,330
)


(46,074
)Previously estimated development costs incurred


58,726







93,397



25,532Sales of oil and gas produced, net


(104,447
)


(11,378
)


(47,524
)


(51,476
)Extensions and discoveries


15,695







48,399



1,624Purchases of reserves in  place


108,838











Sales of reserves in  place


(4,954
)










Revisions of previous quantity estimates


(144,785
)






84,559



(26,524
)Net change in income taxes(a)










107,365



(23,979
)Accretion of discount


42,674







44,771



37,867Timing differences and other(b)


1,201







(88,595
)


(41,463
)Present value, end of period

$
156,057


$
322,538


$
230,832


$
337,939     (a)
    
    There is no change in income taxes for Successor periods because
    we are not a taxable entity.(b)
    
    The change in timing differences and other are related to
    revisions in our estimated time of production and development F-66




---



##### Table of Contents



SIGNATURES  Form 10-K
    By:
    Quest Energy GP, LLC, its general partnerBy:
    /s/  David
    C. Lawler  President and Chief Executive Officer
    Signature

Title

Date/s/  David
    C. LawlerDavid
    C. Lawler

Director, Chief Executive
    Officer and President
    (principal executive officer)

June 16, 2009/s/  Eddie
    M. LeBlanc, IIIEddie
    M. LeBlanc, III

Chief Financial Officer (principal financial and accounting
    officer)

June 16, 2009*Gary
    M. Pittman

Director

June 16, 2009*Mark
    A. Stansberry

Director

June 16, 2009*J.
    Philip McCormick

Director

June 16, 2009*By:

/s/  Eddie
    M. LeBlanc, IIIEddie
    M. LeBlanc, III
    Attorney-in-Fact  137




---



##### Table of Contents



INDEX TO
    EXHIBITS  ExhibitNo.

Description*2
.1

Agreement for Purchase and Sale, dated as of July 11, 2008,
    by and among Quest Resource Corporation, Quest Eastern Resource
    LLC and Quest Cherokee LLC (incorporated herein by reference to
    Exhibit 2.1 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on July 16, 2008).*3
.1

Certificate of Limited Partnership (incorporated herein by
    reference to Exhibit 3.1 to Quest Energy Partners,
    L.P.s Registration Statement on
    Form S-1
    filed on July 19, 2007).*3
.2

First Amended and Restated Agreement of Limited Partnership of
    Quest Energy Partners, L.P. (incorporated herein by reference to
    Exhibit 3.1 to Quest Energy Partners, L.P.s amended
    Current Report on
    Form 8-K/A
    filed on December 7, 2007).*3
.3

Amendment No. 1 to First Amended and Restated Agreement of
    Limited Partnership of Quest Energy Partners, L.P. (incorporated
    herein by reference to Exhibit 3.1 to Quest Energy
    Partners, L.P.s Current Report on
    Form 8-K
    filed on April 11, 2008).*3
.4

Certificate of Formation of Quest Energy GP, LLC (incorporated
    herein by reference to Exhibit 3.3 to Quest Energy
    Partners, L.P.s Registration Statement on
    Form S-1
    filed on July 19, 2007).*3
.5

Amended and Restated Limited Liability Company Agreement of
    Quest Energy GP, LLC (incorporated herein by reference to
    Exhibit 3.2 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on November 21, 2007).*10
.1

Contribution, Conveyance and Assumption Agreement, dated as of
    November 15, 2007, by and among Quest Energy Partners,
    L.P., Quest Energy GP, LLC, Quest Resource Corporation, Quest
    Cherokee, LLC, Quest Oil & Gas, LLC, and Quest Energy
    Service, LLC (incorporated herein by reference to
    Exhibit 10.1 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on November 21, 2007).*10
.2

Omnibus Agreement, dated as November 15, 2007, by and among
    Quest Energy Partners, L.P., Quest Energy GP, LLC and Quest
    Resource Corporation (incorporated herein by reference to
    Exhibit 10.2 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on November 21, 2007).*10
.3

Management Services Agreement, dated as of November 15,
    2007, by and among Quest Energy Partners, L.P., Quest Energy GP,
    LLC and Quest Energy Service, LLC (incorporated herein by
    reference to Exhibit 10.3 to Quest Energy Partners,
    L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.4

Amended and Restated Credit Agreement, dated as of
    November 15, 2007, by and among Quest Resource Corporation,
    as the Initial Co-Borrower, Quest Cherokee, LLC, as the
    Borrower, Quest Energy Partners, L.P., as a Guarantor, Royal
    Bank of Canada, as Administration Agent and Collateral Agent,
    KeyBank National Association, as Documentation Agent, and the
    lenders from time to time party thereto (incorporated herein by
    reference to Exhibit 10.4 to Quest Energy Partners,
    L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.5

First Amendment to Amended and Restated Credit Agreement, dated
    as of April 15, 2008, by and among Quest Cherokee, LLC,
    Royal Bank of Canada, KeyBank National Association and the
    lenders Party thereto (incorporated herein by reference to
    Exhibit 10.1 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on April 23, 2008).*10
.6

Second Amendment to Amended and Restated Credit Agreement, dated
    as of October 28, 2008, by and among Quest Cherokee, LLC,
    Royal Bank of Canada, KeyBank National Association and the
    lenders Party thereto (incorporated herein by reference to
    Exhibit 10.2 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on November 7, 2008).*10
.7

Guaranty for Amended and Restated Credit Agreement by Quest
    Energy Partners, L.P. in favor of Royal Bank of Canada, dated as
    of November 15, 2007 (incorporated herein by reference to
    Exhibit 10.9 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on November 21, 2007).*10
.8

Guaranty for Amended and Restated Credit Agreement by Quest
    Cherokee Oilfield Service, LLC in favor of Royal Bank of Canada,
    dated as of November 15, 2007 (incorporated herein by
    reference to Exhibit 10.10 to Quest Energy Partners,
    L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007). 138




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ExhibitNo.

Description*10
.9

Pledge and Security Agreement for Amended and Restated Credit
    Agreement by Quest Energy Partners, L.P. for the benefit of
    Royal Bank of Canada, dated as of November 15, 2007
    (incorporated herein by reference to Exhibit 10.11 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.10

Pledge and Security Agreement for Amended and Restated Credit
    Agreement by Quest Cherokee Oilfield Service, LLC for the
    benefit of Royal Bank of Canada, dated as of November 15,
    2007 (incorporated herein by reference to Exhibit 10.12 to
    Quest Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.11

Pledge and Security Agreement for Amended and Restated Credit
    Agreement by Quest Cherokee, LLC for the benefit of Royal Bank
    of Canada, dated as of November 15, 2007 (incorporated
    herein by reference to Exhibit 10.13 to Quest Energy
    Partners, L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.12

Assignment and Assumption Agreement, dated as of
    November 15, 2007, by and among Quest Resource Corporation,
    Quest Energy Partners, L.P. and Bluestem Pipeline, LLC
    (incorporated herein by reference to Exhibit 10.5 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.13

Midstream Services and Gas Dedication Agreement, dated
    December 22, 2006 (but effective as of December 1,
    2006), between Bluestem Pipeline, LLC and Quest Resource
    Corporation, including exhibits thereto (incorporated herein by
    reference to Exhibit 10.6 to Quest Resource
    Corporations Current Report on
    Form 8-K
    filed on December 29, 2006).*10
.14

Amendment No. 1 to the Midstream Services and Gas
    Dedication Agreement, dated as of August 9, 2007, by and
    between Quest Resource Corporation and Bluestem Pipeline, LLC
    (incorporated herein by reference to Exhibit 10.1 to Quest
    Resource Corporations Current Report on
    Form 8-K
    (File
    No. 0-17371)
    filed on August 13, 2007).10
.15

Amendment No. 2 to the Midstream Services and Gas
    Dedication Agreement, dated as of February 27, 2009, by and
    between Quest Energy Partners, L.P. and Bluestem Pipeline, LLC.*10
.16

Quest Midstream Omnibus Agreement, dated December 22, 2006,
    among Quest Resource Corporation, Quest Midstream GP, LLC,
    Bluestem Pipeline, LLC and Quest Midstream Partners, L.P.
    (incorporated herein by reference to Exhibit 10.3 to Quest
    Resource Corporations Current Report on
    Form 8-K
    (File
    No. 0-17371)
    filed on December 29, 2006).*10
.17

Acknowledgement and Consent, dated as of November 15, 2007,
    of Quest Energy Partners, L.P. (incorporated herein by reference
    to Exhibit 10.6 to Quest Energy Partners, L.P.s
    Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.18

Quest Energy Partners, L.P. Long-Term Incentive Plan
    (incorporated herein by reference to Exhibit 10.7 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.19

Form of Restricted Unit Award Agreement (incorporated herein by
    reference to Exhibit 10.3 to Quest Energy Partners,
    L.P.s Registration Statement on
    Form S-1
    filed on July 19, 2007).10
.20

Summary of Director Compensation Arrangements.*10
.21

Form of Bonus Unit Award Agreement (incorporated herein by
    reference to Exhibit 10.13 to Quest Energy Partners,
    L.P.s Annual Report on
    Form 10-K
    filed on March 31, 2008).*10
.22

Loan Transfer Agreement, dated as of November 15, 2007, by
    and among Quest Resource Corporation, Quest Cherokee, LLC, Quest
    Oil & Gas, LLC, Quest Energy Service, Inc., Quest
    Cherokee Oilfield Service, LLC, Guggenheim Corporate Funding,
    LLC, Wells Fargo Foothill, Inc., and Royal Bank of Canada
    (incorporated herein by reference to Exhibit 10.8 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on November 21, 2007).*10
.23

Second Lien Senior Term Loan Agreement, dated as of July, 11,
    2008, by and among Quest Cherokee, LLC, Quest Energy Partners,
    L.P., Royal Bank of Canada, KeyBank National Association,
    Société Générale, the lenders party thereto
    and RBC Capital Markets (incorporated herein by reference to
    Exhibit 10.2 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on July 16, 2008). 139




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ExhibitNo.

Description*10
.24

First Amendment to Second Lien Senior Term Loan Agreement, dated
    as of October 28, 2008, but effective as of
    November 5, 2008, by and among Quest Cherokee, LLC, Quest
    Energy Partners, L.P., Quest Cherokee Oilfield Service, LLC,
    Royal Bank of Canada, KeyBank National Association,
    Société Générale and the Lenders party
    thereto (incorporated herein by reference to Exhibit 10.1
    to Quest Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on November 7, 2008).*10
.25

Guaranty for Second Lien Term Loan Agreement by Quest Cherokee
    Oilfield Service, LLC in favor of Royal Bank of Canada, dated as
    of July 11, 2008 (incorporated herein by reference to
    Exhibit 10.2 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on July 16, 2008).*10
.26

Guaranty for Second Lien Term Loan Agreement by Quest Energy
    Partners, L.P. in favor of Royal Bank of Canada, dated as of
    July 11, 2008 (incorporated herein by reference to
    Exhibit 10.3 to Quest Energy Partners, L.P.s Current
    Report on
    Form 8-K
    filed on July 16, 2008).*10
.27

Pledge and Security Agreement for Second Lien Term Loan
    Agreement by Quest Cherokee Oilfield Service, LLC for the
    benefit of Royal Bank of Canada, dated as of July 11, 2008
    (incorporated herein by reference to Exhibit 10.4 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on July 16, 2008).*10
.28

Pledge and Security Agreement for Second Lien Term Loan
    Agreement by Quest Energy Partners, L.P. for the benefit of
    Royal Bank of Canada, dated as of July 11, 2008
    (incorporated herein by reference to Exhibit 10.5 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on July 16, 2008).*10
.29

Pledge and Security Agreement for Second Lien Term Loan
    Agreement by Quest Cherokee, LLC for the benefit of Royal Bank
    of Canada, dated as of July 11, 2008 (incorporated herein
    by reference to Exhibit 10.6 to Quest Energy Partners,
    L.P.s Current Report on
    Form 8-K
    filed on July 16, 2008).*10
.30

Intercreditor Agreement, dated as of July 11, 2008, by and
    between Royal Bank of Canada and Quest Cherokee, LLC
    (incorporated herein by reference to Exhibit 10.7 to Quest
    Energy Partners, L.P.s Current Report on
    Form 8-K
    filed on July 16, 2008).10
.31

Settlement Agreement by and among Quest Resource Corporation,
    Quest Energy Partners, L.P., Quest Midstream Partners, L.P. and
    Jerry D. Cash, dated May 19, 2009.10
.32

Full and Final Settlement Agreement and Mutual Release, by and
    among Quest Resource Corporation, Quest Energy Partners, L.P.,
    Quest Midstream Partners, L.P., Rockport Energy, LLC, Rockport
    Georgetown Partners, LLC, Rockport Georgetown Holdings, LP,
    Jerry D. Cash, Bryan T. Simmons and Steven Hochstein, dated
    May 19, 2009.21
.1

List of Subsidiaries23
.1

Consent of Cawley, Gillespie & Associates, Inc23
.2

Consent of UHY, LLP.24
.1

Power of Attorney.31
.1

Certification by principal executive officer pursuant to
    Rule 13a-14(a)
    or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
    pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31
.2

Certification by principal financial officer pursuant to
    Rule 13a-14(a)
    or 15d-14(a) of the Securities Exchange Act of 1934, as adopted
    pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32
.1

Certification by principal executive officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to
    Section 906 of the Sarbanes-Oxley Act of 2002.32
.2

Certification by principal financial officer pursuant to
    18 U.S.C. Section 1350, as adopted pursuant to
    Section 906 of the Sarbanes-Oxley Act of 2002.     *
    
    Incorporated by reference.
    
    Management contracts and compensatory plans and arrangements
    required to be filed as Exhibits pursuant to Item 15(a) of this
    report.  Form 10-K.
 140




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141