##### Table of Contents





UNITED STATES SECURITIES AND
    EXCHANGE COMMISSIONWashington, D.C.
    20549
  Form 10-K
  (Mark One)þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
    OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
    December 31, 2007ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For the transition period
    from          to          .   Commission file number:
    001-33787
 QUEST ENERGY PARTNERS,
    L.P.
 (Exact name of registrant as
    specified in its charter)
  Delaware(State or other jurisdiction
    of
    incorporation or organization)

26-0518546(I.R.S. Employer
    Identification
    No.)210 Park Avenue, Suite 2750
    Oklahoma City, OK(Address of principal
    executive offices)

73102(Zip
    Code)   (405) 600-7704
 (Registrants telephone
    number, including area code)
  SECURITIES
    REGISTERED PURSUANT TO SECTION 12(b) OF THE 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 ACT:
    None
  o þ
  o þ
  þ o
  Regulation S-K Form 10-K Form 10-K. o
    Large accelerated filer
    o

Accelerated filer
    o

Non-accelerated
    filer þ
    (Do not check if a smaller reporting company)

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


4ITEM 1A.


RISK FACTORS


26ITEM 1B.


UNRESOLVED STAFF COMMENTS


54ITEM 3.


LEGAL PROCEEDINGS


54ITEM 4.


SUBMISSION OF MATTERS TO A VOTE OF SECURITY
    HOLDERS


56PART II


56ITEM 5.


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


56ITEM 6.


SELECTED FINANCIAL DATA


60ITEM 7.


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


61ITEM 7A.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
    MARKET RISK


75ITEM 8.


FINANCIAL STATEMENTS AND SUPPLEMENTARY
    DATA


F-1ITEM 9.


CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
    ON ACCOUNTING AND FINANCIAL DISCLOSURE


76ITEM 9A(T).


CONTROLS AND PROCEDURES


76ITEM 9B.


OTHER INFORMATION


76PART III


76ITEM 10.


DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
    GOVERNANCE


76ITEM 11.


EXECUTIVE COMPENSATION


81ITEM 12.


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


94ITEM 13.


CERTAIN RELATIONSHIPS AND RELATED
    TRANSACTIONS, AND DIRECTOR INDEPENDENCE


96ITEM 14.


PRINCIPAL ACCOUNTANT FEES AND SERVICES


99PART IV


100ITEM 15.


EXHIBITS, FINANCIAL STATEMENT SCHEDULES


100Summary of Director Compensation ArrangementsForm of Bonus Unit Award AgreementConsent of Cawley, Gillespie & Associates, Inc.Consent of Murrell, Hall, McIntosh & Co., PLLPCertification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906   2




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##### Table of Contents



GUIDE
    TO READING THIS REPORT
    
    when we use the terms Quest Energy Partners,
    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 our Parent located
    in the Cherokee Basin (other than its midstream assets), which
    our Parent 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 our Parent, we are referring to
    Quest Resource Corporation (Nasdaq: QRCP), the owner of our
    general partner, and its subsidiaries (other than us); and
    when we use the term Quest Midstream, we are
    referring to Quest Midstream Partners, L.P. and its subsidiaries.   3




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PART I  Items 1.
    and 2.
    Business
    and
    Properties.  Overview
  15-county
      160-acre 80-acre 80-acre
   4




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Recent
    Developments
  Our Formation and IPO.
  Form 8-K
  New Credit Agreement.
 5




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##### Table of Contents



Form 10-K.
  Acquisition of Oil Producing Properties.
  Business
    Strategies
    
    Efficiently control the drilling and development of our acreage
    position in the Cherokee Basin;
    Accumulate additional acreage in the Cherokee Basin in areas
    where management believes the most attractive development
    opportunities exist;
    Pursue selected strategic acquisitions in the Cherokee Basin
    that would add attractive development opportunities and critical
    gas gathering infrastructure;
    Maintain operational control over our assets whenever
    possible; and
    Limit our reliance on third party contractors with respect to
    the completion, stimulation and connection of our wells.  Competitive
    Strengths
    
    Experienced management.  Key members of our
    executive management and technical teams have on average more
    than 20 years of experience developing conventional and
    unconventional oil and natural gas fields in the United States.
    Several have been developing CBM in the Cherokee Basin since
    1995.
    Low geological risk.  The coal seams from which
    we produce CBM are notable for their consistent thickness and
    gas content. In addition, extensive drilling dating back 60 to
    80 years for the development of oil reserves in the
    Cherokee Basin gives us access to substantial information
    related to the coal seams we target. Over 100,000 well
    bores have penetrated the Cherokee Basin since the 1920s. Data
    available from the drilling records of these wells allows us to
    determine the aerial extent, thickness and relative permeability
    of the coal seams we target for development, which greatly
    reduces its dry hole risk.
    High rate of drilling success.  Over 99% of the
    CBM wells that have been drilled on our acreage have been, or
    are capable of being, completed as economic producers.
    Expertise in Cherokee Basin geology.  We have
    spent several years conducting technical research on historical
    data related to the development of the Cherokee Basin. From this
    analysis, we believe we have determined where the most
    attractive opportunities for CBM development exist within the
    basin.
    Large acreage position and inventory of drilling
    sites.We have the right to develop 558,190
    net CBM acres in the Cherokee Basin. As of
    December 31, 2007, our acreage was approximately 51.6%
    developed 6




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and offered approximately 2,100 gross CBM drilling
    locations, of which approximately 800 were classified as proved
    undeveloped.  
    Availability of significant quantities of low cost
    acreage.Presently, several hundred thousand
    acres of unleased CBM acreage are available in the Cherokee
    Basin. We believe this acreage generally can be leased for an
    amount less than acreage in other basins. These circumstances
    afford us the opportunity to sustain long-term organic growth by
    adding undeveloped acreage and CBM drilling locations at a
    reasonable cost.
    Competitive advantage of our gas gathering
    agreement.  Our gas gathering agreement with Quest
    Midstream represents a competitive advantage compared to third
    parties seeking to lease acreage that is readily served by the
    system. The gathering fee that Quest Midstream receives for
    gathering our gas is determined annually compared to a volume
    take allowance of up to 30% before royalties for third party
    operators in the basin. This not only makes development
    economics less attractive for third party operators to lease
    land served by the system, it also makes us a more attractive
    lessee for landowners. The vast geographic extent of Quest
    Midstreams gas gathering system together with our large
    land position makes it unattractive for third parties to lease
    proximate acreage and build duplicate gas gathering facilities.
    Attractive geological characteristics of Cherokee Basin
    CBM.Compared to some other basins in the United
    States where CBM is produced, CBM production in the Cherokee
    Basin has distinct economic advantages. First, the coal seams in
    the Cherokee Basin are relatively more permeable and thus tend
    to produce at a faster rate. This results in a shorter reserve
    life, the need to drill fewer wells, a faster payout period and
    a higher present value of reserves. Second, Cherokee Basin coal
    seams produce relatively less water than coal seams in some
    other basins. Cherokee Basin CBM wells produce gas immediately,
    have a shorter dewatering period, and produce less water overall
    than CBM wells in some other basins.
    Predictable results of our CBM wells.  Our CBM
    wells in the Cherokee Basin have highly consistent behavior in
    terms of recoverable reserves, production rates and decline
    curves, which results in lower development risk.
    Concentrated ownership and operational
    control.  We own 100% of the working interest in
    over 95% of the wells in which we have ownership. As a result of
    this ownership position, we operate substantially all of the
    wells in which we own an economic interest.
    Long-lived reserves.  Our average proved
    reserve-to-production ratio is 8.12 years for our proved
    developed properties based on our reserves as of
    December 31, 2007 and production (17.15 Bcfe) for the
    year ended December 31, 2007. Based on our current rate of
    new well development and current undeveloped acreage, we
    estimate that it would take approximately 6.34 years to
    fully develop our existing acreage. In addition, the standard
    economic life of our typical Cherokee Basin well is
    approximately 15 years. We believe this long reserve life
    reduces the reinvestment risk associated with the Companys
    asset base.  Our
    Relationship with Our Parent
      Omnibus Agreement.
  
    reimbursement of certain insurance, operating and general and
    administrative expenses incurred on our behalf; 7




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
    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 our Parent and its affiliates certain
    assets that they acquire within the Cherokee Basin.    Management Agreement.
        Description
    of Our Properties and Projects
  Cherokee Basin.
 8




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
    the Predecessor acquired approximately 372,000 gross
    (366,000 net) acres of gas leases, 418 gross (325 net) gas
    wells and 207 miles of gas gathering pipelines in the
    Cherokee Basin from Devon Energy Production Company, L.P. and
    Tall Grass Gas Services, LLC in December 2003;
    the Predecessor acquired 53 natural gas and oil leases and
    related assets in Chautauqua, Elk, and Montgomery Counties,
    Kansas from James R. Perkins Energy, L.L.C. and E. Wayne
    Willhite Energy, L.L.C. in June 2003; and
    we acquired all of these properties from our Parent in November
    2007 in connection with the closing of our initial public
    offering.  Characteristics of Coal Bed Methane.
      Cherokee Basin Projects. 160-acre 80-acre 15-20 Mcf/d 55-60 Mcf/d
 9




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50-60 Bbls 30-50 Bbls
  Gas and
    Oil Data
  Estimated Net Proved Reserves. Form EIA-23. Form EIA-23 Form EIA-23
  Successor


PredecessorDecember 31,2007


2006


2005Proved reservesGas (Mcf)


210,923,000



198,040,000



134,319,000Oil (Bbls)


36,556



32,272



32,269Total (Mcfe)


211,142,000



198,234,000



134,513,000Proved developed gas reserves (Mcf)


140,966,000



122,390,000



71,638,000Proved undeveloped gas reserves (Mcf)


69,957,000



75,650,000



62,681,000Proved developed oil reserves (BBls)(1)


36,556



32,272



32,269Proved developed reserves as a percentage of total proved
    reserves


66.9
%


61.8
%


53.4
%Standardized measure in (thousands)(2)

$
322,537


$
268,072


$
482,545     (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 Securities and Exchange Commission (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 because we are not
    subject to income taxes. Standardized measure does not give
    effect to derivative transactions. For a description of our 10




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derivative transactions, see Note 6. Financial Instruments
    and Note 7. Derivatives, in the notes to the
    consolidated/carve out 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 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.    Production Volumes, Sales Prices and Production
    Costs.
  Successor


PredecessorNovember 15


January 1Through


Through


Year EndedDecember 31,


November 14,


December 31,2007


2007


2006


2005Net Production:Gas (bcf)


2.4



14.7



12.29



9.57Oil (bbls)


393



6,677



9,737



9,241Gas equivalent (bcfe)


2.4



14.7



12.34



9.62Gas and Oil Sales ($ in thousands):Gas sales

$
15,420


$
89,903


$
72,865


$
71,137Gas derivatives  gains (loss)

$
388


$
6,892


$
(7,888
)

$
(27,066
)Total gas sales

$
15,808


$
96,795


$
64,977


$
44,071Oil sales

$
34


$
398


$
574


$
494Total gas and oil sales

$
15,842


$
97,143


$
65,551


$
44,565Avg Sales Price (excluding effects of hedging):Gas ($ per mcf)

$
6.45


$
6.11


$
5.93


$
7.44Oil ($ per bbl)

$
85.98


$
59.65


$
58.95


$
53.46Gas equivalent ($ per mcfe)

$
6.45


$
6.12


$
5.95


$
7.45Avg Sales Price (including effects of hedging):Gas ($ per mcf)

$
6.71


$
6.56


$
5.29


$
4.61Oil ($ per bbl)

$
85.98


$
59.65


$
58.95


$
53.46Gas equivalent ($ per mcfe)

$
6.71


$
6.57


$
5.31


$
4.63Expenses ($ per mcfe):Lifting

$
1.22


$
1.33


$
1.29


$
0.98Production and property tax

$
0.45


$
0.46


$
0.55


$
0.58Net Revenue ($ per mcfe)

$
5.04


$
4.78


$
3.47


$
3.07  11




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Producing Wells and Acreage.
  Productive WellsGas(1)


Oil


TotalGross


Net


Gross


Net


Gross


NetPredecessor:December 31, 2005


1,026



999.3



29



27.9



1,055



1,027.2December 31, 2006


1,653



1,609.9



29



27.9



1,682



1,637.8Successor:December 31, 2007


2,225



2,182.2



29



27.9



2,254



2,210.1     (1)
    
    At December 31, 2007, we had approximately 1,320 gross
    wells that were producing from multiple seams.    Leasehold Acreage(1)Producing(2)


Nonproducing


Total LeasedGross


Net


Gross


Net


Gross


NetPredecessor:December 31, 2005


334,676



310,663



198,569



184,322



533,245



494,985December 31, 2006


394,795



385,148



132,189



124,774



526,984



509,923Successor:December 31, 2007


402,888



393,320



179,524



164,870



582,412



558,190     (1)
    
    Approximately 45,000 and 90,000 net acres that were
    included in the 2006 and 2005 leasehold acreage amounts have
    expired.(2)
    
    Includes acreage held by production under the terms of the lease.   12




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Drilling Activities.
  SuccessorNovember 15


PredecessorThrough


January 1





Year EndedDecember 31,


Through


Year Ended December 31,


December 31,2007(1)


November 14, 2007(1)


2006(1)


2005(1)Gas


Gas


Gas


GasGross


Net


Gross


Net


Gross


Net


Gross


NetExploratory Wells Drilled:Capable of Production






























Dry






























Development Wells Drilled:Capable of Production


64



63



511



508



638



621



233



227Dry






























Wells Abandoned






























Wells Acquired






























Net increase in Capable Wells


64



63



511



508



638



621



233



227Recompletion of Old Wells:Capable of Production


3



3



47



46



125



122



205



200     (1)
    
    No change to oil wells for the years ended December 31,
    2007, 2006 and 2005.      Operations
  General.
    mark-ups
 13




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Gas and Oil Leases.
      Gas
    Gathering
      and/or
     14




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Marketing
    and Major Customers
        Hedging
    Activities
   15




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Competition
        Title to
    Properties
       16




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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 gas and oil drilling, production and
    transportation 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.
 17




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Comprehensive Environmental Response, Compensation and
    Liability Act.
    Water Discharges.
      Air Emissions.
 18




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and/or
  Hydrogen Sulfide.
 19




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National Environmental Policy Act
  Endangered Species Act.
  OSHA and Other Laws and Regulation. and/or
    Other
    Regulation of the Gas and Oil Industry
     20




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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.      Gas Marketing.
   21




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e.g.
  State Regulation.
      Other
    and/or
   22




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Employees
    Administrative
    Facilities
      Available
    Information
  Form 10-K, Form 10-Q, Form 8-K
 23




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GLOSSARY
    OF SELECTED TERMS
  Form 10-K.
  Bbl.
  Bbl/d.
  Bcf.
  Bcfe.
  Btu British Thermal Unit.
  CBM.
  Cherokee Basin.
  Completion.
  Developed acreage.
  Development well.
  Dry hole dry well.
  Eligible Holder.
  Exploitation.
  Exploratory well.
  Field. and/or
  Frac/fracturing.
  Gas.
  Gathering system.
  Gross acres gross wells.
  Horizon formation.
  Mcf.
 24




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Mcf/d.
  Mcfe.
  MMBtu.
  MMcf.
  MMcf/d.
  MMcfe.
  Mmcfe/d.
  Net acres net wells.
  Net production.
  Net revenue interest.
  NGLs.
  NYMEX.
  Oil.
  Permeability. and/or
  Perforation.
  Productive well.
  Proved developed non-producing
    reserves.
  Proved developed reserves. Rule 4-10(a)(2-4) Regulation S-X. http://www.sec.gov/about/forms/regs-x.pdf.
  Proved reserves. Rule 4-10(a)(2-4) Regulation S-X. http://www.sec.gov/about/forms/regs-x.pdf.
  Proved undeveloped reserves PUDs. Rule 4-10(a)(2-4) Regulation S-X.
  Recompletion.
 25




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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.
  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 pay
    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
  We may
    not have sufficient cash flow from operations to pay quarterly
    distributions on our common units following the establishment of
    cash reserves and the payment of fees and expenses, including
    reimbursements of expenses to our general partner and its
    affiliates.
   26




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
    the amount of gas and oil we produce;
    the demand for and the price at which we are able to sell our
    gas and oil production;
    the results of our hedging activity;
    the costs incurred for continued development of gas wells and
    proved undeveloped properties;
    the level of our operating costs, including reimbursements of
    expenses to our general partner and its affiliates;
    timing and collectability of receivables;
    prevailing economic conditions;
    our ability to acquire additional gas and oil properties at
    economically attractive prices;
    our ability to continue our exploitation activities at
    economically attractive costs;
    the level of our interest expense, which depends on the amount
    of our indebtedness and the interest payable thereon; and
    the level of our capital expenditures.    Gas
    prices are at relatively high levels and are very volatile, and
    if commodity prices decline significantly for a temporary or
    prolonged period, our cash flow from operations will decline and
    we may have to lower our quarterly distributions or may not be
    able to pay distributions at all.
    
    the domestic and foreign supply of and demand for gas;
    the price and level of foreign imports of gas and oil;
    the level of consumer product demand;
    weather conditions;
    overall domestic and global economic conditions; 27




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
    political and economic conditions in gas and oil 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 gas and oil
    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.    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 our ability to make cash distributions
    to our unitholders.
   28




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We
    will not be able to sustain distributions at the current level
    without making accretive acquisitions or capital expenditures
    that maintain or grow our asset base. If our asset base
    decreases and we do not reduce our distributions, a portion of
    the distributions may be considered a return of part of your
    investment in us as opposed to a return on your
    investment.
      If our
    Parent 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
    adversely affect our cash from operations and our ability to
    make cash distributions.
    
    our Parent 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 our Parent and its affiliates
    on a purchase price or on acceptable purchase terms for our
    Parents properties that are attractive to all parties;
    our Parent 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.   29




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##### Table of Contents



To
    fund our growth capital expenditures, we will be required to use
    cash generated from our operations, additional borrowings or the
    issuance of additional partnership interests, or some
    combination thereof.
    The
    amount of cash we have available for distribution to our
    unitholders depends primarily on our cash flow and not solely on
    our profitability.
    If we
    do not make acquisitions on economically acceptable terms, our
    future growth and ability to sustain or increase distributions
    will be limited.
    Our
    operations require substantial capital expenditures to increase
    our asset base, which will reduce our cash available for
    distribution.
    
    changes in our reserves;
    changes in gas and oil prices;
    changes in labor and drilling costs;
    our ability to acquire, locate and produce reserves; 30




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
    changes in leasehold acquisition costs; and
    government regulations relating to safety and the environment.    
    our proved reserves;
    the level of gas and oil we are able to produce from existing
    wells;
    the prices at which our gas and oil is sold; and
    our ability to acquire, locate and produce new reserves.    The
    credit facility of our operating subsidiary, Quest Cherokee, (to
    which we are a guarantor) has substantial restrictions and
    financial covenants that may restrict our business and financing
    activities and our ability to pay distributions.
    
    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.   31




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We may
    incur substantial additional debt in the future to enable us to
    pay distributions to our unitholders, which may negatively
    affect our ability to execute on our business
    plan.
      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; 32




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
    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
  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.
  15-20 Mcf/d 55-60 Mcf/d
  Any
    acquisitions we complete are subject to substantial risks that
    could reduce our ability to make distributions to
    unitholders.
    
    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;
    dilution to our unitholders and a decrease in available cash per
    unit if we issue additional units to finance acquisitions;
    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; 33




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
    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.      Due to
    the vast majority of our current operations taking place in the
    Cherokee Basin, acquisitions outside of the Cherokee Basin will
    expose us to operational inefficiencies and new operational
    risks.
    
    geology;
    well economics;
    availability of third party services;
    transportation charges;
    content, quantity and quality of gas and oil produced;
    volume of waste water produced;
    state and local regulations and permit requirements; and
    production, severance, ad valorem and other taxes.  Our
    estimated proved reserves are based on many 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 gas and oil prices;
    geological conditions;
    production levels; 34




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
    capital expenditures;
    operating and development costs;
    the effects of regulation; and
    availability of funds.      The
    present value of future net cash flows from our estimated proved
    reserves is not necessarily the same as the current market value
    of our estimated proved reserves.
    
    the actual prices we receive for gas;
    our actual operating costs in producing gas;
    the amount and timing of actual production;
    the amount and timing of our capital expenditures;
    supply of and demand for gas; and
    changes in governmental regulations or taxation.  Statement of
    Financial Accounting Standards No. 69, Disclosures about
    Oil and Gas Producing Activities
  Drilling
    for and producing gas are costly and high-risk activities with
    many uncertainties that could adversely affect our financial
    condition or results of operations, and as a result, our ability
    to pay distributions to our unitholders.
    
    high costs, shortages or delivery delays of drilling rigs,
    equipment, labor or other services;
    reductions in gas prices;
    limitations in the market for gas;
    adverse weather conditions; 35




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
    facility or equipment malfunctions;
    difficulty disposing of water produced as part of the CBM
    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;
    unusual or unexpected geological formations;
    formations with abnormal pressures;
    natural disasters, such as fires;
    blowouts, surface craterings and explosions; and
    uncontrollable flows of gas or well fluids.  160-acre 80-acre
  Our
    hedging activities could result in financial losses or reduce
    our income, which may adversely affect our ability to pay
    distributions to our unitholders.
   36




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
    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 reduce our ability to
    make distributions to our unitholders.
    The
    economic terms of the midstream services agreement may become
    unfavorable to us.
  and/or
   37




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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
  We may
    be unable to compete effectively with larger companies, which
    may adversely affect our ability to generate sufficient revenue
    to allow us to pay distributions to our
    unitholders.
    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; 38




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
    leaks of gas or losses of gas 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.      Any
    amounts that we are required to pay as a result of our pending
    legal proceedings may affect our ability to pay
    distributions.
    The
    credit and risk profile of our Parent could adversely affect our
    credit ratings and risk profile, which could increase our
    borrowing costs or hinder our ability to raise
    capital.
     39




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Our
    operations expose us to significant costs and liabilities with
    respect to environmental and operational safety matters
    applicable to gas and oil exploitation and production
    operations.
      We are
    subject to complex federal, state, local and other laws and
    regulations that could adversely affect the cost, manner or
    feasibility of conducting our operations.
      We may
    face unanticipated water disposal costs.
   40




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
    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 reduce our
    cash available for distribution.
  and/or
  We
    depend on two customers for sales of all of our gas. To the
    extent these customers reduce the volumes of gas they purchase
    from us and are not replaced by new customers, our revenues and
    cash available for distribution could decline.
    We are
    exposed to trade credit risk in the ordinary course of our
    business activities.
  and/or
  Certain
    of our undeveloped leasehold acreage is subject to leases that
    may expire in the near future.
   41




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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, resulting in temporarily lower cash from operations,
    which may impact our ability to pay distributions.
    We may
    incur losses as a result of title deficiencies in the properties
    in which we invest.
     42




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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 and reduce
    our cash from operations and our ability to make cash
    distributions to you.
    We
    depend on a limited number of key management personnel, who
    would be difficult to replace.
    The
    amount of cash distributions that we will be able to distribute
    to unitholders will be reduced by the costs associated with
    being a public company, other general and administrative
    expenses and reserves that our general partner believes prudent
    to maintain for the proper conduct of our business and for
    future distributions.
    If our
    general partner fails to develop or maintain an effective system
    of internal controls, then we may not be able to accurately
    report our financial results or prevent fraud. As a result,
    current and potential unitholders could lose confidence in our
    financial reporting, which would harm our business and the
    trading price of our common units.
   43




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Risks
    Inherent in an Investment in Us
  Our
    Parent controls our general partner, which conducts our business
    and manages our operations. Our Parent 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 our Parent to pursue a business strategy that favors
    us. Our Parents directors and officers have a fiduciary
    duty to make decisions in the best interests of the owners of
    our Parent, 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 our Parent, 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;
    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 our Parent, the
    midstream services agreement between us and Quest Midstream and
    Quest Midstreams midstream omnibus agreement with our
    Parent.  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; 44




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
    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 our Parent and its affiliates for the
    management of our business.
    Unitholders
    have limited voting rights, are not entitled to elect our
    general partner or the directors of our general
    partner.
   45




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Even
    if holders of our common units are dissatisfied, they cannot
    initially remove our general partner without its
    consent.
  2 3
      Our
    Parent may engage in competition with us.
      We are
    restricted from engaging in businesses other than the
    exploration and development of gas and oil.
    
    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 46




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
    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.    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.
    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.
   47




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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.
     48




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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
    partnership agreement requires that we distribute all of our
    available cash, which could limit our ability to grow our
    reserves and production.
    
    general economic and market conditions, including interest
    rates, prevailing at the time we desire to issue securities or
    borrow funds;
    conditions in the gas and oil industry;
    the market price of, and demand for, our common units;
    our results of operations and financial condition; and
    prices for gas and oil.  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.
   49




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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.
    If we
    distribute cash from capital surplus, which is analogous of a
    return of capital, our minimum quarterly distribution rate will
    be reduced proportionately, and the distribution thresholds
    after which the incentive distribution rights entitle our
    general partner to an increased percentage of distributions will
    be proportionately decreased.
   50




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An
    increase in interest rates may cause the market price of our
    common units to decline.
    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.
       51




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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.
    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
 52




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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)
  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.
   53




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Item 1B.
    Unresolved
    Staff Comments.   Item 3.Legal
    Proceedings.    et al No. CJ-2003-30).
  No. CJ-2005-143). et al.
  No. CJ-2007-11079).
  No. 04-C-100-PA)
 54




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No. CJ-06-07)
      No. 07-1225-MLB)
    No. 07-CONS-155-CSHO)
 55




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Item 4.
    Submission
    of Matters to a Vote of Security
    Holders.   PART II  Item 5.
    Market
    for Registrants Common Equity, Related Unitholder Matters
    and Issuer Purchases of Equity
    Securities.  Market
    Information
    Price Range


Cash DistributionHigh


Low


per Common Unit (1)Fourth Quarter

$
16.50


$
13.90


$
0.2043     (1)
    
    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
      
    lessthe 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; 56




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
    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;
    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.   57




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
    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):  Total Quarterly

Marginal Percentage Interest in DistributionsDistributions Target

Limited


GeneralAmount

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
%  58




---



##### Table of Contents



Securities
    Authorized For Issuance Under Equity Compensation
    Plans
    Number ofSecuritiesRemaining AvailableNumber of





for Future IssuanceSecurities to be





Under EquityIssued Upon


Weighted-Average


Compensation PlansExercise of


Exercise Price of


(ExcludingOutstanding


Outstanding


SecuritiesOptions, Warrants


Options, Warrants


Reflected in ColumnPlan Category

and Rights


and Rights


(a))(a)


(b)


(c)Equity compensation plans approved by security holders










Equity compensation plans not approved by security holders










2,115,950Total










2,115,950     Unregistered
    Sales of Equity Securities
    Purchases
    of Equity Securities
   59




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##### Table of Contents



Item 6.
    Selected
    Financial
    Data.       Successor


PredecessorNovember 15


January 1Through


Through








7 Mos EndedDecember 31,


November 14,


Year Ended December 31,


December 31,


Fiscal Year Ended May 31,2007


2007


2006


2005


2004


2004


2003(Consolidated)


(Carve out)


(Carve out)


(Carve out)


(Carve out)


(Carve out)


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

$
15,842


$
97,193


$
65,551


$
44,565


$
24,201


$
28,147


$
8,345Other revenue/expense


22



(45
)


(83
)


387



37



(904
)


(908
)Total revenues


15,864



97,148



65,468



44,952



24,238



27,243



7,437Costs and expenses:Oil and gas production


3,579



24,416



21,208



14,388



5,389



5,003



1,979Transportation expense


4,342



24,836



17,278



7,038



3,196



1,869



644General and administrative


1,562



10,272



8,149



4,068



2,328



2,264



711Provision for impairment of gas and oil properties










30,719















Depreciation and amortization


5,046



30,672



25,521



20,121



6,954



6,698



1,578Total costs and expenses


14,529



90,196



102,875



45,615



17,867



15,834



4,912Operating income (loss)


1,335



6,952



(37,407
)


(663
)


6,371



11,409



2,525Other income (expense):Change in derivative fair value


(6,082
)


(420
)


6,410



(4,668
)


(1,487
)


(2,013
)


(4,867
)Gain (loss) on sale of assets


(18
)


(310
)


(7
)


12







(6
)


(3
)Interest expense, net


(13,746
)


(25,413
)


(16,545
)


(19,873
)


(7,702
)


(6,403
)


(438
)Total other expense


(19,846
)


(26,143
)


(10,142
)


(24,529
)


(9,189
)


(8,422
)


(5,308
)Income (loss) before cumulative effect of accounting change


(18,511
)


(19,191
)


(47,549
)


(25,192
)


(2,818
)


2,987



(2,783
)Cumulative effect of accounting change, net of tax






















(28
)


Net income (loss)


(18,511
)


(19,191
)

$
(47,549
)

$
(25,192
)

$
(2,818
)

$
2,959


$
(2,783
)General partners interest in net (loss)

$
(370
)Limited partners interest in net (loss)

$
(18,141
)Net (loss) per limited partner unit:Common units (basic and diluted)

$
(6.80
)Subordinated units (basic and diluted)

$
(6.80
)Cash distribution per unit

$
Cash Flow Data:Net cash provided by (used in) operating activities

$
(13,732
)

$
22,829


$
11,183


$
584


$
18,778


$
15,701


$
3,306Net cash used in investing activities


(7,603
)


(98,490
)


(117,194
)


(51,645
)


(28,075
)


(125,482
)


(8,397
)Net cash provided by (used in) financing activities


31,505



54,327



124,818



47,141



26,280



111,060



7,203Balance Sheet Data:Total assets

$
359,246






$
311,718


$
217,650


$
178,332


$
149,651


$
23,264Long-term debt, net of current maturities


94,042







225,245



75,889



148,747



126,766



10,575Partners equity (deficit)


228,760







51,091



69,547



(3,877
)


(1,730
)


6,521  60




---



##### Table of Contents



Item 7.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operation.  You should read the following discussion of the financial
    condition and results of operations for the Predecessor and us
    in conjunction with the historical financial statements and
    accompanying notes of the Predecessor and the financial
    statements for Quest Energy Partners, L.P. included in
    Financial Statements and Supplementary Data under
    Item 8 of this report.
  Overview
            Our
    Initial Public Offering
   61




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##### Table of Contents



2008
    Outlook
    160-acre 80-acre 80-acre
    
    the domestic and foreign supply of gas;
    the price and quantity of imports of foreign 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 natural gas inventories;    
    domestic and foreign governmental regulations;
    proximity and capacity of gas pipelines and other transportation
    facilities; and
    the price and availability of alternative fuels.      and/or
 62




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##### Table of Contents



Factors
    That Significantly Affect Comparability of Our Results
    Outstanding Indebtedness.
  Purchase of Derivatives.
  Midstream Services Agreement.
      Results
    of Operations
   63




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##### Table of Contents



Years
    Ended December 31, 2007 and 2006
    Overview.
  Year Ended December 31,2007


2006


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

$
113,035


$
65,551


$
47,484



72.4
%Other revenue/(expense)

$
(23
)

$
(83
)

$
60



72.3
%Oil and gas production costs

$
27,995


$
21,208


$
6,787



32.0
%Transportation expense

$
29,178


$
17,278


$
11,900



68.9
%Depreciation, depletion and amortization

$
35,718


$
25,521


$
10,197



40.0
%General and administrative expenses

$
11,834


$
8,149


$
3,685



45.22
%Change in derivative fair value

$
(6,502
)

$
6,410


$
(12,912
)


(201.4
)%Impairment charge

$



$
30,719


$
(30,719
)


(100.0
)%Interest expense

$
39,575


$
16,935


$
22,640



133.7
%   Production.
  Year Ended December 31,2007


2006


Increase/(Decrease)($ in thousands)Production Data:Total production (MMcfe)


17,148



12,341



4,807



39.0
%Average daily production (MMcfe/d)


47.0



33.8



13.2



39.0
%Average Sales Price per Unit (Mcfe):Excluding hedges

$
6.17


$
5.95


$
0.22



3.6
%Including hedges


6.59



5.31



1.27



24.1
%Average Unit Costs per Mcfe:Production costs

$
1.63


$
1.84


$
(0.21
)


(11.4
)%Transportation expense

$
1.69


$
1.40


$
0.29



20.7
%Depreciation, depletion and amortization


2.10



2.05



0.05



2.4
%   Oil and Gas Sales.
 64




---



##### Table of Contents



Other Revenue/(Expense).
  Operating Expenses.
    Depreciation, Depletion and Amortization.
  General and Administrative Expenses.
  Change in Derivative Fair Value.
  Impairment Charge.
 65




---



##### Table of Contents



Interest Expense.
  Years
    Ended December 31, 2006 and 2005
  Overview.
  Year Ended December 31,2006


2005


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

$
65,551


$
44,565


$
20,986



47.1
%Other revenue/(expense)

$
(83
)

$
387


$
(470
)


121.4
%Oil and gas production costs

$
21,208


$
14,388


$
6,820



47.4
%Transportation expense

$
17,278


$
7,038


$
10,240



145.5
%Depreciation, depletion and amortization

$
25,521


$
20,121


$
5,400



26.8
%General and administrative expenses

$
8,149


$
4,068


$
4,081



100.3
%Change in derivative fair value

$
6,410


$
(4,668
)

$
11,078



237.3
%Impairment charge

$
30,719


$



$
30,719



100.0
%Interest expense

$
16,935


$
19,919


$
(2,984
)


(15.0
)%   Production.
  Year Ended December 31,2006


2005


Increase/(Decrease)Production Data:Total production (MMcfe)


12,341



9,620



2,721



28.3
%Average daily production (MMcfe/d)


33.8



26.4



7.4



28.0
%Average Sales Price per Unit (Mcfe):Excluding hedges

$
5.95


$
7.45


$
(1.50
)


(20.1
)%Including hedges


5.31



4.63



0.68



14.7
%Average Unit Costs per Mcfe:Production costs

$
1.84


$
1.50


$
0.34



22.7
%Transportation expense

$
1.40


$
0.73


$
0.67



91.8
%Depreciation, depletion and amortization


2.05



2.14



(0.09
)


(4.2
)%   Oil and Gas Sales.
 66




---



##### Table of Contents



Other Revenue/(Expense).
  Operating Expenses.
    Depreciation, Depletion and
    Amortization.
  General and Administrative Expenses.
  Interest Expense.
  Change in Derivative Fair Value.
  Impairment Charge.
 67




---



##### Table of Contents



Liquidity
    and Capital Resources
  Liquidity
          Future
    Capital Expenditures
    
    $41.0 million to drill and complete these wells and
    recomplete an estimated 52 gross wells in the Cherokee
    Basin; and
    $37.5 million for acreage, equipment and vehicle
    replacement and purchases and salt water disposal facilities in
    the Cherokee Basin.    
    maintenance capital expenditures, which are those capital
    expenditures required to maintain our production levels and
    asset base over the long term; and
    expansion capital expenditures, which are those capital
    expenditures that we expect will increase our production of our
    gas and oil properties, our asset base over the long term.  and/or
  and/or
 68




---



##### Table of Contents



Cash
    Flows
  Cash Flows from Operating Activities.
  Cash Flows Used in Investing Activities.
  Cash Flows from Financing Activities.
  Credit
    Facility
    Contractual
    Obligations
    Payments Due by PeriodLess Than


1-3


4-5


More ThanTotal


1 Year


Years


Years


5 Years(In thousands)Revolving Credit Facility

$
94,000


$



$



$
94,000


$
Notes Payable


708



666



30



12



Interest expense obligation(1)


35,356



7,304



14,583



13,465



4Drilling contractor


4,241



4,241











Asset retirement obligations


1,700















1,700Derivatives


13,827



8,241



5,586







Total

$
149,832


$
20,452


$
20,199


$
107,477


$
1,704     (1)
    
    The interest payment obligation was computed using the LIBOR
    interest rate as of December 31, 2007. If the interest rate
    were to change 1%, then the interest payment obligation would
    change by $4.6 million.    Off-Balance
    Sheet Arrangements
   69




---



##### Table of Contents



Critical
    Accounting Policies and Estimates
        Accounting
    for Derivative Instruments and Hedging Activities
    Accounting for Derivative Instruments and Hedging
    Activities
     70




---



##### Table of Contents



Gas
    and Oil Properties
        and/or
   71




---



##### Table of Contents



Recent
    Accounting Pronouncements
    Accounting for Certain Hybrid Financial
    Instruments
  Accounting for Servicing of Financial Asset
  Accounting for Uncertainty in Income Taxes an
    interpretation of FASB Statement of Financial Accounting
    Standards No. 109 Accounting for Income Taxes
  Fair Value
    Measurements
 72




---



##### Table of Contents



FAS 157-2, Effective Date of FASB Statement No. 157.
    Employers
    Accounting for Defined Benefit Pension and Other Postretirement
    Plans
    The Fair Value
    Option for Financial Assets and Financial Liabilities
  Business Combinations.
 73




---



##### Table of Contents



Noncontrolling
    Interests in Consolidated Financial Statements, an amendment of
    ARB No. 51
  Disclosures about Derivative
    Instruments and Hedging Activities
  Forward-Looking
    Statements
    
    the volatility of gas and oil prices;
    discovery, estimation, development and replacement of gas and
    oil reserves;
    cash flow, liquidity and financial condition;
    business and financial strategy;
    amount, nature and timing of capital expenditures, including
    future development costs;
    availability and terms of capital;
    timing and amount of future production of gas and oil;
    availability of drilling and production equipment, labor and
    other services;
    operating costs and other expenses;
    prospect development and property acquisitions;
    marketing of gas and oil;
    competition in the gas and oil industry;
    the impact of weather and the occurrence of natural disasters
    such as fires;
    governmental regulation of the gas and oil industry;
    developments in oil-producing and gas-producing
    countries; and
    strategic plans, expectations and objectives for future
    operations. 74




---



##### Table of Contents



Item 7A.
    Quantitative
    and Qualitative Disclosures About Market
    Risk.   75




---



##### 



Item 8.Financial
    Statements and Supplementary Data.  INDEX TO
    FINANCIAL STATEMENTS
   
 REPORT OF INDEPENDENT REGISTERED PUBLIC
    ACCOUNTING FIRM ON CONSOLIDATED FINANCIAL STATEMENTS


F-2REPORT OF INDEPENDENT REGISTERED PUBLIC
    ACCOUNTING FIRM ON CARVE OUT FINANCIAL STATEMENTS


F-3BALANCE SHEETS


F-4STATEMENTS OF OPERATIONS


F-5STATEMENTS OF CASH FLOWS


F-6STATEMENT OF PARTNERS EQUITY


F-7NOTES TO CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS


F-9   F-1




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
    CONSOLIDATED FINANCIAL STATEMENTS               F-2




---



##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
    CARVE OUT FINANCIAL STATEMENTS               F-3




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES



BALANCE
    SHEETS  Successor


PredecessorDecember 31,


December 31,2007


2006(consolidated)


(carve out)($ in thousands)ASSETSCurrent assets:Cash

$
10,170


$
21,334Restricted cash


1,205



1,150Accounts receivable, trade


297



10,211Due from affiliated companies


12,788



Other current assets


2,923



1,053Inventory


4,956



3,378Short-term derivative asset


6,729



10,795Total current assets


39,068



47,921Property and equipment, net of accumulated depreciation of
    $6,183 and 5,045


17,063



16,054Oil and gas properties:Properties being amortized


406,661



316,783Properties not being amortized


19,328



9,445425,989



326,228Less: Accumulated depreciation, depletion, amortization and
    impairment


(127,968
)


(92,733
)Net property, plant and equipment


298,021



233,495Other assets, net


3,526



9,466Long-term derivative asset


1,568



4,782Total assets

$
359,246


$
311,718LIABILITIES AND PARTNERS EQUITYCurrent liabilities:Accounts payable

$
15,195


$
13,929Revenue payable






4,540Accrued expenses


5,056



2,486Current portion of notes payable


666



324Short-term derivative liability


8,241



5,244Total current liabilities


29,158



26,523Non-current liabilities:Long-term derivative liability


5,586



7,449Asset retirement obligation


1,700



1,410Notes payable


94,708



225,569Less current maturities


(666
)


(324
)Non-current liabilities


101,328



234,104Total liabilities


130,486



260,627Commitments and contingencies






Partners equity:Predecessor






50,663Common unitholders  public; 9,100,000 units issued
    and outstanding at December 31, 2007


141,364Common unitholder  affiliate; 3,201,521 units issued
    and outstanding at December 31, 2007


22,598Subordinated unitholder  affiliate; 8,857,981 units
    issued and outstanding at December 31, 2007


63,235General partner  affiliate; 431,827 units issued and
    outstanding at December 31, 2007


3,048Accumulated other comprehensive income (loss)


(1,485
)


428Total partners equity


228,760



51,091Total liabilities and partners equity

$
359,246


$
311,718    F-4




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES



STATEMENTS
    OF OPERATIONS  Successor


PredecessorNovember 15,


January 1,2007)


2007through


through


Year Ended


Year EndedDecember 31,


November 14,


December 31,


December 31,2007


2007


2006


2005(consolidated)


(carve out)


(carve out)


(carve out)($ in thousands, except per unit data)Revenue:Oil and gas sales

$
15,842


$
97,193


$
65,551


$
44,565Other revenue and expense


22



(45
)


(83
)


387Total revenues


15,864



97,148



65,468



44,952Costs and expenses:Oil and gas production


3,579



24,416



21,208



14,388Transportation expense


4,342



24,836



17,278



7,038General and administrative expenses


1,562



10,272



8,149



4,068Provision  impairment of gas properties










30,719



Depreciation, depletion and amortization


5,046



30,672



25,521



20,121Total costs and expenses


14,529



90,196



102,875



45,615Operating income (loss)


1,335



6,952



(37,407
)


(663
)Other income (expense):Change in derivative fair value


(6,082
)


(420
)


6,410



(4,668
)Sale of assets


(18
)


(310
)


(7
)


12Interest expense


(13,760
)


(25,815
)


(16,935
)


(19,919
)Interest income


14



402



390



46Total other income and expense


(19,846
)


(26,143
)


(10,142
)


(24,529
)Loss before income taxes


(18,511
)


(19,191
)


(47,549
)


(25,192
)Income tax expense














Net loss

$
(18,511
)

$
(19,191
)

$
(47,549
)

$
(25,192
)General partners interest in net (loss)

$
(370
)Limited partners interest in net (loss)

$
(18,141
)Net loss per limited partner unit:Common units (basic and diluted)

$
(6.80
)Subordinated units (basic and diluted)

$
(6.80
)Weighted average limited partner units outstanding:Common units (basic and diluted)


1,150,329Subordinated units (basic and diluted)


1,116,348    F-5




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES



STATEMENTS
    OF CASH FLOWS  Successor


PredecessorNovember 15,


January 1,2007


2007Through


Through


Year Ended


Year EndedDecember 31


November 14,


December 31,


December 31,2007


2007


2006


2005(consolidated)


(carve out)


(carve out)


(carve out)($ in thousands)Cash flows from operating activities:Net (loss)

$
(18,511
)

$
(19,191
)

$
(47,549
)

$
(25,192
)Adjustments to reconcile net (loss) to cash provided by
    operations:Depreciation and depletion


5,391



32,904



28,339



20,121Write down of gas properties










30,719



Accrued interest subordinated debt














7,765Change in derivative fair value


6,082



420



(16,917
)


4,580Capital contributions for retirement plan










428



266Capital contributions for audit committee fees














19Capital contributions for director fees










429



Capital contributions to employees


1



12



779



352Amortization of loan origination fees


9,042



1,918



1,202



5,108Amortization of gas swap fees






187



208



Amortization of deferred hedging gains










(328
)


(831
)Bad debt expense










37



192(Gain) loss on sale of assets






328







Other










(3
)


(12
)Change in assets and liabilities:Restricted cash






(55
)


3,167



(4,318
)Accounts receivable






9,840



(219
)


(3,455
)Other receivables


(36
)


110



(28
)


(15
)Other current assets


(1,762
)


(108
)






(1,495
)Inventory


(823
)


(755
)


(1,970
)


(1,124
)Deposits










675



Due from related parties


(10,830
)










Accounts payable


(2,405
)


3,719



5,836



(1,440
)Revenue payable






(4,540
)


4,540



Accrued expenses


119



(1,960
)


1,838



63Net cash provided by (used in) operating activities


(13,732
)


22,829



11,183



584Cash flows from investing activities:Equipment, development and leasehold


(7,597
)


(95,315
)


(111,703
)


(46,269
)Additions to other property and equipment


(6
)


(3,428
)


(5,684
)


(5,413
)Proceeds from sale of property and equipment






253



193



37Other assets














Net cash used in investing activities


(7,603
)


(98,490
)


(117,194
)


(51,645
)Cash flows from financing activities:Proceeds from bank borrowings


94,580



35,000



203,696



59,584Repayments of note borrowings


(260,014
)


(428
)


(54,424
)


(86,728
)Proceeds from subordinated debt














13,297Contributions/distributions  QRC


49,415



21,298



(20,142
)


133,658Proceeds from issuance of common units


163,800Syndication costs of common units


(12,775
)Repayment of subordinated debt














(66,398
)Refinancing costs  RBC


(3,527
)


(1,688
)






Refinancing costs  Guggenheim










(4,479
)


(6,272
)Change in other long-term liabilities


26



145



167



Net cash provided by (used in) financing activities


31,505



54,327



124,818



47,141Net increase (decrease) in cash


10,170



(21,334
)


18,807



(3,920
)Cash, beginning of period






21,334



2,527



6,447Cash, end of period

$
10,170


$



$
21,334


$
2,527    F-6




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##### Table of Contents



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


AccumulatedOther


Other


TotalComprehensive


Comprehensive


OwnersIncome (Loss)


Income (Loss)


Equity(In thousands)Predecessor (Carve Out):Balance, January 1, 2005

$
7,266


$
(11,143
)

$
(3,877
)Comprehensive income:Net income


(25,192
)Change in fixed-price contract and other derivative fair value






(36,028
)Total comprehensive income










(61,220
)Partner contributions


133,658







133,658Contributions for consideration for compensation to employees


427







427Contributions for retirement plan


495







495Contributions for consideration of services


64







64Balance, December 31, 2005


116,718



(47,171
)


69,547Comprehensive income:Net income


(47,549
)Change in fixed-price contract and other derivative fair value






47,599Total comprehensive income










50Contributions for consideration pursuant to compensation plan
    for non-employee directors


429







429Contributions for consideration for compensation to employees


779







779Contributions for retirement plan


428







428Partner distributions


(20,142
)






(20,142
)Balance, December 31, 2006


50,663



428



51,091Comprehensive income:Net income


(19,191
)Change in fixed-price contract and other derivative fair value






(9,437
)Reclassification adjustment into earningsTotal comprehensive income










(28,628
)Capital contributions from QRC


21,298







21,298Balance, November 14, 2007

$
52,770


$
(9,009
)

$
43,761    F-7




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##### Table of Contents



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


Other


TotalCommon


Subordinated


Partner


Comprehensive


PartnersUnitholders


Unitholders


Interest


Income


Equity(In thousands)Successor (Consolidated):Balance at November 14, 2007

$



$



$



$



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


163,800















163,800Offering costs


(12,775
)














(12,775
)Acquisition of the Predecessor


26,001



72,635



3,506



(9,009
)


93,133Comprehensive income:Net income


(10,551
)


(7,590
)


(370
)Change in fixed-price contract and other derivative fair value














7,524Total comprehensive income


















(10,987
)Distributions


(2,513
)


(1,810
)


(88
)






(4,411
)Balance, December 31, 2007

$
163,962


$
63,235


$
3,048


$
(1,485
)

$
228,760    F-8




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL STATEMENTS
  1.
    Formation
    of the Partnership and Description of Business    2.
    Summary
    of Significant Accounting Policies  Basis
    of Presentation
  Regulation S-X,
    Consolidation
    Policy
     F-9




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  Use of
    Estimates
      Basis
    of Accounting
    Revenue
    Recognition
    Cash
    Equivalents
    Uninsured
    Cash Balances
    Restricted
    Cash
    Accounts
    Receivable
      Inventory
   F-10




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  Concentration
    of Credit Risk
    Natural
    Gas and Oil Properties
      and/or
   F-11




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
        Other
    Property and Equipment
        
    Buildings:  25 years;
    Equipment:  10 years; and
    Vehicles:  7 years.  Debt
    Issue Costs
    Other
    Dispositions
    Marketable
    Securities
  Accounting for Certain Investments in Debt and
    Equity Securities
  Income
    Taxes
   F-12




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    Fair
    Value of Financial Instruments
  Accounting for Derivative
    Instruments and Hedging Activities
  Accounting
    for Derivative Instruments and Hedging Activities
  Accounting for Derivative
    Instruments and Hedging Activities
       F-13




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  Asset
    Retirement Obligations
  Accounting for Asset
    Retirement Obligations
    Net
    Income per Limited Partner Unit
  03-06, Participating Securities and the Two 
    Class Method under FASB Statement No. 128 (EITF 03-06). EITF 03-06
  Business
    Segment Reporting
    Allocation
    of Costs
      
    Revenues include all revenues earned by the Cherokee Basin
    Operations, before elimination of intercompany sales with QRC
    and its subsidiaries. Prior to December 1, 2006, pursuant
    to a transportation agreement, Bluestem Pipeline, a wholly-owned
    subsidiary of QRC, generally charged the Cherokee Basin
    Operations transportation fees ranging from $0.78 per thousand
    cubic feet (Mcf) to $0.87 per Mcf. Effective
    December 1, 2006, pursuant to the midstream services
    agreement, the fee for gathering, dehydration and treating
    services was $0.50 per MMBtu of gas and $1.10 per MMBtu of gas
    for compression services, subject to annual adjustment. Please
    read Note 12. Related Party Transactions.
    Certain common expenses of QRCs operations and the
    Cherokee Basin Operations were treated as follows:  
    general and administrative expenses associated with the pipeline
    operations were eliminated; F-14




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
   
    costs associated with the salt water disposal system, which were
    previously reported in Bluestem operations prior to the
    formation of Quest Midstream Partners, L.P. (Quest
    Midstream) in December 2006, were allocated to the
    Cherokee Basin Operations; and
    third party costs incurred at the QRC level that are clearly
    identifiable as Cherokee Basin Operations costs, such as
    insurance premiums related to the Cherokee Basin Operations and
    legal fees of outside counsel related to contracts entered into
    or claims made by or against the Cherokee Basin Operations and
    salaries and benefits of Cherokee Basin Operations executives
    paid by QRC, were allocated to the Cherokee Basin Operations.  
    Non-producing acreage located outside of the Cherokee Basin and
    not transferred to the Partnership was eliminated from the
    balance sheet and related expenses were eliminated.
    To the extent that the common expenses described above were
    charged to the Cherokee Basin Operations in the past, the
    reduction in expenses was retroactively reflected with the
    offsetting debit to partners equity.
    Since the Partnership is not subject to entity level income
    taxes, no allocation of income taxes or deferred income taxes
    was reflected in the financial statements.
    Derivative transactions remained with the Cherokee Basin
    Operations.
    Managements estimates of the expenses of the Cherokee
    Basin Operations on a stand-alone basis were not expected to be
    significantly different from those reflected in the statements.  Recently
    Issued Accounting Standards
    Accounting for Certain Hybrid Financial
    Instruments
  Accounting for Servicing of Financial Asset
  Accounting for Uncertainty in Income Taxes an
    interpretation of FASB Statement of Financial Accounting
    Standards No. 109 Accounting for Income Taxes
 F-15




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    Fair Value
    Measurements
  FAS 157-2, Effective Date of FASB Statement No. 157.
    Employers
    Accounting for Defined Benefit Pension and Other Postretirement
    Plans
    The Fair Value
    Option for Financial Assets and Financial Liabilities
 F-16




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  Business Combinations.
  Noncontrolling
    Interests in Consolidated Financial Statements, an amendment of
    ARB No. 51
  Disclosures about Derivative
    Instruments and Hedging Activities
  Reclassifications
    3.
    Initial
    Public Offering     F-17




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
        
    the contribution of Quest Cherokee, LLC (Quest
    Cherokee) and its subsidiary, Quest Oilfield Service, LLC
    (QCOS), to the Partnership;
    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 the Partnership;
    the issuance of 3,201,521 common units and 8,857,981
    subordinated units to QRC; and
    QRC and its affiliates on the one hand, and Quest Cherokee and
    the Partnership 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 the Partnership;
    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
    the Partnerships right to purchase from QRC and its
    affiliates certain assets that QRC and its affiliates acquire
    within the Cherokee Basin.    No. 333-144716)
   F-18




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##### 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.    4.
    Long-Term
    Debt    December 31,


December 31,2007


2006($ in thousands)Senior credit facilities

$
94,000


$
225,000Notes payable to banks and finance companies, secured by
    equipment and vehicles, due in installments through October 2013
    with interest ranging from 5.5% to 11.5% per annum


708



569Total long-term debt


94,708



225,569Less  current maturities


666



324Total long-term debt, net of current maturities

$
94,042


$
225,245     2008

$
666,0002009


17,0002010


7,0002011


6,0002012


94,006,000Thereafter


6,000$
94,708,000  F-19




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  Credit
    Facility
            pari passu
   F-20




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
      
    permitting the ratio (calculated based on the most recently
    delivered compliance certificate) of the Partnerships
    consolidated current assets (including the unused amount of the
    borrowing base, 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 Credit Agreement) at any fiscal
    quarter-end, commencing with the quarter ended December 31,
    2007, 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 ratio (calculated on the most recently delivered
    compliance certificate) of adjusted consolidated EBITDA to
    consolidated interest charges at any fiscal quarter-end,
    commencing with the quarter ended December 31, 2007, to be
    less than 2.5 to 1.0 measured on a rolling four quarter basis;
    provided that for the periods ending December 31, 2007,
    March 31, 2008, June 30, 2008 and September 30,
    2008, the calculations will be done on a pro forma
    basis; and
    permitting the ratio (calculated based on the most recently
    delivered compliance certificate) of consolidated funded debt to
    adjusted consolidated EBITDA at any fiscal quarter-end,
    commencing with the quarter ended December 31, 2007, to be
    greater than 3.5 to 1.0 measured on a rolling four quarter
    basis; provided that for the periods ending December 31,
    2007, March 31, 2008, June 30, 2008 and
    September 30, 2008, the calculations will be done on a pro
    forma basis.  and/or
       F-21




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    30-day
  Other
    Long-Term Indebtedness
    5.
    Contingencies  et al No. CJ-2003-30).
  No. CJ-2005-143). et al.
  No. CJ-2007-11079).
 F-22




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  No. 04-C-100-PA)
  No. CJ-06-07)
      No. 07-1225-MLB)
 F-23




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
      No. 07-CONS-155-CSHO)
    6.
    Financial
    Instruments    December 31, 2007


December 31, 2006Carrying


Fair


Carrying


FairAmount


Value


Amount


Value(Dollars in thousands)Derivative assets:Interest rate swaps and caps

$



$



$
197


$
197Basis swaps

$
281


$
281


$
62


$
62Fixed-price natural gas swaps

$
2,742


$
2,742


$
2,207


$
2,207Fixed-price natural gas collars

$
5,274


$
5,276


$
13,111


$
13,111Derivative liabilities:Basis swaps

$
(856
)

$
(856
)

$
(377
)

$
(377
)Fixed-price natural gas swaps

$
(5,586
)

$
(5,586
)

$



$
Fixed-price natural gas collars

$
(7,385
)

$
(7,386
)

$
(12,316
)

$
(12,316
)Credit facilities

$
(94,000
)

$
(94,000
)

$
(225,000
)

$
(225,000
)Other financing agreements

$
(708
)

$
(708
)

$
(569
)

$
(569
)    F-24




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
      7.
    Derivatives  Natural
    Gas Hedging Activities
     F-25




---



##### Table of Contents



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


Year Ending


Year EndingDecember 31,


December 31,


December 31,2008


2009


2010


Total(In thousands, except MMBtu data)Natural Gas Swaps:Contract volumes (MMBtu)


2,332,000



12,629,000



10,499,000



25,460,000Weighted-average fixed price per MMBtu(1)

$
7.35


$
7.70


$
7.31


$
7.51Fixed-price sales

$
17,141


$
97,202


$
76,779


$
191,122Fair value, net

$
600


$
199


$
(4,217
)

$
(3,418
)Natural Gas Collars:Contract volumes (MMBtu):Floor


7,028,000











7,028,000Ceiling


7,028,000











7,028,000Weighted-average fixed price per MMBtu(1):Floor

$
6.54










$
6.54Ceiling

$
7.54










$
7.54Fixed-price sales(2)

$
45,973










$
45,973Fair value, net

$
(2,112
)









$
(2,112
)Total Natural Gas Contracts:(3)Contract volumes (MMBtu)


9,360,000



12,629,000



10,499,000



32,488,000Weighted-average fixed price per MMBtu(1)

$
6.74


$
7.70


$
7.31


$
7.30Fixed-price sales(2)

$
63,114


$
97,202


$
76,779


$
237,095Fair value, net

$
(1,512
)

$
199


$
(4,217
)

$
(5,530
)     (1)
    
    The prices to be realized for hedged production are expected to
    vary from the prices shown due to basis.(2)
    
    Assumes floor prices for gas collar volumes.(3)
    
    Does not include basis swaps with notional volumes by year, as
    follows: 2008: 6,276,000 MMBtu.       F-26




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    Interest
    Rate Hedging Activities
      Change
    in Derivative Fair Value
    Successor


PredecessorNovember 15,


January 1,2007


2007Through


Through


Year Ended


Year EndedDecember 31,


November 14,


December 31,


December 31,2007


2007


2006


2005(Dollars in thousands)Change in fair value of derivatives not qualifying as cash flow
    hedges

$
(6,308
)

$
(2,713
)

$
12,233


$
879Amortization of derivative fair value gains and losses
    recognized in earnings prior to actual cash settlements














103Settlements due to ineffective cash flow hedges










(10,234
)


Ineffective portion of derivatives qualifying as cash flow hedges


226



2,293



4,411



(5,650
)$
(6,082
)

$
(420
)

$
6,410


$
(4,668
)     Credit
    Risk
   F-27




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    Market
    Risk
       F-28




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  8.
    Asset
    Retirement Obligation    Successor


PredecessorNovember 15,


January 1,2007


2007Through


Through


Year EndedDecember 31,


November 14,


December 31,2007


2007


2006(Dollars in thousands)Asset retirement obligation beginning balance

$
1,658


$
1,410


$
1,150Liabilities incurred


26



152



175Liabilities settled


(1
)


(6
)


(7
)Accretion expense


17



102



92Revisions in estimated cash flows










Asset retirement obligation ending balance

$
1,700


$
1,658


$
1,410   9.
    Major
    Purchasers    10.
    Partners
    Equity  Issuance
    of Units
    Common
    Units
   F-29




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    
    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 the
    Partnerships 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.      Subordinated
    Units
        General
    Partner Interest
     F-30




---



##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
  Allocations
    of Net Income
    Cash
    Distributions
        
    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.    Total Quarterly

Marginal Percentage Interest in 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
%  F-31




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
    11.
    Net
    Income Per Limited Partner Unit  EITF 03-06.
  Other
    Comprehensive Income (Loss)
    Gross


Tax Effect


Net of Tax(Dollars in thousands)Successor:For the period from November 15, 2007 through
    December 31, 2007:Change in fixed-price contract and other derivative fair value

$
7,524


$



$
7,524Predecessor:For the period from January 1, 2007 through
    November 14, 2007:Change in fixed-price contract and other derivative fair value

$
(9,437
)

$



$
(9,437
)Year Ended December 31, 2006:Change in fixed-price contract and other derivative fair value

$
47,599


$



$
47,599Year Ended December 31, 2005:Change in fixed-price contract and other derivative fair value

$
(36,028
)

$



$
(36,028
)   Comprehensive
    Income
     F-32




---



##### Table of Contents



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


PredecessorNovember 15,


January 1,2007


2007Through


Through


Year Ended


Year EndedDecember 31,


November 14,


December 31,


December 31,2007


2007


2006


2005(Dollars in thousands)Change in fair value of derivatives not qualifying as cash flow
    hedges

$
(6,308
)

$
(2,713
)

$
12,233


$
879Amortization of derivative fair value gains and losses
    recognized in earnings prior to actual cash settlements














103Settlements due to ineffective cash flow hedges










(10,234
)


Ineffective portion of derivatives qualifying as cash flow hedges


226



2,293



4,411



(5,650
)$
(6,082
)

$
(420
)

$
6,410


$
(4,668
)   12.
    Related
    Party Transactions       F-33




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##### Table of Contents



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


PredecessorNovember 15,


January 1,2007


2007Through


ThroughDecember 31,


November 14,


December 31,


December 31,2007


2007


2006


2005(Dollars in thousands)Cash paid for interest

$
4,756


$
23,828


$
20,418


$
10,315Cash paid for income taxes

$



$



$



$
   Supplementary
    Information:
                14.
    Employee
    Benefit Plan With Related Party    15.  SFAS 69
    Supplemental Disclosures (Unaudited)
   Net
    Capitalized Costs
    Successor


PredecessorDecember 31,2007


2006(Dollars in thousands)Natural gas and oil properties and related lease equipment:Proved

$
406,661


$
316,783Unproved


19,328



9,445425,989



326,228Accumulated depreciation, depletion and impairment


(127,968
)


(92,733
)Net capitalized costs

$
298,021


$
233,495  F-34




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##### Table of Contents



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


PredecessorYear Ended December 31,2007


2006(Dollars in thousands)Acquisition of properties proved and unproved

$



$
Development costs


103,076



106,021$
103,076


$
106,021   Results
    of Operations for Natural Gas and Oil Producing
    Activities
    Successor


PredecessorNovember 15


January 1Through


ThroughDecember 31,


November 14,


Year Ended December 31,2007


2007


2006


2005(Dollars in thousands)Production revenues

$
15,842


$
97,193


$
65,551


$
44,565Production costs


(3,579
)


(24,416
)


(21,208
)


(14,388
)Depreciation and depletion


(5,046
)


(30,672
)


(25,521
)


(20,121
)7,217



42,105



18,822



10,056Imputed income tax provision(1)


(2,887
)


(16,842
)


(7,642
)


(3,817
)Results of operations for natural gas/oil producing activity

$
4,330


$
25,263


$
11,180


$
6,239     (1)
    
    The imputed income tax provision is hypothetical (at the
    statutory rate) and determined without regard to the
    Partnerships deduction for general and administrative
    expenses, interest costs and other income tax credits and
    deductions, nor whether the hypothetical tax provision will be
    payable. F-35




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
   Natural
    Gas and Oil Reserve Quantities
    Gas  mcf


Oil  bblsProved reserves:Balance, December 31, 2005


134,319,300



32,269Purchase of
    reserves-in-place






Extensions and discoveries


87,002,842



Revisions of previous estimates(1)


(11,000,000
)


9,740Production


(12,282,142
)


(9,737
)Balance, December 31, 2006


198,040,000



32,272Purchase of
    reserves-in-place






Extensions and discoveries


26,368,000



Revisions of previous estimates(2)


3,663,000



10,807Production


(17,148,000
)


(6,523
)Balance, December 31, 2007


210,923,000



36,556Proved developed reserves:Balance, December 31, 2005


71,638,250



32,269Balance, December 31, 2006


122,390,000



32,272Balance, December 31, 2007


140,966,000



36,556     (1)
    
    Lower natural gas prices reduced the economic lives of the
    underlying natural gas properties and thereby decreased the
    estimated future reserves. Higher oil prices increased the
    economic lives of the underlying oil properties and thereby
    increased the estimated future reserves.(2)
    
    During 2007, higher prices increased the economic lives of the
    underlying oil and natural gas properties and thereby increased
    the estimated future reserves. F-36




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##### Table of Contents



QUEST
    ENERGY PARTNERS, L.P. AND SUBSIDIARIES
  NOTES TO
    CONSOLIDATED/CARVE OUT FINANCIAL
    STATEMENTS  (Continued)
   Standardized
    Measure of Discounted Future Net Cash Flows
    Successor


PredecessorDecember 31,2007


2006


2005(Dollars in thousands)Future production revenues(1)

$
1,351,979


$
1,197,198


$
1,258,579Future production costs


(732,486
)


(638,844
)


(366,474
)Future development costs


(119,448
)


(126,272
)


(122,428
)Future net cash flows


500,045



432,082



769,677Effect of discounting future annual cash flows at 10%


(177,508
)


(164,010
)


(287,132
)Standardized measure of discounted net cash flows before hedges

$
322,537


$
268,072


$
482,545     (1)
    
    The weighted average natural gas and oil wellhead prices used in
    computing the Partnerships and the Predecessors
    reserves were $6.21 per mcf and $92.01 per bbl at
    December 31, 2007; $6.00 per mcf and $58.06 per bbl at
    December 31, 2006; and $9.22 per mcf and $55.69 per bbl at
    December 31, 2005.    Successor


PredecessorYear Ended December 31,2007


2006


2005(Dollars in thousands)Sales and transfers of natural gas and oil, net of production
    costs

$
(56,499
)

$
(25,796
)

$
(25,646
)Net changes in prices and production costs


23,665



(457,808
)


171,468Acquisitions of natural gas and oil in place  less
    related production costs










Extensions and discoveries, less related production costs


63,057



241,621



Revisions of previous quantity estimates less related production
    costs


8,915



(30,424
)


(51,760
)(1)Accretion of discount


15,327



57,934



8,832Total change in standardized measure of discounted future net
    cash flows

$
54,465


$
(214,473
)

$
102,894     (1)
    
    Includes $30.1 million related to increase in future
    development costs. F-37




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##### Table of Contents



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


PredecessorYear Ended December 31,2007


2006


2005(Dollars in thousands)Standardized measure of discounted future net cash flows, before
    hedges

$
322,537


$
268,072


$
482,545Proved natural gas & oil property, net of accumulated
    depletion


278,697



224,048



165,085Standardized measure of discounted future net cash flows in
    excess of net carrying value of proved natural gas &
    oil properties

$
43,840


$
44,024


$
317,460   16.
    Subsequent
    Events   F-38




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##### Table of Contents



Item 9.
    Changes
    in and Disagreements With Accountants on Accounting and
    Financial
    Disclosure.    Item 9A(T).
    Controls
    and
    Procedures.  Evaluation
    of Disclosure Controls and Procedures.
    Internal
    Controls Over Financial Reporting.
    Changes
    in Internal Controls.
    Item 9B.
    Other
    Information.   PART III  Item 10.
    Directors,
    Executive Officers and Corporate
    Governance.  Management
       76




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##### Table of Contents



Directors
    and Executive Officers
    Name

Age

PositionJerry D. Cash(1)


46


Chairman of the Board, Chief Executive Officer, DirectorDavid E. Grose


55


Chief Financial OfficerDavid Lawler


40


Chief Operating Officer and DirectorDavid Bolton


39


Executive Vice President  LandSteve Hochstein


50


Executive Vice President  Exploration/A&DRichard Marlin


55


Executive Vice President  EngineeringGary Pittman(2)


44


DirectorMark Stansberry(2)


52


Director     (1)
    
    Member of the audit committee.(2)
    
    Member of the audit committee, nominating committee and the
    conflicts committee.    Jerry D. Cash
  David E. Grose
 77




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##### Table of Contents



David Lawler
  David Bolton
  Steve Hochstein
  Richard Marlin 175 MMcf/d.
 78




---



##### Table of Contents



Gary Pittman
  Mark Stansberry
  Committees
    of the Board of Directors
    Audit Committee.
    Conflicts Committee.
 79




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##### Table of Contents



Unitholder
    Communications and Other Information
      Reimbursement
    of Expenses of Our General Partner
    Compliance
    with Section 16(a) of the Exchange Act
     80




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##### Table of Contents



Code of
    Ethics
    Form 8-K.
  Item 11.
    Executive
    Compensation.  Compensation
    Discussion and Analysis
        Percentage of Time DevotedPercentage of Time


to Business of Our ParentName

Devoted to Our Business


and Its Other AffiliatesJerry D. Cash


72
%


28
%David E. Grose


67
%


33
%David Lawler


45
%


55
%Richard Marlin


45
%


55
%David Bolton


58
%


42
%   Our
    Parents Compensation Philosophy
    Our
    Parents Compensation Methodology
   81




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##### Table of Contents



Role
    of the Compensation Committee
    
    attract and retain well-qualified executives who will lead our
    Parent and 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
    equityholders to encourage achievement of increases in
    equityholder value.    Role
    of Management in Compensation Process
       82




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##### Table of Contents



Performance
    Peer Group
    Elements
    of our Parents Executive Compensation
    Program
    Base Salary:
    Management Annual Incentive Plan:
       83




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##### Table of Contents



Bonus Plan 2007 Performance Goals.
  Percentage of Goal Achieved50%


100%


150%Performance MeasureEBITDA (earnings before interest, taxes, depreciation and
    amortization)

$
34,000,000


$
54,000,000


$
74,000,000Lease operating expense (excluding gross production taxes and ad
    valorem taxes)

$
1.31/Mcf


$
1.23/Mcf


$
1.15/McfFinding and development cost

$
1.67/Mcf


$
1.50/Mcf


$
1.33/McfYear end proved reserves


193.5 Bcfe



215 Bcfe



236.5 BcfeProduction


16.2 Bcfe



18.0 Bcfe



19.8 Bcfe       Productivity Gain Sharing Payments:
 84




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##### Table of Contents



Discretionary Bonus Plan:
  Equity
    Awards
    Omnibus Stock Award Plan.
  Our Parent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.
 85




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##### 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
 86




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##### Table of Contents



Source of Units.
  Benefits
    Perquisites
    Policy
    Regarding Hedging Equity Ownership
    Compensation
    Recovery Policies
   87




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##### Table of Contents



Executive
    Compensation and Other Information
    Summary
    Compensation Table
  Non-EquityStock

Incentive Plan

All OtherName and Principal Position

Year

Salary

Bonus

Awards(1)

Compensation(2)

Compensation(3)

TotalJerry D. Cash


2007


$
525,000


$
1,200


$
1,814,239


$
182,367


$
46,913
(4)

$
2,569,719Chairman of the Board
    and Chief Executive
    OfficerDavid E. Grose


2007


$
350,000


$
1,200


$
1,066,130


$
124,658


$
15,550


$
1,557,538Chief Financial OfficerDavid Lawler


2007


$
268,739


$
1,200


$
435,494


$
27,783


$
4,148


$
737,364Chief Operating OfficerRichard Marlin


2007


$
248,000


$
1,200


$
254,720


$
80,863


$
20,550


$
605,333Executive VP EngineeringDavid Bolton


2007


$
225,000


$
1,200


$
298,980


$
57,038


$
14,325


$
596,543Executive VP Land     (1)
    
    Includes expense related to bonus shares, restricted stock
    granted in addition to the awards under the Bonus Plan. Expense
    for the bonus shares and restricted stock 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 determined by utilizing the closing stock price
    for our Parents common stock, with expense being
    recognized ratably over the requisite service period. Also
    includes equity portion of the 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 and the remaining portion vests and will
    be paid in March of each of the next three years.(2)
    
    Represents the Bonus Plan awards earned for 2007 and paid in
    2008 and productivity gain sharing bonus payments earned and
    paid in 2007.(3)
    
    Matching and profit sharing contribution by our Parent under the
    401(k) savings plan and life insurance premiums. Salary shown
    above has not been reduced by pre-tax contributions to the
    company-sponsored 401(k) savings plan. For 2007, matching
    contributions and profit sharing contribution amounts were as
    follows: Mr. Cash  $15,500,
    Mr. Grose  $15,500, Mr. Lawler 
    $4,131, Mr. Marlin  $20,500, and
    Mr. Bolton  $14,275.(4)
    
    In addition to the items described in (3) above, also
    includes expenses related to a company provided automobile
    ($30,712) and benefits for gym services. On occasion, family
    members and acquaintances have accompanied Mr. Cash on
    business trips made on private charter flights at no incremental
    cost to us. 88




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##### Table of Contents



Grants
    of Plan-Based Awards in 2007
      Grants of
    Plan-Based Awards in 2007
  All Other

Grant DateEstimated Future Payouts Under

Stock Awards:

Fair Value ofNon-Equity Incentive Plan Awards

Number of

Stock andApproval

Grant

Threshold

Target

Maximum

Shares of

OptionName

Date

Date

($)

($)

($)

Stock (#)

AwardsJerry Cash


3/30/07



4/2/07
(1)














493,080


$
4,329,242(2)

$
115,500


$
220,500


$
525,000(3)





$
69,167David Grose


3/30/07



4/2/07
(1)














105,000


$
921,9003/30/07



3/30/07















70,000
(4)

$
641,900(2)

$
77,000


$
147,000


$
350,000(3)





$
46,458David Lawler


4/10/07



4/10/07
(1)














105,000


$
926,100(2)

$
63,800


$
121,800


$
290,000(3)





$
26,583Richard Marlin


2/23/07



3/21/07
(1)














45,000


$
388,800(2)

$
17,360


$
66,960


$
182,280(3)





$
35,113Dave Bolton


2/23/07



3/07/07
(1)














45,000


$
360,450(2)

$
15,750


$
60,750


$
165,375(3)





$
31,875     (1)
    
    Represents shares granted in connection with the execution of
    the Named Executive Officers employment agreement in 2007.
    Grant date is the date the employment agreements were executed.
    Except for Mr. Lawler, one-third of each award vests on
    March 16, 2008, 2009 and 2010. For Mr. Lawler,
    15,000 shares were immediately vested and
    30,000 shares vested on May 1 of each of 2008, 2009 and
    2010.(2)
    
    Represents an award under the Bonus Plan for 2007. On
    March 5, 2008, the Committee determined the amount of the
    award payable for 2007 based upon 2007 performance. The amount
    for Mr. Lawler is pro-rated based on his employment
    commencement date in 2007. See Compensation Discussion and
    Analysis  Elements of Our Parents Executive
    Compensation Program  Management Annual Incentive
    Plan for a discussion of the performance criteria
    applicable to these awards.(3)
    
    Represents amount payable under our Parents productivity
    gain sharing bonus program.(4)
    
    Award was immediately vested. 89




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##### Table of Contents



Equity
    Awards Outstanding at Fiscal Year-End 2007
    Stock AwardsMarket Valueof Shares of StockNumber of Shares


That HaveThat Have Not Vested


Not VestedJerry Cash(1)


498,264


$
3,572,553David Grose(2)


108,564


$
778,404David Lawler(3 )


90,000


$
645,300Richard Marlin(4)


59,064


$
423,489Dave Bolton(5)


66,110


$
474,009     (1)
    
    166,088 shares vest on each of March 16, 2008, 2009
    and 2010.(2)
    
    36,188 shares vest on each of March 16, 2008, 2009 and
    2010.(3)
    
    30,000 shares vest on each of May 12, 2008, 2009 and
    2010.(4)
    
    15,688 shares vest on each of March 16, 2008, 2009 and
    2010. 12,000 shares vest on April 4, 2008.(5)
    
    15,370 shares vest on each of March 16, 2008, 2009 and
    2010. 20,000 shares vest on October 5, 2008.  Stock
    Vested in 2007
    Stock AwardsNumber of Sharesof Common Stock


Value RealizedName

Acquired on Vesting (#)


on Vesting ($)Jerry Cash


1,728


$
16,813David Grose


119,188


$
1,159,018David Lawler


15,000


$
145,950Richard Marlin


24,688


$
240,214David Bolton


20,370


$
206,600     Director
    Compensation for 2007
    Fees Earned or


All OtherPaid in Cash


Compensation


TotalName

($)


($)


($)Gary Pittman

$
5,086


$
3,065
(1)

$
8,151Mark Stansberry

$
4,442


$
3,065
(1)

$
7,507     (1)
    
    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 90




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##### Table of Contents



Stansberry each received distributions and distribution
    equivalents with respect to the vested and unvested units
    totaling $3,065 for the period from November 15, 2007
    through December 31, 2007.    
    annual director fee of $32,000 per year (the fees for
    Messrs. Pittman and Stansberry were pro rated for the
    fourth quarter of 2007 based on their length of service);
    annual fee of $7,500 per year for the Audit Committee
    Chairperson (the fee for Mr. Pittman was pro rated for the
    fourth quarter of 2007); and
    annual fee of $2,500 per year for any other committee
    chairperson (the fees for Mr. Stansberry were pro rated for
    the fourth quarter of 2007).  Employment
    Contracts
      Number of Shares ofName

Position

Base Salary


Restricted StockJerry Cash

Chief Executive Officer

$
525,000



493,080David Grose

Chief Financial Officer

$
350,000



105,000David Lawler

Chief Operating Officer

$
290,000



90,000David Bolton

Executive Vice President  Land

$
225,000



45,000Richard Marlin

Executive Vice President  Engineering

$
248,000



45,000       
    the executive will receive his base salary for the remainder of
    the term,
    our Parent 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).    
    our Parent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
    our Parent in good faith);
    if our Parent requires the executive to be based anywhere other
    than Oklahoma City, Oklahoma; 91




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##### Table of Contents




    a substantial reduction in the executives duties or
    responsibilities; or
    the executive no longer has the title specified above.    
    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 our Parent
    or conviction of a felony,
    any conflict of interest, except those consented to in writing
    by our Parent;
    any material failure by the executive to observe our
    Parent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 our Parents
    satisfaction;
    any conduct that is materially detrimental to our Parents
    operations, financial condition or reputation; or
    any material breach of the employment agreement by the executive.    UnvestedEquityName

Base Salary(1)


Compensation(2)


Bonus(3)


Benefits(4)


TotalJerry Cash

$
1,575,000


$
3,572,553


$
338,625


$
9,183


$
5,495,361David Grose

$
1,050,000


$
778,404


$
225,750


$
13,701


$
2,067,855David Lawler

$
870,000


$
645,300


$
187,050


$
13,701


$
1,716,051Richard Marlin

$
744,000


$
423,489


$
122,760


$
9,183


$
1,299,432David Bolton

$
675,000


$
474,009


$
111,375


$
13,701


$
1,274,085     (1)
    
    Assumes full three years of salary is paid. Actual amount paid
    will be equal to the remaining base salary payable under the
    agreement.(2)
    
    Assumes all equity awards are unvested on the date of
    termination. For purposes of this table, we have used the number
    of unvested shares as of December 31, 2007 and the closing
    price of our Parents common stock on that date ($7.17).(3)
    
    Represents target amounts payable under our Parents Bonus
    Plan and productivity gain sharing payments for 2008. 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.(4)
    
    Represents 18 months of insurance premiums at current rates.      
    the acquisition by any person or group of our Parent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 our Parent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 our Parents common stock
    possessing 35% or more of the total voting power of our
    Parents common stock; 92




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##### Table of Contents




    a majority of members of our Parent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 our Parent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 our Parent that have a total gross
    fair market value equal to or more than 40% of the total gross
    fair market value of all of our Parents assets immediately
    prior to the acquisition or acquisitions.        Compensation
    Committee Report
  Regulation S-K Form 10-K.
         Compensation
    Committee Interlocks and Insider Participation
    Form 10-K,
 93




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##### Table of Contents



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 directors and officers of our general partner as a group.    Percentage ofCommonPercentage of





Percentage of


Units andCommon


Common


Subordinated


Subordinated


SubordinatedUnits


Units


Units


Units


UnitsBeneficially


Beneficially


Beneficially


Beneficially


BeneficiallyName of Beneficial Owner

Owned(1)


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:Jerry D. Cash


















David E. Grose


















David Lawler


















David Bolton


















Richard Marlin


















Gary Pittman(1)


41,900



*











*Mark Stansberry(2)


3,750



*











*All directors and executive officers as a group (8 persons)


45,650



*











*     *
    
    Signifies less than 1%(1)
    
    38,150 common units are owned by G. Pittman & Company,
    which is wholly owned by Gary and Alice Pittman as tenants by
    the entirety. In addition, Mr. Pittman is entitled to
    receive 11,250 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 11,250
    bonus units upon satisfaction of certain vesting requirements.
    Mr. Stansberry does not have the ability to vote these
    bonus units. 94




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Number of Shares ofOur Parents Common Stock


PercentBeneficially


of Class of Our ParentsName and Address of Beneficial Owner

Owned(1)


Common StockJerry D. Cash(2) 
    210 Park Avenue, Suite 2750 
    Oklahoma City, OK 73102


1,790,245



7.6
%David Grose(3)


176,576



*David C. Lawler(4)


105,000



*Gary M. Pittman(5)


101,158



*David W. Bolton(6)


76,369



*Richard Marlin(7)


67,404



*All Directors and Executive Officers as a Group (8 Persons)


2,329,972



10.1
%     (1)
    
    The number of securities beneficially owned by the 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 individual has
    sole or shared voting power or investment power and also any
    securities that the individual 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 our common stock owned by
    Mr. Cashs wife, Sherry J. Cash,
    (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) and (iii) 493,080 restricted shares, which are
    subject to vesting. Mr. Cash disclaims beneficial ownership
    of the shares owned by Sherry J. Cash. In addition,
    Mr. Cash is entitled to receive 5,185 bonus shares upon
    satisfaction of certain vesting requirements. Mr. Cash does
    not have the ability to vote these bonus shares. Of the
    1,790,245 shares of our Parents common stock
    beneficially owned by Mr. Cash, 848,458 have been pledged
    to secure a personal loan.(3)
    
    Includes (i) 3,281 shares of our Parents common
    stock held in Mr. Groses retirement account
    (Mr. Grose does not have voting rights with respect to
    these shares) and (ii) 105,000 restricted shares, which are
    subject to vesting. In addition, Mr. Grose is entitled to
    receive 3,565 bonus shares upon satisfaction of certain vesting
    requirements. Mr. Grose does not have the ability to vote
    these bonus shares.(4)
    
    Includes 90,000 restricted shares, which are subject to vesting.(5)
    
    The 101,158 shares are owned by G. Pittman &
    Company, which is wholly owned by Gary and Alice Pittman as
    tenants by the entirety.(6)
    
    Includes 65,000 restricted shares, which are subject to vesting.
    In addition, Mr. Bolton is entitled to receive 1,109 bonus
    shares upon satisfaction of certain vesting requirements.
    Mr. Bolton does not have the ability to vote these bonus
    shares.(7)
    
    Includes (i) 8,258 shares held in
    Mr. Marlins retirement account (Mr. Marlin does
    not have voting rights with respect to the these shares) and
    (ii) 45,000 restricted shares, which are subject to
    vesting. In addition, Mr. Marlin is entitled to receive
    2,062 bonus shares upon satisfaction of certain vesting
    requirements. Mr. Marlin does not have the ability to vote
    these bonus shares. 95




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##### Table of Contents



Securities
    Authorized For Issuance Under Equity Compensation
    Plans
    Item 13.
    Certain
    Relationships and Related Transactions, and Director
    Independence.    Distributions
    and Payments to Our General Partner and its Affiliates
    Formation StageThe consideration received by our Parent and its subsidiaries
    for the contribution of the assets and liabilities to us
    
     3,201,521 common units; 
    8,857,981 subordinated units;
    431,827 general partner units; and
    the incentive distribution rights.  Payments at or prior to closing of our initial public offering
    
    We used $151.2 million of the net proceeds of our initial
    public offering to repay indebtedness under existing credit
    facilities of our Parent that were secured by the gas and oil
    properties contributed to us by our Parent in connection with
    that offering. Quest Cherokee, LLC, our principal operating
    subsidiary, was a co-borrower on those credit facilities.Operational StageDistributions of available cash to our general partner and its
    affiliates
    
    We will generally distribute 98% of our available cash to all
    unitholders, including affiliates of our general partner (as the
    holders of an aggregate of 3,201,521 common units and 8,857,981
    subordinated 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 2007, our general partner and its affiliates received a
    distribution of approximately $88,222 on their 2% general
    partner interest and $2,463,756 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 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 96




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##### Table of Contents



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 the period from
    November 15, 2007 to December 31, 2007, we reimbursed
    our general partner and Quest Energy Service for expenses of
    $1.8 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.
        Midstream Services Agreement.
 97




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##### Table of Contents



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 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.   98




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##### Table of Contents




    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
    Accountant Fees and
    Services.    Type of Fee

Successor


Predecessor


2007Audit Fees(1)

$
9,300


$
105,833


$
115,133Audit-Related Fees(2)






2,328



2,328Tax Fees(3)


4,353



15,374



19,727All Other Fees










Total

$
13,653


$
123,535


$
137,188  99




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##### Table of Contents



(1)
    
    Represents fees for professional services provided in connection
    with the audit of our annual financial statements, review of our
    quarterly financial statements and audits performed as part of
    our registration filings for our initial public offering.(2)
    
    Represents fees for professional services that are reasonably
    related to the performance of the audit or review of our
    financial statements and not included in Audit Fees, including
    services provided with respect to the filing of our
    Form S-8
    registration statement with the SEC.(3)
    
    Represents fees for professional services provided for tax
    compliance, tax advice and tax planning. PART IV  Item 15.
    Exhibits,
    Financial Statement
    Schedules.  Exhibits, Financial Statements and Financial
    Statement Schedules:
  Financial Statements:
    Financial Statement Schedules:
    Exhibits:
  Regulation S-K Form 10-K
  Exhibits.
    Financial Statement Schedules.
   100




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##### Table of Contents



SIGNATURES
       By
    /s/  Jerry
    D. Cash        Date

Signature and Title    
       
       
       
       
     101




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##### Table of Contents



EXHIBIT INDEX
  Exhibit No.

Description*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

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
.4

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

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
    (File
    No. 0-17371)
    filed on December 29, 2006).*10
.6

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
.7

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
.8

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
.9

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
.10

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). 102




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##### Table of Contents



Exhibit No.

Description*10
.11

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
.12

Summary of Director Compensation Arrangements.10
.13

Form of Bonus Unit Award Agreement.*10
.14

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
.15

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
.16

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).*10
.17

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
.18

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
.19

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).*21
.1

List of Subsidiaries (incorporated herein by reference to
    Exhibit 21.1 to Quest Energy Partners, L.P.s
    Amendment No. 1 to
    Form S-1
    filed on September 6, 2007).23
.1

Consent of Cawley, Gillespie & Associates, Inc.23
.2

Consent of Murrell, Hall, McIntosh & Co., PLLP.31
.1

Certification by Chief 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 Chief 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 Chief 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 Chief 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 103