##### Table of Contents





UNITED
    STATES
 SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
  FORM 10-K
  þ

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31,
    2009ORo

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934For the transition period from
    
    to   001-14837
  QUICKSILVER
    RESOURCES INC. (Exact
    name of registrant as specified in its charter)
  Delaware

75-2756163(State or other jurisdiction of
    incorporation or organization)

(I.R.S. Employer
    Identification No.)777 West Rosedale St., Fort Worth, Texas

76104(Address of principal executive offices)

(Zip Code)   817-665-5000 (Registrants
    telephone number, including area code)
    Title of each class

Name of each exchange on which
    registeredCommon Stock, $0.01 par value per share


New York Stock ExchangePreferred Share Purchase Rights,$0.01 par value per share


New York Stock Exchange   Securities
    registered pursuant to Section 12(g) of the Act: None
  þ o
  o þ
   þ o
  Regulation S-T o o
  Regulation S-K Form 10-K Form 10-K. þ
  Rule 12b-2
 þ o o o
  Rule 12b-2 o þ
      Class

Outstanding at February 15,
    2010Common Stock, $0.01 par value per share

170,222,678 shares   DOCUMENTS
    INCORPORATED BY REFERENCE
  Document

Parts Into Which IncorporatedProxy Statement for the Registrants May 19,
    2010 Annual Meeting of Stockholders

Part III




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DEFINITIONS
    Bbl Bbls
 Bbld
 Bcf
 Bcfd
 Bcfe
 Canada
 CBM
 CERCLA
 DD&A
 GHG
 EPA
 LIBOR
 MBbl MBbls
 MBbld
 MMBbls
 MMBtu
 MMBtud
 Mcf
 Mcfe
 MMcf
 MMcfd
 MMcfe
 MMcfed
 NGL NGLs
 NYMEX
 NYSE
 Oil
 Tcfe
  COMMONLY
    USED TERMS
    ABR
 AOCI
 Alliance Acquisition
 Alliance Leasehold
 Alliance Midstream Assets
 BBEP
 BreitBurn Transaction
 CMS Litigation
 Eni
 2




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##### Table of Contents



Eni Production
 Eni Transaction
 FASB
 FASC FASB Accounting Standards
    Codification
 GAAP
 Gas Purchase Commitment
 KGS
 KGS Credit Agreement
 KGS IPO
 KGS Secondary Offering
 Mercury
 Michigan Sales Contract
 Northeast Operations
 RSU
 SEC
 Senior Secured Credit Facility
 Senior Secured Second Lien Facility
 3




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##### 



INDEX TO
    ANNUAL REPORT ON
    FORM 10-K
    For the Year Ended December 31, 2009
  PART IITEM 1.


Business


6ITEM 1A.


Risk Factors


20ITEM 1B.


Unresolved Staff Comments


29ITEM 2.


Properties


29ITEM 3.


Legal Proceedings


29ITEM 4.


Reserved


29PART IIITEM 5.


Market for Registrants Common Equity,
    Related Stockholder Matters and Issuer Purchases of Equity
    Securities


29ITEM 6.


Selected Financial Data


31ITEM 7.


Managements Discussion and Analysis of
    Financial Condition and Results of Operations


32ITEM 7A.


Quantitative and Qualitative Disclosures about
    Market Risk


53ITEM 8.


Financial Statements and Supplementary Data


56ITEM 9.


Changes in and Disagreements with Accountants on
    Accounting and Financial Disclosure


108ITEM 9A.


Controls and Procedures


108ITEM 9B.


Other Information


110PART IIIITEM 10.


Directors, Executive Officers and Corporate
    Governance


110ITEM 11.


Executive Compensation


110ITEM 12.


Security Ownership of Certain Beneficial Owners
    and Management and Related Stockholder Matters


110ITEM 13.


Certain Relationships and Related Transactions
    and Director Independence


110ITEM 14.


Principal Accountant Fees and Services


110PART IVITEM 15.


Exhibits and Financial Statement Schedules


111Signatures


162EX-4.5EX-4.7EX-10.22EX-10.30EX-10.31EX-10.32EX-10.35EX-10.36EX-21.1EX-23.1EX-23.2EX-23.3EX-23.4EX-23.5EX-23.6EX-31.1EX-31.2EX-32.1EX-99.1EX-99.2EX-99.3EX-99.4     4




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Forward-Looking
    Information
    
    changes in general economic conditions;
    fluctuations in natural gas, NGL and oil prices;
    failure or delays in achieving expected production from
    exploration and development projects;
    uncertainties inherent in estimates of natural gas, NGL and oil
    reserves and predicting natural gas, NGL and oil reservoir
    performance;
    effects of hedging natural gas, NGL and oil prices;
    fluctuations in the value of certain of our assets and
    liabilities;
    competitive conditions in our industry;
    actions taken or non-performance by third parties, including
    suppliers, contractors, operators, processors, transporters,
    customers and counterparties;
    changes in the availability and cost of capital;
    delays in obtaining oilfield equipment and increases in drilling
    and other service costs;
    operating hazards, natural disasters, weather-related delays,
    casualty losses and other matters beyond our control;
    the effects of existing and future laws and governmental
    regulations, including environmental and climate change
    requirements;
    the effects of existing or future litigation; and
    certain factors discussed elsewhere in this Annual Report.  Forms 10-K, 10-Q 8-K.
   5




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##### Table of Contents



PART I  ITEM 1.
    Business  GENERAL
      FORMATION
    AND DEVELOPMENT OF BUSINESS
    STRATEGIC
    TRANSACTIONS
        BUSINESS
    STRATEGY
   6




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Focus on core areas of repeatable, low-risk development:
  Pursue disciplined organic growth opportunities:
  Enhance profitability through control and marketing of our
    equity natural gas and oil:
  Maintain flexible financial profile:
  BUSINESS
    STRENGTHS
  High-quality asset base with long reserve life:
  Multi-year inventory of development and exploitation drilling
    projects: 10-year
 7




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Proven record of organic growth in reserves and production:
  Midstream strength:
  Experienced management and technical team:
  FINANCIAL
    INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS
    PROPERTIES
    OIL AND
    NATURAL GAS OPERATIONS
   8




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Texas
    high-Btu high-Btu
        Rocky
    Mountain Region
    Canada
   9




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2010
    Capital Program
    OIL AND
    NATURAL GAS RESERVES
    
    the use of an unweighted average of the preceding
    12-month
    first-day-of-the-month
    prices for determination of proved reserve values included in
    calculating full cost ceiling limitations and for annual proved
    reserve disclosures;
    limitations regarding the types of technologies that may be used
    to reliably establish the classification of proved reserves;
    reporting of investments and progress made during the year to
    convert proved undeveloped reserves to proved developed
    reserves; and,
    reporting on the independence and qualifications of our
    personnel and independent petroleum engineers who are
    responsible for the preparation of our reserve estimates.     10




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11




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##### Table of Contents



Proved Developed Reserves


Proved Undeveloped Reserves


Total Proved ReservesFor The Years Ended December 31,


For The Years Ended December 31,


For The Years Ended December 31,2009


2008


2007


2009


2008


2007


2009


2008


2007Natural gas (MMcf)United States


1,044,140



756,191



379,917



511,894



550,306



282,492



1,556,034



1,306,497



662,409Canada


223,300



278,668



260,029



29,753



53,903



68,352



253,053



332,571



328,381Total


1,267,440



1,034,859



639,946



541,647



604,209



350,844



1,809,087



1,639,068



990,790NGL (MBbl)United States


60,997



56,181



50,738



37,264



35,746



39,317



98,261



91,927



90,055Canada


13



8



10



-



-



-



13



8



10Total


61,010



56,189



50,748



37,264



35,746



39,317



98,274



91,935



90,065Oil (MBbl)United States


2,467



2,509



2,763



392



405



311



2,859



2,914



3,074Canada


-



-



-



-



-



-



-



-



-Total


2,467



2,509



2,763



392



405



311



2,859



2,914



3,074Total (MMcfe)United States


1,424,924



1,108,331



700,923



737,830



767,212



520,260



2,162,754



1,875,543



1,221,183Canada


223,378



278,716



260,089



29,753



53,903



68,352



253,131



332,619



328,441Total


1,648,302



1,387,047



961,012



767,583



821,115



588,612



2,415,885



2,208,162



1,549,624   Years Ended December 31,2009 (1)


2008 (2)


2007 (2)Representative prices:Natural gas  Henry Hub

$
3.87


$
5.71


$
6.80Natural gas  AECO


3.76



5.44



6.35NGL  Mont Belvieu, Texas


24.94



21.65



57.35Oil  WTI Cushing


61.18



44.60



95.98Standardized measure of discounted future net cash
    flows (3),

    after income tax (in millions)

$
1,182.7


$
1,794.3


$
2,169.2   (1)
    The natural gas and crude oil
    prices as of each respective year end were based, respectively,
    on the unweighted average of the preceding
    12-month
    first-day-of-the-month
    NYMEX Henry Hub and AECO prices per MMBtu and NYMEX prices per
    Bbl, adjusted to reflect local differentials.(2)
    The natural gas and oil prices as
    of December 31, 2008 and 2007 were based, respectively, on
    last day-of-the-year price for NYMEX Henry Hub and AECO price
    per MMBtu and NYMEX price per Bbl, adjusted to reflect local
    differentials.(3)
    Determined based on year end
    unescalated costs in accordance with the guidelines of the SEC,
    discounted at 10% per annum.  PROVED
    UNDEVELOPED RESERVES
   12




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For The Year Ended December 31, 2009Drilled


Completions


ProducingGross


Net


Gross


Net


Gross


NetUnited States


66.0



39.9



23.0



10.9



18.0



10.6Canada


37.0



18.6



30.0



14.1



24.0



10.1Total


103.0



58.5



53.0



25.0



42.0



20.7         DEVELOPMENT
    AND EXPLORATION ACTIVITIES AT YEAR-END
   13




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DRILLING
    ACTIVITY
    Years Ended December 31,2009


2008


2007Gross


Net


Gross


Net


Gross


NetDevelopment:United StatesProductive (1)


154.0



93.2



292.0



255.7



258.0



226.2Non-productive


-



-



1.0



1.0



-



-CanadaProductive (2)


141.0



36.1



372.0



155.9



351.0



179.1Non-productive


-



-



1.0



1.0



-



-Total


295.0



129.3



666.0



413.6



609.0



405.3Exploratory:United StatesProductive


4.0



4.0



5.0



4.1



32.0



19.2Non-productive


-



-



2.0



2.0



4.0



3.2CanadaProductive


2.0



2.0



-



-



5.0



5.0Non-productive


-



-



-



-



-



-Total


6.0



6.0



7.0



6.1



41.0



27.4Total:Productive


301.0



135.3



669.0



415.7



646.0



429.5Non-productive


-



-



4.0



4.0



4.0



3.2Total


301.0



135.3



673.0



419.7



650.0



432.7   (1)
    U.S. development drilling includes non-operated drilling of
    37 wells (3.0 net), 36 wells (16.1 net) and
    14 wells (7.2 net) for 2009, 2008 and 2007, respectively.(2)
    Canadian development drilling includes non-operated drilling of
    88 wells (8.1 net), 170 wells (15.3 net) and
    130 wells (16.1 net) for 2009, 2008 and 2007, respectively.  VOLUMES,
    SALES PRICES AND OIL AND GAS PRODUCTION EXPENSE
    DELIVERY
    COMMITMENTS AND PURCHASERS OF NATURAL GAS, NGLs AND
    OIL
   14




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ACQUISITION,
    EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES
    United States


Canada


Consolidated(In thousands)2009Proved acreage

$
118


$
-


$
118Unproved acreage


11,300



2,658



13,958Development costs


341,658



24,179



365,837Exploration costs


32,798



59,402



92,200Total

$
385,874


$
86,239


$
472,1132008Proved acreage

$
787,172


$
-


$
787,172Unproved acreage


484,770



54,048



538,818Development costs


836,032



68,629



904,661Exploration costs


30,161



10,280



40,441Total

$
2,138,135


$
132,957


$
2,271,0922007Proved acreage

$
-


$
-


$
-Unproved acreage


17,031



31,448



48,479Development costs


648,632



67,608



716,240Exploration costs


75,862



11,953



87,815Total

$
741,525


$
111,009


$
852,534   PRODUCTIVE
    OIL AND GAS WELLS
    As of December 31, 2009Natural Gas


OilGross


Net


Gross


NetUnited States


834.0



697.0



198.0



194.0Canada


2,815.0



1,297.3



4.0



0.1Total


3,649.0



1,994.3



202.0



194.1   OIL AND
    GAS ACREAGE
   15




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As of December 31, 2009Developed Acreage


Undeveloped AcreageGross


Net


Gross


NetTexas


75,752



66,376



553,800



468,491Other


116,988



107,973



198,732



154,090United States


192,740



174,349



752,532



622,581Canada


458,933



272,693



249,231



222,524Total


651,673



447,042



1,001,763



845,105     2010 Expirations


2011 Expirations


2012 ExpirationsNet





Net Acres with





Net Acres with





Net Acres withUndeveloped


Net Acres


Options


Net Acres


Options


Net Acres


OptionsAcres





to Extend





to Extend





to ExtendTexas


468,491



352,858



22,236



54,967



1,032



18,580



2,378Other U.S.


154,090



28,773



128



28,219



5,628



16,171



-Canada


222,524



25,379



-



70,043



-



83,006



-Totals


845,105



407,010



22,364



153,229



6,660



117,757



2,378     COMPETITION
    GOVERNMENTAL
    REGULATION
    SAFETY
    REGULATION
   16




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ENVIRONMENTAL
    MATTERS
        cap-and-trade cap-and-trade
   17




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AVAILABILITY
    OF REPORTS AND CORPORATE GOVERNANCE DOCUMENTS
  Form 10-K, Form 10-Q, Form 8-K
  EMPLOYEES
    EXECUTIVE
    OFFICERS OF THE REGISTRANT
    Name

Age


Position(s)Thomas F. Darden


56


Director, Chairman of the BoardGlenn Darden


54


Director, President and Chief Executive OfficerAnne Darden Self


52


Director, Vice President - Human ResourcesJeff Cook


53


Executive Vice President - OperationsPhilip W. Cook


48


Senior Vice President - Chief Financial OfficerJohn C. Cirone


60


Senior Vice President, General Counsel and SecretaryJohn C. Regan


40


Vice President, Controller and Chief Accounting OfficerRobert N. Wagner


46


Vice President - Reservoir Engineering     THOMAS F. DARDEN
  GLENN DARDEN
  ANNE DARDEN SELF
  JEFF COOK
 18




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PHILIP W. COOK
  JOHN C. CIRONE
  JOHN C. REGAN
  ROBERT N. WAGNER
 19




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ITEM 1A.
    Risk
    Factors    Natural
    gas, NGL and oil prices fluctuate widely, and low prices could
    have a material adverse impact on our business, financial
    condition, results of operations and cash flows.
      
    domestic and foreign demand for natural gas, NGLs and oil;
    the level and locations of domestic and foreign natural gas,
    NGLs and oil supplies;
    the quality, price and availability of alternative fuels;
    weather conditions;
    domestic and foreign governmental regulations;
    impact of trade organizations, such as OPEC;
    political conditions in oil, NGLs and natural gas producing
    regions; and
    worldwide economic conditions.    If
    natural gas, NGL or oil prices decrease, our exploration and
    development efforts are unsuccessful or our costs increase
    substantially, we may be required to recognize impairment of our
    oil and gas properties, which could have a material adverse
    effect on our financial condition, our results of operations and
    our ability to borrow under and comply with our debt
    agreements.
    Reserve estimates depend on many assumptions that may turn
    out to be inaccurate and any material inaccuracies in these
    reserve estimates or underlying assumptions may materially
    affect the quantities and present value of our reserves.
   20




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Form 10-K 12-month first-day-of-the-month
  Our
    production is concentrated in a small number of geographic
    areas.
    Our
    Canadian operations present unique risks and uncertainties,
    different from or in addition to those we face in our
    U.S. operations.
   21




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If we
    are unable to obtain needed capital or financing on satisfactory
    terms, our ability to replace our reserves or to maintain
    current production levels may be limited.
    Our
    business involves many hazards and operational risks, some of
    which may not be insurable.  The occurrence of a significant
    accident or other event that is not insured or not adequately
    insured could curtail our operations and have a material adverse
    effect on our business, results of operations and financial
    condition.
       22




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The
    failure to replace our reserves could adversely affect our
    production and cash flows.
    We
    have risk through our investment in BBEP.
      We
    have risk through our ownership of KGS.
    
    changes in general economic conditions;
    fluctuations in natural gas prices;
    failure or delays in us and third parties achieving expected
    production from natural gas projects;
    competitive conditions in the midstream industry;
    actions taken on non-performance by third parties, including
    suppliers, contractors, operators, processors, transporters and
    customers;
    changes in the availability and cost of capital;
    operating hazards, natural disasters, weather-related delays,
    casualty losses and other matters beyond our control;
    construction costs or capital expenditures exceeding estimated
    or budgeted amounts;
    the effects of existing and future laws and governmental
    regulations;
    the effects of future litigation; and
    other factors discussed in KGS Annual Report on
    Form 10-K
    and as are or may be detailed from time to time in KGS
    public announcements and other filings with the SEC.  We
    cannot control the operations of gas processing, liquids
    fractionation and transportation facilities we do not own or
    operate.
   23




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The
    loss of key personnel could adversely affect our ability to
    operate.
    Competition in our industry is intense, and we are smaller
    and have a more limited operating history than many of our
    competitors.
    Hedging our production may result in losses or limit our
    ability to benefit from price increases.
    
    our production could be materially less than expected; or
    the other parties to the hedging contracts could fail to perform
    their contractual obligations.    Delays
    in obtaining oil field equipment and increases in drilling and
    other service costs could adversely affect our ability to pursue
    our drilling program and our results of
    operations.
   24




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Our
    activities are regulated by complex laws and regulations that
    can adversely affect the cost, manner or feasibility of doing
    business.
    
    discharge permits for drilling operations;
    water obtained for drilling purposes;
    drilling permits and bonds;
    reports concerning operations;
    spacing of wells;
    disposal wells;
    unitization and pooling of properties; and
    taxation.        We are
    subject to environmental laws, regulations and permits,
    including greenhouse gas requirements that may expose us to
    significant costs, liabilities and obligations.
       25




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##### Table of Contents



cap-and-trade cap-and-trade
    The
    risks associated with our debt could adversely affect our
    business, financial condition and results of operations and the
    value of our securities.
      
    make it more difficult for us to satisfy our obligations with
    respect to our debt;
    require us to dedicate a substantial portion of our cash flow
    from operations to payments on our debt, thereby reducing the
    amount of our cash flow available for working capital, capital
    expenditures, acquisitions and other general corporate purposes;
    require us to make principal payments if the quantity and value
    of our proved reserves are insufficient to support our level of
    borrowings;
    limit our flexibility in planning for, or reacting to, changes
    in the oil and natural gas industry;
    place us at a competitive disadvantage compared to our
    competitors who may have lower debt service obligations and
    greater financing flexibility than we do;
    limit our financial flexibility, including our ability to borrow
    additional funds;
    increase our interest expense on our variable rate borrowings if
    interest rates increase;
    limit our ability to make capital expenditures to develop our
    properties;
    increase our vulnerability to exchange risk associated with
    Canadian dollar denominated indebtedness; increase our
    vulnerability to general adverse economic and industry
    conditions; and
    result in a default or event of default under our debt
    agreements, which, if not cured or waived, could adversely
    affect our financial condition, results of operations and cash
    flows. 26




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
    reducing or delaying capital expenditures;
    seeking additional debt financing or equity capital;
    selling assets;
    restructuring or refinancing debt; or
    reorganizing our capital structure.    The
    provisions of our debt agreements and the risks associated with
    our debt could adversely affect our business, financial
    condition and results of operations.
    
    incur additional debt;
    pay dividends on, or redeem or repurchase capital stock;
    make certain investments;
    incur or permit certain liens to exist;
    enter into certain types of transactions with affiliates;
    merge, consolidate or amalgamate with another company;
    transfer or otherwise dispose of assets, including capital stock
    of subsidiaries; and
    redeem subordinated debt.      Parties
    with whom we do business may become unable or unwilling to
    timely perform their obligations to us.
   27




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A
    small number of existing stockholders exercise significant
    control over our company, which could limit your ability to
    influence the outcome of stockholder votes.
    A
    large number of our outstanding shares and shares to be issued
    upon conversion of our outstanding convertible debentures or
    exercise of our outstanding options may be sold into the market
    in the future, which could cause the market price of our common
    stock to drop significantly, even if our business is performing
    well.
      Our
    amended and restated certificate of incorporation, restated
    bylaws and stockholder rights plan contain provisions that could
    discourage an acquisition or change of control without our board
    of directors approval.
    
    our board of directors is authorized to issue preferred stock
    without stockholder approval;
    our board of directors is classified; and
    advance notice is required for director nominations by
    stockholders and actions to be taken at annual meetings at the
    request of stockholders.    If we
    do not make acquisitions on economically acceptable terms, our
    future growth will be limited.
      
    mistaken assumptions about volumes, revenue and costs, including
    synergies;
    an inability to integrate successfully the assets we acquire;
    the assumption of unknown liabilities; 28




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
    limitations on rights to indemnity from the seller;
    mistaken assumptions about the overall costs of equity or debt;
    the diversion of managements and employees attention
    from other business matters;
    unforeseen difficulties operating in new product areas, with new
    customers, or new geographic areas; and
    customer or key employee losses at the acquired businesses.  ITEM 1B.
    Unresolved
    Staff Comments    ITEM 2.
    Properties    ITEM 3.
    Legal
    Proceedings    ITEM 4.
    Reserved PART II.  ITEM 5.
    Market
    For Registrants Common Equity, Related Stockholder Matters
    and Issuer Purchase of Equity Securities  Market
    Information
      HIGH


LOW2009Fourth Quarter

$
16.55


$
11.78Third Quarter


15.10



7.93Second Quarter


13.35



5.29First Quarter


8.89



3.982008Fourth Quarter

$
20.74


$
3.74Third Quarter


40.70



17.13Second Quarter


44.98



34.96First
    Quarter (1)


38.72



24.28   (1)

    
    Per share amounts previously reported have been adjusted to
    reflect a two-for-one stock split effected in the form of a
    stock dividend in January 2008.     29




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Performance
    Graph
    Comparison
    of Cumulative Five Year Total Return
  
  Issuer
    Purchases of Equity Securities
    Total Number of


Maximum Number ofTotal Number of





Shares Purchased as


Shares that May YetShares


Average Price


Part of Publicly


Be Purchased UnderPeriod

Purchased
    (1)


Paid per Share


Announced Plan
    (2)


the Plan
    (2)October 2009


2,197


$
13.38



-



-November 2009


1,323


$
13.27



-



-December 2009


573


$
12.46



-



-Total


4,093


$
13.22



-



-   (1)
    Represents shares of common stock surrendered by employees to
    satisfy the income tax withholding obligations arising upon the
    vesting of restricted stock issued under our stock plans.(2)
    We do not have a publicly announced plan for repurchasing our
    common stock. 30




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##### Table of Contents



ITEM 6.
    Selected
    Financial Data    Years Ended December 31,2009
    (2)


2008
    (3)


2007
    (4)


2006


2005(In thousands, except for per share data and ratios)Operating Results InformationTotal revenues

$
832,735


$
800,641


$
561,258


$
390,362


$
310,448Operating income (loss)


(613,873
)


(249,697
)


803,581



174,196



149,129Income (loss) before income taxes


(836,856
)


(585,077
)


730,806



126,248



122,658Net income (loss)


(545,239
)


(373,622
)


476,445



90,097



83,979Net income (loss) attributable to Quicksilver


(557,473
)


(378,276
)


475,390



90,006



83,979Diluted earnings (loss) per common
    share(1)

$
(3.30
)

$
(2.33
)

$
2.87


$
0.58


$
0.54Dividends paid per share


-



-



-



-



-Cash provided by operating activities

$
612,240


$
456,566


$
319,104


$
242,186


$
140,242Capital expenditures


693,838



1,286,715



1,020,684



619,061



331,805Financial Condition InformationProperty, plant and equipment - net

$
3,085,940


$
3,797,715


$
2,142,346


$
1,679,280


$
1,112,002Total assets


3,612,882



4,498,208



2,773,751



1,881,052



1,241,437Long-term debt


2,427,523



2,586,045



788,518



887,917



469,330All other long-term obligations


121,877



282,101



434,190



191,627



153,518Total equity


696,822



1,211,563



1,192,468



602,119



406,399   (1)
    Per share amounts have been adjusted to reflect a three-for-two
    stock split effected in the form of a stock dividend in June
    2005 and a two-for-one stock split effected in the form of a
    stock dividend in January 2008.(2)
    Operating loss for 2009 includes pre-tax charges of
    $786.9 million and $192.7 million for impairments
    associated with our U.S. and Canadian oil and gas properties,
    respectively.  Net loss also includes $75.4 million of
    pre-tax income attributable to our proportionate ownership of
    BBEP and a pre-tax charge of $102.1 million for impairment
    of that investment.(3)
    Operating loss for 2008 includes a pre-tax charge of
    $633.5 million for impairment associated with our U.S. oil
    and gas properties.  Net loss also includes $93.3 million
    for pre-tax income attributable to our proportionate ownership
    of BBEP and a pre-tax charge of $320.4 million for
    impairment of that investment.(4)
    Operating income and net income for 2007 include a pre-tax gain
    of $628.7 million recognized from the divestiture of our
    Northeast Operations and a pre-tax charge of $63.5 million
    associated with the Michigan Sales Contract (See Note 2 to
    the consolidated financial statements in Item 8 of this
    Annual Report). 31




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##### Table of Contents



ITEM 7.
    Managements
    Discussion and Analysis of Financial Condition and Results of
    Operations      
    Overview a general description of our
    business; the value drivers of our business; measurements; and
    opportunities, challenges and risks.
    Financial Risk Management  information about
    debt financing and financial risk management.
    2009 Highlights  a summary of significant
    activities and events affecting Quicksilver.
    Results of Operations  an analysis of our
    consolidated results of operations for the three years presented
    in our financial statements.
    Liquidity, Capital Resources and Financial
    Position an analysis of our cash flows, sources
    and uses of cash, contractual obligations and commercial
    commitments.
    Critical Accounting Estimates  a discussion of
    critical accounting estimates that represent choices between
    acceptable alternatives
    and/or
    require management judgments and assumptions.  OVERVIEW
          
    reserve growth;
    production growth; and
    maximizing our operating cash flows. 32




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##### Table of Contents



Years Ended December 31,2009


2008


2007Organic reserve
    growth (1)


23
%


29
%


59
%Production volumes (Bcfe)


118.5



96.2



77.9Cash flow from operating activities (in millions)

$
612.2


$
456.6


$
319.1Diluted earnings (loss) per
    share (2)(3)(4)

$
(3.30
)

$
(2.33
)

$
2.87   (1)
    This ratio is calculated by subtracting adjusted beginning of
    the year proved reserves from adjusted end of the year proved
    reserves and dividing by adjusted beginning of the year proved
    reserves.  Adjusted beginning of the year reserves are
    calculated by deducting divested reserves and adjusted current
    year production from beginning of the year reserves. Adjusted
    current year production excludes production from purchased
    reserves.  Adjusted end of the year reserves are calculated by
    deducting purchased reserves from end of the year reserves.(2)
    Diluted earnings for 2009 include pre-tax charges of
    $786.9 million and $192.7 million for impairments
    associated with our U.S. and Canadian oil and gas properties,
    respectively.  Net loss also includes $75.4 million of
    pre-tax income attributable to our proportionate ownership of
    BBEP and a pre-tax charge of $102.1 million for impairment
    of that investment.(3)
    Diluted earnings for 2008 include a pre-tax charge of
    $633.5 million for impairment associated with our U.S. oil
    and gas properties.  Net loss also includes $93.3 million
    of pre-tax income attributable to our proportionate ownership of
    BBEP and a pre-tax charge of $320.4 million for impairment
    of that investment.(4)
    Diluted earnings for 2007 include a pre-tax gain of
    $628.7 million recognized from the divestiture of our
    Northeast Operations and a pre-tax charge of $63.5 million
    associated with the Michigan Sales Contract.  FINANCIAL
    RISK MANAGEMENT
   33




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##### Table of Contents



2009
    HIGHLIGHTS
  Eni
    Transaction
    Long-Term
    Debt
          KGS
    Secondary Offering
    Increase
    in Production
  Results of
    Operations
  Horn
    River Basin Discovery
     34




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##### Table of Contents



Litigation
    Update
      BBEP
    Update
      RESULTS
    OF OPERATIONS
  Revenue
  Natural
    Gas, NGL and Oil
    Natural Gas


NGL


Oil


Total2009


2008


2007


2009


2008


2007


2009


2008


2007


2009


2008


2007(In millions)Texas

$
236.6


$
371.1


$
121.6


$
135.5


$
198.1


$
106.7


$
14.0


$
30.4


$
9.2


$
386.1


$
599.6


$
237.5Northeast Operations


-



-



100.8



-



-



4.5



-



-



18.6



-



-



123.9Other U.S.


0.5



0.8



0.3



0.3



0.8



0.6



8.0



14.8



10.2



8.8



16.4



11.1Hedging


213.1



(2.4
)


26.3



-



(8.6
)


(5.2
)


-



(7.1
)


(0.7
)


213.1



(18.1
)


20.4Total U.S.


450.2



369.5



249.0



135.8



190.3



106.6



22.0



38.1



37.3



608.0



597.9



392.9Canada


90.5



182.7



126.4



0.1



0.4



0.2



0.1



-



-



90.7



183.1



126.6Hedging


98.0



(0.2
)


25.6



-



-



-



-



-



-



98.0



(0.2
)


25.6Total Canada


188.5



182.5



152.0



0.1



0.4



0.2



0.1



-



-



188.7



182.9



152.2Total

$
638.7


$
552.0


$
401.0


$
135.9


$
190.7


$
106.8


$
22.1


$
38.1


$
37.3


$
796.7


$
780.8


$
545.1     Natural Gas


NGL


Oil


Equivalent Total2009


2008


2007


2009


2008


2007


2009


2008


2007


2009


2008


2007(MMcfd)








(Bbld)








(Bbld)








(MMcfed)Texas


168.3



122.8



50.1



13,598



11,425



6,395



729



873



349



254.2



196.6



90.6Northeast Operations


-



-



56.1



-



-



331



-



-



799



-



-



62.9Other U.S.


0.6



0.3



0.3



34



36



29



434



447



452



3.4



3.2



3.2Total U.S.


168.9



123.1



106.5



13,632



11,461



6,755



1,163



1,320



1,600



257.6



199.8



156.7Canada


66.9



63.0



56.8



5



3



13



2



-



-



66.9



63.0



56.9Total


235.8



186.1



163.3



13,637



11,464



6,768



1,165



1,320



1,600



324.5



262.8



213.6  35




---



##### Table of Contents



Natural Gas


NGL


Oil


Equivalent Total2009


2008


2007


2009


2008


2007


2009


2008


2007


2009


2008


2007(per Mcf)








(per Bbl)








(per Bbl)








(per Mcfe)Texas

$
3.85


$
8.26


$
6.65


$
27.31


$
47.38


$
45.70


$
52.62


$
95.16


$
72.37


$
4.16


$
8.33


$
7.18Northeast Operations


-



-



4.92



-



-



37.36



-



-



63.81



-



-



5.40Other U.S.


3.62



7.43



4.68



27.02



70.52



52.35



50.53



89.41



61.49



7.41



13.92



9.63Hedging


3.45



(0.05
)


0.81



-



(2.06
)


(2.10
)


-



(14.72
)


(1.19
)


2.26



(0.25
)


0.45Total U.S.

$
7.31


$
8.20


$
6.40


$
27.30


$
45.39


$
43.22


$
51.84


$
78.83


$
63.87


$
6.47


$
8.18


$
6.87Canada


3.71



7.92



6.10



54.66



325.52



48.02



54.80



-



-



3.71



7.94



6.10Hedging


4.01



(0.01
)


1.23



-



-



-



-



-



-



4.01



(0.01
)


1.23Total Canada

$
7.72


$
7.91


$
7.33


$
54.66


$
325.52


$
48.02


$
54.80


$
-


$
-


$
7.72


$
7.93


$
7.33Total

$
7.42


$
8.10


$
6.73


$
27.32


$
45.44


$
43.23


$
51.85


$
78.83


$
63.87


$
6.73


$
8.12


$
6.99     NaturalGas


NGL


Oil


Total(In thousands)Revenue for 2007

$
400,989


$
106,787


$
37,313


$
545,089Volume variances


57,227



74,591



(6,463
)


125,355Hedge settlement variances


(59,632
)


(3,475
)


(6,422
)


(69,529
)Price variances


153,462



12,763



13,648



179,873Revenue for 2008

$
552,046


$
190,666


$
38,076


$
780,788Volume variances


145,141



35,484



(4,544
)


176,081Hedge settlement variances


313,493



8,648



7,117



329,258Price variances


(371,975
)


(98,858
)


(18,596
)


(489,429
)Revenue for 2009

$
638,705


$
135,940


$
22,053


$
796,698          36




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##### Table of Contents



high-BTU
    Sales of
    Purchased Natural Gas and Costs of Purchased Natural
    Gas
  Years Ended December 31,2009


2008


2007(in thousands)Sales of purchased natural gas:Purchases from Eni

$
11,195


$
-


$
-Purchases from others


12,459



-



-Total


23,654



-



-Costs of purchased natural gas sold:Purchases from Eni


12,268



-



-Purchases from others


11,265



-



-Unrealized valuation loss on Gas Purchase Commitment


6,625



-



-Total


30,158Net sales and purchases of natural gas

$
(6,504
)

$
-


$
-     Other
    Revenue
     37




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##### Table of Contents



Operating
    Expenses
  Oil and
    Gas Production Expense
  Years Ended December 31,2009


2008


2007(In thousands, except per unit amounts)Per





Per





PerMcfe





Mcfe





McfeTexasCash expense

$
84,216


$
0.91


$
90,737


$
1.26


$
52,998


$
1.60Equity compensation


761



0.01



1,130



0.02



339



0.01$
84,977


$
0.92


$
91,867


$
1.28


$
53,337


$
1.61Northeast OperationsCash expense

$
-


$
-


$
-


$
-


$
48,489


$
2.11Equity compensation


-



-



-



-



422



0.02$
-


$
-


$
-


$
-


$
48,911


$
2.13Other U.S.Cash expense

$
6,359


$
5.21


$
6,318


$
5.35


$
3,278


$
2.97Equity compensation


195



0.16



190



0.16



193



0.16$
6,554


$
5.37


$
6,508


$
5.51


$
3,471


$
3.13Total U.S.Cash expense

$
90,575


$
0.95


$
97,055


$
1.32


$
104,765


$
1.83Equity compensation


956



0.02



1,320



0.02



954



0.02$
91,531


$
0.97


$
98,375


$
1.34


$
105,719


$
1.85CanadaCash expense

$
34,070


$
1.39


$
33,781


$
1.47


$
28,415


$
1.37Equity compensation


2,114



0.09



2,146



0.09



1,969



0.09$
36,184


$
1.48


$
35,927


$
1.56


$
30,384


$
1.46Total CompanyCash expense

$
124,645


$
1.04


$
130,836


$
1.36


$
133,180


$
1.70Equity compensation


3,070



0.04



3,466



0.04



2,923



0.04$
127,715


$
1.08


$
134,302


$
1.40


$
136,103


$
1.74          38




---



##### Table of Contents



Production
    and Ad Valorem Taxes
  Years Ended December 31,2009


2008


2007(In thousands, except per unit amounts)Per





Per





PerProduction and ad valorem taxes




Mcfe





Mcfe





McfeU.S.

$
21,403


$
0.23


$
15,999


$
0.22


$
13,912


$
0.24Canada


2,478


$
0.10



2,735


$
0.12



3,136


$
0.15Total

$
23,881


$
0.20


$
18,734


$
0.19


$
17,048


$
0.22       Other
    Operating Expense
    Depletion,
    Depreciation and Accretion
  Years Ended December 31,2009


2008


2007(In thousands, except per unit amounts)Per





Per





PerMcfe





Mcfe





McfeDepletionU.S.

$
127,888


$
1.36


$
120,845


$
1.65


$
65,020


$
1.14Canada


33,782



1.38



40,337



1.75



34,666



1.67161,670



1.36



161,182



1.68



99,686



1.28Total depletionU.S.

$
33,329


$
0.35


$
21,751


$
0.30


$
15,389


$
0.27Canada


3,952



0.16



3,780



0.16



4,115



0.20Total depreciation


37,281



0.31



25,531



0.27



19,504



0.25Accretion


2,436



0.02



1,483



0.01



1,507



0.02Total

$
201,387


$
1.70


$
188,196


$
1.96


$
120,697


$
1.55   U.S.-Canadian
 39




---



##### Table of Contents



Impairment
    of Oil and Gas Properties
    
    estimated future net cash flows, discounted at 10% per annum,
    from proved reserves, based on an unweighted average of
    preceding
    12-month
    first-day-of-the-month
    prices for the year then ended (year-end prices for 2008 and
    2007) adjusted to reflect local differentials, unescalated
    period end costs and expenses, adjusted for financial
    derivatives that qualify as cash flow hedges of our oil and gas
    revenue,
    the costs of properties not being amortized,
    the lower of cost or market value of unproved properties not
    included in the costs being amortized, less
    income tax effects related to differences between book and tax
    bases of the oil and gas properties.  18-month
  12-month first-day-of-the-month
   40




---



##### Table of Contents



General
    and Administrative Expense
  Years Ended December 31,2009


2008


2007(In thousands, except per unit amounts)Per





Per





PerGeneral and administrative expense




Mcfe





Mcfe





McfeCash expense

$
55,200


$
0.47


$
49,982


$
0.52


$
38,595


$
0.50Litigation resolution


5,000



0.04



9,633



0.10



-



-Equity compensation


17,043



0.14



12,639



0.13



8,465



0.11Total

$
77,243


$
0.65


$
72,254


$
0.75


$
47,060


$
0.60       Other
    Components of Operating Income
    Income
    from Earnings of BBEP
  11-month
    Impairment
    of Investment in BBEP
   41




---



##### Table of Contents



Interest
    Expense
  Years Ended December 31,2009


2008


2007(in thousands)Interest costs on debt outstanding

$
155,696


$
105,108


$
67,379Add:Non-cash interest
    (1)


18,410



13,215



10,374Non-cash loss on early debt extinguishment


27,122



-



-Less: Interest capitalized


(6,127
)


(9,225
)


(1,091
)Interest expense

$
195,101


$
109,098


$
76,662   (1)
    Amortization of deferred financing costs and original issue
    discount.      Income
    Taxes
  Years Ended December 31,2009


2008


2007(in thousands)Income tax expense (benefit)

$
(291,617
)

$
(211,455
)

$
254,361Effective tax rate


34.8
%


36.1
%


34.8
%    42




---



##### Table of Contents



Quicksilver
    Resources Inc.  and its Restricted Subsidiaries
    Results of Operations Financial
    Position
  LIQUIDITY,
    CAPITAL RESOURCES AND FINANCIAL POSITION
  Cash Flow
    Activity
  Operating
    Cash Flows
  Years Ended December 31,2009


2008


2007(In thousands)Net cash provided by operating activities

$
612,240


$
456,566


$
319,104     Results of Operations
 43




---



##### Table of Contents



Investing
    Cash Flows
  Years Ended December 31,2009


2008


2007(In thousands)Purchases of property, plant and equipment

$
(693,838
)

$
(1,286,715
)

$
(1,020,684
)Alliance Acquisition


-



(993,212
)


-Return of investment from equity affiliates


-



-



9,635Proceeds from sales of properties & equipment


220,974



1,339



741,297Net cash used by investing activities

$
(472,864
)

$
(2,278,588
)

$
(269,752
)            44




---



##### Table of Contents



Financing
    Cash Flows
  Years Ended December 31,2009


2008


2007(In thousands)Issuance of debt

$
1,420,727


$
2,948,672


$
817,821Repayments of debt


(1,649,630
)


(1,096,163
)


(968,557
)Debt issuance costs


(32,472
)


(25,219
)


(5,130
)Gas Purchase Commitment


58,294



-



-Gas Purchase Commitment repayments


(14,175
)


-



-Issuance of KGS common units


80,729



-



109,809Distributions paid on KGS common units


(9,925
)


(8,644
)


(8,794
)Proceeds from exercise of stock options


4,046



1,244



21,387Excess tax benefit on exercise of stock options


-



-



2,755Purchase of treasury stock


(922
)


(23,137
)


(1,567
)Net cash provided (used) by financing activities

$
(143,328
)

$
1,796,753


$
(32,276
)           Liquidity
    and Borrowing Capacity
   45




---



##### Table of Contents



Financial
    Position
    
    Our current and non-current derivative assets and liabilities
    decreased $165.8 million on a net basis.  Our net open
    derivative position decreased $310.9 million because of
    monthly settlements during 2009 and $54.9 million received
    for early settlement of a derivative hedging a portion of our
    2010 production.  The valuation of our open derivative positions
    at December 31, 2009 partially offset these decreases.  Our
    current deferred income tax liability related to our derivatives
    was almost unchanged 46




---



##### Table of Contents



because of changes in the allocation of open derivative
    positions between the U.S. and Canada and the difference
    between U.S. and Canadian statutory tax rates.  
    Our net property, plant and equipment balance decreased
    $711.8 million from December 31, 2008 to
    December 31, 2009.  During 2009, we recorded charges for
    impairment of our oil and gas properties of $979.5 million
    and 2009 DD&A expense of $199.1 million.  Our
    property, plant and equipment balances were also decreased by
    proceeds of $219.6 million for the Eni Transaction.  These
    decreases were partially offset by $601.7 million of costs
    incurred for property, plant and equipment, and an additional
    $84.7 million for changes to
    U.S.-Canadian
    exchange rates and assets recognized when retirement obligations
    were established for new wells and facilities.
    Our deferred income tax liability has decreased
    $192.5 million and a U.S. deferred tax asset of
    $133.1 million was recognized in connection with the
    impairments of both our investment in BBEP and our U.S. oil
    and gas properties.
    Equity held by noncontrolling interests increased
    $34.1 million, which consisted of $30.1 million from
    the KGS Secondary Offering, employee unit compensation of
    $1.7 million and income attributable to noncontrolling
    interests of $12.2 million partially offset by
    $9.9 million of distributions paid to noncontrolling
    interests.  Contractual
    Obligations and Commercial Commitments
  Contractual Obligations.
  Payments Due by PeriodLess than


1-3


4-5


More thanTotal


1 Year


Years


Years


5 Years(In thousands)Long-term debt

$
2,467,969


$
-


$
592,969


$
475,000


$
1,400,000Scheduled interest obligations


1,135,247



166,782



494,438



309,705



164,322Transportation and processing contracts


629,116



43,909



238,382



157,272



189,553Drilling rig contracts


96,606



45,519



51,087



-



-Gas Purchase Commitment


50,744



50,744



-



-



-Purchase obligations


24,827



19,554



5,273



-



-Asset retirement obligations


59,378



109



195



130



58,944Unrecognized tax benefits


9,219



-



9,219



-



-Operating lease obligations


7,928



2,678



4,274



976



-Total obligations

$
4,481,034


$
329,295


$
1,395,837


$
943,083


$
1,812,819   
    Long-Term Debt.  As of December 31, 2009,
    our outstanding indebtedness included $468 million
    outstanding under our Senior Secured Credit Facility,
    $475 million of Senior Notes due 2015, $600 million of
    Senior Notes due 2016, $300 million of Senior Notes due
    2019, $350 million of Senior Subordinated Notes,
    $150 million of contingently convertible debentures and
    $125 million outstanding under the KGS Credit Facility (all
    before original issue discount).  Based upon our debt
    outstanding and interest rates in effect at December 31,
    2009, we anticipate interest payments, including our scheduled
    interest obligations, to be approximately $184.3 million in
    2010.  Although we do not expect year-over-year increased
    borrowings under our Senior Secured Credit Facility during 2010,
    should we be required to increase those borrowings and based on
    interest rates in effect at December 31, 2009, an
    additional $50 million in borrowings would result in
    additional annual interest payments of approximately
    $1.7 million.  If the current borrowing base under our
    Senior Secured Credit Facility were to be fully utilized by
    year-end 2010 at interest rates in effect at December 31,
    2009, we estimate that annual interest payments would increase
    by approximately $16.5 million.  If interest rates on our
    December 31, 2009 variable debt balances of approximately
    $1.4 billion, including $825 million subject to fixed
    to 47




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##### Table of Contents



floating interest rate swaps, increase or decrease by one
    percentage point, our annual pre-tax income would decrease or
    increase by $14.2 million.  
    Scheduled Interest Obligations.  As of
    December 31, 2009, we had scheduled interest payments of
    $39.2 million annually on our Senior Notes due 2015,
    $70.5 million annually on our Senior Notes due 2016,
    $27.4 million annually on our Senior Notes due 2019,
    $24.9 million annually on our $350 million of Senior
    Subordinated Notes and $2.8 million annually on our
    $150 million of contingently convertible debentures.
    Additional interest of $1.3 million and $0.7 million
    is payable in 2010 on the Senior Secured Credit Facility and KGS
    Credit Agreement, respectively.
    Transportation and Processing Contracts.Under contracts
    with various pipeline and processing companies, we are obligated
    to provide minimum daily natural gas volumes for transport or
    processing, as calculated on a monthly basis, or pay for any
    volume deficiencies at a specified reservation fee rate.  Our
    production committed to the pipelines or processing plants is
    expected to meet, or exceed, the daily volumes provided in the
    contracts.
    Drilling Rig Contracts.  We utilize drilling
    rigs from third parties in our development and exploration
    programs.  The outstanding drilling rig contracts require
    payment of a specified day rate ranging from $20,500 to $26,500
    for the entire lease term regardless of our utilization of the
    drilling rigs.
    Gas Purchase Commitment.  Pursuant to the Eni
    Transaction we agreed to purchase Enis share of Alliance
    Leasehold production at $8.60 per MMBtu less costs related to
    gathering and processing Enis Alliance Production through
    December 2010.
    Purchase Obligations.  At December 31,
    2009, we and KGS were under contract to purchase goods and
    services for use in field and gas plant operations. KGS
    remaining cash obligations for such items were $7.4 million.
    Asset Retirement Obligations.  Our obligations
    result from the acquisition, construction or development and the
    normal operation of our long-lived assets.
    Unrecognized Tax Benefits.  We have recorded
    obligations that have resulted from tax benefit claims in our
    tax returns that do not meet the recognition standard of more
    likely than not to be sustained upon examination by tax
    authorities.  The $9.2 million balance of unrecognized tax
    benefits includes $8.9 million of amounts that, if
    recognized, would reduce our effective tax rate.
    Operating Lease Obligations.  We lease office
    buildings and other property under operating leases.  Commercial Commitments.
  Amounts of Commitments by Expiration PeriodLess than


1-3


4-5


More thanTotal


1 Year


Years


Years


5 Years(In thousands)Surety bonds

$
39,069


$
39,069


$
-


$
-


$
-Standby letters of credit


34,522



34,522



-



-



-Total

$
73,591


$
73,591


$
-


$
-


$
-   
    Surety Bonds.  Our surety bonds have been
    issued to fulfill contractual, legal or regulatory
    requirements.  Surety bonds generally have an annual renewal
    option.
    Standby Letters of Credit.  Our letters of
    credit have been issued to fulfill contractual or regulatory
    requirements, including $21.4 million issued to provide
    credit support for surety bonds.  All of these letters of credit
    were issued under our Senior Secured Credit Facility and
    generally have an annual renewal option.  CRITICAL
    ACCOUNTING ESTIMATES
   48




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##### Table of Contents



Oil and
    Gas Reserves
  Policy
    Description
    
    the use of an unweighted average of the preceding
    12-month
    first-day-of-the-month
    prices for determination of proved reserve values included in
    calculating full cost ceiling limitations and for annual proved
    reserve disclosures;
    consideration of and limitations on the types of technologies
    that may be used to reliably establish and estimate proved
    reserves;
    reporting of investments and progress made during the year to
    convert proved undeveloped reserves to proved developed
    reserves; and,
    reporting on the independence and qualifications of our
    personnel and independent petroleum engineers who are
    responsible for the preparation of our reserve estimates.    Judgments
    and Assumptions
     49




---



##### Table of Contents



Full Cost
    Ceiling Calculations
  Policy
    Description
  country-by-country
  12-month
  Judgments
    and Assumptions
       50




---



##### Table of Contents



Derivative
    Instruments
  Policy
    Description
            Judgments
    and Assumptions
   51




---



##### Table of Contents



Stock-based
    Compensation
  Policy
    Description
    Judgments
    and Assumptions
      Income
    Taxes
  Policy
    Description
    Judgments
    and Assumptions
    OFF-BALANCE
    SHEET ARRANGEMENTS
  Regulation S-K.
 52




---



##### Table of Contents



RECENTLY
    ISSUED ACCOUNTING STANDARDS
    ITEM 7A.
    Quantitative
    and Qualitative Disclosures About Market Risk  Commodity
    Price Risk
     53




---



##### Table of Contents



Weighted AvgPrice Per Mcf orProduct

Type


Contract Period


Volume


Bbl


Fair Value(In thousands)Gas


Collar



Jan 2010-Dec 2010



20 MMcfd


$
8.00-11.00


$
17,163Gas


Collar



Jan 2010-Dec 2010



20 MMcfd



8.00-11.00



17,163Gas


Collar



Jan 2010-Dec 2010



20 MMcfd



8.00-12.20



17,289Gas


Collar



Jan 2010-Dec 2010



20 MMcfd



8.00-12.20



17,289Gas


Collar



Jan 2010-Dec 2010



10 MMcfd



8.50-12.05



10,320Gas


Collar



Jan 2010-Dec 2010



20 MMcfd



8.50-12.05



20,640Gas


Collar



Jan 2010-Dec 2010



10 MMcfd



8.50-12.08



10,328Gas


Collar



Jan 2010-Dec 2011



10 MMcfd



6.00-7.00



1,921Gas


Collar



Jan 2010-Dec 2011



10 MMcfd



6.00-7.00



1,921Gas


Collar



Jan 2010-Dec 2011



20 MMcfd



6.00-7.00



3,843Gas


Collar



Jan 2010-Dec 2012



20 MMcfd



6.50-7.15



10,456Gas


Collar



Jan 2010-Dec 2012



20 MMcfd



6.50-7.18



10,993Gas


Collar



Jan 2011-Dec 2011



10 MMcfd



6.25-7.50



1,187Gas


Collar



Jan 2011-Dec 2011



10 MMcfd



6.25-7.50



1,187Gas


Collar



Jan 2011-Dec 2011



20 MMcfd



6.25-7.50



2,374Gas


Collar



Jan 2012-Dec 2012



20 MMcfd



6.50-8.01



3,277Gas


Basis



Jan 2010-Dec 2010



20 MMcfd



(1)



(638
)Gas


Basis



Jan 2010-Dec 2010



20 MMcfd



(1)



(638
)Gas


Basis



Jan 2011-Dec 2011



10 MMcfd



(1)



122Gas


Basis



Jan 2011-Dec 2011



10 MMcfd



(1)



122Gas


Basis



Jan 2011-Dec 2011



20 MMcfd



(1)



243NGL


Swap



Jan 2010-Dec 2010



2 MBld


$
32.65



(6,930
)NGL


Swap



Jan 2010-Dec 2010



3 MBld



32.98



(9,752
)NGL


Swap



Jan 2010-Dec 2010



1 MBld



33.63



(3,108
)NGL


Swap



Jan 2010-Dec 2010



1 MBld



34.15



(2,980
)NGL


Swap



Jan 2010-Dec 2010



3 MBld



34.22



(8,397
)NGL


Swap



Jan 2011-Dec 2011



3 MBld



36.06



(4,333
)NGL


Swap



Jan 2011-Dec 2011



2 MBld



36.31



(3,181
)Total


$
107,881   (1)

    
    Basis swaps hedge the AECO basis adjustment at a deduction of
    $0.45 per Mcf from NYMEX for 2010 and $0.39 per Mcf from NYMEX
    for 2011.    Weighted AvgPrice PerProduct

Type


Contract Period


Volume


Mcf or BblNGL


Swap



Jan 2011-Dec 2011



3 MBbld


$
41.95Gas


Basis



Feb 2010-Dec 2010



20 MMcfd



(2)Gas


Basis



Apr 2010-Dec 2010



10 MMcfd



(3)Gas


Basis



Apr 2010-Dec 2010



10 MMcfd



(3)  54




---



##### Table of Contents



(2)

    
    Basis swap hedges the Houston Ship Channel basis adjustment at a
    deduction of $0.09 per Mcf from NYMEX for February through
    December 2010.(3)

    
    Basis swaps hedge the Houston Ship Channel basis adjustment at
    deductions of $0.45 and $0.425 per Mcf, respectively, from NYMEX
    for April through December 2010.    (In thousands)Initial valuation of
    liability(1)

$
58,294Decrease due to gas volumes purchased


(14,175
)Embedded derivative increase (decrease) due to:Price changes


7,904Volume changes


(1,279
)Total embedded derivative


6,625Balance at December 31, 2009

$
50,744   (1)

    
    Initial valuation of the Gas Purchase Commitment was estimated
    using estimated Eni production volumes from June 19, 2009
    through December 2010 and published future market prices and
    risk-adjusted interest rates as of June 19, 2009.  Interest
    Rate Risk
        Foreign
    Currency Risk
   55




---



##### Table of Contents



ITEM 8.  Financial
    Statements and Supplementary Data  QUICKSILVER
    RESOURCES INC.
    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
  PageReport of Independent Registered Public
    Accounting Firm


57Consolidated Statements of Income (Loss) and
    Comprehensive Income (Loss) for the Years Ended
    December 31, 2009, 2008 and 2007


58Consolidated Balance Sheets as of
    December 31, 2009 and 2008


59Consolidated Statements of Equity for the Years
    ended December 31, 2009, 2008 and 2007


60Consolidated Statements of Cash Flows for the
    Years Ended December 31, 2009, 2008 and 2007


61Notes to Consolidated Financial Statements for
    the Years Ended December 31, 2009, 2008 and 2007


62Supplemental Selected Quarterly Financial Data
    (Unaudited)


98Supplemental Oil and Gas Information
    (Unaudited)


99  56




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM            No. 2010-3,
  Internal ControlIntegrated Framework
  /s/ Deloitte &
    Touche LLP
    57




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##### Table of Contents



QUICKSILVER
    RESOURCES INC.CONSOLIDATED STATEMENTS OF INCOME
    (LOSS) AND COMPREHENSIVE INCOME (LOSS)FOR THE YEARS ENDED DECEMBER 31, 2009,
    2008 AND 2007
    In thousands, except for per share data
  2009


2008


2007RevenueNatural gas, NGL and oil

$
796,698


$
780,788


$
545,089Sales of purchased natural gas


23,654



-



-Other


12,383



19,853



16,169Total revenue


832,735



800,641



561,258Operating expenseOil and gas production expense


127,715



134,302



136,103Production and ad valorem taxes


23,881



18,734



17,048Costs of purchased natural gas


30,158



-



-Other operating expense


6,684



3,337



2,614Depletion, depreciation and accretion


201,387



188,196



120,697General and administrative expense


77,243



72,254



47,060Total expense


467,068



416,823



323,522Impairment related to oil and gas properties


(979,540
)


(633,515
)


-Income from equity affiliates


-



-



661Gain on sale of oil and gas properties


-



-



628,709Loss on natural gas sales contract


-



-



(63,525
)Operating income (loss)


(613,873
)


(249,697
)


803,581Income from earnings of BBEP


75,444



93,298



-Impairment of investment in BBEP


(102,084
)


(320,387
)


-Other income (expense)  net


(1,242
)


807



3,887Interest expense


(195,101
)


(109,098
)


(76,662
)Income (loss) before income taxes


(836,856
)


(585,077
)


730,806Income tax (expense) benefit


291,617



211,455



(254,361
)Net income (loss)


(545,239
)


(373,622
)


476,445Net income attributable to noncontrolling interests


(12,234
)


(4,654
)


(1,055
)Net income (loss) attributable to Quicksilver

$
(557,473
)

$
(378,276
)

$
475,390Other comprehensive income (loss)Reclassification adjustments related to settlements of
    derivative contracts  net of income tax


(211,863
)


11,969



(34,648
)Net change in derivative fair value  net of income tax


125,989



182,472



(14,794
)Foreign currency translation adjustment


22,106



(49,403
)


29,409Comprehensive income (loss)

$
(621,241
)

$
(233,238
)

$
455,357Earnings (loss) per common share  basic

$
(3.30
)

$
(2.33
)

$
3.04Earnings (loss) per common share  diluted

$
(3.30
)

$
(2.33
)

$
2.87Basic weighted average shares outstanding


169,004



162,004



156,517Diluted weighted average shares outstanding


169,004



162,004



168,029    58




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##### Table of Contents



QUICKSILVER
    RESOURCES INC.CONSOLIDATED BALANCE SHEETSAS OF DECEMBER 31, 2009 AND 2008
    In thousands, except for share data
  2009


2008ASSETSCurrent assetsCash and cash equivalents

$
1,785


$
2,848Accounts receivable  net of allowance for doubtful
    accounts


65,253



143,315Derivative assets at fair value


97,957



171,740Other current assets


54,943



75,433Total current assets


219,938



393,336Investments in equity affiliates


112,763



150,503Property, plant and equipment  netOil and gas properties, full cost method (including
    unevaluated
    costs of $458,037 and $543,533, respectively)


2,338,244



3,142,608Other property and equipment


747,696



655,107Property, plant and equipment  net


3,085,940



3,797,715Derivative assets at fair value


14,427



116,006Deferred income taxes


133,051



Other assets


46,763



40,648$
3,612,882


$
4,498,208LIABILITIES AND EQUITYCurrent liabilitiesCurrent portion of long-term debt

$



$
6,579Accounts payable


157,986



282,636Accrued liabilities


156,604



66,963Derivative liabilities at fair value


395



9,928Current deferred tax liability


51,675



52,393Total current liabilities


366,660



418,499Long-term debt


2,427,523



2,586,045Asset retirement obligations


59,268



34,753Other liabilities


20,691



12,962Deferred income taxes


41,918



234,386Commitments and contingencies (Note 16)EquityPreferred stock, par value $0.01, 10,000,000 shares
    authorized, none outstanding






Common stock, $0.01 par value, 400,000,000 and
    200,000,000 shares authorized,
    respectively; 174,469,836 and 171,742,699 shares issued,
    respectively


1,745



1,717Paid in capital in excess of par value


730,265



656,958Treasury stock of 4,704,448 and 4,572,795 shares,
    respectively


(36,363
)


(35,441
)Accumulated other comprehensive income


121,336



185,104Retained earnings (deficit)


(180,985
)


376,488Quicksilver stockholders equity


635,998



1,184,826Noncontrolling interests


60,824



26,737Total equity


696,822



1,211,563$
3,612,882


$
4,498,208    59




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##### Table of Contents



QUICKSILVER
    RESOURCES INC.CONSOLIDATED STATEMENTS OF
    EQUITYFOR THE YEARS ENDED DECEMBER 31, 2009,
    2008 AND 2007In thousands, except for share
    data
  Quicksilver Resources Inc. Stockholders EquityAccumulatedAdditional





OtherCommon


Paid-in


Treasury


Comprehensive


Retained


NoncontrollingStock


Capital


Stock


Income


Earnings


Interest


TotalBalances at December 31. 2006

$
1,578


$
264,078


$
(10,737
)

$
60,099


$
279,719


$
7,382


$
602,119Net income


-



-



-



-



475,390



1,055



476,445Adoption of new rules for uncertain tax positions


-



-



-



-



(345
)


-



(345
)Hedge derivative contract settlements reclassified into earnings
    from accumulated other comprehensive income, net of income tax
    of $16,491


-



-



-



(34,648
)


-



-



(34,648
)Net change in derivative fair value, net income tax of $8,436


-



-



-



(14,794
)


-



-



(14,794
)Foreign currency translation adjustment


-



-



-



29,409



-



-



29,409Issuance & vesting of stock compensation


6



13,863



(1,567
)


-



-



129



12,431Stock option exercises, including income tax benefits


22



21,365



-



-



-



-



21,387Issuance of KGS common units


-



79,316



-



-



-



29,942



109,258Distributions paid on KGS common units


-



-



-



-



-



(8,794
)


(8,794
)Balances at December 31. 2007


1,606



378,622



(12,304
)


40,066



754,764



29,714



1,192,468Net income (loss)


-



-



-



-



(378,276
)


4,654



(373,622
)Hedge derivative contract settlements reclassified into earnings
    from accumulated other comprehensive income, net of income tax
    of $6,424


-



-



-



11,969



-



-



11,969Net change in derivative fair value, net income tax of $93,251


-



-



-



182,472



-



-



182,472Foreign currency translation adjustment


-



-



-



(49,403
)


-



-



(49,403
)Issuance & vesting of stock compensation


5



15,106



(3,237
)


-



-



1,013



12,887Stock option exercises


2



1,242



-



-



-



-



1,244Issuance of common stock  Alliance Acquisition


104



261,988



-



-



-



-



262,092Acquisition of treasury stock


-



-



(19,900
)


-



-



-



(19,900
)Distributions paid on KGS common units


-



-



-



-



-



(8,644
)


(8,644
)Balances at December 31. 2008


1,717



656,958



(35,441
)


185,104



376,488



26,737



1,211,563Net income (loss)


-



-



-



-



(557,473
)


12,234



(545,239
)Hedge derivative contract settlements reclassified into earnings
    from accumulated other comprehensive income, net of income tax
    of $99,004


-



-



-



(211,863
)


-



-



(211,863
)Net change in derivative fair value, net income tax of $57,007


-



-



-



125,989



-



-



125,989Foreign currency translation adjustment


-



-



-



22,106



-



-



22,106Issuance & vesting of stock compensation


22



19,085



(922
)


-



-



1,645



19,830Stock option exercises


6



4,040



-



-



-



-



4,046Issuance of KGS common units


-



50,182



-



-



-



30,133



80,315Distributions paid on KGS common units


-



-



-



-



-



(9,925
)


(9,925
)Balances at December 31. 2009

$
1,745


$
730,265


$
(36,363
)

$
121,336


$
(180,985
)

$
60,824


$
696,822    60




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##### Table of Contents



QUICKSILVER
    RESOURCES INC.CONSOLIDATED STATEMENTS OF CASH
    FLOWSFOR THE YEARS END DECEMBER 31, 2009, 2008
    AND 2007
    In thousands
  2009


2008


2007Operating activities:Net income (loss)

$
(545,239
)

$
(373,622
)

$
476,445Adjustments to reconcile net income (loss) to net cash
    provided
    by operating activities:Depletion, depreciation and accretion


201,387



188,196



120,697Impairment related to oil and gas properties


979,540



633,515



-Deferred income tax expense (benefit)


(291,414
)


(166,440
)


207,796(Gain) loss from sale of property, plant and equipment


-



605



(627,348
)Non-cash (gain) loss from hedging and derivative activities


6,756



(1,139
)


62,515Stock-based compensation


20,752



16,128



11,243Non-cash interest expense


45,532



13,215



10,374Income from BBEP in excess of cash distributions


(64,344
)


(50,762
)


-Impairment of investment in BBEP


102,084



320,387



-Other


747



-



(349
)Divestiture expenses


-



-



2,015Changes in assets and liabilitiesAccounts receivable


77,527



(53,071
)


(14,423
)Derivative assets at fair value


54,896



-



-Prepaid expenses and other assets


3,061



(5,448
)


(4,805
)Accounts payable


(12,320
)


7,602



18,939Income taxes payable


-



(46,561
)


46,012Accrued and other liabilities


33,275



(26,039
)


9,993Net cash provided by operating activities


612,240



456,566



319,104Investing activities:Purchases of property, plant and equipment


(693,838
)


(1,286,715
)


(1,020,684
)Alliance Acquisition


-



(993,212
)


-Return of investment from equity affiliates


-



-



9,635Proceeds from sales of properties and equipment


220,974



1,339



741,297Net cash used in investing activities


(472,864
)


(2,278,588
)


(269,752
)Financing activities:Issuance of debt


1,420,727



2,948,672



817,821Repayments of debt


(1,649,630
)


(1,096,163
)


(968,557
)Debt issuance costs paid


(32,472
)


(25,219
)


(5,130
)Gas Purchase Commitment


58,294



-



-Gas Purchase Commitment repayments


(14,175
)


-



-Issuance of KGS common units  net offering costs


80,729



-



109,809Distributions paid on KGS common units


(9,925
)


(8,644
)


(8,794
)Proceeds from exercise of stock options


4,046



1,244



21,387Excess tax benefits on exercise of stock options


-



-



2,755Purchase of treasury stock


(922
)


(23,137
)


(1,567
)Net cash provided by (used in) financing activities


(143,328
)


1,796,753



(32,276
)Effect of exchange rate changes in cash


2,889



(109
)


5,869Net increase (decrease) in cash


(1,063
)


(25,378
)


22,945Cash and cash equivalents at beginning of period


2,848



28,226



5,281Cash and cash equivalents at end of period

$
1,785


$
2,848


$
28,226    61




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##### Table of Contents



QUICKSILVER
    RESOURCES INC.NOTES TO CONSOLIDATED FINANCIAL
    STATEMENTS
 FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
  1.
    NATURE OF
    OPERATIONS      2.
    SIGNIFICANT
    ACCOUNTING POLICIES  Basis of
    Presentation
    Form 10-K,
  Changes
    in Presentation
    Stock
    Split
  two-for-one
  Use of
    Estimates
   62




---



##### Table of Contents



Cash and
    Cash Equivalents
    Accounts
    Receivable
  30-60 days.
  Hedging
    and Derivatives
         63




---



##### Table of Contents



Investments
    in Equity Affiliates
      Property,
    Plant, and Equipment
  country-by-country unit-of-production
  12-month first-day-of-the-month
 64




---



##### Table of Contents



Asset
    Retirement Obligations
    Revenue
    Recognition
    Environmental
    Compliance and Remediation
    Debt
    Income
    Taxes
    Stock-based
    Compensation
    Disclosure
    of Fair Value of Financial Instruments
   65




---



##### Table of Contents



Foreign
    Currency Translation
    Noncontrolling
    Interests in Consolidated Subsidiaries
    Earnings
    per Share
    Recently
    Issued Accounting Standards
     Pronouncements
    Impacting Quicksilver That Have Been Implemented During
    2009
  Form 10-K,
  FASB Accounting Standards
    Codification
   66




---



##### Table of Contents



Fair Value Measurements and
    Disclosures,
    825-10, Financial Instruments
    Fair Value Measurements and
    Disclosures
  12-month first-day-of-the-month
      3.
    ENI
    TRANSACTION     67




---



##### Table of Contents



Total AggregateYear

Linear Feet2010


58,4482011


44,0802012


26,9742013


34,102     4.
    ALLIANCE
    ACQUISITION    (In thousands)Purchase Price:Cash paid

$
1,000,000Cash received from post-closing settlement


(9,086
)Cash paid for acquisition-related expenses


1,368Total cash


992,282Issuance of 10,400,468 common shares


262,092$
1,254,374     (In thousands)Allocation of Purchase Price:Oil and gas properties  proved

$
788,457Oil and gas properties  unproved


440,372Midstream assets


27,652Liabilities assumed


(1,035
)Asset retirement obligations


(1,072
)$
1,254,374    68




---



##### Table of Contents



Pro Forma
    Information
    For The Years EndedDecember 31,2008


2007(In thousands, except per share data)Revenues


$  875,607



$ 629,868Net income (loss)


$ (384,645
)


$ 428,314Earnings (loss) per common share - basic


($2.29
)


$2.57Earnings (loss) per common share - diluted


($2.29
)


$2.40   5.
    DIVESTITURE
    OF NORTHEAST OPERATIONS           69




---



##### Table of Contents



6.
    DERIVATIVES
    AND FAIR VALUE MEASUREMENTS  Commodity
    Price Derivatives
    Interest
    Rate Derivatives
        Other
    Derivatives
   70




---



##### Table of Contents



(In thousands)Initial valuation of liability
    (1)

$
58,294Decrease due to gas volumes purchased


(14,175
)Embedded derivative increase (decrease) due to:Price changes


7,904Volume changes


(1,279
)Total embedded derivative


6,625Balance at December 31, 2009

$
50,744   (1)

    
    Initial valuation of the Gas Purchase Commitment was estimated
    using estimated Eni production volumes from June 19, 2009
    through December 2010 and published future market prices and
    risk-adjusted interest rates as of June 19, 2009.    Asset Derivatives



Liability DerivativesAs of December 31,



As of December 31,2009


2008



2009


2008(In thousands)



(In thousands)Derivatives designated as hedges:Commodity contracts reported in:Current derivative assets

$
97,883


$
179,079



$
638


$
2,500Noncurrent derivative assets


11,031



116,006




-



-Current derivative liabilities


243



-




638



1,865Interest rate contracts reported in:Current derivative assets


712



-




-



-Noncurrent derivative assets


3,396



-




-



-Total derivatives designated as hedges

$
113,265


$
295,085



$
1,276


$
4,365Derivatives not designated as hedges:Gas Purchase Commitment reported in:Accrued liabilities

$
-


$
-



$
6,625


$
-Michigan Sales Contract natural gas purchase
    derivatives (1) reported

    in current derivative assets


-



-




-



4,839Michigan Sales
    Contract (1) reported

    in current derivative liabilities


-



-




-



8,063Total derivatives not designated as hedges

$
-


$
-



$
6,625


$
12,902Total derivatives

$
113,265


$
295,085



$
7,901


$
17,267   (1)

    
    During 2009, our net cash payments were $16.5 million,
    including derivative settlements, to complete our obligations
    under the Michigan Sales Contract. 71




---



##### Table of Contents



Significant Other ObservableInputs - Level 2at December 31,2009


2008(In thousands)DerivativesGas Purchase Commitment

$
(6,625
)

$
-Michigan Sales Contract


-



(8,063
)Commodity futures contracts


107,881



285,881Interest rate contracts


4,108



-Total
    derivatives-net

$
105,364


$
277,818       For the Two Years Ended December 31, 2009Michigan


Gas Purchase


Fair Value


Cash FlowContract


Commitment
    (1)


Derivatives


Derivatives


Total(In thousands)Derivative fair value at December 31, 2007

$
(63,777
)

$
-


$
-


$
(5,505
)

$
(69,282
)Change in amounts receivable/payable-net


3,518



-



-



(438
)


3,080Net settlements


48,284



-



-



-



48,284Net settlements reported in revenue


-



-



-



18,392



18,392Ineffectiveness reported in other revenue


(926
)


-



-



2,547



1,621Unrealized gains reported in OCI


-



-



-



275,723



275,723Derivative fair value at December 31, 2008

$
(12,901
)

$
-


$
-


$
290,719


$
277,818Change in amounts receivable/payable-net


(3,518
)


-



9,180



-



5,662Net settlements


16,479



-



-



-



16,479Net settlements reported in revenue


-



-



-



(310,868
)


(310,868
)Net settlements reported in interest expense


-



-



13,724



-



13,724Unrealized change in fair value of Gas Purchase Commitment
    reported in costs of purchased gas


-



(6,625
)


-



-



(6,625
)Change in fair value of effective interest swaps


-



-



(18,796
)


-



(18,796
)Ineffectiveness reported in other revenue


(60
)


-



-



(71
)


(131
)Cash settlement reported in OCI


-



-



-



(54,896
)


(54,896
)Unrealized gains reported in OCI


-



-



-



182,997



182,997Derivative fair value at December 31, 2009

$
-


$
(6,625
)

$
4,108


$
107,881


$
105,364   (1)

    
    Reported in accrued liabilities.   72




---



##### Table of Contents



7.
    ACCOUNTS
    RECEIVABLE    As of December 31,2009


2008(In thousands)Accrued production receivables

$
33,241


$
47,552Joint interest receivables


12,889



29,420Interest rate swap settlement receivable


9,180



-Income tax receivable


7,018



47,928Accrued production taxes receivable


2,120



12,877Other receivables


1,254



5,624Allowance for doubtful accounts


(449
)


(86
)$
65,253


$
143,315   8.
    OTHER
    CURRENT ASSETS    As of December 31,2009


2008(In thousands)Spare parts and supplies

$
44,258


$
64,185Prepaid production taxes


5,071



7,239Prepaid drilling rentals


-



384Deposits


2,758



1,680Other prepaid expenses


2,856



1,945$
54,943


$
75,433   9.
    INVESTMENT
    IN BREITBURN ENERGY PARTNERS L.P.    other-than-temporary. other-than-temporary.
   73




---



##### Table of Contents



For the


For theTwelve Months


Eleven MonthsEnded


EndedSeptember 30,2009


September 30, 2008(In thousands)Revenue
    (1)

$
534,192


$
420,321Operating expense
    (2)


307,391



251,618Operating income


226,801



168,703Interest and other
    (3)


37,458



27,795Income tax (benefit) expense


336



593Noncontrolling interests


15



206Net income available to BBEP

$
188,992


$
140,109Net income available to common unitholders

$
188,992


$
141,660   (1)
    Unrealized gains on commodity derivatives of $193.5 million
    and $39.4 million were included for the twelve months ended
    September 30, 2009 and eleven months ended
    September 30, 2008, respectively.  Realized gains on
    commodity derivatives of $70.6 million for the early
    settlement of derivative positions were included for the twelve
    months ended September 30, 2009.(2)
    An impairment of BBEPs oil and gas properties of
    $86.4 million was included for the twelve months ended
    September 30, 2009.(3)
    The twelve months ended September 30, 2009 included
    $11.1 million for unrealized losses on interest rate swaps
    and the eleven months ended September 30, 2008 included
    $2.3 million for unrealized losses on interest rate swaps.  As of


As ofSeptember 30, 2009


December 31, 2008(In thousands)Current assets

$
121,207


$
140,566Property, plant and equipment


1,754,174



1,840,341Other assets


114,673



235,927Current liabilities


64,573



79,990Long-term debt


585,000



736,000Other non-current liabilities


72,519



47,413Partners equity


1,267,962



1,353,431  74




---



##### Table of Contents



As of December 31,2009


2008(In thousands)Beginning investment balance

$
150,503


$
420,171Equity income in BBEP


75,444



93,298Distributions from BBEP


(11,100
)


(42,579
)Non-cash impairment of BBEP


(102,084
)


(320,387
)Ending investment balance

$
112,763


$
150,503   Rule 3-09.
  10.
    PROPERTY,
    PLANT AND EQUIPMENT    As of December 31,2009


2008(In thousands)Oil and gas propertiesSubject to depletion

$
3,947,676


$
3,621,831Unevaluated costs


458,037



543,533Accumulated depletion


(2,067,469
)


(1,022,756
)Net oil and gas properties


2,338,244



3,142,608Other plant and equipmentPipelines and processing facilities


779,493



533,234General properties


68,698



57,941Construction in progress


5,630



130,878Accumulated depreciation


(106,125
)


(66,946
)Net other property and equipment


747,696



655,107Property, plant and equipment, net of accumulated depletion and
    depreciation

$
3,085,940


$
3,797,715   Ceiling
    Test Analysis and Impairment
       75




---



##### Table of Contents



12-month first-day-of-the-month
      Net





Pre-taxCapitalized


Ceiling


Charge forCosts(1)


Limitation(2)


Impairment(In thousands)First Quarter 2009United States

$
2,727,130


$
1,940,263


$
786,867Canada


458,135



348,519



109,616Total

$
3,185,265


$
2,288,782


$
896,483Second Quarter 2009Canada

$
400,696


$
330,053


$
70,643Fourth Quarter 2009Canada

$
385,931


$
373,517


$
12,4142009 Consolidated charge for impairment









$
979,540   Net





Pre-taxCapitalized


Ceiling


Charge forCosts(1)


Limitation(2)


Impairment(In thousands)Fourth Quarter 2008United States

$
3,016,147


$
2,391,832


$
624,315   (1)

    
    Net capitalized costs before impairment includes all costs
    associated with development, exploration and acquisition of oil
    and gas properties net of accumulated depletion and impairment,
    reduced by the related deferred income tax liability. 76




---



##### Table of Contents



(2)

    
    The cost center ceiling is defined as the sum of
    (1) estimated future net revenue, discounted at 10% per
    annum, from proved reserves, based on the unweighted average of
    the preceding
    12-month
    first day-of the-month prices (end of year prices for 2008 and
    2007) adjusted to reflect local differentials and contract
    provisions, unescalated year-end costs and financial derivatives
    that hedge the our oil and gas revenue, (2) the cost of
    properties not being amortized, (3) the lower of cost or
    market value of unproved properties included in the cost being
    amortized less (4) income tax effects related to
    differences between the book and tax bases of the oil and gas
    properties.  ,
    Unevaluated
    Natural Gas and Oil Properties Not Subject to
    Depletion
    December 31, 2009 Costs Incurred During


December 31, 2008 Costs Incurred During2009


2008


2007


Prior


Total


2008


2007


2006


Prior


Total(In thousands)


(In thousands)Acquisition costs

$
12,463


$
275,409


$
54,855


$
63,089


$
405,816


$
381,203


$
54,094


$
31,328


$
53,998


$
520,623Exploration costs


29,029



16,470











45,499



19,632















19,632Capitalized interest


3,985



2,737











6,722



3,278















3,278Total

$
45,477


$
294,616


$
54,855


$
63,089


$
458,037


$
404,113


$
54,094


$
31,328


$
53,998


$
543,533     As of December 31,2009


2008(In thousands)Fort Worth Basin

$
312,892


$
440,144Canadian Horn River Basin


117,330



80,590Green River Basin


27,131



18,580Other


684



4,219Total

$
458,037


$
543,533     Other
    Matters
   77




---



##### Table of Contents



11.
    OTHER
    ASSETS    As of December 31,2009


2008(In thousands)Deferred financing costs

$
60,114


$
46,375Less accumulated amortization


(14,249
)


(9,507
)Net deferred financing costs


45,865



36,868Deposits






3,008Other


898



772$
46,763


$
40,648     12.
    ACCRUED
    LIABILITIES    As of December 31,2009


2008(In thousands)Gas Purchase Commitment liability

$
50,744


$
Interest payable


71,768



30,713Accrued operating expenses


21,136



20,296Prepayments from partners


5,224



974Revenue payable


4,141



7,181Accrued production and property taxes


2,157



4,137Environmental liabilities


659



50Accrued product purchases


483



1,382Accrued capital expenditures






1,695Other


292



535$
156,604


$
66,963  78




---



##### Table of Contents



13.
    LONG-TERM
    DEBT    As of December 31,2009


2008(In thousands)Senior Secured Credit Facility

$
467,569


$
827,868Senior notes due 2015, net of unamortized discount of $5,036 and
    $5,938


469,964



469,062Senior notes due 2016, net of unamortized discount of $18,641
    and $-


581,359



Senior notes due 2019, net of unamortized discount of $6,996 and
    $-


293,004



Senior subordinated notes due 2016


350,000



350,000Convertible debentures, net of unamortized discount of $13,881
    and $20,761


136,119



129,239KGS Credit Agreement


125,400



174,900Senior secured second lien facility, net of unamortized discount
    of $- and $13,050






641,555Total debt


2,423,415



2,592,624Fair value of interest rate swaps  hedges


4,108



Less current maturities






(6,579
)Long-term debt

$
2,427,523


$
2,586,045     SeniorTotal


Senior Secured


Senior Notes


Senior Notes


Senior Notes


Subordinated


Convertible


KGS CreditIndebtedness


Credit Facility


due in 2015


due in 2016


due in 2019


Notes


Debentures


Agreement(In thousands)2010

$



$



$



$



$



$



$



$
2011






























2012


592,969



467,569























125,4002013






























2014






























Thereafter


1,875,000







475,000



600,000



300,000



350,000



150,000



$
2,467,969


$
467,569


$
475,000


$
600,000


$
300,000


$
350,000


$
150,000


$
125,400   Senior
    Secured Credit Facility
   79




---



##### Table of Contents



Senior
    Notes Due 2015
    Senior
    Notes Due 2016
    Senior
    Notes Due 2019
    Senior
    Secured Second Lien Facility
    Senior
    Subordinated Notes
    Convertible
    Debentures
    KGS
    Credit Agreement
   80




---



##### Table of Contents



Summary
    of All Outstanding Debt
    Priority on Collateral and Structural
    Seniority (1)

Recourse only toKGS assetsHighest
priority 3⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄43⁄4 Lowest
priorityEqual prioritySenior Secured


2015


2016


2019


Senior


Convertible

KGS CreditCredit Facility


Senior Notes


Senior Notes


Senior Notes


Subordinated Notes


Debentures

AgreementScheduled maturity date

February 9, 2012


August 1, 2015


January 1, 2016


September 1, 2019


April 1, 2016


November 1, 2024

August 10, 2012Interest rate atDecember 31, 2009
    (2)

3.30%


8.25%


11.75%


9.125%


7.125%


1.875%

3.26%Base interest rate options
    (3)

LIBOR, ABR or
    specified(4)


N/A


N/A


N/A


N/A


N/A

LIBOR, ABR or specified(5)Financial covenants
    (6)

- Minimum current
    ratio of 1.0


N/A


N/A


N/A


N/A


N/A

- Maximum debt to EBITDA ratio of 4.5- Minimum EBITDA to interest expense ratio of 2.5
















- Minimum EBITDA
    to interest expense
    ratio of 2.5Significant restrictive

- Incurrence of debt


- Incurrence of debt


- Incurrence of debt


- Incurrence of debt


- Incurrence of debt


N/A

- Incurrence of debtcovenants
    (6)

- Incurrence of liens


- Incurrence of liens


- Incurrence of liens


- Incurrence of liens


- Incurrence of liens




- Incurrence of liens- Payment of dividends


- Payment of dividends


- Payment of dividends


- Payment of dividends


- Payment of dividends




- Equity purchases- Equity purchases


- Equity purchases


- Equity purchases


- Equity purchases


- Equity purchases




- Asset sales- Asset sales


- Asset sales


- Asset sales


- Asset sales


- Asset sales




- Limitations on- Affiliate transactions


- Affiliate transactions


- Affiliate transactions


- Affiliate transactions


- Affiliate transactions




derivatives- Limitations on derivativesEstimated fair value
    (7)

$467.6 million


$486.9 million


$681.0 million


$313.8 million


$326.4 million


$180.0 million

$125.4 million   (1)
    The Senior Secured Credit Facility is secured by a first
    perfected lien on substantially all our assets excluding
    KGS assets.  The other debt presented is based upon
    structural seniority and priority of payment.(2)
    Represents the weighted average borrowing rate payable to
    lenders and excludes effects of interest rate derivatives.(3)
    Interest rate options include a base rate plus a spread.(4)
    The Senior Secured Credit Facility was amended in August 2009 to
    add a floor to ABR of one-month LIBOR plus a 1%, increase in the
    ABR margin to a range of 1.375% to 2.375% and an increase in the
    Eurodollar and specified rate margins to a range of 2.25% to
    3.25%.(5)
    The KGS Credit Agreement was amended in October 2009 to add a
    floor to ABR of one-month LIBOR plus a 1%, increase in the ABR
    margin to a range of 2.00% to 3.00% and an increase in the
    Eurodollar and specified rate margins to a range of 3.00% to
    4.00%.(6)
    The covenant information presented in this table is qualified in
    all respects by reference to the full text of the covenants and
    related definitions contained in the documents governing the
    various components of our debt.(7)
    The estimated fair value is determined based on market
    quotations on the balance sheet date for fixed rate
    obligations.  We consider debt with market-based interest rates
    to have a fair value equal to its carrying value. 81




---



##### Table of Contents



14.
    ASSET
    RETIREMENT OBLIGATIONS    As of December 31,2009


2008(In thousands)Beginning asset retirement obligations

$
35,193


$
24,510Additional liability incurred


6,567



8,231Change in estimates


12,916



4,288Accretion expense


2,325



1,483Sale of properties


(380
)


-Asset retirement costs incurred


(379
)


(359
)Gain on settlement of liability


131



119Currency translation adjustment


3,004



(3,079
)Ending asset retirement obligations


59,377



35,193Less current portion


(109
)


(440
)Non-current asset retirement obligation

$
59,268


$
34,753   15.
    INCOME
    TAXES    As of December 31,2009


2008(In thousands)Deferred tax assets:Net operating loss carry forwards

$
290,894


$
176,957Cash flow hedge settlements


19,214



-Deferred compensation expense


10,654



4,236Other


8,712



969Deferred tax assets


329,474



182,162Deferred tax liabilities:Property, plant and equipment

$
(186,658
)

$
(318,070
)Cash flow hedge gains


(55,372
)


(92,854
)BBEP investment


(29,398
)


(40,270
)Convertible debenture interest


(18,588
)


(17,297
)Deferred tax liabilities


(290,016
)


(468,941
)Total deferred tax asset (liability)

$
39,458


$
(286,779
)Reflected in the consolidated balance sheets as:Non-current deferred income tax asset

$
133,051


$
-Current deferred income tax liability


(51,675
)


(52,393
)Non-current deferred income tax liability


(41,918
)


(234,386
)$
39,458


$
(286,779
)  82




---



##### Table of Contents



2009


2008


2007(In thousands)Current state income tax expense (benefit)

$
(2
)

$
(4
)

$
1,143Current U.S. federal income tax expense (benefit)


(202
)


(45,210
)


45,394Current Canadian income tax expense


-



199



28Total current income tax expense (benefit)


(204
)


(45,015
)


46,565Deferred state income tax expense (benefit)


(4,928
)


1,939



2,538Deferred U.S. federal income tax expense (benefit)


(262,217
)


(190,938
)


194,129Deferred Canadian income tax expense (benefit)


(24,268
)


22,559



11,129Total deferred income tax expense (benefit)


(291,413
)


(166,440
)


207,796Total income tax expense (benefit)

$
(291,617
)

$
(211,455
)

$
254,361     2009


2008


2007U.S. federal statutory tax rate


35.00
%


35.00
%


35.00
%Permanent differences


(0.18
)%


(0.33
)%


0.01
%Noncontrolling interest benefit


0.71
%


-



-State income taxes net of federal deduction


0.38
%


(0.22
)%


0.33
%Recognition of uncertain tax position


-



(0.09
)%


1.18
%Foreign income taxes


(0.98
)%


1.38
%


(1.71
)%Other


(0.08
)%


0.40
%


-Effective income tax rate


34.85
%


36.14
%


34.81
%         83




---



##### Table of Contents



As of December 31,2009


2008(In thousands)Beginning unrecognized tax benefits

$
9,255


$
9,997Gross amounts of increases in unrecognized tax benefits as a
    result of tax positions taken during a prior period


-



834Amount of decreases in unrecognized tax benefits related to
    settlements with taxing authorities


-



(1,301
)Gross amounts of decreases in unrecognized tax benefits as a
    result of tax positions taken during the current year


(36
)


-Reductions resulting from the lapse of applicable statutes of
    limitations


-



(275
)Unrecognized tax benefits

$
9,219


$
9,255     16.
    COMMITMENTS
    AND CONTINGENCIES  Contractual
    Obligations.
    Transportationand Processing


Drilling Rig


Operating


PurchaseContracts
    (1)


Contracts
    (2)


Leases
    (3)


Obligations
    (4)(In thousands)2010

$
43,909


$
45,519


$
2,678


$
19,5542011


56,356



32,420



2,271



5,2732012


80,905



17,876



1,363



-2013


101,121



791



640



-2014


79,391



-



558



-Thereafter


267,434



-



418



-Total

$
629,116


$
96,606


$
7,928


$
24,827   (1)
    Under contracts with various pipeline companies, we are
    obligated to provide minimum daily natural gas volumes for
    transport or processing, as calculated on a monthly basis, or
    pay for any deficiencies at a specified reservation fee rate.
    Our available production committed to the pipelines and
    processing plants is expected to meet, or exceed, the daily
    volumes required under the contracts.(2)
    We lease drilling rigs from third parties for use in our
    development and exploration programs.  The outstanding drilling
    rig contracts require payment of a specified day rate ranging
    from $20,500 to $26,500 for the entire lease term regardless of
    our utilization of the drilling rigs.(3)
    We lease office buildings and other property under operating
    leases.  Rent expense for operating leases with terms exceeding
    one month was $4.1 million in 2009, $5.0 million in
    2008 and $5.2 million in 2007. 84




---



##### Table of Contents



(4)
    At December 31, 2009, we and KGS were under contract to
    purchase goods and services related to field operations and gas
    processing plant operations.  KGS obligations totaled
    $7.4 million.  Commitments
    Contingencies
  10-year
       85




---



##### Table of Contents



Environmental
    Compliance
    17.
    NONCONTROLLING
    INTERESTS AND KGS      KGS OwnershipQuicksilver


Third Parties


TotalGeneral partner interests


1.7
%


-



1.7
%Limited partner interests:Common interests


20.1
%


37.5
%


57.6
%Subordinated interests


40.7
%


-



40.7
%Total interests


62.5
%


37.5
%


100.0
%     18.
    EARNINGS
    PER SHARE    86




---



##### Table of Contents



Years Ended December 31,2009


2008


2007(In thousands, except per share data)Net income (loss)

$
(557,473
)

$
(378,276
)

$
475,390Impact of assumed conversions  interest on 1.875%
    convertible debentures, net of income taxes


-



-



6,056Income (loss) available to stockholders assuming conversion of
    convertible debentures

$
(557,473
)

$
(378,276
)

$
481,446Weighted average common shares  basic


169,004



162,004



156,517Effect of dilutive securities
    (1):Employee stock options


-



-



1,326Employee stock awards


-



-



370Contingently convertible debentures


-



-



9,816Weighted average common shares  diluted


169,004



162,004



168,029Earnings (loss) per common share  basic

$
(3.30
)

$
(2.33
)

$
3.04Earnings (loss) per common share  diluted

$
(3.30
)

$
(2.33
)

$
2.87   (1)
    For 2009 and 2008, the effects of convertible debt of
    9.8 million shares and stock options and unvested
    restricted stock units representing 0.8 million shares and
    0.9 million, respectively were antidilutive and, therefore,
    excluded from the diluted share calculations.  No outstanding
    options were excluded from the diluted net income per share
    calculation for the year ended December 31, 2007.  19.
    QUICKSILVER
    STOCKHOLDERS EQUITY  Common
    Stock, Preferred Stock and Treasury Stock
      Common


TreasuryShares Issued


Shares HeldOpening balance at January 1, 2007


157,783,515



2,579,671Stock options exercised


2,257,840



-Restricted stock activity


591,915



37,055Balance at December 31, 2008


160,633,270



2,616,726Stock issuance


10,400,468



-Stock repurchase


-



1,885,600Stock options exercised


249,732



-Restricted stock activity


459,229



70,469Balance at December 31, 2008


171,742,699



4,572,795Stock options exercised


610,000



-Restricted stock activity


2,117,137



131,653Balance at December 31, 2009


174,469,836



4,704,448   Quicksilver
    Stockholder Rights Plan
   87




---



##### Table of Contents



two-for-one
        Stock-Based
    Compensation
  2006
    Equity Plan
    Stock
    Options
    2009


2008


2007Wtd avg grant date fair value

$
6.21


$
13.67



N/AWtd avg grant date


Jan 2, 2009



Jan 2, 2008



N/AWtd avg risk-free interest rate


1.90
%


3.41
%


N/AExpected life (in years)


6.0



6.0



N/AWtd avg volatility


56.76
%


40.2
%


N/AExpected dividends


-



-



N/A  88




---



##### Table of Contents



Wtd Avg


Wtd AvgExercise


Remaining


AggregateShares


Price


Contractual Life


Intrinsic Value(In thousands)Outstanding at January 1, 2009


1,103,336


$
14.20Granted


2,605,699



6.21Exercised


(610,000
)


6.63Cancelled


(84,594
)


8.84Outstanding at December 31, 2009


3,014,441


$
8.97



8.5


$
23,486Exercisable at December 31, 2009


372,219


$
13.98



5.4


$
2,170       Restricted
    Stock
    Payable in shares


Payable in cashWtd Avg





Wtd AvgGrant Date





Grant DateShares


Fair Value


Shares


Fair ValueOutstanding at January 1, 2009


1,336,111


$
24.01



-


$
-Granted


2,279,679



6.28



339,835



6.22Vested


(730,373
)


22.20



-



-Cancelled


(162,542
)


14.12



(11,140
)


6.22Outstanding at December 31, 2009


2,722,875


$
10.33



328,695


$
6.22     KGS
    Restricted Phantom Units
   89




---



##### Table of Contents



Payable in units


Payable in cashWtd Avg





Wtd AvgGrant Date





Grant DateShares


Fair Value


Shares


Fair ValueOutstanding at January 1, 2009


139,918


$
25.15



60,319


$
21.63Granted


(49,789
)


25.25



(26,526
)


13.79Vested


405,428



10.06



5,420



16.65Cancelled


(9,885
)


15.90



(5,973
)


21.36Outstanding at December 31, 2009


485,672


$
12.73



33,240


$
27.12     20.
    CONDENSED
    CONSOLIDATING FINANCIAL INFORMATION    Guarantor Subsidiaries -

Non-Guarantor SubsidiariesRestricted

Restricted

UnrestrictedCowtown Pipeline Funding, Inc.

Quicksilver Resources Canada, Inc.

Quicksilver Gas Services Holdings LLCCowtown Pipeline Management, Inc.

Mercury Michigan, Inc.
    (1)

Quicksilver Gas Services GP LLCCowtown Pipeline L.P.

Terra Energy Ltd.
    (1)

Quicksilver Gas Services LPCowtown Gas Processing L.P.

GTG Pipeline Corporation
    (1)

Quicksilver Gas Services Operating LLC
    (4)Terra Pipeline Company
    (1)

Quicksilver Gas Services Operating GP LLC
    (4)Beaver Creek Pipeline, LLC
    (1)

Cowtown Pipeline Partners
    L.P. (4)Quicksilver Resources Horn River Inc.
    (2)

Cowtown Gas Processing Partners L.P.
    (4)Cowtown Drilling Inc.
    (3)   (1)
    Prior to the sale of our Northeast Operations in November 2007,
    these entities were restricted guarantor subsidiaries.  After
    the sale, they have been reclassified to restricted
    non-guarantor subsidiaries for all periods presented.(2)
    This entity was amalgamated into Quicksilver Resources Canada
    Inc. on January 1, 2009.(3)
    This entity was dormant for the three-year period ended
    December 31, 2009.(4)
    Each entity is a wholly owned subsidiary of and consolidated
    into KGS.   90




---



##### Table of Contents




    incurring additional indebtedness;
    paying dividends;
    selling assets;
    making investments; and
    making restricted payments.      Condensed
    Consolidating Balance Sheets
  December 31, 2009Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor


Consolidating


Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)ASSETSCurrent assets

$
313,485


$
394


$
42,622


$
(121,580
)

$
234,921


$
2,268


$
(17,251
)

$
219,938Property and equipment


1,980,053



217,407



491,528



-



2,688,988



396,952



-



3,085,940Investment in subsidiaries (equity method)


549,200



149,945



-



(436,437
)


262,708



-



(149,945
)


112,763Other assets


235,304



-



3,112



-



238,416



9,067



(53,242
)


194,241Total assets

$
3,078,042


$
367,746


$
537,262


$
(558,017
)

$
3,425,033


$
408,287


$
(220,438
)

$
3,612,882LIABILITIES AND EQUITYCurrent liabilities

$
349,415


$
120,302


$
25,321


$
(121,580
)

$
373,458


$
10,453


$
(17,251
)

$
366,660Long-term liabilities


2,092,629



13,108



309,840



-



2,415,577



187,065



(53,242
)


2,549,400Quicksilver stockholders equity


635,998



234,336



202,101



(436,437
)


635,998



149,945



(149,945
)


635,998Noncontrolling interests


-



-



-



-



-



60,824



-



60,824Total liabilities and equity

$
3,078,042


$
367,746


$
537,262


$
(558,017
)

$
3,425,033


$
408,287


$
(220,438
)

$
3,612,882   December 31, 2008Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor


Consolidating


Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)ASSETSCurrent assets

$
424,862


$
163


$
102,384


$
(123,071
)

$
404,338


$
2,439


$
(13,441
)

$
393,336Property and equipment


2,756,915



1,774



550,906



-



3,309,595



432,272



55,848



3,797,715Assets of discontinued operations


-



-



-



-



-



56,022



(56,022
)


-Investment in subsidiaries (equity method)


513,706



79,316



-



(363,203
)


229,819



-



(79,316
)


150,503Other assets


206,099



123,298



910



-



330,307



1,916



(175,569
)


156,654Total assets

$
3,901,582


$
204,551


$
654,200


$
(486,274
)

$
4,274,059


$
492,649


$
(268,500
)

$
4,498,208LIABILITIES AND EQUITYCurrent liabilities

$
357,077


$
122,677


$
44,907


$
(123,071
)

$
401,590


$
27,183


$
(10,274
)

$
418,499Long-term liabilities


2,359,679



-



327,964



-



2,687,643



299,111



(118,608
)


2,868,146Liabilities of discontinued operations


-



-



-



-



-



60,302



(60,302
)


-Quicksilver stockholders equity


1,184,826



81,874



281,329



(363,203
)


1,184,826



79,316



(79,316
)


1,184,826Noncontrolling interests


-



-



-



-



-



26,737



-



26,737Total liabilities and equity

$
3,901,582


$
204,551


$
654,200


$
(486,274
)

$
4,274,059


$
492,649


$
(268,500
)

$
4,498,208  91




---



##### Table of Contents



Condensed
    Consolidating Statements of Income
  For The Year Ended December 31, 2009Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor


Consolidated


Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)Revenue

$
634,321


$
4,395


$
188,769


$
(2,014
)

$
825,471


$
91,706


$
(84,442
)

$
832,735Operating expense


1,202,124



9,413



273,969



(2,014
)


1,483,492



47,610



(84,494
)


1,446,608Equity in net earnings of subsidiaries


(52,643
)


27,161



-



52,643



27,161



-



(27,161
)


-Operating income (loss)


(620,446
)


22,143



(85,200
)


52,643



(630,860
)


44,096



(27,109
)


(613,873
)Income from earnings of BBEP


75,444



-



-



-



75,444



-



-



75,444Impairment of investment in BBEP


(102,084
)


-



-



-



(102,084
)


-



-



(102,084
)Interest expense and other


(180,980
)


3,725



(8,526
)


-



(185,781
)


(8,518
)


(2,044
)


(196,343
)Income tax (expense) benefit


270,593



(9,054
)


24,269



-



285,808



5,809



-



291,617Discontinued operations


-



-



-



-



-



(1,992
)


1,992



-Net income (loss)

$
(557,473
)

$
16,814


$
(69,457
)

$
52,643


$
(557,473
)

$
39,395


$
(27,161
)

$
(545,239
)Net income attributable to noncontrolling interests


-



-



-



-



-



(12,234
)


-



(12,234
)Net income (loss) attributable to Quicksilver

$
(557,473
)

$
16,814


$
(69,457
)

$
52,643


$
(557,473
)

$
27,161


$
(27,161
)

$
(557,473
)   For The Year Ended December 31, 2008Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor





Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)Revenue

$
600,906


$
514


$
187,126


$
(426
)

$
788,120


$
76,084


$
(63,563
)

$
800,641Operating expense


976,984



11,157



86,937



(426
)


1,074,652



38,659



(62,973
)


1,050,338Equity in net earnings of subsidiaries


74,331



21,762



-



(74,331
)


21,762



-



(21,762
)


-Operating income (loss)


(301,747
)


11,119



100,189



(74,331
)


(264,770
)


37,425



(22,352
)


(249,697
)Income from earnings of BBEP


93,298



-



-



-



93,298



-



-



93,298Impairment of investment in BBEP


(320,387
)


-



-



-



(320,387
)


-



-



(320,387
)Interest expense and other


(89,657
)


6,023



(14,491
)


-



(98,125
)


(8,426
)


(1,740
)


(108,291
)Income tax (expense) benefit


240,217



(6,000
)


(22,509
)


-



211,708



(253
)


-



211,455Discontinued operations


-



-



-



-



-



(2,330
)


2,330



-Net income (loss)

$
(378,276
)

$
11,142


$
63,189


$
(74,331
)

$
(378,276
)

$
26,416


$
(21,762
)

$
(373,622
)Net income attributable to noncontrolling interests


-



-



-



-



-



(4,654
)


-



(4,654
)Net income (loss) attributable to Quicksilver

$
(378,276
)

$
11,142


$
63,189


$
(74,331
)

$
(378,276
)

$
21,762


$
(21,762
)

$
(378,276
)   For The Year Ended December 31, 2007Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor





Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)Revenue

$
367,894


$
-


$
187,154


$
(160
)

$
554,888


$
35,695


$
(29,325
)

$
561,258Operating expense


241,174



601



88,517



(160
)


330,132



22,513



(29,123
)


323,522Income from equity affiliates


14



-



647



-



661



-



-



661Gain on sale of properties


628,709



-



-



-



628,709



-



-



628,709Loss on natural gas supply contracts


(63,525
)


-



-



-



(63,525
)


-



-



(63,525
)Equity in net earnings of subsidiaries


73,468



7,407



-



(73,468
)


7,407



-



(7,407
)


-Operating income (loss)


765,386



6,806



99,284



(73,468
)


798,008



13,182



(7,609
)


803,581Interest expense and other


(56,212
)


2,609



(14,776
)


-



(68,379
)


(4,021
)


(375
)


(72,775
)Income tax (expense) benefit


(233,784
)


(3,228
)


(17,036
)


-



(254,048
)


(313
)


-



(254,361
)Discontinued operations


-



-



-



-



-



(592
)


592



-Net income (loss)

$
475,390


$
6,187


$
67,472


$
(73,468
)

$
475,581


$
8,256


$
(7,392
)

$
476,445Net income attributable to noncontrolling interests


-



(191
)


-



-



(191
)


(864
)


-



(1,055
)Net income (loss) attributable to Quicksilver

$
475,390


$
5,996


$
67,472


$
(73,468
)

$
475,390


$
7,392


$
(7,392
)

$
475,390  92




---



##### Table of Contents



Condensed
    Consolidating Statements of Cash Flows
  For The Year Ended December 31, 2009Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor





Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)Net cash flow provided by operating activities

$
358,342


$
73,202


$
148,280


$
-


$
579,824


$
68,133


$
(35,717
)

$
612,240Purchases of property, plant and equipment


(474,659
)


(73,202
)


(94,209
)


-



(642,070
)


(54,818
)


3,050



(693,838
)Proceeds from sales of property, plant and equipment


220,206



-



768



-



220,974



-



-



220,974Net cash flow used for investing activities


(254,453
)


(73,202
)


(93,441
)


-



(421,096
)


(54,818
)


3,050



(472,864
)Issuance of debt


1,305,137



-



59,590



-



1,364,727



56,000



-



1,420,727Repayments of debt


(1,428,105
)


-



(116,025
)


-



(1,544,130
)


(105,500
)


-



(1,649,630
)Debt issuance costs


(29,901
)


-



(1,125
)


-



(31,026
)


(1,446
)


-



(32,472
)Repayments to parent


-



-



-



-



-



(5,645
)


5,645



-Gas Purchase Commitment  net


44,119



-



-



-



44,119



-



-



44,119Issuance of KGS common units






-



-



-



-



80,729



-



80,729Distributions to parent






-



-



-



-



(27,022
)


27,022



-Distributions to noncontrolling interests


-



-



-



-



-



(9,925
)


-



(9,925
)Proceeds from exercise of stock options


4,046



-



-



-



4,046



-



-



4,046Purchase of treasury stock


(922
)


-



-



-



(922
)


-



-



(922
)Other


63



-



-



-



63



(63
)


-



-Net cash flow provided by (used for) financing activities


(105,563
)


-



(57,560
)


-



(163,123
)


(12,872
)


32,667



(143,328
)Effect of exchange rates on cash


-



-



2,889



-



2,889



-



-



2,889Net decrease in cash and equivalents


(1,674
)


-



168



-



(1,506
)


443



-



(1,063
)Cash and equivalents at beginning of period


1,679



-



866



-



2,545



303



-



2,848Cash and equivalents at end of period

$
5


$
-


$
1,034


$
-


$
1,039


$
746


$
-


$
1,785   For The Year Ended December 31, 2008Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor





Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)Net cash flow provided by operations

$
290,160


$
-


$
137,005


$
-


$
427,165


$
52,683


$
(23,282
)

$
456,566Purchases of property, plant and equipment


(1,995,791
)


-



(136,057
)


-



(2,131,848
)


(148,079
)


-



(2,279,927
)Proceeds from sale of equipment to subsidiaries


42,914



-



-



-



42,914



-



(42,914
)


-Proceeds from sales of property, plant and equipment


721



-



618



-



1,339



-



-



1,339Net cash flow used for investing activities


(1,952,156
)


-



(135,439
)


-



(2,087,595
)


(148,079
)


(42,914
)


(2,278,588
)Issuance of debt


2,570,611



-



208,161



-



2,778,772



169,900



-



2,948,672Repayments of debt


(886,429
)


-



(209,734
)


-



(1,096,163
)


-



-



(1,096,163
)Debt issuance costs


(24,733
)


-



-



-



(24,733
)


(486
)


-



(25,219
)Payments to parent


-



-



-



-



-



(42,914
)


42,914



-Distributions to parent


-



-



-



-



-



(23,282
)


23,282



-Distributions to noncontrolling interests


-



-



-



-



-



(8,644
)


-



(8,644
)Proceeds from exercise of stock options


1,244



-



-



-



1,244



-



-



1,244Purchase of treasury stock


(23,137
)


-



-



-



(23,137
)


-



-



(23,137
)Net cash flow provided by (used for) financing activities


1,637,556



-



(1,573
)


-



1,635,983



94,574



66,196



1,796,753Effect of exchange rates on cash


(893
)


-



784



-



(109
)


-



-



(109
)Net decrease in cash and equivalents


(25,333
)


-



777



-



(24,556
)


(822
)


-



(25,378
)Cash and equivalents at beginning of period


27,012



-



89



-



27,101



1,125



-



28,226Cash and equivalents at end of period

$
1,679


$
-


$
866


$
-


$
2,545


$
303


$
-


$
2,848   93




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##### Table of Contents



For The Year Ended December 31, 2007Restricted


Restricted


Restricted


Quicksilver


Unrestricted





QuicksilverQuicksilver


Guarantor


Non-Guarantor


Subsidiary


and Restricted


Non-Guarantor





Resources Inc.Resources Inc.


Subsidiaries


Subsidiaries


Eliminations


Subsidiaries


Subsidiaries


Eliminations


Consolidated(In thousands)Net cash flow provided by operations

$
190,777


$
(596
)

$
116,935


$
-


$
307,116


$
14,949


$
(2,961
)

$
319,104Purchases of property, plant and equipment


(824,321
)


(267
)


(151,807
)


-



(976,395
)


(73,797
)


29,508



(1,020,684
)Investment in subsidiaries and affiliates


(38,908
)


-



-



-



(38,908
)


-



38,908



-Return on investment in subsidiaries and affiliates


121,577



-



171



-



121,748



-



(112,113
)


9,635Proceeds from sales of property, plant and equipment


741,297



-



-



-



741,297



-



-



741,297Net cash flow used for investing activities


(355
)


(267
)


(151,636
)


-



(152,258
)


(73,797
)


(43,697
)


(269,752
)Issuance of debt


594,500



-



218,321



-



812,821



5,000



-



817,821Repayments of debt


(777,866
)


-



(190,691
)


-



(968,557
)


-



-



(968,557
)Debt issuance costs


(3,148
)


-



(664
)


-



(3,812
)


(1,318
)


-



(5,130
)Proceeds from sale of KGS units, net


-



-



-



-



-



109,642



-



109,642Contributions from noncontrolling interests


-



-



-



-



-



167



-



167Contributions from parent


-



863



-



-



863



67,553



(68,416
)


-Distributions to parent


-



-



-



-



-



(115,074
)


115,074



-Distributions to noncontrolling interests


-



-



-



-



-



(8,794
)


-



(8,794
)Proceeds from exercise of stock options


21,387



-



-



-



21,387



-



-



21,387Excess tax benefits on exercise of stock options


2,755



-



-



-



2,755



-



-



2,755Purchase of treasury stock


(1,567
)


-



-



-



(1,567
)


-



-



(1,567
)Net cash flow provided by (used for) financing activities


(163,939
)


863



26,966



-



(136,110
)


57,176



46,658



(32,276
)Effect of exchange rates on cash


446



-



5,423



-



5,869



-



-



5,869Net decrease in cash and equivalents


26,929



-



(2,312
)


-



24,617



(1,672
)


-



22,945Cash and equivalents at beginning of period


83



-



2,401



-



2,484



2,797



-



5,281Cash and equivalents at end of period

$
27,012


$
-


$
89


$
-


$
27,101


$
1,125


$
-


$
28,226   21.
    SEGMENT
    INFORMATION    94




---



##### Table of Contents



Exploration & Production


Processing &








QuicksilverUnited States


Canada


Gathering


Corporate


Elimination


Consolidated(In thousands)2009Revenue

$
634,321


$
188,770


$
99,817


$
-


$
(90,173
)

$
832,735DD&A


134,066



38,965



26,682



1,674



-



201,387Impairment related to oil and gas properties


786,867



192,673



-



-



-



979,540Operating income (loss)


(500,164
)


(81,529
)


46,737



(78,917
)


-



(613,873
)Investment in equity affiliates


112,763



-



-



-



-



112,763Property, plant and equipment  net


1,968,430



491,528



614,359



11,623



-



3,085,940Property and equipment costs incurred


391,916



91,949



115,655



2,161



-



601,6812008Revenue

$
600,292


$
187,740


$
78,572


$
-


$
(65,963
)

$
800,641DD&A


127,010



44,948



15,134



1,104



-



188,196Impairment related to oil and gas properties


624,315



-



9,200



-



-



633,515Operating income


(321,756
)


104,131



34,879



(66,951
)


-



(249,697
)Investment in equity affiliates


150,503



-



-



-



-



150,503Property, plant and equipment  net


2,716,754



550,413



519,447



11,101



-



3,797,715Property and equipment costs incurred


2,173,469



138,360



265,222



7,984



-



2,585,0352007Revenue

$
396,768


$
158,121


$
35,941


$
-


$
(29,572
)

$
561,258DD&A


72,132



39,445



8,146



974



-



120,697Operating income


750,703



85,155



12,380



(44,657
)


-



803,581Investment in equity affiliates


420,171



-



-



-



-



420,171Property, plant and equipment  net


1,290,728



571,496



275,807



4,315



-



2,142,346Property and equipment costs incurred


758,601



115,073



168,523



2,017



-



1,044,214  95




---



##### Table of Contents



22.
    SUPPLEMENTAL
    CASH FLOW INFORMATION    Years Ended December 31,2009


2008


2007(In thousands)Interest

$
128,217


$
83,400


$
69,038Income taxes


(41,267
)


49,433



-     Years Ended December 31,2009


2008


2007(In thousands)Working capital related to capital expenditures

$
118,294


$
230,624


$
159,819Issuance of common stock as consideration for the Alliance
    Acquisition


-



262,092



-Noncash acquisition of interest in BBEP earnings


-



-



429,618Tax benefit recognized on employee stock option exercises


-



-



2,755   23.
    EMPLOYEE
    BENEFITS        24.
    RELATED
    PARTY TRANSACTIONS       96




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##### Table of Contents



97




---



##### Table of Contents



SUPPLEMENTAL
    SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)  Form 10-K.
  Quarter EndedMarch 31


June 30


September 30


December 31(In thousands, except per share data)2009
    (1)(2)(3)Operating revenues

$
185,932


$
206,041


$
206,657


$
234,105Operating income (loss)


(825,692
)


10,573



103,703



97,543Net income (loss)


(567,309
)


(20,450
)


2,159



34,154Net income (loss) attributable to Quicksilver


(568,979
)


(21,762
)


730



32,538Basic net earnings (loss) per share

$
(3.37
)

$
(0.13
)

$
-


$
0.19Diluted net earnings (loss) per share


(3.37
)


(0.13
)


-



0.192008
    (4)Operating revenues

$
157,617


$
197,901


$
236,262


$
208,861Operating income (loss)


70,723



107,103



119,990



(547,513
)Net income (loss)


41,642



52,323



(2,630
)


(464,957
)Net income (loss) attributable to Quicksilver


41,134



51,335



(3,755
)


(466,990
)Basic net earnings (loss) per share

$
0.26


$
0.32


$
(0.02
)

$
(2.79
)Diluted net earnings (loss) per share


0.25



0.31



(0.02
)


(2.79
)    (1)

    
    Operating loss for the first quarter of 2009 includes a charge
    of $896.5 million for the impairment of our U.S. and
    Canadian oil and gas properties.  Net loss for the
    first quarter of 2009 also includes $102.1 million for
    pre-tax income attributable to our proportionate ownership of
    BBEP and a pre-tax charge of $102.1 million for impairment
    of the related investment, respectively.(2)

    
    Operating income for the second quarter of 2009 includes a
    charge of $70.6 million for the impairment of our Canadian
    oil and gas properties.  Net loss for the second
    quarter of 2009 also includes $19.0 million of pre-tax
    income attributable to our proportionate ownership of BBEP.(3)

    
    Operating income for the fourth quarter of 2009 includes a
    charge of $12.4 million for the impairment of our Canadian
    oil and gas properties.  Net income for the fourth
    quarter of 2009 also includes $1.9 million pre-tax loss
    attributable to our proportionate ownership of BBEP.(4)

    
    Operating loss for the fourth quarter of 2008 includes a charge
    of $633.5 million for the impairment of our U.S. oil and
    gas properties.  Net loss for the fourth quarter of
    2008 also includes $93.3 million for pre-tax income
    attributable to our proportionate ownership of BBEP and a
    pre-tax charge of $320.4 million for impairment of the
    related investment, respectively. 98




---



##### Table of Contents



SUPPLEMENTAL
    OIL AND GAS INFORMATION (UNAUDITED)  12-month first-day-of-the-month 12-month
      Consolidated
    Quicksilver (Excluding BBEP Reserves)
    Natural Gas (MMcf)


NGL (MBbl)


Oil (MBbl)United








United








UnitedStates


Canada


Total


States


Canada


Total


States


Canada


TotalDecember 31, 2006


933,342



308,335



1,241,677



47,985



16



48,001



6,315



-



6,315Revisions
    (5)


(30,494
)


17,761



(12,733
)


1,112



(1
)


1,111



633



-



633Extensions and discoveries
    (4)


302,098



24,463



326,561



46,571



-



46,571



658



-



658Sales in place
    (1)


(503,651
)


(1,446
)


(505,097
)


(3,147
)


-



(3,147
)


(3,947
)


-



(3,947
)Production


(38,887
)


(20,732
)


(59,619
)


(2,466
)


(5
)


(2,471
)


(584
)


-



(584
)December 31, 2007


662,408



328,381



990,789



90,055



10



90,065



3,075



-



3,075Revisions
    (5)


(171,009
)


4,923



(166,086
)


(25,596
)


-



(25,596
)


(106
)


-



(106
)Extensions and discoveries
    (4)


560,205



22,363



582,568



31,662



-



31,662



428



-



428Purchases in place
    (2)


299,952



-



299,952



-



-



-



-



-



-Sales in place


-



(27
)


(27
)


-



-



-



-



-



-Production


(45,059
)


(23,069
)


(68,128
)


(4,194
)


(2
)


(4,196
)


(483
)


-



(483
)December 31, 2008


1,306,497



332,571



1,639,068



91,927



8



91,935



2,914



-



2,914Revisions
    (5)


(28,833
)


(67,207
)


(96,040
)


(4,178
)


7



(4,171
)


205



1



206Extensions and discoveries
    (4)


460,214



12,153



472,367



15,487



-



15,487



165



-



165Purchases in place


314



-



314



-



-



-



-



-



-Sales in place
    (3)


(120,539
)


(44
)


(120,583
)


-



-



-



-



-



-Production


(61,619
)


(24,420
)


(86,039
)


(4,975
)


(2
)


(4,977
)


(425
)


(1
)


(426
)December 31, 2009


1,556,034



253,053



1,809,087



98,261



13



98,274



2,859



-



2,859Proved developed reservesDecember 31, 2007


379,917



260,029



639,946



50,738



10



50,748



2,763



-



2,763December 31, 2008


756,191



278,668



1,034,859



56,181



8



56,189



2,509



-



2,509December 31, 2009


1,044,140



223,300



1,267,440



60,997



13



61,010



2,467



-



2,467Proved undeveloped reservesDecember 31, 2007


282,491



68,352



350,843



39,317



-



39,317



312



-



312December 31, 2008


550,306



53,903



604,209



35,746



-



35,746



405



-



405December 31, 2009


511,894



29,753



541,647



37,264



-



37,264



392



-



392  99




---



##### Table of Contents



(1)

    
    Sales of reserves in place during 2007 relate principally to the
    BreitBurn Transaction, which is more fully described in
    Note 5 to our consolidated financial statements.(2)

    
    Purchases of reserves in place during 2008 relate principally to
    the Alliance Transaction, which is more fully described in
    Note 4 to our consolidated financial statements.(3)

    
    Sales of reserves in place during 2009 relate principally to the
    Eni Transaction, which is more fully described in Note 3 to
    our consolidated financial statements.(4)

    
    Extensions and discoveries for each period presented represent
    extensions to reserves attributable to additional drilling
    activity subsequent to discovery.  U.S. extensions and
    discoveries for:  
    2009 are 99% attributable to the Barnett Shale (of which 42%
    were proved developed);
    2008 are 100% attributable to the Barnett Shale (of which 49%
    were proved developed); and
    2007 are 96% attributable to the Barnett Shale (of which 49%
    were proved developed) and 4% were attributable to the Northeast
    Operations (which were all derecognized pursuant to the
    BreitBurn Transaction).    (5)
    
    Revisions for each period presented reflect upward (downward)
    changes in previous estimates attributable to new information
    gained primarily from development drilling activity and
    production history.  Revisions include
    132,846 MMcfe, (166,198) MMcfe and (55,584) MMcfd for such
    matters in 2009, 2008 and 2007,
    respectively.  Revisions also include changes in
    previous estimates due to changes in sales
    price.  Revisions include (251,676) MMcfe, (154,100)
    MMcfe, and 53,315 MMcfe for such sales price changes in
    2009, 2008 and 2007.    United States


Canada


Consolidated(In thousands)2009Proved properties

$
3,218,796


$
728,880


$
3,947,676Unevaluated properties


340,707



117,330



458,037Accumulated DD&A


(1,670,923
)


(396,546
)


(2,067,469
)Net capitalized costs

$
1,888,580


$
449,664


$
2,338,2442008Proved properties

$
3,068,326


$
553,505


$
3,621,831Unevaluated properties


462,943



80,590



543,533Accumulated DD&A


(902,281
)


(120,475
)


(1,022,756
)Net capitalized costs

$
2,628,988


$
513,620


$
3,142,6082007Proved properties

$
1,231,109


$
580,186


$
1,811,295Unevaluated properties


163,274



51,954



215,228Accumulated DD&A


(157,122
)


(105,001
)


(262,123
)Net capitalized costs

$
1,237,261


$
527,139


$
1,764,400  100




---



##### Table of Contents



United States


Canada


Consolidated(In thousands)2009Proved acreage

$
118


$
-


$
118Unproved acreage


11,300



2,658



13,958Development costs


341,658



24,179



365,837Exploration costs


32,798



59,402



92,200Total

$
385,874


$
86,239


$
472,1132008Proved acreage

$
787,172


$
-


$
787,172Unproved acreage


484,770



54,048



538,818Development costs


836,032



68,629



904,661Exploration costs


30,161



10,280



40,441Total

$
2,138,135


$
132,957


$
2,271,0922007Proved acreage

$
-


$
-


$
-Unproved acreage


17,031



31,448



48,479Development costs


648,632



67,608



716,240Exploration costs


75,862



11,953



87,815Total

$
741,525


$
111,009


$
852,534  101




---



##### Table of Contents



United States


Canada


Consolidated(In thousands)2009Natural gas, NGL and oil revenue

$
608,013


$
188,685


$
796,698Oil & gas production expense


112,935



38,661



151,596Depletion & amortization expense


127,888



33,783



161,671Impairment related to oil and gas properties


786,867



192,673



979,540(419,677
)


(76,432
)


(496,109
)Income tax expense (benefit)


(146,887
)


(22,165
)


(169,052
)Results from producing activities

$
(272,790
)

$
(54,267
)

$
(327,057
)2008Natural gas, NGL and oil revenue

$
597,889


$
182,899


$
780,788Oil & gas production expense


114,374



38,662



153,036Depletion & amortization expense


120,845



40,337



161,182Impairment related to oil and gas properties


624,315







624,315(261,645
)


103,900



3,437Income tax expense (benefit)


(91,576
)


30,131



(61,445
)Results from producing activities

$
(170,069
)

$
73,769


$
64,8822007Natural gas, NGL and oil revenue

$
392,841


$
152,248


$
545,089Oil & gas production expense


119,630



33,521



153,151Depletion & amortization expense


65,701



35,330



101,031207,510



83,397



290,907Income tax expense


72,629



24,185



96,814Results from producing activities

$
134,881


$
59,212


$
194,093     12-month first-day-of-the-month
 102




---



##### Table of Contents



At December 31,2009


2008
    (1)


2007
    (1)Natural gas  Henry Hub

$
3.87


$
5.71


$
6.80Natural gas  AECO


3.76



5.44



6.35NGL  Mont Belvieu, Texas


24.94



21.65



57.35Oil  WTI Cushing


61.18



44.60



95.98   (1)

    
    The prices used for all 2008 and 2007 proved reserve estimates
    were year-end spot prices, which were previously required by
    guidance from the SEC and FASB then in
    effect.  Additional information regarding the change
    during 2009 for reserve recognition guidance is included in
    Note 2 to our consolidated financial statements.      United States


Canada


Total(In thousands)December 31, 2009Future revenues

$
7,787,422


$
916,765


$
8,704,187Future production costs


(4,169,783
)


(403,874
)


(4,573,657
)Future development costs


(938,675
)


(93,588
)


(1,032,263
)Future income taxes


(222,576
)


(47,125
)


(269,701
)Future net cash flows


2,456,388



372,178



2,828,56610% discount


(1,492,469
)


(153,418
)


(1,645,887
)Standardized measure of discounted future cash flows relating to
    proved reserves

$
963,919


$
218,760


$
1,182,679December 31, 2008Future revenues

$
8,783,936


$
1,764,268


$
10,548,204Future production costs


(4,162,737
)


(551,395
)


(4,714,132
)Future development costs


(1,140,466
)


(113,800
)


(1,254,266
)Future income taxes


(504,753
)


(215,212
)


(719,965
)Future net cash flows


2,975,980



883,861



3,859,84110% discount


(1,623,862
)


(441,717
)


(2,065,579
)Standardized measure of discounted future cash flows relating to
    proved reserves

$
1,352,118


$
442,144


$
1,794,262 103




---



##### Table of Contents



United States


Canada


Total(In thousands)December 31, 2007Future revenues

$
9,566,791


$
2,037,478


$
11,604,269Future production costs


(3,286,618
)


(675,890
)


(3,962,508
)Future development costs


(651,802
)


(156,289
)


(808,091
)Future income taxes


(1,772,021
)


(228,883
)


(2,000,904
)Future net cash flows


3,856,350



976,416



4,832,76510% discount


(2,168,150
)


(495,413
)


(2,663,562
)Standardized measure of discounted future cash flows relating to
    proved reserves

$
1,688,200


$
481,003


$
2,169,203     Years Ended December 31,2009


2008


2007(In thousands)Sales of oil and gas net of production costs

$
(645,102
)

$
(628,333
)

$
(392,116
)Net changes in price and production cost


(715,484
)


(2,368,940
)


1,048,432Extensions and discoveries


561,544



1,630,418



1,045,296Development costs incurred


205,781



373,124



170,686Changes in estimated future development costs


81,754



(413,097
)


(234,649
)Purchase and sale of reserves, net


(144,279
)


722,662



(1,010,263
)Revision of estimates


(248,681
)


(618,527
)


(8,090
)Accretion of discount


192,325



324,064



196,275Net change in income taxes


196,691



509,854



(293,374
)Timing and other differences


(96,132
)


93,834



161,181Net increase (decrease)

$
(611,583
)

$
(374,941
)

$
683,378  104




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##### Table of Contents



Quicksilver
    Share of BBEP Reserves
  Rule 3-09.
    For The Years Ended December 31,2009


2008


2007Total


Gas


Oil


Total


Gas


Oil


Total


Gas


Oil(Mboe)


(MMcf)


(MBbl)


(Mboe)


(MMcf)


(MBbl)


(Mboe)


(MMcf)


(MBbl)Beginning balance


42,038



189,176



9,471



45,314



160,864



17,465











Revision of previous estimates


6,191



(4,203
)


6,891



(12,903
)


(6,591
)


(11,805
)










Extensions, discoveries and other additions


























38







38Purchase of reserves in place
    (1)














12,389



43,982



5,060



46,238



162,181



18,169Sale of reserves in place
    (1)


(566
)


(543
)


(476
)






















Production


(2,636
)


(8,561
)


(1,209
)


(2,762
)


(9,079
)


(1,249
)


(962
)


(1,317
)


(742
)Ending balance


45,027



175,869



14,677



42,038



189,176



9,471



45,314



160,864



17,465Proved developed reservesBeginning balance


38,791



175,933



9,469



40,877



145,696



16,595











Ending balance


40,846



161,491



13,931



38,791



175,933



9,469



40,877



145,696



16,595Proved undeveloped reservesBeginning balance


3,247



13,244



1,040



4,437



15,169



1,908











Ending balance


4,180



14,378



1,784



3,247



13,244



1,040



4,437



15,169



1,908     Years Ended December 31,2009
    (2)


2008
    (3)


2007
    (3)Representative prices:Natural gas  Henry Hub

$
3.87


$
5.71


$
6.80Oil  WTI Cushing


61.18



44.60



95.95   (1)

    
    Amounts are included as needed to reconcile Quicksilvers
    portion of beginning reserves to ending reserves that result
    from changes in Quicksilvers proportionate ownership of
    BBEP.(2)

    
    Prices used for 2009 proved reserve estimates were the
    unweighted average of the preceding
    12-month
    first-day-of-the-month
    prices.(3)

    
    The prices used for all 2008 and 2007 proved reserve estimates
    were year-end spot prices, which were previously required by
    guidance from the SEC and FASB then in effect.    At December 31,2009


2008(In thousands)Proved properties and related producing assets

$
698,541


$
703,654Pipeline and processing facilities


55,243



45,719Unproved properties


79,166



85,120Accumulated depreciation, depletion and amortization


(130,204
)


(90,678
)Net capitalized costs

$
702,747


$
743,815  105




---



##### Table of Contents



2009


2008


2007(In thousands)Proved properties

$
-


$
-


$
457,726Unproved properties


-



-



67,950Development costs


11,598



52,524



8,586Asset retirement costs


1,975



553



1,141Pipelines and processing facilities


-



-



15,546Total

$
13,573


$
53,077


$
550,949     2009


2008


2007(In thousands)Oil, natural gas and NGL sales

$
103,126


$
189,560


$
58,722Realized gain (loss) on derivative instruments


67,836



(22,691
)


(2,088
)Unrealized gain (loss) on derivative instruments


(88,644
)


157,385



(33,080
)Operating costs


(56,029
)


(65,706
)


(23,565
)Depreciation, depletion & amortization


(42,194
)


(72,460
)


(9,325
)Income tax (expense) benefit


618



(786
)


391Results from producing activities

$
(15,287
)

$
185,302


$
(8,945
)     At December 31,2009


2008


2007(In thousands)Future revenues

$
1,552,493


$
1,429,072


$
2,597,342Future development costs


(79,983
)


(86,369
)


(118,034
)Future production costs


(850,917
)


(747,884
)


(1,070,304
)Future net cash flows


621,593



594,819



1,409,00410% discount


(314,290
)


(354,610
)


(799,884
)Standardized measure of discounted future cash flows relating to
    proved reserves

$
307,303


$
240,209


$
609,120  106




---



##### Table of Contents



At December 31,2009


2008


2007(In thousands)Beginning balance

$
240,209


$
609,120


$
-Sales, net of production costs


(47,097
)


(128,854
)


(35,157
)Net changes in sales and transfer prices, net of production
    expense


88,093



(529,993
)


77,515Previously estimated development costs incurred


11,748



23,400



4,921Changes in estimated future development costs


(14,969
)


(39,773
)


(7,225
)Extensions, discoveries and improved recovery, net of costs


-



-



829Purchase of reserves in
    place(1)


-



166,538



541,014Sale of reserves in
    place(1)


(2,231
)


-



-Revision of quantity estimates and timing of production


7,590



57,205



17,270Accretion of discount


23,960



77,566



9,953Ending balance

$
307,303


$
240,209


$
609,120   (1)

    
    Amounts are included as needed to reconcile Quicksilvers
    portion of beginning value to ending value that result from
    changes in Quicksilvers proportionate ownership of BBEP. 107




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##### Table of Contents



ITEM 9.
    Changes
    in and Disagreements with Accountants or Accounting and
    Financial Disclosure    ITEM 9A.
    Controls
    and Procedures  Disclosure
    Controls and Procedures
    Form 10-K,
    Managements
    Report on Internal Control Over Financial Reporting
  Rules 13a-15(f)
  Internal Control  Integrated
    Framework
    Changes
    in Internal Control Over Financial Reporting
   108




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
      Internal Control 
    Integrated Framework
        Internal Control  Integrated Framework
    /s/
    Deloitte & Touche LLP
   
 109




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##### Table of Contents



ITEM 9B.
    Other
    Information   PART III  ITEM 10.
    Directors,
    Executive Officers and Corporate Governance        ITEM 11.
    Executive
    Compensation    ITEM 12.
    Security
    Ownership of Management and Certain Beneficial Owners and
    Management and Related Stockholder Matters    ITEM 13.
    Certain
    Relationships and Related Transactions, and Director
    Independence      ITEM 14.
    Principal
    Accountant Fees and Services   110




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##### Table of Contents



PART IV ITEM 15.    Financial
    Statements
    Financial
    Statement Schedules
  Rule 3-09 Regulation S-X.
     111




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##### Table of Contents



Report of
    Independent Registered Public Accounting Firm
  To the Board of Directors of BreitBurn GP, LLC and
    Unitholders of BreitBurn Energy Partners L.P.
          112




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##### Table of Contents





BreitBurn
    Energy Partners L.P. and Subsidiaries
  Consolidated Statements of Operations
  Year Ended December 31,Thousands of dollars, except
    per unit amounts

2009


2008


2007Revenues and other income items:Oil, natural gas and natural gas liquid sales

$
254,917


$
467,381


$
184,372Gains (losses) on commodity derivative instruments, net 
    (note 16)


(51,437
)


332,102



(110,418
)Other revenue, net (note 11)


1,382



2,920



1,037Total revenues and other income items


204,862



802,403



74,991Operating costs and expenses:Operating costs


138,498



162,005



73,989Depletion, depreciation and amortization (note 6)


106,843



179,933



29,422General and administrative expenses


36,367



31,111



26,928Loss on sale of assets


5,965



-



-Total operating costs and expenses


287,673



373,049



130,339Operating income (loss)


(82,811
)


429,354



(55,348
)Interest and other financing costs, net


18,827



29,147



6,258Loss on interest rate swaps (note 16)


7,246



20,035



-Other income, net


(99
)


(191
)


(111
)Income (loss) before taxes


(108,785
)


380,363



(61,495
)Income tax expense (benefit) (note 7)


(1,528
)


1,939



(1,229
)Net income (loss)


(107,257
)


378,424



(60,266
)Less: Net income attributable to noncontrolling interest


(33
)


(188
)


(91
)Net income (loss) attributable to the partnership


(107,290
)


378,236



(60,357
)General Partners interest in net loss


-



(2,019
)


(672
)Net income (loss) attributable to limited partners

$
(107,290
)

$
380,255


$
(59,685
)Basic net income (loss) per unit (note 14)

$
(2.03
)

$
6.29


$
(1.83
)Diluted net income (loss) per unit (note 14)

$
(2.03
)

$
6.28


$
(1.83
)   The accompanying notes are an integral part of these
    consolidated financial statements.
 113




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##### Table of Contents







BreitBurn
    Energy Partners L.P. and Subsidiaries
  Consolidated Balance Sheets
  December 31,


December 31,Thousands

2009


2008ASSETSCurrent assets:Cash

$
5,766


$
2,546Accounts and other receivables, net (note 2)


65,209



47,221Derivative instruments (note 16)


57,133



76,224Related party receivables (note 8)


2,127



5,084Inventory (note 9)


5,823



1,250Prepaid expenses


5,888



5,300Intangibles (note 10)


495



2,771Other current assets


-



170Total current assets


142,441



140,566Equity investments (note 11)


8,150



9,452Property, plant and equipmentOil and gas properties (note 4)


2,058,968



2,057,531Non-oil and gas assets (note 4)


7,717



7,8062,066,685



2,065,337Accumulated depletion and depreciation (note 6)


(325,596
)


(224,996
)Net property, plant and equipment


1,741,089



1,840,341Other long-term assetsIntangibles (note 10)


-



495Derivative instruments (note 16)


74,759



219,003Other long-term assets


4,590



6,977Total assets

$
1,971,029


$
2,216,834LIABILITIES AND PARTNERS EQUITYCurrent liabilities:Accounts payable

$
21,314


$
28,302Book overdraft


-



9,871Derivative instruments (note 16)


20,057



10,192Related party payables (note 8)


13,000



-Revenue and royalties payable


18,224



20,084Salaries and wages payable


10,244



6,249Accrued liabilities


9,051



5,292Total current liabilities


91,890



79,990Long-term debt (note 12)


559,000



736,000Deferred income taxes (note 7)


2,492



4,282Asset retirement obligation (note 13)


36,635



30,086Derivative instruments (note 16)


50,109



10,058Other long-term liabilities


2,102



2,987Total liabilities


742,228



863,403Equity:Partners equity (note 14)


1,228,373



1,352,892Noncontrolling interest (note 15)


428



539Total equity


1,228,801



1,353,431Total liabilities and equity

$
1,971,029


$
2,216,834Limited partner units outstanding


52,784



52,636   The accompanying notes are an integral part of these
    consolidated financial statements.
 114




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##### Table of Contents







BreitBurn
    Energy Partners L.P. and Subsidiaries
  Consolidated Statements of Cash Flows
  Year Ended December 31,Thousands of
    dollars

2009


2008


2007Cash flows from operating activitiesNet income (loss)

$
(107,257
)

$
378,424


$
(60,266
)Adjustments to reconcile net income (loss) to cash flow from 
    operating activities:Depletion, depreciation and amortization


106,843



179,933



29,422Unit-based compensation expense


12,661



6,907



12,999Unrealized (gain) loss on derivative instruments


213,251



(370,734
)


103,862Distributions greater (less) than income from equity affiliates


1,302



1,198



(28
)Deferred income tax


(1,790
)


1,207



(1,229
)Amortization of intangibles


2,771



3,131



2,174Loss on sale of assets


5,965



-



-Other


3,294



2,643



2,182Changes in net assets and liabilities:Accounts receivable and other assets


(6,313
)


258



(24,713
)Inventory


(4,573
)


4,454



4,829Net change in related party receivables and payables


2,957



32,688



(39,202
)Accounts payable and other liabilities


(4,753
)


(13,413
)


30,072Net cash provided by operating activities


224,358



226,696



60,102Cash flows from investing activities (a)Capital expenditures


(29,513
)


(131,082
)


(23,549
)Proceeds from sale of assets, net


23,284



-



-Property acquisitions


-



(9,957
)


(996,561
)Net cash used by investing activities


(6,229
)


(141,039
)


(1,020,110
)Cash flows from financing activitiesIssuance of common units, net of discount


-



-



663,338Purchase of common units


-



(336,216
)


-Distributions to predecessor members concurrent with initial 
    public offering


-



-



581Distributions (b)


(28,038
)


(121,349
)


(60,497
)Proceeds from the issuance of long-term debt


249,975



803,002



574,700Repayments of long-term debt


(426,975
)


(437,402
)


(205,800
)Book overdraft


(9,871
)


7,951



(116
)Long-term debt issuance costs


-



(5,026
)


(6,362
)Net cash provided (used) by financing activities


(214,909
)


(89,040
)


965,844Increase (decrease) in cash


3,220



(3,383
)


5,836Cash beginning of period


2,546



5,929



93Cash end of period

$
5,766


$
2,546


$
5,929   (a) Non-cash investing
    activity in 2007 was $700 million, reflecting the issuance
    of 21.348 million Common Units for the Quicksilver
    acquisition.
  (b) 2009 and 2008 include
    distributions on equivalent units of $0.7 million and
    $2.3 million, respectively.
  The accompanying notes are an integral part of these
    consolidated financial statements.
 115




---



##### Table of Contents







BreitBurn
    Energy Partners L.P. and Subsidiaries
  Consolidated Statements of Partners Equity
  Limited


GeneralThousands

Common Units


Partners


Partner


TotalBalance, December 31, 2006


21,976


$
174,395


$
2,813


$
177,208Issuance of units (a)


21,348



700,000



-



700,000Private offering investment (b)


23,697



663,338



-



663,338Distributions


-



(59,746
)


(751
)


(60,497
)Unit-based compensation


-



5,133



-



5,133Net loss


-



(59,685
)


(672
)


(60,357
)Other


-



(17
)


-



(17
)Balance, December 31, 2007


67,021


$
1,423,418


$
1,390


$
1,424,808Redemption of common units from predecessors (c)


(14,405
)


(336,216
)


-



(336,216
)Distributions


-



(118,580
)


(427
)


(119,007
)Distributions paid on unissued units under incentive plans


-



(2,335
)


(7
)


(2,342
)Unit-based compensation


-



7,383



-



7,383Net income (loss)


-



380,255



(2,019
)


378,236Contribution of general partner interest to the
    Partnership (d)


-



(1,063
)


1,063



-BreitBurn Management purchase (e)


20



-



-



-Other


-



30



-



30Balance, December 31, 2008


52,636


$
1,352,892


$
-


$
1,352,892Distributions


-



(27,371
)


-



(27,371
)Distributions paid on unissued units under incentive plans


-



(667
)


-



(667
)Units issued under incentive plans


148



7,488







7,488Unit-based compensation






3,322



-



3,322Net loss


-



(107,290
)


-



(107,290
)Other


-



(1
)


-



(1
)Balance, December 31, 2009


52,784


$
1,228,373


$
-


$
1,228,373   (a)
    Reflects the issuance of Common
    Units for the Quicksilver acquisition.(b)
    Reflects the issuance of Common
    Units in three private placements.(c)
    Reflects the purchase of Common
    Units from subsidiaries of Provident.(d)
    General partner interests were
    purchased as of June 17, 2008.(e)
    Reflects issuance of Common Units
    to Co-CEOs in exchange for their interest in BreitBurn
    Management.  The accompanying notes are an integral part of these
    consolidated financial statements.
 116




---



##### Table of Contents





Notes to
    Consolidated Financial Statements
  Note 1.
    Organization            2.
    Summary
    of Significant Accounting Policies  Principles
    of consolidation
    Basis of
    Presentation
     117




---



##### Table of Contents



Year Ended December 31,Thousands of
    dollars

2008


2007Operating costsAs previously reported

$
149,681


$
70,329District expense reclass from G&A


12,324



3,660As revised

$
162,005


$
73,989G&A expensesAs previously reported

$
43,435


$
30,588District expense reclass to operating costs


(12,324
)


(3,660
)As revised

$
31,111


$
26,928   Use of
    estimates
    Business Combinations.
  Business
    segment information
  Segment Reporting area-by-area project-by-project
  Revenue
    recognition
    Cash and
    cash equivalents
   118




---



##### Table of Contents



Accounts
    Receivable
          Inventory
    Investments
    in Equity Affiliates
    Property,
    plant and equipment
  Oil
    and gas properties
    field-by-field
  Non-oil
    and gas assets
   119




---



##### Table of Contents



Oil and
    natural gas reserve quantities
  Release
    No. 33-8995,
    Modernization of Oil and Gas Reporting 33-8995),
  Asset
    retirement obligations
  Asset Retirement and
    Environmental Obligations.
  Impairment
    of assets
  Property, Plant and Equipment.
  field-by-field
  Debt
    issuance costs
   120




---



##### Table of Contents



Equity-based
    compensation
  Compensation  Stock
    Compensation
  Fair
    market value of financial instruments
    Accounting
    for business combinations
  Business
    Combinations.
  Concentration
    of credit risk
    Derivatives
  Derivatives and Hedging
  Fair Value Measurements, Fair Value
    Measurements and Disclosures
 121




---



##### Table of Contents



Income
    taxes
    Income
    Taxes.
      Net
    Income or loss per unit
  Earnings per Share
  Environmental
    expenditures
   122




---



##### Table of Contents



3.
    Accounting
    Pronouncements    Generally Accepted Accounting
    Principles
  SEC Release
    No. 33-8995,
    Modernization of Oil and Gas Reporting. Release 33-8995 first-day-of-the-month 33-8995 33-8995
  Accounting Standards Update (ASU)
    2010-03
    Extractive Activities  Oil and Gas. 2010-03 Extractive
    Activities  Oil and Gas, SEC release
    No. 33-8995,
    Modernization of Oil and Gas Reporting. 2010-03 Extractive Activities  Oil
    and Gas.
  ASU
    2010-06
    Fair Value Measurements and Disclosures. ASU 2010-06 820-10
 123




---



##### Table of Contents



ASU 2010-06 (ASC 820-10) 2010-06 820-10)
    4.
    Acquisitions      Thousands of
    dollarsRelated party receivables  current, net

$
10,662Other current assets


21Oil and gas properties


8,451Non-oil and gas assets


4,343Related party receivables  non-current


6,704Current liabilities


(13,510
)Long-term liabilities


(6,704
)$
9,967     Pro Forma
    Information
   124




---



##### Table of Contents



Pro Forma Year EndedThousands of dollars, except
    per unit amounts

December 31,
    2007 (1)Revenues

$
233,761Net income (loss)


(43,966
)Net income (loss) per unitBasic

$
(0.65
)Diluted


(0.65
)        5.
    Disposition
    of Assets      6.
    Impairments
    and Price Related Depletion and Depreciation
    Adjustments       125




---



##### Table of Contents



7.
    Income
    Taxes      Year Ended December 31,Thousands of
    dollars

2009


2008


2007Federal income tax expense (benefit)Current

$
247


$
257


$
-Deferred (a)


(1,790
)


1,207



(1,229
)State income tax expense (benefit) (b)


15



475



-Total

$
(1,528
)

$
1,939


$
(1,229
)   (a)
    Related to Phoenix Production Company, our wholly owned
    subsidiary. (b)
    Primarily in the states of Michigan, California and Texas.    Year Ended December 31,Thousands of
    dollars

2009


2008


2007Income (loss) subject to federal income tax


(4,052
)


3,904



(4,498
)Federal income tax rate


34
%


34
%


34
%Income tax at statutory rate


(1,378
)


1,327



(1,529
)Other


(299
)


-



300Income tax expense (benefit)

$
(1,677
)

$
1,327


$
(1,229
)    126




---



##### Table of Contents



December 31,Thousands of
    dollars

2009


2008Deferred tax assets:Net operating loss carryforwards

$
422


$
767Asset retirement obligation


358



337Unrealized hedge loss


85



-Other


276



103Deferred tax liabilities:Depreciation, depletion and intangible drilling costs


(3,101
)


(3,404
)Unrealized hedge gain


-



(2,085
)Deferred realized hedge gain


(532
)


-Net deferred tax liability

$
(2,492
)

$
(4,282
)       Income Taxes more-likely-than-not
    8.
    Related
    Party Transactions       127




---



##### Table of Contents



128




---



##### Table of Contents



9.
    Inventory        10.
    Intangibles   129




---



##### Table of Contents



11.
    Equity
    Investments      12.
    Long-Term
    Debt       130




---



##### Table of Contents



1-month 1-month
   131




---



##### Table of Contents



Year Ended December 31,Thousands of
    dollars

2009


2008


2007Credit agreement (including commitment fees)

$
15,532


$
26,534


$
5,876Amortization of discount and deferred issuance costs


3,295



2,613



382Total

$
18,827


$
29,147


$
6,258Cash paid for interest

$
28,350


$
29,767


$
3,545   13.
    Asset
    Retirement Obligation    Fair Value Measurements and Disclosures
    Year Ended December 31,Thousands of
    dollars

2009


2008Carrying amount, beginning of period

$
30,086


$
27,819Liabilities settled in the current period


(470
)


(1,054
)Revisions (a)


4,883



1,363Acquisitions (dispositions) (b)


(252
)


-Accretion expense


2,388



1,958Carrying amount, end of period

$
36,635


$
30,086      14.
    Partners
    Equity   132




---



##### Table of Contents



long-term
               133




---



##### Table of Contents



Earnings
    per Common Unit
  Earnings per Share
    134




---



##### Table of Contents



Year Ended December 31,Thousands, except per unit
    amounts

2009


2008


2007Net income (loss) attributable to limited partners

$
(107,290
)

$
380,255


$
(59,685
)Distributions on participating units not expected to vest


-



22



-Net income (loss) attributable to common unitholders and
    participating securities

$
(107,290
)

$
380,277


$
(59,685
)Weighted average number of units used to calculate basic and
    diluted net income (loss) per unit:Common Units


52,757



59,239



32,577Participating securities (a)


-



1,184



-Denominator for basic earnings per Common Unit


52,757



60,423



32,577Dilutive units (b)


-



142



-Denominator for diluted earnings per Common Unit


52,757



60,565



32,577Net income (loss) per common unitBasic

$
(2.03
)

$
6.29


$
(1.83
)Diluted

$
(2.03
)

$
6.28


$
(1.83
)    anti-dilutive
  Cash
    Distributions
         135




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##### Table of Contents



15.
    Noncontrolling
    interest  Consolidation
      16.
    Financial
    Instruments  Fair
    Value of Financial Instruments
    Credit
    and Counterparty Risk
   136




---



##### Table of Contents



Commodity
    Activities
  Derivatives and Hedging
         137




---



##### Table of Contents



Year2010


2011


2012


2013


2014Gas Positions:Fixed Price Swaps:Hedged Volume (MMBtu/d)


43,869



25,955



19,129



27,000



-Average Price ($/MMBtu)

$
8.20


$
7.26


$
7.10


$
6.92


$
-Collars:Hedged Volume (MMBtu/d)


3,405



16,016



19,129



-



-Average Floor Price ($/MMBtu)

$
9.00


$
9.00


$
9.00


$
-


$
-Average Ceiling Price ($/MMBtu)

$
12.79


$
11.28


$
11.89


$
-


$
-Total:Hedged Volume (MMBtu/d)


47,275



41,971



38,257



27,000



-Average Price ($/MMBtu)

$
8.26


$
7.92


$
8.05


$
6.92


$
-Oil Positions:Fixed Price Swaps:Hedged Volume (Bbls/d)


2,808



2,616



2,539



3,500



748Average Price ($/Bbl)

$
81.35


$
66.22


$
67.24


$
76.79


$
88.65Participating Swaps: (a)Hedged Volume (Bbls/d)


1,993



1,439



-



-



-Average Price ($/Bbl)

$
64.40


$
61.29


$
-


$
-


$
-Average Participation %


55.5
%


53.2
%


-



-



-Collars:Hedged Volume (Bbls/d)


1,279



2,048



2,477



500



-Average Floor Price ($/Bbl)

$
102.85


$
103.42


$
110.00


$
77.00


$
-Average Ceiling Price ($/Bbl)

$
136.16


$
152.61


$
145.39


$
103.10


$
-Floors:Hedged Volume (Bbls/d)


500



-



-



-



-Average Floor Price ($/Bbl)

$
100.00


$
-


$
-


$
-


$
-Total:Hedged Volume (Bbls/d)


6,580



6,103



5,016



4,000



748Average Price ($/Bbl)

$
81.81


$
77.54


$
88.35


$
76.82


$
88.65     Interest
    Rate Activities
   138




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##### Table of Contents



LIBOR-base
  Notional amounts in
    thousands of dollars

Notional Amount


Fixed RatePeriod CoveredJanuary 1, 2010 to January 8, 2010

$
100,000



3.3873%January 1, 2010 to December 20, 2010


300,000



3.6825%January 20, 2010 to October 20, 2011


100,000



1.6200%December 20, 2010 to October 20, 2011


200,000



2.9900%           Oil


Natural Gas


Interest


Commodity


TotalCommodity


Commodity


Rate


derivative


FinancialBalance sheet location, thousands of dollars

Derivatives


Derivatives


Derivatives


netting (a)


InstrumentsDecember 31, 2009AssetsCurrent assets - derivative instruments

$
17,666


$
39,467


$
-


$
-


$
57,133Other long-term assets - derivative instruments


35,382



42,620



-



(3,243)



74,759Total assets


53,048



82,087



-



(3,243)



131,892LiabilitiesCurrent liabilities - derivative instruments


(10,234
)


-



(9,823
)


-



(20,057
)Long-term liabilities - derivative instruments


(51,730
)


-



(1,622
)


3,243



(50,109
)Total liabilities


(61,964
)


-



(11,445
)


3,243



(70,166
)Net assets (liabilities)

$
(8,916
)

$
82,087


$
(11,445
)

$
-


$
61,726December 31, 2008AssetsCurrent assets - derivative instruments

$
44,086


$
32,138


$
-


$
-


$
76,224Other long-term assets - derivative instruments


145,061



73,942



-



-



219,003Total assets


189,147



106,080



-



-



295,227LiabilitiesCurrent liabilities - derivative instruments


(1,115
)


-



(9,077
)


-



(10,192
)Long-term liabilities - derivative instruments


(1,820
)


-



(8,238
)


-



(10,058
)Total liabilities


(2,935
)


-



(17,315
)


-



(20,250
)Net assets (liabilities)

$
186,212


$
106,080


$
(17,315
)

$
-


$
274,977  139




---



##### Table of Contents



(a)
    
    Represents counterparty netting
    under derivative netting agreements  these contracts
    are reflected net on the balance sheet.    Oil

Natural Gas



TotalCommodity

Commodity

Interest Rate

FinancialLocation of gain/loss,
    thousands of dollars

Derivatives (a)

Derivatives (a)

Derivatives (b)

InstrumentsYear Ended December 31, 2009Realized gains (losses)


66,176


101,507


(13,115)

$
154,568Unrealized gains (losses)


(195,127)


(23,993)


5,869


(213,251)Net gains (losses)

$
(128,951)

$
77,514

$
(7,246)

$
(58,683)Year Ended December 31, 2008Realized losses

$
(35,146)

$
(20,800)

$
(2,721)

$
(58,667)Unrealized gains (losses)


293,720


94,328


(17,314)


370,734Net gains (losses)

$
258,574

$
73,528

$
(20,035)

$
312,067    (a)
    
    Included in gains (losses) on commodity derivative instruments
    on the consolidated statements of operations.(b)
    
    Included in loss on interest rate swaps on the consolidated
    statements of operations.  Fair Value Measurements and
    Disclosures.
         140




---



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141




---



##### Table of Contents



As of December 31, 2009Thousands of
    dollars

Level 1


Level 2


Level 3


TotalAssets (Liabilities):Commodity Derivatives (swaps, put and call options)

$
-


$
(29,303
)

$
102,475


$
73,172Other Derivatives (interest rate swaps)


-



(11,446
)


-



(11,446
)Total

$
-


$
(40,749
)

$
102,475


$
61,726   As of December 31,2008Thousands of
    dollars

Level 1


Level 2


Level 3


TotalAssets (Liabilities):Commodity Derivatives (swaps, put and call options)

$
-


$
139,074


$
153,218


$
292,292Other Derivatives (interest rate swaps)


-



(17,315
)


-



(17,315
)Total

$
-


$
121,759


$
153,218


$
274,977     Year Ended December 31,Thousands of
    dollars

2009

2008Assets (Liabilities):Beginning balance

$
153,218

$
44,236Realized and unrealized gains (losses)


(44,713)


106,154Purchases and issuances


-


7,452Settlements (a)


(6,030)


(4,624)Ending balance

$
102,475

$
153,218      17.
    Unit and
    Other Valuation-Based Compensation Plans   142




---



##### Table of Contents



Unit
    Based Compensation
  Compensation  Stock
    Compensation
        Restricted
    Phantom Units (RPUs)
   143




---



##### Table of Contents



December 31,2009


2008


2007 (a)Number of


Weighted


Number of


Weighted


Number of


WeightedRPU


Average


RPU


Average


RPU


AverageUnits


Fair Value *


Units


Fair Value *


Units


Fair Value *Outstanding, beginning of period


607,263


$
26.91



372,945


$
30.98



-


$
-Granted


1,790,589



8.17



245,290



20.44



372,945



30.98Exercised


(808,700
)


13.08



-



-



-



-Cancelled


(14,402
)


14.45



(10,972
)


20.83



-



-Outstanding, end of period


1,574,750


$
12.82



607,263


$
26.91



372,945


$
30.98Exercisable, end of period


-


$
-



-


$
-



-


$
-       Convertible
    Phantom Units (CPUs)
   144




---



##### Table of Contents



145




---



##### Table of Contents




    if such termination occurs on or before December 31, 2008,
    a percentage equal to 40 percent;
    if such termination occurs on or before December 31, 2009,
    a percentage equal to 60 percent;
    if such termination occurs on or before December 31, 2010,
    a percentage equal to 80 percent; and
    if such termination occurs on or after January 1, 2011, a
    percentage equal to 100 percent.    Founders
    Plan Awards
       146




---



##### Table of Contents



December 31,2009


2008


2007Number of




Weighted


Number of


Weighted


Number of


WeightedAppreciation




Average


Appreciation


Average


Appreciation


AverageRights Units




Exercise Price


Rights Units


Exercise Price


Rights Units


Exercise PriceOutstanding, beginning of period


122,644




$
18.50



214,107


$
18.50



305,570


$
18.50Exercised


-





-



(91,463
)


18.50



(91,463
)


18.50Cancelled(a)


(101,856
)




18.50



-



-



-



-Outstanding, end of period


20,788




$
18.50



122,644


$
18.50



214,107


$
18.50Exercisable, end of period


-




$
-



-


$
-



-


$
-     BreitBurn
    Management LTIP and the Partnership LTIP
  BreitBurn
    Management LTIP
  and/or
     147




---



##### Table of Contents



PVE indexed unitsDecember 31,2008


2007Weighted





WeightedNumber of


Average


Number of


AverageUnits


Grant Price


Units


Grant PriceOutstanding, beginning of period


267,702


$
10.77



318,389


$
10.82Granted


-



-



-



-Exercised


(267,351
)


10.77



(36,203
)


10.87Cancelled


(351
)


10.73



(14,484
)


11.53Outstanding, end of period


-


$
10.77



267,702


$
10.77Exercisable, end of period


-


$
-



-


$
-   Partnership
    LTIP
  and/or
     148




---



##### Table of Contents



PTUs and RTUsDecember 31,2009


2008


2007Weighted





Weighted





WeightedNumber of


Average


Number of


Average


Number of


AverageUnits


Grant Price


Units


Grant Price


Units


Grant PriceOutstanding, beginning of period


86,992


$
24.10



108,717


$
23.64



20,483


$
21.67Granted


-



-



-



-



91,834



24.10Exercised


(6,357
)


24.10



(20,645
)


20.39



(98
)


24.10Cancelled


(75,034
)


24.10



(1,080
)


24.10



(3,502
)


24.10Outstanding, end of period


5,601


$
24.10



86,992


$
24.10



108,717


$
23.64Exercisable, end of period


-


$
-



-


$
-



-


$
-   Unit
    Appreciation Right Plan Awards
        Director
    Restricted Phantom Units
     149




---



##### Table of Contents



December 31,2009


2008


2007Number of


Weighted


Number of


Weighted


Number of


WeightedPerformance


Average


Performance


Average


Performance


AverageUnits


Fair Value *


Units


Fair Value *


Units


Fair Value *Outstanding, beginning of period


35,429


$
22.60



37,473


$
21.11



20,026


$
18.50Granted


56,736



9.20



20,146



25.02



17,447



24.10Exercised


(10,810
)


18.50



(22,190
)


22.28



-



-Outstanding, end of period


81,355


$
13.80



35,429


$
22.60



37,473


$
21.11Exercisable, end of period


-


$
-



-


$
-



-


$
-     18.
    Commitments
    and Contingencies  Lease
    Rental Obligations
    Payments Due by YearThousands of
    dollars

2010


2011


2012


2013


2013


after 2013


TotalOperating leases

$
2,838


$
2,636


$
2,174


$
814


$
465


$
543


$
9,470     Surety
    Bonds and Letters of Credit
    Legal
    Proceedings
      19.
    Retirement
    Plan   150




---



##### Table of Contents



20.
    Significant
    Customers    21.
    Subsequent
    Events    600 Bbl/d
    22.
    Supplemental
    Information about Oil and Natural Gas Activities
    (Unaudited)  33-8995 first-day-of-the-month
 151




---



##### Table of Contents



first-day-of-the-month Extractive
    Activities  Oil and Gas, No. 33-8995.
  Costs
    incurred
    Year Ended December 31,Thousands of
    dollars

2009


2008


2007Property acquisition costsProved

$
-


$
-


$
1,437,129Unproved


-



-



213,344Development costs


28,669



129,503



26,959Asset retirement costs


4,883



1,363



3,583Pipelines and processing facilities


-



-



48,810$
33,552


$
130,866


$
1,729,825   Capitalized
    costs
    At December 31,Thousands of
    dollars

2009


2008Proved properties and related producing assets

$
1,726,722


$
1,734,932Pipelines and processing facilities


136,556



112,726Unproved properties


195,690



209,873Accumulated depreciation, depletion and amortization


(321,851
)


(223,575
)Net capitalized costs

$
1,737,117


$
1,833,956     Results
    of operations for oil and gas producing activities
    152




---



##### Table of Contents



Year Ended December 31,Thousands of
    dollars

2009


2008


2007Oil, natural gas and NGL sales

$
254,917


$
467,381


$
184,372Realized gain (loss) on derivative instruments


167,683



(55,946
)


(6,556
)Unrealized gain (loss) on derivative instruments


(219,120
)


388,048



(103,862
)Operating costs


(138,498
)


(162,005
)


(73,989
)Depreciation, depletion, and amortization


(104,299
)


(178,657
)


(29,277
)Income tax (expense) benefit


1,528



(1,939
)


1,229Results of operations from producing activities

$
(37,789
)

$
456,882


$
(28,083
)   Supplemental
    reserve information
         153




---



##### Table of Contents



Year Ended December 31,2009


2008


2007Total


Oil


Gas


Total


Oil


Gas


Total


Oil


GasIn Thousands

(MBoe)


(MBbl)


(MMcf)


(MBoe)


(MBbl)


(MMcf)


(MBoe)


(MBbl)


(MMcf)Proved ReservesBeginning balance


103,649



25,910



466,434



142,273



58,095



505,069



30,740



30,042



4,190Revision of previous
    estimates (a)


15,303



17,034



(10,389
)


(31,815
)


(29,106
)


(16,251
)


3,171



3,260



(534
)Extensions, discoveries and other
    additions (a)


-



-



-



-



-



-



118



118



-Purchase of reserves in-place


-



-



-



-



-



-



111,263



27,005



505,547Sale of reserves in-place


(1,135
)


(1,109
)


(154
)


-



-



-



-



-



-Production


(6,516
)


(2,989
)


(21,161
)


(6,810
)


(3,079
)


(22,384
)


(3,019
)


(2,330
)


(4,134
)Ending balance


111,301



38,846



434,730



103,649



25,910



466,434



142,273



58,095



505,069Proved Developed ReservesBeginning balance


95,643



23,346



433,780



128,344



52,103



457,444



28,484



27,786



4,190Ending balance


100,968



34,436



399,190



95,643



23,346



433,780



128,343



52,103



457,444Proved Undeveloped
    Reserves (b) (c)Beginning balance


8,006



2,564



32,654



13,930



5,992



47,625



2,256



2,256



-Ending balance


10,333



4,410



35,540



8,006



2,564



32,654



13,930



5,992



47,625   (a) Additions to proved
    reserves classified in revisions due to infill drilling,
    re-completions and workovers were approximately 1,563 MBbl
    for oil and 32,376 MMcf for natural gas in 2009,
    741 MBbl for oil and 35,834 MMcf for natural gas in
    2008 and 1,422 MBbl for oil and 19 MMcf for natural
    gas in 2007.
 (b) During the year ended
    December 31, 2009, we incurred $5,807 in capital
    expenditures and drilled 11 wells to convert 568 MBbl
    of oil and 484 MMcf of natural gas from proved undeveloped
    to proved developed.
 (c) As of December 31,
    2009, we had no material proved undeveloped reserves that have
    remained undeveloped for more than five years. The increase in
    proved undeveloped reserves during the year ended
    December 31, 2009 was primarily due to the economic effect
    of higher 2009 SEC pricing on properties previously deemed
    uneconomical as well as revisions of estimates, partially offset
    by the conversion of proved undeveloped reserves to proved
    developed.
 154




---



##### Table of Contents



Standardized
    measure of discounted future net cash flows
    Year Ended December 31,Thousands of
    dollars

2009


2008


2007Future cash inflows

$
3,837,605


$
3,523,524


$
8,154,921Future development costs


(197,709
)


(212,951
)


(370,594
)Future production expense


(2,103,381
)


(1,843,986
)


(3,360,451
)Future net cash flows


1,536,515



1,466,587



4,423,876Discounted at 10% per year


(776,893
)


(874,327
)


(2,511,409
)Standardized measure of discounted future net cash flows

$
759,622


$
592,260


$
1,912,467     1.
    An estimate was made of the quantity of proved reserves and the
    future periods in which they are expected to be produced based
    on year-end economic conditions.2.
    In accordance with SEC guidelines, the reserve engineers
    estimates of future net revenues from our estimated proved
    properties and the present value thereof for 2009 are made using
    unweighted average
    first-day-of-the-month
    oil and gas sales prices and are held constant throughout the
    life of the properties, except where such guidelines permit
    alternate treatment, including the use of fixed and determinable
    contractual price escalations.  We have entered into various
    arrangements to fix or limit the prices relating to a portion of
    our oil and gas production.  Arrangements in effect at
    December 31, 2009 are discussed in Note 16.  Such risk
    management arrangements are not reflected in the reserve
    reports.  Representative unweighted average
    first-day-of-the-month
    market prices for the reserve reports for the year ended
    December 31, 2009 were $61.18 ($51.29 for Wyoming) per
    barrel of oil and $3.87 per MMBtu of gas.3.
    In accordance with SEC guidelines for 2008 and 2007, the reserve
    engineers estimates of future net revenues from our
    estimated proved properties and the present value thereof are
    made using oil and gas prices in effect as of the dates of such
    estimates and are held constant throughout the life of the
    properties, except where such guidelines permit alternate
    treatment, including the use of fixed and determinable
    contractual price escalations. Representative market prices at
    the as-of date for the reserve reports as of December 31,
    2008 and 2007 were $44.60 ($20.12 for Wyoming) and $95.95
    ($54.52 for Wyoming) per barrel of oil, respectively, and $5.71
    and $6.80 per MMBtu of gas, respectively.4.
    The future gross revenue streams were reduced by estimated
    future operating costs (including production and ad valorem
    taxes) and future development and abandonment costs, all of
    which were based on current costs.  Future net cash flows assume
    no future income tax expense as we are essentially a non-taxable
    entity except for two tax paying corporations whose future
    income tax liabilities on a discounted basis are insignificant.5.
    It is not practical to estimate the impact that adopting SEC
    Release
    33-8995 had
    on our financial statements due to the technical challenges of
    calculating a cumulative effect of adoption by preparing reserve
    reports under both old and new rules. 155




---



##### Table of Contents



Year Ended December 31,Thousands of dollars

2009


2008


2007Beginning balance

$
592,260


$
1,912,467



312,499Sales, net of production expense


(116,419
)


(305,376
)


(110,383
)Net change in sales and transfer prices, net of production
    expense


217,756



(1,306,752
)


243,374Previously estimated development costs incurred during year


29,041



57,694



15,451Changes in estimated future development costs


(37,002
)


(98,064
)


(22,683
)Extensions, discoveries and improved recovery, net of costs


-



-



2,602Purchase of reserves in place


-



-



1,386,133Sale of reserves in-place


(4,001
)


-



-Revision of quantity estimates and timing of estimated production


18,761



141,044



54,224Accretion of discount


59,226



191,247



31,250Ending balance

$
759,622


$
592,260


$
1,912,467   23.
    Quarterly
    Financial Data (Unaudited)  Year Ended December 31, 2009First


Second


Third


FourthThousands of dollars except per unit amounts

Quarter


Quarter


Quarter


QuarterOil, natural gas and natural gas liquid sales

$
57,643


$
59,872


$
62,674


$
74,728Gains (losses) on derivative instruments


70,020



(97,259
)


12,719



(36,917
)Other revenue, net


276



393



261



452Total revenue

$
127,939


$
(36,994
)

$
75,654


$
38,263Operating income (loss)


53,696



(104,346
)


2,848



(35,009
)Net income (loss)


46,357



(108,525
)


(5,396
)


(39,693
)Basic net loss per limited partner unit (a)


0.85



(2.06
)


(0.10
)


(0.75
)Diluted net loss per limited partner unit (a)


0.84



(2.06
)


(0.10
)


(0.75
)   Year Ended December 31, 2008First


Second


Third


FourthThousands of dollars except per unit amounts

Quarter


Quarter


Quarter


QuarterOil, natural gas and natural gas liquid sales

$
115,849


$
139,962


$
130,249


$
81,321Gains (losses) on derivative instruments


(83,387
)


(353,282
)


407,441



361,330Other revenue, net


875



643



806



596Total revenue

$
33,337


$
(212,677
)

$
538,496


$
443,247Operating income (loss) (b)


(34,455
)


(282,267
)


468,625



277,451Net income (loss) (b)


(41,086
)


(286,170
)


454,505



251,175Limited Partners interest in loss (b)


(40,867
)


(284,494
)


454,454



251,162Basic net loss per limited partner unit (a)


(0.61
)


(4.39
)


8.43



4.66Diluted net loss per limited partner unit (a)


(0.61
)


(4.39
)


8.41



4.65     156




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##### Table of Contents



Exhibits
  Exhibit No.

Sequential Description**2
.1

Contribution Agreement, dated September 11, 2007, between
    Quicksilver Resources Inc. and BreitBurn Operating
    L.P.  (filed as Exhibit 10.2 to the
    Companys
    Form 8-K
    filed November 7, 2007 and included herein by reference.)**2
.2

Purchase and Sale Agreement, dated as of July 3, 2008,
    among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus
    Development, L.P., and Perot Investment Partners, Ltd., as
    Sellers, and Quicksilver Resources Inc., as Purchaser (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed July 7, 2008 and included herein by reference).**2
.3

Purchase and Sale Agreement, dated as of July 3, 2008,
    among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P.,
    Chief Resources, LP, Hillwood Alliance Operating Company, L.P.,
    Chief Resources Alliance Pipeline LLC, Chief Oil & Gas
    LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark
    Rollins, as Sellers, and Quicksilver Resources Inc., as
    Purchaser (filed as Exhibit 10.2 to the Companys
    Form 8-K
    filed July 7, 2008 and included herein by reference).3
.1

Amended and Restated Certificate of Incorporation of Quicksilver
    Resources Inc. filed with the Secretary of State of the State of
    Delaware on May 21, 2008 (filed as Exhibit 4.1 to the
    Companys
    Form S-3,
    File
    No. 333-151847,
    filed June 23, 2008 and included herein by reference).3
.2

Amended and Restated Certificate of Designation of Series A
    Junior Participating Preferred Stock of Quicksilver Resources
    Inc.  (filed as Exhibit 3.3 to the Companys
    Form 10-Q
    filed May 6, 2006 and included herein by reference).3
.3

Amended and Restated Bylaws of Quicksilver Resources
    Inc.  (filed as Exhibit 3.1 to the Companys
    Form 8-K
    filed November 16, 2007 and included herein by reference).4
.1

Indenture Agreement for 1.875% Convertible Subordinated
    Debentures Due 2024, dated as of November 1, 2004, between
    Quicksilver Resources Inc., as Issuer, and The Bank of New York,
    as Trustee (as successor in interest to JPMorgan Chase Bank,
    National Association) (filed as Exhibit 4.1 to the
    Companys
    Form 8-K
    filed November 1, 2004 and included herein by reference).4
.2

First Supplemental Indenture, dated July 31, 2009, between
    Quicksilver Resources Inc. and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.2
    to the Companys
    Form 10-Q
    filed August 10, 2009 and included herein by reference).4
.3

Indenture, dated as of December 22, 2005, between
    Quicksilver Resources Inc. and The Bank of New York, as Trustee
    (as successor in interest to JPMorgan Chase Bank, National
    Association) (filed as Exhibit 4.7 to the Companys
    Form S-3,
    File
    No. 333-130597,
    filed December 22, 2005 and included herein by reference).4
.4

First Supplemental Indenture, dated as of March 16, 2006,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York, as Trustee (as successor
    in interest to JPMorgan Chase Bank, National Association) (filed
    as Exhibit 4.1 to the Companys
    Form 8-K
    filed March 21, 2006 and included herein by reference).*4
.5

Second Supplemental Indenture, dated as of July 31, 2006,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York, as Trustee (as successor
    in interest to JPMorgan Chase Bank, National Association).4
.6

Third Supplemental Indenture, dated as of September 26,
    2006, among Quicksilver Resources Inc., the subsidiary
    guarantors named therein and The Bank of New York, as Trustee
    (as successor in interest to JPMorgan Chase Bank, National
    Association) (filed as Exhibit 4.1 to the Companys
    Form 10-Q
    filed November 7, 2006 and included herein by reference).*4
.7

Fourth Supplemental Indenture, dated as of October 31,
    2007, among Quicksilver Resources Inc., the subsidiary
    guarantors named therein and The Bank of New York, as Trustee
    (as successor in interest to JPMorgan Chase Bank, National
    Association).4
.8

Fifth Supplemental Indenture, dated as of June 27, 2008,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Trust Company, N.A.,
    as trustee (filed as Exhibit 4.1 to the Companys
    Form 8-K
    filed June 30, 2008 and included herein by reference). 157




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##### Table of Contents



Exhibit No.

Sequential Description4
.9

Sixth Supplemental Indenture, dated as of July 10, 2008,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.1
    to the Companys
    Form 8-K
    filed July 10, 2008 and included herein by reference).4
.10

Seventh Supplemental Indenture, dated as of June 25, 2009,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.1
    to the Companys
    Form 8-K
    filed June 26, 2009 and included herein by reference).4
.11

Eighth Supplemental Indenture, dated as of August 14, 2009,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.1
    to the Companys
    Form 8-K
    filed August 17, 2009 and included herein by reference).4
.12

Amended and Restated Rights Agreement, dated as of
    December 20, 2005, between Quicksilver Resources Inc. and
    Mellon Investor Services LLC, as Rights Agent (filed as
    Exhibit 4.1 to the Companys
    Form 8-A/A
    (Amendment No. 1) filed December 21, 2005 and
    included herein by reference).10
.1

Wells Agreement dated as of December 15, 1970, between
    Union Oil Company of California and Montana Power Company (filed
    as Exhibit 10.5 to the Companys Predecessor, MSR
    Exploration Ltd.s
    Form S-4/A,
    File
    No. 333-29769,
    filed August 21, 1997 and included herein by reference).+ 10
.2

Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.6 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.3

Form of Incentive Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed January 28, 2005 and included herein by reference).+ 10
.4

Form of Non-Qualified Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.3 to the Companys
    Form 8-K
    filed January 28, 2005 and included herein by reference).+ 10
.5

Form of Retention Share Agreement pursuant to the Quicksilver
    Resources Inc.  Amended and Restated 1999 Stock Option
    and Retention Stock Plan (filed as Exhibit 10.3 to the
    Companys
    Form 8-K
    filed April 19, 2005 and included herein by reference).+ 10
.6

Form of Restricted Stock Unit Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.4 to the Companys
    Form 8-K
    filed April 19, 2005 and included herein by reference).+ 10
.7

Quicksilver Resources Inc.  Amended and Restated 2004
    Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
    the Companys
    Form 8-K
    filed May 25, 2007 and included herein by reference).+ 10
.8

Form of Non-Qualified Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 2004
    Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
    the Companys
    Form 8-K
    filed January 28, 2005 and included herein by reference).+ 10
.9

Form of Restricted Share Agreement pursuant to the Quicksilver
    Resources Inc.  Amended and Restated 2004 Non-Employee
    Director Equity Plan (filed as Exhibit 10.2 to the
    Companys
    Form 8-K
    filed May 18, 2005 and included herein by reference).+ 10
.10

Quicksilver Resources Inc.  Third Amended and Restated
    2006 Equity Plan (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed May 22, 2009 and included herein by reference).+ 10
.11

Form of Restricted Share Agreement pursuant to the Quicksilver
    Resources Inc.  2006 Equity Plan, as amended (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.12

Form of Restricted Stock Unit Agreement pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.2 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference). 158




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##### Table of Contents



Exhibit No.

Sequential Description+ 10
.13

Form of Quicksilver Resources Canada Inc.  Restricted
    Stock Unit Agreement (Cash Settlement) pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.3 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.14

Form of Quicksilver Resources Canada Inc.  Restricted
    Stock Unit Agreement (Stock Settlement) pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.4 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.15

Form of Incentive Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.5 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.16

Form of Nonqualified Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.6 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.17

Form of Non-Employee Director Nonqualified Stock Option
    Agreement pursuant to the Quicksilver Resources
    Inc.  2006 Equity Plan, as amended (One-Year Vesting)
    (filed as Exhibit 10.8 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.18

Form of Non-Employee Director Nonqualified Stock Option
    Agreement pursuant to the Quicksilver Resources
    Inc.  2006 Equity Plan, as amended (Three-Year
    Vesting) (filed as Exhibit 10.5 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.19

Form of Non-Employee Director Restricted Share Agreement
    pursuant to the Quicksilver Resources Inc.  2006
    Equity Plan, as amended (One-Year Vesting) (filed as
    Exhibit 10.7 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.20

Form of Non-Employee Director Restricted Share Agreement
    pursuant to the Quicksilver Resources Inc.  2006
    Equity Plan, as amended (Three-Year Vesting) (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed May 25, 2007 and included herein by reference).+ 10
.21

Quicksilver Resources Inc.  2008 Executive Bonus Plan
    (filed as Exhibit 10.1 to the Companys
    Form 8-K
    filed December 14, 2007 and included herein by reference).*+ 10
.22

Quicksilver Resources Inc. Amended and Restated 2009 Executive
    Bonus Plan.+ 10
.23

Quicksilver Resources Inc.  2010 Executive Bonus Plan
    (filed as Exhibit 10.1 to the Companys
    Form 8-K
    filed December 10, 2009 and included herein by reference).+ 10
.24

Quicksilver Resources Inc.  Amended and Restated
    Change in Control Retention Incentive Plan (filed as
    Exhibit 10.9 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.25

Quicksilver Resources Inc.  Second Amended and
    Restated Key Employee Change in Control Retention Incentive Plan
    (filed as Exhibit 10.8 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.26

Quicksilver Resources Inc.  Amended and Restated
    Executive Change in Control Retention Incentive Plan (filed as
    Exhibit 10.7 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.27

Form of Director and Officer Indemnification Agreement (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed August 26, 2005 and included herein by reference).10
.28

Amended and Restated Credit Agreement, dated as of
    February 9, 2007, among Quicksilver Resources Inc. and the
    lenders identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed February 12, 2007 and included herein by reference).10
.29

Amended and Restated Credit Agreement, dated as of
    February 9, 2007, among Quicksilver Resources Canada Inc.
    and the lenders and/or agents identified therein (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed February 12, 2007 and included herein by reference).* 10
.30

First Amendment to Combined Credit Agreements, dated as of
    February 4, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein. 159




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##### Table of Contents



Exhibit No.

Sequential Description* 10
.31

Second Amendment to Combined Credit Agreements, dated as of
    May 8, 2008, among Quicksilver Resources Inc., Quicksilver
    Resources Canada Inc. and the agents and combined lenders
    identified therein.* 10
.32

Third Amendment to Combined Credit Agreements, dated as of
    May 28, 2008, among Quicksilver Resources Inc., Quicksilver
    Resources Canada Inc. and the agents and combined lenders
    identified therein.10
.33

Fourth Amendment to Combined Credit Agreements, dated as of
    June 20, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed June 25, 2008 and included herein by reference).10
.34

Fifth Amendment to Combined Credit Agreements, dated as of
    August 4, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed August 5, 2008 and included herein by reference).* 10
.35

Sixth Amendment to Combined Credit Agreements, dated as of
    September 30, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein.* 10
.36

Seventh Amendment to Combined Credit Agreements, dated as of
    April 20, 2009, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein.10
.37

Eighth Amendment to Combined Credit Agreements, dated as of
    May 28, 2009, among Quicksilver Resources Inc., Quicksilver
    Resources Canada Inc. and the agents and combined lenders
    identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed June 17, 2009 and included herein by reference).10
.38

Credit Agreement, dated as of August 8, 2008, among
    Quicksilver Resources Inc., the lenders party thereto and Credit
    Suisse, Cayman Islands Branch, as administrative agent (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed August 8, 2008 and included herein by reference).10
.39

Amendment No. 1 to Credit Agreement, dated as of
    June 3, 2009, among Quicksilver Resources Inc., the lenders
    party thereto and Credit Suisse, Cayman Islands Branch, as
    administrative agent (filed as Exhibit 10.2 to the
    Companys
    Form 8-K
    filed June 17, 2009 and included herein by reference).10
.40

Registration Rights Agreement, dated as of November 1,
    2007, between Quicksilver Resources Inc. and BreitBurn Energy
    L.P. (filed as Exhibit 10.1 to the Companys
    Form 8-K
    filed November 7, 2007 and included herein by reference).+ 10
.41

Quicksilver Gas Services LP Second Amended and Restated 2007
    Equity Plan (filed as Exhibit 10.16 to Quicksilver Gas
    Services LPs
    Form 10-K,
    File
    No. 001-3363,
    filed March 15, 2010 and included herein by reference).+ 10
.42

Form of Phantom Unit Award Agreement for
    Non-Directors
    pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
    amended (Cash) (filed as Exhibit 10.10 to Quicksilver Gas
    Services LPs
    Form S-1/A,
    File
    No. 333-140599,
    filed July 17, 2007 and included herein by reference).+ 10
.43

Form of Phantom Unit Award Agreement for
    Non-Directors
    pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
    amended (Units) (filed as Exhibit 10.11 to Quicksilver Gas
    Services LPs
    Form S-1/A,
    File
    No. 333-140599,
    filed July 25, 2007 and included herein by reference).+ 10
.44

Quicksilver Gas Services LP Annual Bonus Plan (filed as
    Exhibit 10.1 to Quicksilver Gas Services LPs
    Form 8-K,
    File
    No. 001-33631,
    filed December 13, 2007 and included herein by reference).+ 10
.45

Form of Indemnification Agreement by and between Quicksilver Gas
    Services GP LLC and its officers and directors (filed as
    Exhibit 10.7 to Quicksilver Gas Services LPs
    Form S-1/A,
    File
    No. 333-140599,
    filed July 17, 2007 and included herein by reference). 160




---



##### Table of Contents



Exhibit No.

Sequential Description10
.46

Asset Purchase Agreement, dated as of May 15, 2009, among
    Quicksilver Resources Inc., as Seller, and ENI US Operating Co.
    Inc. and ENI Petroleum US LLC, as Buyers (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed May 19, 2009 and included herein by reference).10
.47

Letter Agreement, dated as of June 15, 2009, among
    Quicksilver Resources Inc., Quicksilver Resources Canada Inc.
    and the agents and combined lenders identified therein (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed June 17, 2009 and included herein by reference).* 21
.1

List of subsidiaries of Quicksilver Resources Inc.* 23
.1

Consent of Deloitte & Touche LLP..* 23
.2

Consent of PricewaterhouseCoopers LLP.* 23
.3

Consent of Schlumberger Data and Consulting Services.* 23
.4

Consent of LaRoche Petroleum Consultants, Ltd.* 23
.5

Consent of Netherland, Sewell & Associates, Inc.* 23
.6

Consent of Schlumberger Data and Consulting Services.* 31
.1

Certification Pursuant to Section 302 of the Sarbanes-Oxley
    Act of 2002.* 31
.2

Certification Pursuant to Section 302 of the Sarbanes-Oxley
    Act of 2002.* 32
.1

Certification Pursuant to 18 U.S.C. Section 1350, as
    adopted pursuant to Section 906 of the Sarbanes-Oxley Act
    of 2002.* 99
.1

Report of Schlumberger Data and Consulting Services.* 99
.2

Report of LaRoche Petroleum Consultants, Ltd.* 99
.3

Report of Netherland, Sewell & Associates, Inc.* 99
.4

Report of Schlumberger Data and Consulting Services.     *
    
    Filed herewith.**
    
    Excludes schedules and exhibits we agree to furnish
    supplementally to the SEC upon request.+
    
    Identifies management contracts and compensatory plans or
    arrangements. 161




---



##### Table of Contents



SIGNATURES    
  By:
    /s/  Glenn
    Darden         Signature

Title

Date/s/  Thomas
    F. DardenThomas
    F. Darden

Chairman of the Board; Director

March 15, 2010/s/  Glenn
    DardenGlenn
    Darden

President and Chief Executive Officer
    (Principal Executive Officer); Director

March 15, 2010/s/  Philip
    CookPhilip
    Cook

Senior Vice President  Chief Financial Officer
    (Principal Financial Officer)

March 15, 2010/s/  John
    C. ReganJohn
    C. Regan

Vice President, Controller and Chief Accounting Officer
    (Principal Accounting Officer)

March 15, 2010/s/  Anne
    Darden SelfAnne
    Darden Self

Director

March 15, 2010/s/  W.
    Byron DunnW.
    Byron Dunn

Director

March 15, 2010/s/  Steven
    M. MorrisSteven
    M. Morris

Director

March 15, 2010/s/  Yandell
    Rogers, IIIW.
    Yandell Rogers, III

Director

March 15, 2010/s/  Mark
    J. WarnerMark
    J. Warner

Director

March 15, 2010  162




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##### Table of Contents



EXHIBIT INDEX
  Exhibit No.

Sequential Description**2
.1

Contribution Agreement, dated September 11, 2007, between
    Quicksilver Resources Inc. and BreitBurn Operating
    L.P.  (filed as Exhibit 10.2 to the
    Companys
    Form 8-K
    filed November 7, 2007 and included herein by reference.)**2
.2

Purchase and Sale Agreement, dated as of July 3, 2008,
    among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus
    Development, L.P., and Perot Investment Partners, Ltd., as
    Sellers, and Quicksilver Resources Inc., as Purchaser (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed July 7, 2008 and included herein by reference).**2
.3

Purchase and Sale Agreement, dated as of July 3, 2008,
    among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P.,
    Chief Resources, LP, Hillwood Alliance Operating Company, L.P.,
    Chief Resources Alliance Pipeline LLC, Chief Oil & Gas
    LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark
    Rollins, as Sellers, and Quicksilver Resources Inc., as
    Purchaser (filed as Exhibit 10.2 to the Companys
    Form 8-K
    filed July 7, 2008 and included herein by reference).3
.1

Amended and Restated Certificate of Incorporation of Quicksilver
    Resources Inc. filed with the Secretary of State of the State of
    Delaware on May 21, 2008 (filed as Exhibit 4.1 to the
    Companys
    Form S-3,
    File
    No. 333-151847,
    filed June 23, 2008 and included herein by reference).3
.2

Amended and Restated Certificate of Designation of Series A
    Junior Participating Preferred Stock of Quicksilver Resources
    Inc.  (filed as Exhibit 3.3 to the Companys
    Form 10-Q
    filed May 6, 2006 and included herein by reference).3
.3

Amended and Restated Bylaws of Quicksilver Resources
    Inc.  (filed as Exhibit 3.1 to the Companys
    Form 8-K
    filed November 16, 2007 and included herein by reference).4
.1

Indenture Agreement for 1.875% Convertible Subordinated
    Debentures Due 2024, dated as of November 1, 2004, between
    Quicksilver Resources Inc., as Issuer, and The Bank of New York,
    as Trustee (as successor in interest to JPMorgan Chase Bank,
    National Association) (filed as Exhibit 4.1 to the
    Companys
    Form 8-K
    filed November 1, 2004 and included herein by reference).4
.2

First Supplemental Indenture, dated July 31, 2009, between
    Quicksilver Resources Inc. and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.2
    to the Companys
    Form 10-Q
    filed August 10, 2009 and included herein by reference).4
.3

Indenture, dated as of December 22, 2005, between
    Quicksilver Resources Inc. and The Bank of New York, as Trustee
    (as successor in interest to JPMorgan Chase Bank, National
    Association) (filed as Exhibit 4.7 to the Companys
    Form S-3,
    File
    No. 333-130597,
    filed December 22, 2005 and included herein by reference).4
.4

First Supplemental Indenture, dated as of March 16, 2006,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York, as Trustee (as successor
    in interest to JPMorgan Chase Bank, National Association) (filed
    as Exhibit 4.1 to the Companys
    Form 8-K
    filed March 21, 2006 and included herein by reference).*4
.5

Second Supplemental Indenture, dated as of July 31, 2006,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York, as Trustee (as successor
    in interest to JPMorgan Chase Bank, National Association).4
.6

Third Supplemental Indenture, dated as of September 26,
    2006, among Quicksilver Resources Inc., the subsidiary
    guarantors named therein and The Bank of New York, as Trustee
    (as successor in interest to JPMorgan Chase Bank, National
    Association) (filed as Exhibit 4.1 to the Companys
    Form 10-Q
    filed November 7, 2006 and included herein by reference).*4
.7

Fourth Supplemental Indenture, dated as of October 31,
    2007, among Quicksilver Resources Inc., the subsidiary
    guarantors named therein and The Bank of New York, as Trustee
    (as successor in interest to JPMorgan Chase Bank, National
    Association).4
.8

Fifth Supplemental Indenture, dated as of June 27, 2008,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Trust Company, N.A.,
    as trustee (filed as Exhibit 4.1 to the Companys
    Form 8-K
    filed June 30, 2008 and included herein by reference).




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##### Table of Contents



Exhibit No.

Sequential Description4
.9

Sixth Supplemental Indenture, dated as of July 10, 2008,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.1
    to the Companys
    Form 8-K
    filed July 10, 2008 and included herein by reference).4
.10

Seventh Supplemental Indenture, dated as of June 25, 2009,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.1
    to the Companys
    Form 8-K
    filed June 26, 2009 and included herein by reference).4
.11

Eighth Supplemental Indenture, dated as of August 14, 2009,
    among Quicksilver Resources Inc., the subsidiary guarantors
    named therein and The Bank of New York Mellon
    Trust Company, N.A., as trustee (filed as Exhibit 4.1
    to the Companys
    Form 8-K
    filed August 17, 2009 and included herein by reference).4
.12

Amended and Restated Rights Agreement, dated as of
    December 20, 2005, between Quicksilver Resources Inc. and
    Mellon Investor Services LLC, as Rights Agent (filed as
    Exhibit 4.1 to the Companys
    Form 8-A/A
    (Amendment No. 1) filed December 21, 2005 and
    included herein by reference).10
.1

Wells Agreement dated as of December 15, 1970, between
    Union Oil Company of California and Montana Power Company (filed
    as Exhibit 10.5 to the Companys Predecessor, MSR
    Exploration Ltd.s
    Form S-4/A,
    File
    No. 333-29769,
    filed August 21, 1997 and included herein by reference).+ 10
.2

Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.6 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.3

Form of Incentive Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed January 28, 2005 and included herein by reference).+ 10
.4

Form of Non-Qualified Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.3 to the Companys
    Form 8-K
    filed January 28, 2005 and included herein by reference).+ 10
.5

Form of Retention Share Agreement pursuant to the Quicksilver
    Resources Inc.  Amended and Restated 1999 Stock Option
    and Retention Stock Plan (filed as Exhibit 10.3 to the
    Companys
    Form 8-K
    filed April 19, 2005 and included herein by reference).+ 10
.6

Form of Restricted Stock Unit Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 1999
    Stock Option and Retention Stock Plan (filed as
    Exhibit 10.4 to the Companys
    Form 8-K
    filed April 19, 2005 and included herein by reference).+ 10
.7

Quicksilver Resources Inc.  Amended and Restated 2004
    Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
    the Companys
    Form 8-K
    filed May 25, 2007 and included herein by reference).+ 10
.8

Form of Non-Qualified Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  Amended and Restated 2004
    Non-Employee Director Equity Plan (filed as Exhibit 10.4 to
    the Companys
    Form 8-K
    filed January 28, 2005 and included herein by reference).+ 10
.9

Form of Restricted Share Agreement pursuant to the Quicksilver
    Resources Inc.  Amended and Restated 2004 Non-Employee
    Director Equity Plan (filed as Exhibit 10.2 to the
    Companys
    Form 8-K
    filed May 18, 2005 and included herein by reference).+ 10
.10

Quicksilver Resources Inc.  Third Amended and Restated
    2006 Equity Plan (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed May 22, 2009 and included herein by reference).+ 10
.11

Form of Restricted Share Agreement pursuant to the Quicksilver
    Resources Inc.  2006 Equity Plan, as amended (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.12

Form of Restricted Stock Unit Agreement pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.2 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.13

Form of Quicksilver Resources Canada Inc.  Restricted
    Stock Unit Agreement (Cash Settlement) pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.3 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).




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##### Table of Contents



Exhibit No.

Sequential Description+ 10
.14

Form of Quicksilver Resources Canada Inc.  Restricted
    Stock Unit Agreement (Stock Settlement) pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.4 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.15

Form of Incentive Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.5 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.16

Form of Nonqualified Stock Option Agreement pursuant to the
    Quicksilver Resources Inc.  2006 Equity Plan, as
    amended (filed as Exhibit 10.6 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.17

Form of Non-Employee Director Nonqualified Stock Option
    Agreement pursuant to the Quicksilver Resources
    Inc.  2006 Equity Plan, as amended (One-Year Vesting)
    (filed as Exhibit 10.8 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.18

Form of Non-Employee Director Nonqualified Stock Option
    Agreement pursuant to the Quicksilver Resources
    Inc.  2006 Equity Plan, as amended (Three-Year
    Vesting) (filed as Exhibit 10.5 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.19

Form of Non-Employee Director Restricted Share Agreement
    pursuant to the Quicksilver Resources Inc.  2006
    Equity Plan, as amended (One-Year Vesting) (filed as
    Exhibit 10.7 to the Companys
    Form 8-K
    filed May 25, 2006 and included herein by reference).+ 10
.20

Form of Non-Employee Director Restricted Share Agreement
    pursuant to the Quicksilver Resources Inc.  2006
    Equity Plan, as amended (Three-Year Vesting) (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed May 25, 2007 and included herein by reference).+ 10
.21

Quicksilver Resources Inc.  2008 Executive Bonus Plan
    (filed as Exhibit 10.1 to the Companys
    Form 8-K
    filed December 14, 2007 and included herein by reference).*+ 10
.22

Quicksilver Resources Inc.  Amended and Restated 2009
    Executive Bonus Plan.+ 10
.23

Quicksilver Resources Inc.  2010 Executive Bonus Plan
    (filed as Exhibit 10.1 to the Companys
    Form 8-K
    filed December 10, 2009 and included herein by reference).+ 10
.24

Quicksilver Resources Inc.  Amended and Restated
    Change in Control Retention Incentive Plan (filed as
    Exhibit 10.9 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.25

Quicksilver Resources Inc.  Second Amended and
    Restated Key Employee Change in Control Retention Incentive Plan
    (filed as Exhibit 10.8 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.26

Quicksilver Resources Inc.  Amended and Restated
    Executive Change in Control Retention Incentive Plan (filed as
    Exhibit 10.7 to the Companys
    Form 8-K
    filed November 24, 2008 and included herein by reference).+ 10
.27

Form of Director and Officer Indemnification Agreement (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed August 26, 2005 and included herein by reference).10
.28

Amended and Restated Credit Agreement, dated as of
    February 9, 2007, among Quicksilver Resources Inc. and the
    lenders identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed February 12, 2007 and included herein by reference).10
.29

Amended and Restated Credit Agreement, dated as of
    February 9, 2007, among Quicksilver Resources Canada Inc.
    and the lenders and/or agents identified therein (filed as
    Exhibit 10.2 to the Companys
    Form 8-K
    filed February 12, 2007 and included herein by reference).* 10
.30

First Amendment to Combined Credit Agreements, dated as of
    February 4, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein.* 10
.31

Second Amendment to Combined Credit Agreements, dated as of
    May 8, 2008, among Quicksilver Resources Inc., Quicksilver
    Resources Canada Inc. and the agents and combined lenders
    identified therein.* 10
.32

Third Amendment to Combined Credit Agreements, dated as of
    May 28, 2008, among Quicksilver Resources Inc., Quicksilver
    Resources Canada Inc. and the agents and combined lenders
    identified therein.




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##### Table of Contents



Exhibit No.

Sequential Description10
.33

Fourth Amendment to Combined Credit Agreements, dated as of
    June 20, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed June 25, 2008 and included herein by reference).10
.34

Fifth Amendment to Combined Credit Agreements, dated as of
    August 4, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed August 5, 2008 and included herein by reference).* 10
.35

Sixth Amendment to Combined Credit Agreements, dated as of
    September 30, 2008, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein.* 10
.36

Seventh Amendment to Combined Credit Agreements, dated as of
    April 20, 2009, among Quicksilver Resources Inc.,
    Quicksilver Resources Canada Inc. and the agents and combined
    lenders identified therein.10
.37

Eighth Amendment to Combined Credit Agreements, dated as of
    May 28, 2009, among Quicksilver Resources Inc., Quicksilver
    Resources Canada Inc. and the agents and combined lenders
    identified therein (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed June 17, 2009 and included herein by reference).10
.38

Credit Agreement, dated as of August 8, 2008, among
    Quicksilver Resources Inc., the lenders party thereto and Credit
    Suisse, Cayman Islands Branch, as administrative agent (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed August 8, 2008 and included herein by reference).10
.39

Amendment No. 1 to Credit Agreement, dated as of
    June 3, 2009, among Quicksilver Resources Inc., the lenders
    party thereto and Credit Suisse, Cayman Islands Branch, as
    administrative agent (filed as Exhibit 10.2 to the
    Companys
    Form 8-K
    filed June 17, 2009 and included herein by reference).10
.40

Registration Rights Agreement, dated as of November 1,
    2007, between Quicksilver Resources Inc. and BreitBurn Energy
    L.P.  (filed as Exhibit 10.1 to the
    Companys
    Form 8-K
    filed November 7, 2007 and included herein by reference).+ 10
.41

Quicksilver Gas Services LP Second Amended and Restated 2007
    Equity Plan (filed as Exhibit 10.16 to Quicksilver Gas
    Services LPs
    Form 10-K,
    File
    No. 001-3363,
    filed March 15, 2010 and included herein by reference).+ 10
.42

Form of Phantom Unit Award Agreement for
    Non-Directors
    pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
    amended (Cash). (filed as Exhibit 10.10 to Quicksilver Gas
    Services LPs
    Form S-1/A,
    File
    No. 333-140599,
    filed July 17, 2007 and included herein by reference).+ 10
.43

Form of Phantom Unit Award Agreement for
    Non-Directors
    pursuant to the Quicksilver Gas Services LP 2007 Equity Plan, as
    amended (Units) (filed as Exhibit 10.11 to Quicksilver Gas
    Services LPs
    Form S-1/A,
    File
    No. 333-140599,
    filed July 25, 2007 and included herein by reference).+ 10
.44

Quicksilver Gas Services LP Annual Bonus Plan (filed as
    Exhibit 10.1 to Quicksilver Gas Services LPs
    Form 8-K,
    File
    No. 001-33631,
    filed December 13, 2007 and included herein by reference).+ 10
.45

Form of Indemnification Agreement by and between Quicksilver Gas
    Services GP LLC and its officers and directors (filed as
    Exhibit 10.7 to Quicksilver Gas Services LPs
    Form S-1/A,
    File
    No. 333-140599,
    filed July 17, 2007 and included herein by reference).10
.46

Asset Purchase Agreement, dated as of May 15, 2009, among
    Quicksilver Resources Inc., as Seller, and ENI US Operating Co.
    Inc. and ENI Petroleum US LLC, as Buyers (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed May 19, 2009 and included herein by reference).10
.47

Letter Agreement, dated as of June 15, 2009, among
    Quicksilver Resources Inc., Quicksilver Resources Canada Inc.
    and the agents and combined lenders identified therein (filed as
    Exhibit 10.1 to the Companys
    Form 8-K
    filed June 17, 2009 and included herein by reference).* 21
.1

List of subsidiaries of Quicksilver Resources Inc.* 23
.1

Consent of Deloitte & Touche LLP.* 23
.2

Consent of PricewaterhouseCoopers LLP.




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##### Table of Contents



Exhibit No.

Sequential Description* 23
.3

Consent of Schlumberger Data and Consulting Services.* 23
.4

Consent of LaRoche Petroleum Consultants, Ltd.* 23
.5

Consent of Netherland, Sewell & Associates, Inc.* 23
.6

Consent of Schlumberger Data and Consulting Services.* 31
.1

Certification Pursuant to Section 302 of the Sarbanes-Oxley
    Act of 2002.* 31
.2

Certification Pursuant to Section 302 of the Sarbanes-Oxley
    Act of 2002.* 32
.1

Certification Pursuant to 18 U.S.C. Section 1350, as
    adopted pursuant to Section 906 of the Sarbanes-Oxley Act
    of 2002.* 99
.1

Report of Schlumberger Data and Consulting Services.* 99
.2

Report of LaRoche Petroleum Consultants, Ltd.* 99
.3

Report of Netherland, Sewell & Associates, Inc.* 99
.4

Report of Schlumberger Data and Consulting Services.     *
    
    Filed herewith.**
    
    Excludes schedules and exhibits we agree to furnish
    supplementally to the SEC upon request.+
    
    Identifies management contracts and compensatory plans or
    arrangements