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Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number: 001-14837
Quicksilver Resources Inc.
(Exact name of registrant as specified in its charter)
     
Delaware   75-2756163
(State or other jurisdiction of   (I.R.S. Employer Identification No.)
incorporation or organization)    
     
801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas   76102
(Address of principal executive offices)   (Zip Code)
(817) 665-5000
(Registrant’s telephone number, including area code)
     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
 
      (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
     
Title of Class   Outstanding as of April 22, 2011
Common Stock, $0.01 par value   171,111,829
 
 

 


Table of Contents

DEFINITIONS
As used in this Quarterly Report unless the context otherwise requires:
ABR” means alternate base rate
AMT” means alternative minimum tax in the U.S.
AOCI” means accumulated other comprehensive income
Bbl” or “Bbls” means barrel or barrels
Bbld” means barrel or barrels per day
Bcf” means billion cubic feet
Bcfd” means billion cubic feet per day
Bcfe” means Bcf of natural gas equivalents
Canada” means our oil and natural gas operations located in Canada
DD&A” means Depletion, Depreciation and Accretion
GPT” means gathering, processing and transportation expense
LIBOR” means London Interbank Offered Rate
MBbl” or “MBbls” means thousand barrels
MBbld” means thousand barrels per day
MMBbls” means million barrels
MMBtu” means million British Thermal Units, a measure of heating value, and is approximately equal to one Mcf of natural gas
MMBtud” means million Btu per day
Mcf” means thousand cubic feet
Mcfe” means Mcf natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcf” means million cubic feet
MMcfd” means million cubic feet per day
MMcfe” means MMcf of natural gas equivalents
MMcfed” means MMcfe per day
NGL” or “NGLs” means natural gas liquids
NYMEX” means New York Mercantile Exchange
NYSE” means New York Stock Exchange
OCI” means other comprehensive income
Oil” includes crude oil and condensate
RSU” means restricted stock unit
Tcf” means trillion cubic feet
COMMONLY USED TERMS
Other commonly used terms and abbreviations include:
Alliance Leasehold” means the natural gas leasehold and royalty interests acquired in the Alliance Acquisition and developed thereafter
Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth Basin of North Texas
BBEP” means BreitBurn Energy Partners L.P.
BBEP Unit” means BBEP limited partner unit
Crestwood” means Crestwood Holdings LLC
Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, consisting of 100% of the general partner units, including incentive distribution rights, all of our common and subordinated units and the subordinated note due from KGS
Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA
Eni Production” means production attributable to Eni pursuant to the Eni Transaction
Eni Transaction” means the 2009 conveyance of a 27.5% interest in our Alliance Leasehold
FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.
FASC” means the FASB Accounting Standards Codification, which is the single source of authoritative U.S. GAAP not promulgated by the SEC
GAAP” means accounting principles generally accepted in the U.S.

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Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase the Eni Production at a fixed price and which expired on December 31, 2010
Greater Green River Asset” means our operations and our assets in the Greater Green River Basin located in Colorado and southern Wyoming
HCDS” means Hill County Dry System, a gas gathering system in Hill County, Texas within the Barnett Shale
Horn River Asset” means our operations and our assets in the Horn River Basin of Northeast British Columbia
Horseshoe Canyon Asset” means our operations and our assets in Horseshoe Canyon, the coalbed methane fields of southern and central Alberta
KGS” means Quicksilver Gas Services LP, a publicly-traded partnership, which we formerly owned that traded under the ticker symbol of “KGS” and subsequent to the Crestwood Transaction renamed itself Crestwood Midstream Partners LP and trades under the ticker symbol “CMLP”
KGS Secondary Offering” means the public offering of 4,000,000 KGS common units in 2009 and the underwriters’ purchase of an additional 549,200 KGS common units in 2010
Mercury” means Mercury Exploration Company, which is owned by members of the Darden family
SEC” means the U.S. Securities and Exchange Commission
Senior Secured Credit Facility” means our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility
Southern Alberta Asset” means our operations and our assets in the Southern Alberta Basin of northern Wyoming and Montana, including our Cutbank field operations and assets

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INDEX TO QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2011
         
  6    
 
       
  6    
 
       
  25    
 
       
  37    
 
       
  38    
 
       
  39    
 
       
  39    
 
       
  39    
 
       
  39    
 
       
  40    
 
       
  40    
 
       
  40    
 
       
  40    
 
       
  41    
 EX-31.1
 EX-31.2
 EX-32.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT
Except as otherwise specified and unless the context otherwise requires, references to the “Company,” “Quicksilver,” “we,” “us,” and “our” refer to Quicksilver Resources Inc. and its subsidiaries.

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Forward-Looking Information
     Certain statements contained in this Quarterly Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995.  Forward-looking statements give our current expectations or forecasts of future events.  Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements.  They can be affected by assumptions used or by known or unknown risks or uncertainties.  Consequently, no forward-looking statements can be guaranteed.  Actual results may vary materially.  You are cautioned not to place undue reliance on any forward-looking statements.  You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties.  Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
    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;
 
    delays in construction of transportation pipelines and gathering and treating facilities;
 
    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 Quarterly Report.
     This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business.  Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K.  All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control.  The forward-looking statements included in this Quarterly Report are made only as of the date of this Quarterly Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law. 
     All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. 

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PART I FINANCIAL INFORMATION
ITEM 1. Condensed Consolidated Interim Financial Statements (Unaudited)
QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
In thousands, except for per share data – Unaudited
                 
    For the Three Months Ended  
    March 31,  
    2011     2010  
Revenue:
               
Natural gas, NGL and oil
  190,301     201,563  
Sales of purchased natural gas
    20,426       16,224  
Other
    1,460       4,371  
 
       
Total revenue
    212,187       222,158  
 
       
 
               
Operating expense:
               
Lease operating
    21,557       19,964  
Gathering, processing and transportation
    44,014       16,002  
Production and ad valorem taxes
    7,581       8,506  
Costs of purchased natural gas
    19,743       33,307  
Other operating
    160       1,254  
Depletion, depreciation and accretion
    52,471       46,757  
Impairment
    49,063       -  
General and administrative
    18,391       20,523  
 
       
Total expense
    212,980       146,313  
 
       
Operating income (loss)
    (793 )     75,845  
Loss from earnings of BBEP
    (20,884 )     (15,989 )
Other income - net
    1,121       343  
Interest expense
    (46,178 )     (44,517 )
 
       
Income (loss) before income taxes
    (66,734 )     15,682  
Income tax expense
    (4,024 )     (5,082 )
 
       
Net income (loss)
    (70,758 )     10,600  
Net income attributable to noncontrolling interests
    -       (2,412 )
 
       
Net income (loss) attributable to Quicksilver
  $ (70,758 )   8,188  
 
       
Other comprehensive income (loss)
               
Reclassification adjustments related to settlements
               
of derivative contracts - net of income tax
    (16,219 )     (26,269 )
Net change in derivative fair value - net of income tax
    (17,195 )     98,606  
Foreign currency translation adjustment
    12,004       6,960  
 
       
Comprehensive income (loss)
  $ (92,168 )   87,485  
 
       
 
               
Earnings (loss) per common share - basic
  $ (0.42 )   0.05  
 
               
Earnings (loss) per common share - diluted
  $ (0.42 )   0.05  
The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for share data – Unaudited
                 
    March 31,     December 31,  
    2011     2010  
ASSETS
Current assets
               
Cash and cash equivalents
  2     54,937  
Accounts receivable - net of allowance for doubtful accounts
    76,694       63,380  
Derivative assets at fair value
    61,132       89,205  
Other current assets
    28,285       30,650  
 
       
Total current assets
    166,113       238,172  
Investments in equity affiliates
    55,674       83,341  
Property, plant and equipment - net
               
Oil and gas properties, full cost method (including unevaluated costs of $356,566 and $304,269, respectively)
    2,912,947       2,834,645  
Other property and equipment
    271,045       233,200  
 
       
Property, plant and equipment - net
    3,183,992       3,067,845  
Assets of midstream operations held for sale
    26,421       27,178  
Derivative assets at fair value
    38,008       57,557  
Other assets
    39,744       38,241  
 
       
 
  3,509,952     3,512,334  
 
       
LIABILITIES AND EQUITY
Current liabilities
               
Current portion of long-term debt
  145,396     143,478  
Accounts payable
    141,532       167,857  
Accrued liabilities
    106,038       122,904  
Derivative liabilities at fair value
    1,965       -  
Current deferred tax liability
    19,050       28,861  
 
       
Total current liabilities
    413,981       463,100  
Long-term debt
    1,880,768       1,746,716  
Liabilities of midstream operations held for sale
    1,448       1,431  
Asset retirement obligations
    61,329       56,235  
Derivative liabilities at fair value
    972       -  
Other liabilities
    28,461       28,461  
Deferred income taxes
    154,704       156,983  
Commitments and contingencies (Note 8)
               
Stockholders’ equity
               
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding
    -       -  
Common stock, $0.01 par value, 400,000,000 shares authorized, and 176,665,190 and 175,524,816 shares issued, respectively
    1,767       1,755  
Paid in capital in excess of par value
    720,703       714,869  
Treasury stock of 5,373,195 and 5,050,450 shares, respectively
    (46,284 )     (41,487 )
Accumulated other comprehensive income
    108,777       130,187  
Retained earnings
    183,326       254,084  
 
       
Total stockholders’ equity
    968,289       1,059,408  
 
       
 
  3,509,952     3,512,334  
 
       
The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
In thousands – Unaudited
                                                         
    Quicksilver Resources Inc. Stockholders’ Equity              
                            Accumulated                    
            Additional             Other                    
    Common     Paid-in     Treasury     Comprehensive     Retained     Noncontrolling        
    Stock     Capital     Stock     Income     Earnings     Interest     Total  
Balances at December 31, 2009
    1,745       730,265       (36,363 )     121,336       (180,985 )     60,824       696,822  
Net income
    -       -       -       -       8,188       2,412       10,600  
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $14,006
    -       -       -       (26,269 )     -       -       (26,269 )
Net change in derivative fair value, net of income tax of $49,567
    -       -       -       98,606       -       -       98,606  
Currency translation adjustment
    -       -       -       6,960       -       -       6,960  
Issuance & vesting of stock compensation
    8       5,006       (4,766 )     -       -       (478 )     (230 )
Stock option exercises
    1       759       -       -       -       -       760  
Issuance of KGS common units
    -       6,743       -       -       -       4,307       11,050  
Distributions paid on KGS common units
    -       -       -       -       -       (4,404 )     (4,404 )
 
                           
Balances at March 31, 2010
  1,754     742,773     $ (41,129 )   200,633     $ (172,797 )   62,661     793,895  
 
                           
 
                                                       
Balances at December 31, 2010
  1,755     714,869     $ (41,487 )   130,187     254,084     -     1,059,408  
Net loss
    -       -       -       -       (70,758 )     -       (70,758 )
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $7,781
    -       -       -       (16,219 )     -       -       (16,219 )
Net change in derivative fair value, net of income tax of $9,311
    -       -       -       (17,195 )     -       -       (17,195 )
Currency translation adjustment
    -       -       -       12,004       -       -       12,004  
Issuance & vesting of stock compensation
    11       5,467       (4,797 )     -       -       -       681  
Stock option exercises
    1       367       -       -       -       -       368  
 
                           
Balances at March 31, 2011
  1,767     720,703     $ (46,284 )   108,777     183,326     -     968,289  
 
                           
The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands – Unaudited
                 
    For the Three Months Ended  
    March 31,  
    2011     2010  
Operating activities:
               
Net income (loss)
  $ (70,758 )   10,600  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depletion, depreciation and accretion
    52,471       46,757  
Impairment expense
    49,063       -  
Deferred income tax expense
    4,024       5,082  
Non-cash loss from hedging and derivative activities
    54       1,421  
Stock-based compensation
    5,478       5,680  
Non-cash interest expense
    3,880       5,075  
Gain on disposition of BBEP units
    (1,289 )     -  
Loss from BBEP in excess of cash distributions
    27,253       15,989  
Other
    89       (323 )
Changes in assets and liabilities
               
Accounts receivable
    (13,256 )     4,905  
Derivative assets at fair value
    -       14,260  
Prepaid expenses and other assets
    (3,451 )     5,519  
Accounts payable
    (24,711 )     (15,553 )
Accrued and other liabilities
    (17,134 )     (33,640 )
 
       
Net cash provided by operating activities
    11,713       65,772  
 
       
 
               
Investing activities:
               
Purchases of property, plant and equipment
    (196,547 )     (129,331 )
Proceeds from sale of BBEP units
    1,703       -  
Proceeds from sale of properties and equipment
    507       718  
 
       
Net cash used by investing activities
    (194,337 )     (128,613 )
 
       
 
               
Financing activities:
               
Issuance of debt
    147,983       295,446  
Repayments of debt
    (15,145 )     (227,639 )
Debt issuance costs paid
    -       (109 )
Gas Purchase Commitment repayments
    -       (7,317 )
Issuance of KGS common units - net offering costs
    -       11,050  
Distributions paid on KGS common units
    -       (4,404 )
Proceeds from exercise of stock options
    368       760  
Taxes paid on vesting of KGS equity compensation
    -       (1,144 )
Purchase of treasury stock
    (4,797 )     (4,766 )
 
       
Net cash provided by financing activities
    128,409       61,877  
 
       
Effect of exchange rate changes in cash
    (720 )     (220 )
 
       
Net decrease in cash
    (54,935 )     (1,184 )
Cash and cash equivalents at beginning of period
    54,937       1,785  
 
       
Cash and cash equivalents at end of period
  2     601  
 
       
The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Unaudited
1. ACCOUNTING POLICIES AND DISCLOSURES
     The accompanying condensed consolidated interim financial statements have not been audited.  In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of March 31, 2011 and our results of operations and cash flows for the three months ended March 31, 2010 and 2011.  All such adjustments are of a normal recurring nature.  The results for interim periods are not necessarily indicative of annual results. 
     The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates. 
     Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted.  Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2010 Annual Report on Form 10-K. 
Recently Issued Accounting Standards
     Accounting standards-setting organizations frequently issue new or revised accounting rules.  We regularly review all new pronouncements to determine their impact, if any, on our financial statements.  No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K. 
2. CRESTWOOD TRANSACTION AND MIDSTREAM OPERATIONS
     In October 2010, we completed the sale of all of our interests in KGS to Crestwood.  We received net proceeds of $700 million and recognized a gain of $473.2 million during the fourth quarter of 2010.  Our board of directors approved a plan for disposal of the HCDS, which is included in our midstream segment.  Subsequent to our board of directors’ approval, we conducted an impairment analysis of the HCDS and recognized a charge for impairment in the third quarter of 2010. 
     The operating results of these midstream operations, as classified in our statement of income, are summarized below:
         
For the Three Months Ended March 31, 2010  
    (In thousands)  
Revenue
  $ 3,744  
GPT expense (1)
    (16,522 )
Ad valorem taxes
    1,533  
Other operations
    1,274  
DD&A
    6,126  
General and administrative expense
    1,128  
 
   
Operating results of midstream operations
    10,205  
Interest and other expense
    (2,082 )
 
   
Results of midstream operations before income tax
    8,123  
Income tax expense
    (2,878 )
 
   
Results of midstream operations, net of income tax
  $ 5,245  
 
   
 
(1)   Our KGS operations earned revenue from gathering and processing of our natural gas and NGL production. This revenue was consolidated as a reduction of processing, gathering and transportation expense for purposes of presenting our consolidated statements of income.

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     Details of balance sheet items for these midstream operations are summarized below:
                 
    March 31,     December 31,  
    2011     2010  
Assets:   (In thousands)
 
               
Accounts receivable, net
  39     57  
Property, plant and equipment, net
    26,382       27,121  
 
       
Total
  26,421     27,178  
 
       
 
               
Liabilities:
               
 
               
Other non-current liabilities
  1,448     1,431  
 
       
Total
  1,448     1,431  
 
       
     Note 3 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction. 
3. DERIVATIVES AND FAIR VALUE MEASUREMENTS
     The following table identifies our derivative instruments where estimated fair value is based upon the use of “Level 2” inputs at March 31, 2011 and December 31, 2010:
                 
    March 31,     December 31,  
    2011     2010  
    (In thousands)  
Commodity contracts
  96,203     146,762  
 
       
Total
  96,203     146,762  
 
       
     The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties.  Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value.  This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. 
Commodity Price Derivatives
     As of March 31, 2011, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:
                 
Production   Daily Production  
Year   Gas     NGL  
    MMcfd     MBbld  
2011     190       10.5  
2012     130       2.0  
2013     70       -  
2014-2015     30       -  
Interest Rate Derivatives
     In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes.  We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned.  Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes. 

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     The remaining $26.4 million deferral of the 2010 early settlements from all interest rate swaps will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:
         
(In thousands)  
   
2011   3,711  
2012     5,315  
2013     5,769  
2014     6,261  
2015     4,824  
2016     569  
 
   
 
  26,449  
 
   
Fair Value Disclosures
     The estimated fair value of our derivative instruments at March 31, 2011 and December 31, 2010 were as follows:
                                   
    Asset Derivatives       Liability Derivatives  
    March 31,     December 31,       March 31,     December 31,  
    2011     2010       2011     2010  
    (In thousands)       (In thousands)  
Derivatives designated as hedges:
                                 
Commodity contracts reported in:
                                 
Current derivative assets
  82,720     97,863       21,588     8,658  
Noncurrent derivative assets
    41,149       63,419         3,141       5,862  
Current derivative liabilities
    -       -         1,965       -  
Noncurrent derivative liabilities
    2,192       -         3,164       -  
 
                 
Total derivatives designated as hedges
  126,061     161,282       29,858     14,520  
 
                 
 
                                 
Derivatives not designated as hedges:
  -     -       -     -  
 
                 
Total derivatives
  126,061     161,282       29,858     14,520  
 
                 
     The decrease in carrying value of our commodity price derivatives since December 31, 2010 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments and, to a lesser degree, monthly settlements received during 2011. 
     The changes in the carrying value of our derivatives for the three months ended March 31, 2011 and 2010 are presented below:
                                         
    For the Three Months Ended March 31,  
    2011     2010  
    Cash Flow     Gas Purchase     Fair Value     Cash Flow        
    Derivatives     Commitment     Derivatives     Derivatives     Total  
            (In thousands)  
Derivative fair value at beginning of period
  146,762     $ (6,625 )   4,108     107,881     105,364  
Change in amounts receivable/payable-net
    (218 )     -       (4,997 )     (2,223 )     (7,220 )
Net settlements reported in revenue
    (23,782 )     -       -       (24,557 )     (24,557 )
Net settlements reported in interest expense
    -       -       (2,296 )     -       (2,296 )
Cash settlements reported in long-term debt
    -       -       (13,934 )     -       (13,934 )
Unrealized change in fair value of Gas Purchase Commitment reported in costs of purchased gas
    -       (16,638 )     -       -       (16,638 )
Change in fair value of effective interest swaps
    -       -       12,089       -       12,089  
Ineffectiveness reported in other revenue
    (53 )     -       -       1,395       1,395  
Unrealized gains (losses) reported in OCI
    (26,506 )     -       -       148,222       148,222  
 
                   
Derivative fair value at end of period
  96,203     $ (23,263 )   $ (5,030 )   230,718     202,425  
 
                   

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     Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $41.0 million net of income taxes.  Hedge derivative ineffectiveness resulted in net losses of $0.1 million and net gains of $1.4 million for the three months ended March 31, 2011 and 2010, respectively. 
4. INVESTMENT IN BBEP
     At March 31, 2011, we owned 15.6 million BBEP Units, or 26%, of BBEP, whose price closed at $21.73 per unit as of that date.  Our ownership interest in BBEP was reduced in February 2011 when BBEP issued approximately 4.9 million BBEP Units.  We further reduced our ownership during the three months ended March 31, 2011 through the sale of approximately 0.1 million BBEP Units at a weighted average unit sales price of $21.83.  We recognized a gain of $1.3 million as other income for the difference between our carrying value at the time of the sale of $5.31 per BBEP Unit and the net sales proceeds. 
     Changes in the balance of our investment in BBEP for the three months ended March 31, 2011 were as follows:
         
(In thousands)  
Balance at December 31, 2010
  $ 83,341  
Equity loss in BBEP
    (20,884 )
Distributions from BBEP
    (6,369 )
Disposal of BBEP Units
    (414 )
 
   
Ending investment balance
  $ 55,674  
 
   
     We account for our investment in BBEP Units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information.  Summarized estimated financial information for BBEP is as follows:
                 
    For the Three Months Ended  
    December 31,  
    2010     2009  
    (In thousands)  
Revenue (1)
  $ 18,165     $ 38,263  
Operating expense
    79,483       73,272  
 
       
Operating loss
    (61,318 )     (35,009 )
Interest and other (2)
    9,989       5,859  
Income tax benefit
    (439 )     (1,174 )
Noncontrolling interests
    35       19  
 
       
Net loss available to BBEP
  $ (70,903 )   $ (39,713 )
 
       
  (1)  For the three months ended December 31, 2010 and 2009, unrealized losses of $82.3 million and $54.7 million on commodity derivatives were recognized, respectively.
 
  (2)  The three months ended December 31, 2010 and 2009 included unrealized gains of $3.1 million and unrealized losses of $0.7 million, respectively, from interest rate swaps.
                 
    As of December 31,
    2010   2009
    (In thousands)
Current assets
  $ 145,233     $ 142,441  
Property, plant and equipment
    1,728,256       1,741,089  
Other assets
    98,113       87,499  
Current liabilities
    85,035       91,890  
Long-term debt
    516,000       559,000  
Other non-current liabilities
    64,715       91,338  
Partners’ equity
    1,305,852       1,228,801  

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5. PROPERTY, PLANT AND EQUIPMENT
     Property, plant and equipment consisted of the following:
                 
    March 31,   December 31,
    2011   2010
    (In thousands)
Oil and gas properties
               
Subject to depletion
  $    4,939,775     $    4,805,161  
Unevaluated costs
    356,566       304,269  
Accumulated depletion
    (2,383,394 )     (2,274,785 )
 
           
Net oil and gas properties
    2,912,947       2,834,645  
 
               
Other plant and equipment
               
Pipelines and processing facilities
    277,500       235,676  
General properties
    70,907       70,267  
Accumulated depreciation
    (77,362 )     (72,743 )
 
           
Net other property and equipment
    271,045       233,200  
 
           
 
               
Property, plant and equipment, net of accumulated depletion and depreciation
  $    3,183,992     $    3,067,845  
 
           
Ceiling Test Analysis
     We recorded impairment expense of $49.1 million for our Canadian oil and gas properties at March 31, 2011.  We computed the March 31, 2011 ceiling amount using an AECO price of $3.59 Mcf of natural gas, calculated as the unweighted average of the preceding 12-month first-day-of-the-month prices.  The AECO natural gas price used to compute the ceiling amount at March 31, 2011 was 12% lower than the AECO price used in computing the ceiling amount at December 31, 2010.  The ceiling test prepared for our U.S.  oil and gas properties resulted in no impairment at March 31, 2011. 
     Notes 2 and 8 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis. 
6. LONG-TERM DEBT
     Long-term debt consisted of the following:
                 
    March 31,   December 31,
    2011   2010
    (In thousands)
Senior Secured Credit Facility
  $    155,386     $    21,114  
Senior notes due 2015, net of unamortized discount
    471,092       470,866  
Senior notes due 2016, net of unamortized discount
    584,219       583,605  
Senior notes due 2019, net of unamortized discount
    293,622       293,496  
Senior subordinated notes due 2016
    350,000       350,000  
Convertible debentures, net of unamortized discount
    145,396       143,478  
 
           
Total debt
    1,999,715       1,862,559  
Unamortized deferred gain - terminated interest rate swaps
    26,449       27,635  
Current portion of long-term debt
    (145,396 )     (143,478 )
 
           
Long-term debt
  $    1,880,768     $    1,746,716  
 
           

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Senior Secured Credit Facility
     The Senior Secured Credit Facility borrowing base and commitments remained at $1 billion and the aggregate letter of credit capacity was $175 million.  At March 31, 2011, there was $795 million available under the facility. 
Convertible Debentures
     The convertible debentures due November 1, 2024 are contingently convertible into shares of our common stock.  The debentures bear interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1.  Additionally, holders of the debentures can require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 and 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest.  The debentures are convertible into shares of our common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment.  Generally, except upon the occurrence of specified events including certain changes of control, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock is at least $18.34 (120% of the conversion price per share) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter.  Upon conversion, we have the option to deliver any combination of our common stock and cash.  Should all debentures be converted to our common stock, an additional 9,816,270 shares, subject to adjustment, would become outstanding; however, as of April 1, 2011, the debentures were not convertible based on share prices for the quarter ended March 31, 2011. 
     Because we may be required to repurchase these obligations at the option of the holders on November 1, 2011, we have reported them as current obligations in our March 31, 2011 and December 31, 2010 balance sheets.  To the extent that the holders of these obligations do not elect to put them to us on November 1, 2011, any remaining obligations will be reclassified to long-term after that date. 
     At March 31, 2011 and December 31, 2010, the remaining unamortized discount on the debentures was $4.6 million and $6.5 million, respectively, resulting in a carrying value of $145.4 million and $143.5 million, respectively.  The remaining discount will be accreted to face value through October 2011.  For the three months ended March 31, 2011 and 2010, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $2.6 million and $2.5 million, respectively, including contractual interest of $0.7 million for each period. 

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Summary of All Outstanding Debt
     The following table summarizes significant aspects of our long-term debt:
                                                 
    Priority on Collateral and Structural Seniority (1)
    Highest priority   (ARROW) Lowest priority  
        Equal priority        
    Senior Secured 2015 2016 2019 Senior Convertible
    Credit Facility Senior Notes Senior Notes Senior Notes Subordinated Notes Debentures(1)
Principal amount
  $1.0 billion (3)   $475 million   $600 million   $300 million   $350 million   $150 million
 
Scheduled maturity date (5)
  February 9, 2013   August 1, 2015   January 1, 2016   August 15, 2019   April 1, 2016   November 1, 2024
 
Interest rate on outstanding
borrowings at
March 31, 2011 (4)
    3.22 %     8.25 %     11.75 %     9.125 %     7.125 %     1.875 %
 
Base interest rate options
  LIBOR, ABR or
specified(5)
    N/A       N/A       N/A       N/A       N/A  
 
Financial covenants (5)
  - Minimum current
ratio of 1.0
    N/A       N/A       N/A       N/A       N/A  
 
  - Minimum EBITDA to
interest expense ratio
of 2.5
                                       
 
Significant restrictive
covenants (6)
  - Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
- Limitations on derivatives
  - Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
  - Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
  - Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
  - Incurrence of debt
- Incurrence of liens
- Payment of dividends
- Equity purchases
- Asset sales
- Affiliate transactions
    N/A  
 
Optional redemption (6)
  Any time   August 1,
2012: 103.875
2013: 101.938
2014: par       
  July 1,
2013: 105.875
2014: 102.938
2015: par       
  August 15,
2014: 104.563
2015: 103.042
2016: 101.521
2017: par       
  April 1,
2011: 103.563
2012: 102.375
2013: 101.188
2014: par       
  November 8, 2011
and thereafter
 
Make-whole redemption (6)
    N/A     Callable prior to
August 1, 2012 at
make-whole call price of
Treasury + 50 bps
  Callable prior to
July 1, 2013 at
make-whole call price of
Treasury + 50 bps
  Callable prior to
August 15, 2014 at
make-whole call price of
Treasury + 50 bps
  Callable prior to
April 1, 2011 at
make-whole call price of
Treasury + 50 bps
    N/A  
 
Change of control (6)
  Event of default   Put at 101% of principal
plus accrued interest
  Put at 101% of principal
plus accrued interest
  Put at 101% of principal
plus accrued interest
  Put at 101% of principal
plus accrued interest
  Put at 100% of principal
plus accrued interest
 
Equity clawback (6)
    N/A     Redeemable until
August 1, 2011 at
107.75%, plus accrued
interest for up to 35%
  Redeemable until
July 1, 2012 at
111.75%, plus accrued
interest for up to 35%
  Redeemable until
August 15, 2012 at
109.125%, plus accrued
interest for up to 35%
    N/A       N/A  
 
Subsidiary guarantors (6)
  Cowtown Pipeline
Funding, Inc.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.
Quicksilver Resources
Canada Inc.
  Cowtown Pipeline
Funding, Inc.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.
  Cowtown Pipeline
Funding, Inc.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.
  Cowtown Pipeline
Funding, Inc.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.
  Cowtown Pipeline
Funding, Inc.
Cowtown Pipeline
Management, Inc.
Cowtown Pipeline L.P.
Cowtown Gas
Processing L.P.
    N/A  
 
Estimated fair value (7)
  $155.4 million   $496.4 million   $702.0 million   $323.6 million   $347.4 million   $160.2 million
   
(1)   As discussed in “Convertible Debentures” above, holders of the convertible debentures can require us to repurchase all or a part of the debentures on November 1, 2011.
 
(2)   The Senior Secured Credit Facility is secured by a first perfected lien on substantially all our assets including a portion of our BBEP Units. The other debt presented is based upon structural seniority and priority of payment.
 
(3)   The principal amount for the Senior Secured Credit Facility represents the borrowing base and commitments as of March 31, 2011.

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(4)   Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives.
 
(5)   Amounts outstanding under the Senior Secured Credit Facility bear interest, at our election, at (i) LIBOR plus an applicable margin between 2.00% to 3.00%, (ii) bankers’ acceptance rate (as defined in the credit facilities) plus an applicable margin between 2.00% and 3.00%, (iii) ABR, which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) the Adjusted Eurodollar Rate (as defined in the credit facilities) plus 1.0%, plus, in each case under scenario (ii), an applicable margin between 1.125% to 2.125%, or (iii) the specified rate (as defined in the credit facilities) plus an applicable margin between 2.00% to 3.00%.
 
(6)   The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions 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.
     Note 11 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our long-term debt. 
7. ASSET RETIREMENT OBLIGATIONS
     The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the three months ended March 31, 2011. 
         
(In thousands)        
 
Beginning asset retirement obligations
  $ 57,809  
Additional liability incurred
    3,610  
Accretion expense
    613  
Asset retirement costs incurred
    (268 )
Gain on settlement of liability
    135  
Currency translation adjustment
    1,004  
 
   
Ending asset retirement obligations
    62,903  
Less current portion
    (1,574 )
 
   
Long-term asset retirement obligation
  $ 61,329  
 
   
8. COMMITMENTS AND CONTINGENCIES
Contractual Obligations and Commitments
     There have been no significant changes to our contractual obligations and commitments as reported in our 2010 Annual Report except for a series of contracts with NOVA Gas Transmission Ltd. (“NGTL”), a subsidiary of TransCanada Pipelines Limited, for the construction of a pipeline and meter station (the “project”) that will serve our Horn River Asset.  Under these agreements, we agreed to provide financial assurances in the form of letters of credit to NGTL during the construction phase, which is expected to continue through 2014.  Assuming the project is fully constructed and based on estimated costs of C$295 million, including taxes of C$30 million, we expect to provide cumulative letters of credit as follows:

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    NGTL  
    Cumulative  
    Financial  
    Assurances  
    (C$ in thousands)  
April 16, 2011
  $ 14,750  
June 1, 2011
  $ 32,450  
March 1, 2012
  $ 67,850  
October 1, 2012
  $ 109,150  
July 1, 2013
  $ 147,500  
October 1, 2013
  $ 295,000  
     Should other companies subscribe to the project, then our financial assurances under the agreements will be reduced.  If the project is terminated by NGTL, then we would be responsible for all of the costs incurred or for which NGTL is liable, and we would have the option to purchase NGTL’s rights in the project for a nominal fee.  If the project is terminated by NGTL after June 2011, then we would also be required to pay NGTL an additional C$26.4 million.  No amounts have been recognized on our consolidated balance sheet as of March 31, 2011.  Upon completion of the project, all construction-related guarantees will expire. 
     We have also entered into agreements to deliver production from our Horn River Asset to NGTL over a ten-year period.  These agreements will be extended in the event NGTL has either not received 1 Tcf of gas from us and other third parties, or recovered its costs as of the end of the ten-year period.  In such event, the extension will be for delivery of minimum volumes of 106 MMcfd. 
     Also under the agreements, we are required to treat the gas to meet NGTL pipeline specifications.  Such treatment will require us to construct treating facilities.  We will develop our plans to address the treating requirements prior to the commissioning of the assets being constructed by NGTL. 
Contingencies
     On March 10, 2011, the Court granted our motions for summary judgment on Eagle’s remaining tort claims, but directed further briefing on choice of law issues after which the Court will consider a motion for reconsideration of the summary judgment motions.  The Court denied Eagle’s summary judgment motion on our contract claims on March 31, 2011. 
     Note 14 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our contractual obligations, commitments and contingencies for which there are no other significant updates during the quarter ended March 31, 2011. 
9. QUICKSILVER STOCKHOLDERS’ EQUITY
Common Stock, Preferred Stock and Treasury Stock
     We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share.  At March 31, 2011 and December 31, 2010, we had 171.3 million and 170.5 million shares of common stock outstanding, respectively. 
     Note 16 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains additional information about our equity-based compensation plan. 

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Stock Options
     Options to purchase shares of common stock were granted in 2011 with an estimated fair value of $7.6 million.  The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the three months ended March 31, 2011:
         
    2011  
Wtd avg grant date fair value
  $9.16  
Wtd avg grant date
  Jan 3, 2011  
Wtd avg risk-free interest rate
  2.38%  
Expected life (in years)
  6.0  
Wtd avg volatility
  66.8%
Expected dividends
  -  
     The following table summarizes our stock option activity for the three months ended March 31, 2011:
                                 
            Wtd Avg     Wtd Avg      
            Exercise     Remaining     Aggregate  
    Shares     Price     Contractual Life     Intrinsic Value  
                    (In years)     (In thousands)  
Outstanding at January 1, 2011
    3,348,642     $ 11.10                  
Granted
    834,970       14.88                  
Exercised
    (59,127 )     6.21                  
Cancelled
    (65,089 )     10.11                  
 
                           
Outstanding at March 31, 2011
    4,059,396     $ 11.96     8.1     $ 16,776  
 
                           
Exercisable at March 31, 2011
    2,027,475     $ 11.75     7.4     $ 11,180  
 
                           
     We estimate that a total of 4.0 million stock options will become vested including those options already exercisable.  Compensation expense related to stock options of $1.9 million and $1.7 million was recognized for the three months ended March 31, 2011 and 2010, respectively.  Cash received from the exercise of stock options totaled $0.4 million for the three months ended March 31, 2011.  The total intrinsic value of those options exercised was $0.5 million. 
Restricted Stock
     The following table summarizes our restricted stock and stock unit activity for the three months ended March 31, 2011:
                                 
    Payable in shares     Payable in cash  
            Wtd Avg Grant             Wtd Avg Grant  
            Date Fair             Date Fair  
    Shares     Value     Shares     Value  
 
                               
Outstanding at January 1, 2011
    2,329,089     $ 11.27       372,633     $ 10.31  
Granted
    1,144,724       14.85       214,515       14.88  
Vested
    (1,089,297 )     12.06       (137,463 )     9.49  
Cancelled
    (63,477 )     11.62       (5,966 )     13.49  
 
                       
Outstanding at March 31, 2011
    2,321,039     $ 12.66       443,719     $ 13.12  
 
                       
     As of December 31, 2010, the unrecognized compensation cost related to outstanding unvested restricted stock was $13.9 million, which is expected to be recognized in expense through December 2013.  Grants of restricted stock and RSUs during the three months ended March 31, 2011 had an estimated grant date fair value of $17.0 million.  The fair value of RSUs settled in cash was $6.3 million at March 31, 2011.  For the three months ended March 31, 2011 and 2010, compensation expense of $3.6 million and $3.8 million, respectively, was recognized.  The total fair value of shares vested during the three months ended March 31, 2011 was $15.6 million. 

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10. EARNINGS PER SHARE
     The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share. 
                 
    For the Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands, except  
    per share data)  
Net income (loss) attributable to Quicksilver
  $   (70,758 )   $ 8,188  
Basic income allocable to participating securities (1)
    -       (107 )
 
       
Basic net income (loss) attributable to Quicksilver
  $   (70,758 )   $ 8,081  
Impact of assumed conversions – interest on 1.875% convertible debentures, net of income taxes
    -       -  
 
       
Income (loss) available to stockholders assuming conversion of convertible debentures
  $   (70,758 )   $ 8,081  
 
       
 
               
Weighted average common shares – basic
    168,872       167,856  
Effect of dilutive securities (2):
               
Share-based compensation awards
    -       864  
Contingently convertible debentures
    -       -  
 
       
Weighted average common shares – diluted
    168,872       168,720  
 
       
 
               
Earnings (loss) per common share – basic
  $   (0.42 )   $ 0.05  
 
               
Earnings (loss) per common share – diluted
  $   (0.42 )   $ 0.05  
(1)   Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings using the two-class method.  Participating securities, however, do not participate in undistributed net losses.
 
(2)   For the three months ended March 31, 2011 and 2010, the effects of 9.8 million shares associated with our contingently convertible debt and stock options and unvested restricted stock units representing 2.8 million shares and 1.3 million, respectively, were antidilutive and, therefore, excluded from the diluted share calculations.

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11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
     Note 18 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries.  After completing the Crestwood Transaction during the fourth quarter of 2010, we no longer have any unrestricted subsidiaries. 
     The following tables present financial information about Quicksilver and our restricted subsidiaries for the three-month periods covered by the consolidated financial statements. 
Condensed Consolidating Balance Sheets
                                         
    March 31, 2011  
            Restricted     Restricted     Restricted     Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
Current assets
  $   147,331     $   86,914     $   43,696     $   (111,828 )   $   166,113  
Property and equipment
    2,503,149       67,837       613,006       -       3,183,992  
Assets of midstream operations
    -       26,421       -       -       26,421  
Investment in subsidiaries (equity method)
    312,940       -       -       (257,266 )     55,674  
Other assets
    316,241       3,675       1,457       (243,621 )     77,752  
 
                   
Total assets
  $   3,279,661     $   184,847     $   658,159     $   (612,715 )   $   3,509,952  
 
                   
 
                                       
LIABILITIES AND EQUITY
                                       
Current liabilities
  $   359,655     $   110,049     $   56,105     $   (111,828 )   $   413,981  
Long-term liabilities
    1,951,717       20,360       397,778       (243,621 )     2,126,234  
Liabilities of midstream operations
    -       1,448       -       -       1,448  
Stockholders’ equity
    968,289       52,990       204,276       (257,266 )     968,289  
 
                   
Total liabilities and equity
  $   3,279,661     $   184,847     $   658,159     $   (612,715 )   $   3,509,952  
 
                   
                                         
    December 31, 2010  
            Restricted     Restricted     Restricted     Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
Current assets
  $   210,652     $   86,582     $   49,424     $   (108,486 )   $   238,172  
Property and equipment
    2,417,680       68,390       581,775       -       3,067,845  
Assets of midstream operations
    -       27,178       -       -       27,178  
Investment in subsidiaries (equity method)
    367,845       -       -       (284,504 )     83,341  
Other assets
    339,227       -       191       (243,620 )     95,798  
 
                   
Total assets
  $   3,335,404     $   182,150     $   631,390     $   (636,610 )   $   3,512,334  
 
                   
 
                                       
LIABILITIES AND EQUITY
                                       
Current liabilities
  $   411,586     $   106,627     $   53,373     $ (108,486 )   $   463,100  
Long-term liabilities
    1,864,410       20,346       347,259       (243,620 )     1,988,395  
Liabilities of midstream operations
    -       1,431       -       -       1,431  
Stockholders’ equity
    1,059,408       53,746       230,758       (284,504 )     1,059,408  
 
                   
Total liabilities and equity
  $   3,335,404     $   182,150     $   631,390     $ (636,610 )   $   3,512,334  
 
                   
Condensed Consolidating Statements of Income
                                         
    For the Three Months Ended March 31, 2011  
                    Restricted     Restricted     Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenue
  $   179,571     $   1,510     $   32,341     $ (1,235 )   $   212,187  
Operating expenses
    137,169       2,266       74,780       (1,235 )     212,980  
Equity in net earnings of subsidiaries
    (33,808 )     -       -       33,808       -  
 
                   
Operating income (loss)
    8,594       (756 )     (42,439 )     33,808       (793 )
Loss from earnings of BBEP
    (20,884 )     -       -       -       (20,884 )
Interest expense and other
    (43,270 )     -       (1,787 )     -       (45,057 )
Income tax (expense) benefit
    (15,198 )     265       10,909       -       (4,024 )
 
                   
Net loss
  $ (70,758 )   $ (491 )   $ (33,317 )   $   33,808     $ (70,758 )
 
                   

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    For the Three Months Ended March 31, 2010  
            Restricted     Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor     Consolidated     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenue
  $ 182,500     $ 1,645     $ 35,849     $ (696 )   $ 219,298     $ 24,739     $ (21,879 )   $ 222,158  
Operating expenses
    127,841       1,883       23,345       (696 )     152,373       15,819       (21,879 )     146,313  
Equity in net earnings of subsidiaries
    10,602       3,777       -       (10,602 )     3,777       -       (3,777 )     -  
 
                               
Operating income
    65,261       3,539       12,504       (10,602 )     70,702       8,920       (3,777 )     75,845  
Loss from earnings of BBEP
    (15,989 )     -       -       -       (15,989 )     -       -       (15,989 )
Interest expense and other
    (40,059 )     -       (1,437 )     -       (41,496 )     (2,678 )     -       (44,174 )
Income tax expense
    (1,025 )     (1,239 )     (2,765 )     -       (5,029 )     (53 )     -       (5,082 )
 
                               
Net income
  $ 8,188     $ 2,300     $ 8,302     $ (10,602 )   $ 8,188     $ 6,189     $ (3,777 )   $ 10,600  
Net income attributable to noncontrolling interests
    -       -       -       -       -       (2,412 )     -       (2,412 )
 
                               
Net income attributable to Quicksilver
  $ 8,188     $ 2,300     $ 8,302     $ (10,602 )   $ 8,188     $ 3,777     $ (3,777 )   $ 8,188  
 
                               
Condensed Consolidating Statements of Cash Flows
                                         
    For the Three Months Ended March 31, 2011  
            Restricted     Restricted     Restricted     Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Net cash flow provided (used) by operations
  $ (805 )   $ 417     $ 12,101     $ -     $ 11,713  
Purchases of property, plant and equipment
    (128,911 )     (417 )     (67,219 )     -       (196,547 )
Proceeds from sale of BBEP units
    1,703       -       -       -       1,703  
Proceeds from sale of properties and equipment
    507       -       -       -       507  
 
                   
Net cash flow used by investing activities
    (126,701 )     (417 )     (67,219 )     -       (194,337 )
Issuance of debt
    87,000       -       60,983       -       147,983  
Repayments of debt
    (10,000 )     -       (5,145 )     -       (15,145 )
Proceeds from exercise of stock options
    368                       -       368  
Purchase of treasury stock
    (4,797 )                     -       (4,797 )
 
                     
 
                   
Net cash flow provided by financing activities
    72,571       -       55,838       -       128,409  
Effect of exchange rates on cash
    -       -       (720 )     -       (720 )
 
                   
Net decrease in cash and equivalents
    (54,935 )     -       -       -       (54,935 )
Cash and equivalents at beginning of period
    54,937       -       -       -       54,937  
 
                   
Cash and equivalents at end of period
  $ 2     $ -     $ -     $ -     $ 2  
 
                   
                                                         
    For the Three Months Ended March 31, 2010  
            Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
                            (In thousands)                          
Net cash flow provided (used) by operating activities
  $ 50,013     $ 130     $ 20,759     $ 70,902     $ (1,457 )   $ (3,673 )   $ 65,772  
Purchases of property, plant and equipment
    (85,571 )     (130 )     (22,980 )     (108,681 )     (17,163 )     (3,487 )     (129,331 )
Distribution to parent
    80,276       -       -       80,276       (80,276 )             -  
Proceeds from sale of properties and equipment
    718       -       -       718       -       -       718  
 
                           
Net cash flow used by investing activities
    (4,577 )     (130 )     (22,980 )     (27,687 )     (97,439 )     (3,487 )     (128,613 )
Issuance of debt
    159,000       -       24,446       183,446       112,000       -       295,446  
Repayments of debt
    (193,000 )     -       (23,039 )     (216,039 )     (11,600 )     -       (227,639 )
Debt issuance costs
    (109 )     -       -       (109 )     -       -       (109 )
Gas Purchase Commitment - net
    (7,317 )     -       -       (7,317 )     -       -       (7,317 )
Issuance of KGS common units
    -       -       -       -       11,050       -       11,050  
Distributions to parent
    -       -               -       (7,160 )     7,160       -  
Distributions to noncontrolling interests
    -       -       -       -       (4,404 )     -       (4,404 )
Proceeds from exercise of stock options
    760       -       -       760       -       -       760  
Taxes paid on vested KGS equity compensation
    -       -       -       -       (1,144 )     -       (1,144 )
Purchase of treasury stock
    (4,766 )     -       -       (4,766 )     -       -       (4,766 )
 
                           
Net cash flow provided (used) by financing activities
    (45,432 )     -       1,407       (44,025 )     98,742       7,160       61,877  
Effect of exchange rates on cash
    -       -       (220 )     (220 )     -       -       (220 )
 
                           
Net increase (decrease) in cash and equivalents
    4       -       (1,034 )     (1,030 )     (154 )     -       (1,184 )
Cash and equivalents at beginning of period
    5       -       1,034       1,039       746       -       1,785  
 
                           
Cash and equivalents at end of period
  $ 9     $ -     $ -     $ 9     $ 592     $ -     $ 601  
 
                           

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12. SEGMENT INFORMATION
     We operate in two geographic segments, the U.S.  and Canada, where we are engaged in the exploration and production segment of the oil and gas industry.  Prior to the Crestwood Transaction, our processing and gathering segment provided natural gas gathering and processing services predominantly through KGS.  Revenue earned by KGS prior to the Crestwood Transaction for the gathering and processing of our gas was eliminated on a consolidated basis as is the GPT expense recognized by our producing properties.  We evaluate performance based on operating income and property and equipment costs incurred.
                                                 
    Exploration & Production     Gathering &                     Quicksilver  
    U.S.     Canada     Processing     Corporate     Elimination     Consolidated  
    (In thousands)  
For the Three Months Ended March 31:
                                               
2011  
                                               
Revenue
  $   179,571     $   32,341     $   1,510     $   -     $ (1,235 )   $   212,187  
DD&A
    38,756       11,424       1,713       578       -       52,471  
Impairment expense
    -       49,063       -       -       -       49,063  
Operating income (loss)
    60,245       (41,314 )     (755 )     (18,969 )     -       (793 )
Property and equipment costs incurred
    116,591       74,004       5,236       829       -       196,660  
 
                                               
2010  
                                               
Revenue
  $   182,500     $   35,849     $   25,803     $   -     $ (21,994 )   $   222,158  
DD&A
    27,949       11,285       7,057       466       -       46,757  
Operating income (loss)
    72,279       13,433       11,123       (20,990 )     -       75,845  
Property and equipment costs incurred
    77,367       30,585       27,634       620       -       136,206  
 
                                               
Property, plant and equipment – net
                                               
March 31, 2011
    2,488,172       613,006       67,837       14,977       -       3,183,992  
December 31, 2010
    2,403,039       581,775       68,389       14,642       -       3,067,845  
 
                                               
Investment in equity affiliates
                                               
March 31, 2011
    55,674       -       -       -       -       55,674  
December 31, 2010
    83,341       -       -       -       -       83,341  
13. SUPPLEMENTAL CASH FLOW INFORMATION
     Cash paid (received) for interest and income taxes was as follows:
                 
    For the Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands)  
Interest
  $   70,490     $   50,025  
Income taxes
    (57 )     (7,006 )
     Other significant non-cash transactions were as follows:
                 
    For the Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands)  
Working capital related to capital expenditures
  $   98,973     $   126,393  

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14. TRANSACTIONS WITH RELATED PARTIES
     As of March 31, 2011, members of the Darden family and entities controlled by them beneficially own approximately 32% of our outstanding common stock.  Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver. 
     We paid $0.2 million in the first three months of 2010 for rent on buildings owned by entities controlled by members of the Darden family.  For the first three months of 2011, rentals paid to these entities were negligible.  Rental rates were determined based on comparable rates charged by third parties. 
     During the first three months of 2011 and 2010, we paid $0.2 million and $0.1 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family.  Usage rates were determined based upon comparable rates charged by third parties. 
     Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services were $0.1 million for the first three months of 2010.  In late 2010, Mercury changed carriers for its employees’ health insurance plan, thereby reducing our charges to, and payments from, Mercury.  Those 2011 payments received from Mercury were negligible. 

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ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources.  MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report.  Prior to the Crestwood Transaction, we conducted our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller gathering and processing segment.  Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.
     Our MD&A includes the following sections:
    2011 Highlights – a summary of significant activities and events affecting Quicksilver
 
    2011 Capital Program – a summary of our planned capital expenditures during 2011
 
    Results of Operations – an analysis of our consolidated results of operations for the three-month periods 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
2011 HIGHLIGHTS
Strategic Alternatives for Quicksilver
     On March 24, 2011, an investor group, consisting of members of the Darden family and an entity controlled by them, announced its decision not to pursue a previously announced plan for a take private transaction of the Company.  As a result, our Board of Directors disbanded its transaction committee, and going forward, the Board of Directors as a whole will again work together to evaluate and pursue strategic and growth opportunities for Quicksilver.
Horn River Basin Exploration
     We had four wells tied into sales lines and producing as of December 31, 2010.  In 2011, we have spent $71.2 million for construction of infrastructure to gather, compress and deliver gas to third-party processing facilities, completion activities for a fifth well, and drilling activities on three other wells, bringing our total count of wells drilled to eight.
Increase in Production
     Daily production increased 23% during the first quarter of 2011 from the 2010 first quarter.  The production increase is discussed further in Results of Operations below.

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2011 CAPITAL PROGRAM
     We had capital expenditures of $197 million for the first three months of 2011.  The most significant change from our previously disclosed capital program is a $24 million increase in our planned acreage acquisition in the Greater Green River Basin.
     For all of 2011, we continue to expect our average production to be greater than our first quarter 2011 production rate as we continue to develop our acreage in the Barnett Shale and conduct further exploration on our Horn River Asset, the Greater Green River Basin and the Southern Alberta Asset.
FINANCIAL RISK MANAGEMENT
     We have established internal control policies and procedures for managing risk within our organization.  The possibility of decreasing prices received for our natural gas, NGL and oil production is among the several risks that we face.  We seek to manage this risk by entering into derivative contracts which we strive to treat as financial hedges.  We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, we have also limited our ability to benefit from favorable price movements.  This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression.  Item 3 of this Quarterly Report contains details of our commodity price and interest rate risk management.

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RESULTS OF OPERATIONS
     The following discussion compares the results of operations for the three months ended March 31, 2011 and 2010, or the 2011 quarter and 2010 quarter, respectively.  “Other U.S.” refers to the combined amounts for our Greater Green River Asset and Southern Alberta Basin Asset.
Revenue
Natural Gas, NGL and Oil
Production Revenue:
                                                                 
    Natural Gas     NGL     Oil     Total  
    2011     2010     2011     2010     2011     2010     2011     2010  
                            (In millions)                          
Barnett Shale
  $ 89.4     $ 81.5     $ 46.4     $ 41.1     $ 2.7     $ 3.2     $ 138.5     $ 125.8  
Other U.S.
    0.3       1.2       0.2       0.1       2.9       2.3       3.4       3.6  
Hedging
    23.9       48.3       (7.2 )     (9.6 )                 16.7       38.7  
 
                                               
Total U.S.
    113.6       131.0       39.4       31.6       5.6       5.5       158.6       168.1  
Horseshoe Canyon
    20.9       28.9             0.1                   20.9       29.0  
Horn River
    3.5       3.0                               3.5       3.0  
Hedging
    7.3       1.5                               7.3       1.5  
 
                                               
Total Canada
    31.7       33.4             0.1                   31.7       33.5  
 
                                               
Total
  $ 145.3     $ 164.4     $ 39.4     $ 31.7     $ 5.6     $ 5.5     $ 190.3     $ 201.6  
 
                                               
Average Daily Production Volume:
                                                                 
    Natural Gas     NGL     Oil     Equivalent Total  
    2011     2010     2011     2010     2011     2010     2011     2010  
    (MMcfd)     (Bbld)     (Bbld)     (MMcfed)  
Barnett Shale
    247.4       173.3       11,531       11,263       335       474       318.6       243.7  
Other U.S.
    0.8       2.3       23       17       381       381       3.2       4.8  
 
                                               
Total U.S.
    248.2       175.6       11,554       11,280       716       855       321.8       248.5  
Horseshoe Canyon
    59.4       62.5       6       11                   59.4       62.5  
Horn River
    11.1       7.4                               11.1       7.4  
 
                                               
Total Canada
    70.5       69.9       6       11                   70.5       69.9  
 
                                               
 
                                                             
Total
    318.7       245.5       11,560       11,291       716       855       392.3       318.4  
 
                                               

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Average Realized Price:
                                                                 
    Natural Gas     NGL     Oil     Equivalent Total  
    2011     2010     2011     2010     2011     2010     2011     2010  
    (per Mcf)     (per Bbl)     (per Bbl)     (per Mcfe)  
Barnett Shale
  $ 4.02     $ 5.23     $ 44.68     $ 40.51     $ 90.72     $ 73.63     $ 4.83     $ 5.73  
Other U.S.
    4.43       4.99       77.55       85.70       83.80       68.49       11.51       8.29  
Hedging
    1.07       3.06       (6.93 )     (9.43 )                 0.58       1.73  
Total U.S.
  $ 5.09     $ 8.28     $ 37.82     $ 31.19     $ 87.05     $ 71.36     $ 5.48     $ 7.52  
Horseshoe Canyon
  $ 3.90     $ 5.13     $ 73.64     $ 73.92     $     $     $ 3.91     $ 5.14  
Horn River
    3.53       4.60                               3.53       4.60  
Hedging
    1.15       0.24                               1.15       0.24  
Total Canada
  $ 4.99     $ 5.32     $ 73.64     $ 73.92     $     $     $ 4.99     $ 5.32  
Total
  $ 5.07     $ 7.44     $ 37.84     $ 31.19     $ 87.05     $ 71.36     $ 5.39     $ 7.03  
     The following table summarizes the changes in our natural gas, NGL and oil revenue:
                                 
    Natural                    
    Gas     NGL     Oil     Total  
    (In thousands)  
Revenue for the 2010 quarter
  164,379     31,691     5,493     201,563  
Volume variances
    34,116       985       (900 )     34,201  
Hedge revenue variances
    (18,646 )     2,371             (16,275 )
Price variances
    (34,524 )     4,325       1,011       (29,188 )
 
                       
Revenue for the 2011 quarter
  $ 145,325     $ 39,372     $ 5,604     $ 190,301  
 
                       
     Natural gas revenue for the 2011 quarter decreased from the 2010 quarter despite a 30% increase in production.  Realized prices, without hedge gains, were 23% lower for the 2011 quarter as compared to the 2010 quarter and more than offset production increases.  The 43% increase in natural gas volume from our Barnett Shale Asset was primarily the result of wells tied into sales lines since the 2010 quarter.  Canadian natural gas production increased because of a 50% production increase from our Horn River Asset offset by a 5% decrease in production from our Horseshoe Canyon Asset due to decreased capital spending.  
     The increase in NGL revenue for the 2011 quarter resulted from a 21% increase in realized prices, before hedge losses, and a small increase in production from our Barnett Shale Asset compared to the 2010 quarter.  
     Utilization of derivatives to hedge our sales of natural gas and NGL may result in realized prices varying from market prices that we receive from the sale of our production.  Our revenue from natural gas and NGL production for the 2011 quarter and 2010 quarter were higher by $24.0 million and $40.3 million, respectively, because of our hedging activities.

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Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
                 
    Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands)  
Sales of purchased natural gas:
               
Purchases from Eni
  $ 13,917     $ 12,578  
Purchases from others
    6,509       3,646  
 
           
Total
    20,426       16,224  
Costs of purchased natural gas sold:
               
Purchases from Eni
    13,794       12,518  
Purchases from others
    5,949       4,151  
Unrealized valuation (gain) loss on Gas Purchase Commitment
          16,638  
 
           
Total
    19,743       33,307  
 
           
Net sales and purchases of natural gas
  $ 683     $ (17,083 )
 
           
     As the Gas Purchase Commitment with Eni expired on December 31, 2010, no unrealized valuation gain or loss was recognized for the 2011 quarter.  
Other Revenue
                 
    Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands)  
Midstream revenue:
               
KGS
  $     $ 1,983  
Canada
    844       641  
Other Texas
    275       352  
 
           
Total midstream revenue
    1,119       2,976  
Gain (loss) from hedge ineffectiveness
    (53 )     1,395  
Other
    394        
 
           
Total
  $ 1,460     $ 4,371  
 
           
     Midstream revenue was $1.9 million lower from the 2010 quarter primarily as a result of the sale of our interests in KGS in October 2010, and lower volume on our HCDS.  Losses from hedge ineffectiveness were $0.1 million for the 2011 quarter as compared to gains for the 2010 quarter.

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Operating Expense
Lease Operating
                                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Barnett Shale
                               
Cash expense
    $  11,106       $  0.39       $  10,109       $  0.46  
Equity compensation
    269       0.01       211       0.01  
 
                       
 
    $  11,375       $  0.40       $  10,320       $  0.47  
Other U.S.
                               
Cash expense
    $  1,246       $  4.27       $  1,957       $  4.57  
Equity compensation
    55       0.19       41       0.10  
 
                       
 
    $  1,301       $  4.46       $  1,998       $  4.67  
Total U.S.
                               
Cash expense
    $  12,352       $  0.43       $  12,066       $  0.54  
Equity compensation
    324       0.01       252       0.01  
 
                       
 
    $  12,676       $  0.44       $  12,318       $  0.55  
Horseshoe Canyon
                               
Cash expense
    $  7,739       $  1.45       $  6,935       $  1.23  
Equity compensation
    164       0.03       327       0.06  
 
                       
 
    $  7,903       $  1.48       $  7,262       $  1.29  
Horn River
                               
Cash expense
    $  978       $  0.98       $  384       $  0.58  
Equity compensation
                       
 
                       
 
    $  978       $  0.98       $  384       $  0.58  
Total Canada
                               
Cash expense
    $  8,717       $  1.37       $  7,319       $  1.16  
Equity compensation
    164       0.03       327       0.05  
 
                       
 
    $  8,881       $  1.40       $  7,646       $  1.21  
Total Company
                               
Cash expense
    $  21,069       $  0.60       $  19,385       $  0.68  
Equity compensation
    488       0.01       579       0.02  
 
                       
 
    $  21,557       $  0.61       $  19,964       $  0.70  
 
                       
     Although U.S. lease operating expense for the 2011 quarter was almost unchanged in comparison to the 2010 quarter, lease operating expense per Mcfe was 21% lower than the 2010 quarter.  A 31% increase in production volume in our Barnett Shale Asset for the 2011 quarter as compared to 2010 quarter increased lease operating expense slightly, but also contributed to the decrease in per Mcfe expense as our fixed costs have been spread across higher production for the 2011 quarter compared to the 2010 quarter.  
     Lease operating expense for the 2011 quarter in Canada increased 16% when compared to the 2010 quarter.  Lease operating expense for the 2011 quarter on a Canadian dollar basis increased C$0.8 million or 11%, and 10% on a Canadian dollar basis per Mcfe from the 2010 quarter.  The C$0.3 million increase in Horseshoe Canyon lease operating expense was due to additional repair and maintenance of compressors during the 2011 quarter.  The increase in Horn River lease operating expense of C$0.5 million for the 2011 quarter was primarily the result of increased road fees in the area as well as additional producing wells and production.

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Gathering, Processing and Transportation
                                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Barnett Shale
    $  40,377       $  1.41       $  13,257       $  0.60  
Other U.S.
    16       0.05       6       0.01  
 
                           
Total U.S.
    $  40,393       $  1.39       $  13,263       $  0.59  
Horseshoe Canyon
    1,019       0.19       1,342       0.24  
Horn River
    2,602       2.61       1,397       2.11  
 
                           
Total Canada
    3,621       0.57       2,739       0.43  
 
                           
Total
    $  44,014       $  1.25       $  16,002       $  0.56  
 
                           
     GPT expense increased for the 2011 quarter compared to the 2010 quarter primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction.  KGS’ revenue earned from gathering and processing production from our Barnett Shale Asset was $16.0 million, or $0.73 per Mcfe, for the first quarter of 2010.  Canadian GPT expense increased for the 2011 quarter as compared to the 2010 quarter both in total dollars and on a per Mcfe basis primarily as a result of transportation fees associated with increased production from our Horn River Asset for the 2011 quarter.  
Production and Ad Valorem Taxes
                                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Production taxes
                               
U.S.
    $  1,684       $  0.06       $  2,222       $  0.10  
Canada
    14             140       0.02  
 
                           
Total production taxes
    1,698       0.04       2,362       0.09  
Ad valorem taxes
                               
U.S.
    $  5,231       0.18       $  5,538       0.25  
Canada
    652       0.10       606       0.10  
 
                           
Total ad valorem taxes
    5,883       0.17       6,144       0.21  
 
                           
Total
    $  7,581       $  0.21       $  8,506       $  0.30  
 
                           
     Production taxes for the 2011 quarter reflect a 16% decrease in realized prices before hedge settlements partially offset by a 31% increase in production volume from our Barnett Shale Asset when compared to the 2010 quarter.  During the 2011 quarter, we received a refund of 2008 severance taxes for our Alliance Leasehold in the amount of $0.8 million, which was recorded as a reduction to U.S. production taxes.  The absence of $1.5 million of KGS ad valorem taxes for the 2010 quarter partially offset U.S. ad valorem taxes on producing wells added during 2010, particularly in areas with higher ad valorem tax rates, and increases to ad valorem tax rates assessed by taxing entities in Texas.  

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Depletion, Depreciation and Accretion
                                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Depletion
                               
U.S.
    $  37,145       $  1.28       $  26,257       $  1.17  
Canada
    9,855       1.55       9,774       1.55  
 
                           
Total depletion
    47,000       1.33       36,031       1.26  
Depreciation of other fixed assets
                               
U.S.
    $  3,622       $  0.13       $  8,905       $  0.40  
Canada
    1,219       0.19       1,083       0.17  
 
                           
Total depreciation
    4,841       0.14       9,988       0.35  
Accretion
    630       0.02       738       0.02  
 
                           
Total
    $  52,471       $  1.49       $  46,757       $  1.63  
 
                           
     U.S. depletion for the 2011 quarter reflected a 9% increase in the U.S. depletion rate and a 29% increase in U.S. production when compared to the 2010 quarter.  Changes in the U.S.-Canadian dollar exchange rate accounted for a $0.5 million increase in Canadian depletion that was nearly offset by a 5% decrease in the Canadian dollar depletion rate.   Following the impairment recognized in the 2011 quarter, we expect Canadian depletion will be $1.42 per Mcfe.
     U.S. depreciation for the 2011 quarter was lower than the 2010 quarter primarily because KGS’ depreciation of $5.4 million was included for the 2010 quarter.
Impairment Expense
     As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties.  We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred.  The calculation of impairment expense is more fully described in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.
     In the 2011 quarter, we recognized a $49.1 million non-cash charge for impairment of our Canadian oil and gas properties as of March 31, 2011.  The AECO natural gas price used to prepare the estimate of the ceiling limit for our Canadian full-cost pool decreased approximately 12% from the AECO price used at December 31, 2010 when we also recognized an impairment charge for our Canadian oil and gas properties.
General and Administrative
                                 
    Three Months Ended March 31,  
    2011     2010  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Cash expense
    $  13,401       $  0.38       $  15,658       $  0.55  
Equity compensation
    4,990       0.14       4,865       0.17  
 
                       
Total
    $  18,391       $  0.52       $  20,523       $  0.72  
 
                       
     General and administrative expense for the 2011 quarter was lower than the 2010 quarter despite expense of $0.7 million recognized in connection with evaluation of a take-private transaction including legal, professional and other costs and expenses.  The increase were partially offset by the absence of expense associated with our litigation with BBEP, which was settled in April 2010, and the absence of $1.7 million of expense attributable to KGS for the 2010 quarter.

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Loss from Earnings of BBEP
     We record our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available.  As a result, our 2011 and 2010 quarter results of operations include BBEP’s earnings for the three months ended December 31, 2010 and 2009, respectively.
     We recognized losses of $20.9 million and $16.0 million for equity earnings from our investment in BBEP for the 2011 and 2010 quarters, respectively.  BBEP continues to experience significant volatility in its net earnings primarily due to changes in the value of its derivative instruments for which it does not employ hedge accounting.  
Other Income
     Gains of $1.3 million were recognized in the 2011 quarter from the sale of BBEP Units.
Interest Expense
                 
    Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands)  
Interest costs on debt outstanding
  43,446     40,875  
Add: Non-cash interest (1)
    3,880       5,075  
Less: Interest capitalized
    (1,148 )     (1,433 )
 
           
Interest expense
  $ 46,178     $ 44,517  
 
           
     (1) Amortization of deferred financing costs, original issue discount net of interest swap settlement amortization.
     Interest costs on debt outstanding for the 2011 quarter were higher when compared to the 2010 quarter primarily because of the absence of $6.5 million received in the 2010 quarter from interest rate swaps.  Offsetting this increase was $2.1 million of interest expense recognized in the 2010 quarter that was attributable to KGS and lower outstanding debt balances during the 2011 quarter.
Income Taxes
                 
    Three Months Ended  
    March 31,  
    2011     2010  
Income tax expense (In thousands)
  $ 4,024     $ 5,082  
Effective tax rate
    -6.0 %     32.4 %
     Our income tax provision for the 2011 quarter remains comparable to the 2010 quarter income tax provision despite the loss recognized before income taxes for the 2011 quarter.  The effective tax rate for the 2011 quarter reflects a projection of a full year of Canadian taxable loss partially offset by projection of a full year of U.S. taxable income.  As the Canadian taxable loss was taxed at the lower applicable Canadian tax rate and U.S. taxable income was taxed at a higher U.S. effective tax rate, our consolidated income tax provision resulted in income tax expense for the 2011 quarter.  We expect that the effective tax rate of (6.0%) for the 2011 quarter will be our effective tax rate for all of 2011, based upon our projection of pretax income and estimated permanent differences for 2011.
Quicksilver Resources Inc. and its Restricted Subsidiaries
     Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 11 to our condensed consolidated financial statements included in Item 1 of this Quarterly Report.
     The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations.”  The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries which prior to October 1, 2010

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consisted of KGS and its subsidiaries.  The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Cash Flow Activity.”
LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Cash Flow Activity
     Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our natural gas, NGL and oil production and the volumes of natural gas, NGL and oil that we produce.
     The natural gas, NGLs and oil that we produce are commodity products for which established trading markets exist.  Accordingly, product pricing is generally influenced by the relationship between supply and demand for these products.  Product supply is affected primarily by fluctuations in production volumes, and product demand is affected by the state of the economy in general, the availability and price of alternative fuels and a variety of other factors.  Prices for our products historically have been volatile, and we have no meaningful influence over the timing and extent of price changes for our products.  Although we have mitigated our near term exposure to such price declines through derivative financial instruments covering substantial portions of our expected near-term production, we cannot confidently predict whether or when market prices for natural gas, NGL and oil will increase or decrease.
     The volumes that we produce may be significantly affected by the rates at which we acquire leaseholds and other mineral interests and explore, exploit and develop our leasehold and other mineral interests through drilling and production activities.  These activities require substantial capital expenditures, and our ability to fund these activities through cash flow from our operations, borrowings and other sources may be affected by instability in the capital markets.
     For the remainder of 2011 through 2015, price collars and swaps hedge a portion of our natural gas and NGL revenue.  The following summarizes future production hedged with commodity derivatives as of March 31, 2011.
         
Production   Daily Production Volume
Year   Gas   NGL
    MMcfd   MBbld
2011   190   10.5
2012   130   2.0
2013   70  
2014 - 2015   30  
     The following summarizes our cash flow activity for the 2011 quarter and 2010 quarter:
                 
    Three Months Ended  
    March 31,  
    2011     2010  
    (In thousands)  
Net cash provided by operating activities
  $ 11,713     $ 65,772  
Net cash used by investing activities
    (194,337 )     (128,613 )
Net cash provided by financing activities
    128,409       61,877  
Operating Cash Flows
     Net cash provided by operations for the 2011 quarter decreased from the 2010 quarter, primarily due to lower realized prices (including hedging effects) and higher payments to KGS for GPT costs partially offset by receipt of BBEP distributions of $6.4 million in the 2011 quarter.  In addition, the 2010 quarter included nonrecurring cash receipts for income tax refunds and interest rate swap settlements and terminations totaling $32.4 million.

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Investing Cash Flows
     Our expenditures for property, plant and equipment for the 2011 quarter and 2010 quarter were as follows:
                         
    United States     Canada     Consolidated  
    (In thousands)  
For the Three Months Ended March 31, 2011
                       
Exploration and production
  $ 116,246     $   40,315     $ 156,561  
Gathering and processing
    5,236       33,566       38,802  
Administrative
    1,174       123       1,297  
 
                 
Total
  $ 122,656     $ 74,004     $ 196,660  
 
                 
                         
    United States     Canada     Consolidated  
    (In thousands)  
For the Three Months Ended March 31, 2010
                       
Exploration and production
  $ 75,792     $   30,584     $ 106,376  
Gathering and processing (1)
    27,634             27,634  
Administrative
    2,196             2,196  
 
                 
Total
  $ 105,622     $ 30,584     $ 136,206  
 
                 
     (1) Includes KGS’ capital expenditures of $27.4 million.
     Our 2011 capital expenditures for our exploration and production activities have increased $40.5 million and $9.7 million for the U.S. and Canada, respectively.  Our capital expenditures for gathering and processing during the 2011 quarter reflect the sale of KGS in 2010 and construction of infrastructure to gather, compress and deliver our Horn River gas production to third-party processing facilities.
Financing Cash Flows
     Net financing cash flows in the 2011 quarter include borrowings of $132.8 million under our Senior Secured Credit Facility and activity for our stock-compensation plan.  Net financing cash flows in the 2010 quarter included net borrowings of $67.8 million under our Senior Secured Credit facility.  The 2010 quarter also included proceeds of $11.1 million from the KGS Secondary Offering partially offset by repayments of $7.3 million under the Gas Purchase Commitment and activity for KGS’ stock-compensation plans.
Liquidity and Borrowing Capacity
     At March 31, 2011, the borrowing base and commitments under the Senior Secured Credit Facility, which matures February 9, 2013, were $1.0 billion and the aggregate letter of credit capacity was $175 million.  The Senior Secured Credit Facility provides us an option to increase availability by up to $250 million, with a maximum of $1.45 billion with lender consents and additional commitments.  We can also extend the maturity date up to two additional years with lenders’ approval.  At March 31, 2011, there was $795 million available under the facility.  Our ability to remain in compliance with the financial covenants in our credit facilities may be affected by events beyond our control, including market prices for our products.  Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness.
     Additional information about our debt and related covenants are more fully described in Note 6 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.
     We believe that our capital resources are adequate to meet the requirements of our existing business.  We continue to anticipate that our 2011 capital expenditure program will be substantially funded by cash flow from operations, utilization of our Senior Secured Credit Facility and asset sales.  
     Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, other possible capital markets transactions or the sale of assets, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes.  We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio.

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Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or other securities, the sale of assets or a combination of those sources.
Financial Position
     The following impacted our balance sheet as of March 31, 2011, as compared to our balance sheet as of December 31, 2010:
    Our net property, plant and equipment balance increased $116.1 million from December 31, 2010 to March 31, 2011.  We have incurred capital expenditures of $196.7 million during 2011 and also recognized assets for retirement obligations established for new wells and facilities.  Changes to U.S.-Canadian exchange rates further increased our property, plant and equipment balances $16.1 million.  Offsetting the increases was $101.5 million of DD&A and impairment expense.
 
    The valuation of our current and non-current derivative assets and liabilities was $50.6 million lower on a net basis for March 31, 2011 as compared to December 31, 2010.  The decrease was the result of 2011 settlements received of $24.0 million and unrealized valuation losses of $26.5 million for our remaining commodity derivatives.  
 
    The $26.3 million decrease in accounts payable was primarily due to Texas ad valorem taxes of $17.4 million included in accounts payable as of December 31, 2010 and a reduction in capital expenditures decreased accounts payable $5.1 million from the December 31, 2010 amount.
 
    Long-term debt increased $134.1 million for net borrowings under the Senior Secured Credit Facility and amortization of original issuance discounts on our bond issuances partially offset by recognition of a portion of the gains deferred from our 2010-settled interest rate swap derivatives.
Contractual Obligations and Commercial Commitments
     There have been no significant changes to our contractual obligations and commitments as reported in our 2010 Annual Report except for contracts we entered into with NGTL in April 2011.  Note 8 to the condensed consolidated financial statements found in this Quarterly Report contains additional information about our contracts with NGTL.
Critical Accounting Estimates
     Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report.  The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense.  Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2010 Annual Report on Form 10-K.  These critical estimates, for which no significant changes occurred during the three months ended March 31, 2011, include estimates and assumptions for:
             
  oil and gas reserves     stock-based compensation
  full cost ceiling calculations     income taxes
  derivative instruments        
     These estimates and assumptions are based upon what we believe is the best information available at the time we make the estimate or assumption.  The estimates and assumptions could change materially as conditions within and beyond our control change.  Accordingly, actual results could differ materially from those estimates and assumptions.
OFF-BALANCE SHEET ARRANGEMENTS
     Our contracts with NOVA Gas Transmission Ltd. (“NGTL”) provide financial assurances to NGTL during the construction phase, which is expected to continue through 2014.  Assuming the project is fully constructed at estimated costs of C$295 million, we expect to provide letters of credit.  Note 8 to the condensed consolidated financial statements found in this Quarterly Report contains additional information about our contracts with NGTL.

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RECENTLY ISSUED ACCOUNTING STANDARDS
     No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.
ITEM 3.   Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
     We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue.  Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas, and NGLs that vary from market prices.  As a result of settlements of derivative contracts, our revenue from natural gas, and NGL production was greater by $24.0 million and $40.3 million for the 2011 quarter and 2010 quarter, respectively.  Other revenue was $0.1 million lower and $1.4 million greater, respectively, for the 2011 quarter and 2010 quarter due to hedge ineffectiveness.
     The following table details our open derivative positions at March 31, 2011:
                                 
                    Weighted Avg        
        Production   Remaining Contract       Price Per Mcf     Fair Value  
Product   Type   Hedged   Period   Volume   or Bbl     Total  
                            (In thousands)  
Gas
  Collar   Canada   Apr 2011-Dec 2011   10 MMcfd   $ 6.00- 7.00     $ 4,033  
Gas
  Collar   Canada   Apr 2011-Dec 2011   10 MMcfd     6.00- 7.00       4,033  
Gas
  Collar   Canada   Apr 2011-Dec 2011   20 MMcfd     6.00- 7.00       8,065  
Gas
  Collar   U.S.   Apr 2011-Dec 2011   10 MMcfd     6.25- 7.50       4,715  
Gas
  Collar   U.S.   Apr 2011-Dec 2011   10 MMcfd     6.25- 7.50       4,715  
Gas
  Collar   U.S.   Apr 2011-Dec 2011   20 MMcfd     6.25- 7.50       9,429  
Gas
  Collar   U.S.   Apr 2011-Dec 2012   20 MMcfd     6.50- 7.15       21,741  
Gas
  Collar   U.S.   Apr 2011-Dec 2012   20 MMcfd     6.50- 7.18       21,832  
Gas
  Collar   U.S.   Jan 2012-Dec 2012   20 MMcfd     6.50- 8.01       11,395  
Gas
  Basis   Canada   Apr 2011-Dec 2011   10 MMcfd     (1)       432  
Gas
  Basis   Canada   Apr 2011-Dec 2011   10 MMcfd     (1)       432  
Gas
  Basis   Canada   Apr 2011-Dec 2011   20 MMcfd     (1)       863  
Gas
  Swap   Canada   Apr 2011-Dec 2013   10 MMcfd   $ 5.00       (474)
Gas
  Swap   U.S.   Apr 2011-Dec 2013   10 MMcfd     5.00       (474)
Gas
  Swap   U.S.   Apr 2011-Dec 2013   10 MMcfd     5.00       (474)
Gas
  Swap   U.S.   Apr 2011-Dec 2013   10 MMcfd     5.00       (474)
Gas
  Swap   U.S.   Apr 2011-Dec 2015   10 MMcfd     6.00       9,981  
Gas
  Swap   U.S.   Apr 2011-Dec 2015   20 MMcfd     6.00       19,962  
NGL
  Swap   U.S.   Apr 2011-Dec 2011   3 MBbld     36.06       (8,894)
NGL
  Swap   U.S.   Apr 2011-Dec 2011   2 MBbld     36.31       (5,795)
NGL
  Swap   U.S.   Apr 2011-Dec 2011   1 MBbld     40.50       (1,754)
NGL
  Swap   U.S.   Apr 2011-Dec 2011   1.5 MBbld     40.42       (2,661)
NGL
  Swap   U.S.   Apr 2011-Dec 2011   3 MBbld     41.95       (4,051)
NGL
  Swap   U.S.   Jan 2012-Dec 2012   1 MBbld     42.81       (234)
NGL
  Swap   U.S.   Jan 2012-Dec 2012   1 MBbld     43.07       (140)
 
                             
 
                  Total   $ 96,203  
 
                             
     (1) Basis swaps hedge the AECO basis adjustment at a deduction of $0.39 per Mcf from NYMEX for 2011.

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Interest Rate Risk
     In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes.  We deferred gains of $30.8 million as a fair value adjustment to our debt, which we began to recognize over the life of the associated debt instruments.  During the 2011 quarter, we recognized $1.2 million of those deferred gains as a reduction of interest expense.  During the 2010 quarter, we recognized $0.3 million of those deferred gains and $6.2 million received in periodic settlements as reductions of interest expense.
     The remaining gain deferred from the 2010 early settlements will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:
         
(In thousands)  
2011
  $ 3,711  
2012
    5,315  
2013
    5,769  
2014
    6,261  
2015
    4,824  
2016
    569  
 
     
 
  $ 26,449  
 
     
     The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value confirmed by counterparties.  Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value.  This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.  
Foreign Currency Risk
     Our Canadian subsidiary uses the Canadian dollar as its functional currency.  To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk.  Non-functional currency transactions for the 2011 quarter and the 2010 quarter resulted in losses of $0.1 million for each quarter and were included in other income.  Furthermore, the Senior Secured Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts.  However, the aggregate borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent.  Accordingly, there is a risk that exchange rate movements could impact our available borrowing capacity.
ITEM 4.   Controls and Procedures
Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures
     We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15.  Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2011, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
     There has been no change in our internal control over financial reporting during the quarter ended March 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II.   OTHER INFORMATION
ITEM 1.   Legal Proceedings
     On March 10, 2011, the Court granted our motions for summary judgment on Eagle’s remaining tort claims, but directed further briefing on choice of law issues after which the Court will consider a motion for reconsideration of the summary judgment motions.  The Court denied Eagle’s summary judgment motion on our contract claims on March 31, 2011.
     There have been no other material changes in the legal proceedings described in Part I, Item 3 included in our 2010 Annual Report on Form 10-K.
ITEM 1A. Risk Factors
     There have been no material changes in the risk factors described in Part I, Item 1A included in our 2010 Annual Report on Form 10-K with the exception of the risk factor provided below:
     We have substantial financial and other commitments related to our development of a gathering, processing and transportation system for our Horn River Asset.
     We have agreed to provide NOVA Gas Transmission Ltd. (“NGTL”) financial assurances in the form of letters of credit to cover its costs to construct a pipeline and meter station (the “project”) that will connect the gas produced from our Horn River Asset, to NGTL’s Alberta System (the “Horn River Mainline”).  Our financial exposure is staged in increments as the project is built and ultimately, the costs for the project are estimated to be C$295 million including taxes of approximately C$30 million.  Upon completion of the project, the requirement to provide the letters of credit will terminate.  We have also committed to deliver for transport up to 1 Tcf of gas to NGTL and to construct a treatment facility to deliver gas that will meet NGTL’s specifications for the Horn River Mainline.  Our ability to fund these commitments may be affected by economic and capital markets conditions and other factors that may be beyond our control. In addition, we only have 16.4 MMcf of proved reserves in the Horn River Basin as of December 31, 2010.  Accordingly, our ability to deliver up to 1 Tcf of gas depends upon our ability to drill additional successful wells on our Horn River Asset, find third-party sources to supplement or satisfy our obligation, or to pay a demand charge.  Failure to satisfy our financial or other commitments could have a material adverse affect on our business, results of operations and financial condition.
ITEM 2.   Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
     The following table summarizes our repurchases of Quicksilver common stock during the quarter ended March 31, 2011.
                                 
                    Total Number of     Maximum Number of  
    Total Number of             Shares Purchased as     Shares that May Yet  
    Shares     Average Price     Part of Publicly     Be Purchased Under  
Period   Purchased(1)     Paid per Share     Announced Plan(2)     the Plan(2)  
January 2011
    263,667     $ 14.80              
February 2011
    58,992     $ 15.15              
March 2011
    86     $ 13.86              
 
                         
Total
    322,745     $ 14.86              
  (1)   Represents shares of common stock surrendered by employees to satisfy income tax withholding obligations arising upon the vesting of restricted stock issued under our Amended and Restated 2006 Equity Plan.  
 
  (2)   We do not currently have in place any publicly announced, specific plans or programs to purchase equity securities.
     We have not paid cash dividends on our common stock and intend to retain our cash flows from operations for future operations and development of our business.  In addition, we have debt agreements that restrict the payment of dividends.

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ITEM 3.   Defaults Upon Senior Securities
     None.
ITEM 4.   [Removed and Reserved]
ITEM 5.   Other Information
     None.
ITEM 6.   Exhibits
     
Exhibit No.   Description
10.1
  Quicksilver Resources Inc. 2011 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K, filed February 25, 2011, and included herein by reference)
* 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
* 101.INS
  XBRL Instance Document
* 101.SCH
  XBRL Taxonomy Extension Schema Linkbase Document
* 101.CAL
  XBRL Taxonomy Extension Calculation Linkbase Document
* 101.LAB
  XBRL Taxonomy Extension Labels Linkbase Document
* 101.PRE
  XBRL Taxonomy Extension Presentation Linkbase Document
* 101.DEF
  XBRL Taxonomy Extension Definition Linkbase Document
 
*   Filed herewith.

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SIGNATURE
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: May 9, 2011
         
  Quicksilver Resources Inc.
 
 
  By:   /s/ Philip Cook    
    Philip Cook   
    Senior Vice President - Chief Financial Officer   
 

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EXHIBIT INDEX
     
Exhibit No.   Description
10.1
  Quicksilver Resources Inc. 2011 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K, filed February 25, 2011, and included herein by reference)
* 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
* 101.INS
  XBRL Instance Document
* 101.SCH
  XBRL Taxonomy Extension Schema Linkbase Document
* 101.CAL
  XBRL Taxonomy Extension Calculation Linkbase Document
* 101.LAB
  XBRL Taxonomy Extension Labels Linkbase Document
* 101.PRE
  XBRL Taxonomy Extension Presentation Linkbase Document
* 101.DEF
  XBRL Taxonomy Extension Definition Linkbase Document
 
*   Filed herewith.

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