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Quicksilver Resources 10-Q 2009

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.1
e10vq
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 September 30, 2009
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)    
     
777 West Rosedale, Fort Worth, Texas   76104
(Address of principal executive offices)   (Zip Code)
(817) 665-5000
(Registrant’s telephone number, including area code)
None
(Former name, former address and former fiscal year, if changed since last report)
     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 at least the past 90 days.   Yes þ No o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 file).   Yes o 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
(Do not check if a smaller reporting company)
Smaller reporting company o
     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 October 26, 2009
Common Stock, $0.01 par value   169,133,374
 
 

 


 

QUICKSILVER RESOURCES INC.
INDEX TO FORM 10-Q
For the Period Ending September 30, 2009
         
       
 
       
       
 
       
    5  
 
       
    6  
 
       
    7  
 
       
    8  
 
       
    9  
 
       
    31  
 
       
    47  
 
       
    49  
 
       
       
 
       
    49  
 
       
    50  
 
       
    57  
 
       
    57  
 
       
    57  
 
       
    57  
 
       
    58  
 
       
    59  
 EX-31.1
 EX-31.2
 EX-32.1
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.

 


Table of Contents

DEFINITIONS
As used in this quarterly report unless the context otherwise requires:
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, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
Btu” means British Thermal Units, a measure of heating value
Canada” means the division of Quicksilver encompassing oil and natural gas properties located in Canada
CBM” means coalbed methane
DD&A” means Depletion, Depreciation and Accretion
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 Btu and is approximately equal to 1 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, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcfed” means MMcf of natural gas equivalents per day, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
NGL” or “NGLs” means natural gas liquids
NYMEX” means New York Mercantile Exchange
Oil” includes crude oil and condensate
Tcf” means trillion cubic feet
Tcfe” means Tcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
COMMONLY USED TERMS
Other commonly used terms and abbreviations include:
ABR” means adjusted base rate
AOCI” means accumulated other comprehensive income
Alliance Acquisition” means the August 8, 2008 purchase of leasehold, royalty and midstream assets in the Barnett Shale in northern Tarrant and southern Denton counties of Texas
Alliance Leasehold” means the natural gas leasehold and royalty interests acquired in the Alliance Acquisition and developed thereafter
BBEP” means BreitBurn Energy Partners L.P.
BreitBurn Transaction” means the November 1, 2007 conveyance of our Northeast Operations in exchange for aggregate proceeds of $1.47 billion
“CMS Litigation” means litigation against CMS Marketing Services and Trading Company concerning a gas supply contract under which we agreed to deliver 10 MMcfd at a floor price of $2.49 per Mcf
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 June 19, 2009 conveyance of a 27.5% working interest in our Alliance Leasehold and royalty assets to Eni for aggregate proceeds of $280 million
Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase Eni’s share of Alliance Leasehold production at $8.60 per MMBtu less actual costs incurred by us for gathering and processing Eni’s Alliance Production through December 2010, plus the costs that would be incurred to transport such production from the location where it is produced to Henry Hub
FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.

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“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 United States
KGS” means Quicksilver Gas Services LP, which is our publicly traded partnership that trades under the ticker symbol “KGS”
KGS Credit Agreement” means the KGS senior secured revolving credit facility
Mercury” means Mercury Exploration Company, which is owned by members of the Darden family
Michigan Sales Contract” means the gas supply contract which expired in March 2009 under which we agreed to deliver 25 MMcfd at a floor price of $2.49 per Mcf
Northeast Operations” means the oil and gas properties and facilities in Michigan, Indiana and Kentucky which were conveyed to BBEP in November 2007
OCI” means other comprehensive income
PCAOB” means the Public Company Accounting Oversight Board
RSU” means restricted stock unit
SEC” means the United States 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
Forward-Looking Information
     Certain statements contained in this 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 crude oil prices;
 
    failure or delays in achieving expected production from exploration and development projects;
 
    uncertainties inherent in estimates of natural gas, NGL and crude oil reserves and predicting natural gas, NGL and crude oil reservoir performance;
 
    effects of hedging natural gas, NGL and crude oil prices;
 
    fluctuations in the value of certain of our assets and liabilities;
 
    competitive conditions in our industry;
 
    actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;
 
    changes in the availability and cost of capital;
 
    delays in obtaining oilfield equipment and increases in drilling and other service costs;
 
    operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
 
    the effects of existing and future laws and governmental regulations;
 
    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 report are made only as of the date of this 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. Financial Statements (Unaudited)
QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
In thousands, except for per share data — Unaudited
                                 
    For the Three Months Ended     For the Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
Revenue
                               
Natural gas, NGL and crude oil
  $ 198,287     $ 218,214     $ 581,156     $ 574,717  
Sales of purchased natural gas
    5,964             11,181        
Other
    2,406       18,048       6,293       17,063  
 
                       
Total revenue
    206,657       236,262       598,630       591,780  
 
                       
 
                               
Operating expenses
                               
Oil and gas production expense
    29,064       33,068       92,938       98,443  
Production and ad valorem taxes
    6,630       4,944       18,437       10,684  
Costs of purchased natural gas
    2,964             11,546        
Other operating costs
    2,066       878       5,337       2,679  
Depletion, depreciation and accretion
    44,548       51,777       155,210       125,756  
General and administrative
    17,682       25,605       59,452       56,402  
 
                       
Total expenses
    102,954       116,272       342,920       293,964  
Impairment related to oil and gas properties
                (967,126 )      
 
                       
Operating income (loss)
    103,703       119,990       (711,416 )     297,816  
Loss from earnings of BBEP — net
    (43,685 )     (89,814 )     (24,669 )     (93,864 )
Other expense — net
    (645 )     (2,113 )     (739 )     (1,055 )
Interest expense
    (41,619 )     (35,988 )     (149,901 )     (65,521 )
 
                       
Income (loss) before income taxes
    17,754       (7,925 )     (886,725 )     137,376  
Income tax (expense) benefit
    (15,595 )     5,295       301,125       (46,041 )
 
                       
Net income (loss)
    2,159       (2,630 )     (585,600 )     91,335  
Net income attributable to noncontrolling interests
    (1,429 )     (1,125 )     (4,411 )     (2,621 )
 
                       
Net income (loss) attributable to Quicksilver
  $ 730     $ (3,755 )   $ (590,011 )   $ 88,714  
Other comprehensive income (loss) — net of income tax
                               
Reclassification adjustments related to settlements of derivative contracts
    (63,196 )     17,500       (160,183 )     40,396  
Net change in derivative fair value
    1,030       308,096       113,333       46,847  
Foreign currency translation adjustment
    11,937       (11,044 )     18,719       (17,858 )
 
                       
Comprehensive income (loss)
  $ (49,499 )   $ 310,797     $ (618,142 )   $ 158,099  
 
                       
 
                               
Earnings (loss) per common share — basic
  $     $ (0.02 )   $ (3.49 )   $ 0.55  
Earnings (loss) per common share — diluted
  $     $ (0.02 )   $ (3.49 )   $ 0.55  
Basic weighted average shares outstanding
    169,021       164,439       168,917       160,293  
Diluted weighted average shares outstanding
    170,657       164,439       168,917       171,099  
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
                 
    September 30,     December 31,  
    2009     2008  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $ 1,568     $ 2,848  
Accounts receivable — net of allowance for doubtful accounts
    75,225       143,315  
Derivative assets at fair value
    147,815       171,740  
Other current assets
    57,066       75,433  
 
           
Total current assets
    281,674       393,336  
Investment in BBEP
    114,733       150,503  
Property, plant and equipment
               
Oil and gas properties, full cost method (including unevaluated costs of $497,301 and $543,533, respectively)
    2,261,930       3,142,608  
Other property and equipment
    731,870       655,107  
 
           
Property, plant and equipment — net
    2,993,800       3,797,715  
Derivative assets at fair value
    34,170       116,006  
Deferred income taxes
    143,450        
Other assets
    47,728       40,648  
 
           
 
  $ 3,615,555     $ 4,498,208  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities
               
Current portion of long-term debt
  $     $ 6,579  
Accounts payable
    143,989       282,636  
Income taxes payable
    5,583       40  
Accrued liabilities
    152,205       66,923  
Derivative liabilities at fair value
    871       9,928  
Deferred income taxes
    63,394       52,393  
 
           
Total current liabilities
    366,042       418,499  
Long-term debt
    2,531,632       2,586,046  
Asset retirement obligations
    44,902       34,753  
Other liabilities
    30,049       12,962  
Deferred income taxes
    36,542       234,385  
Commitments and contingencies (Note 10)
           
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; 173,997,988 and 171,742,699 shares issued, respectively
    1,740       1,717  
Paid in capital in excess of par value
    672,475       656,958  
Treasury stock of 4,700,335 and 4,572,795 shares, respectively
    (36,309 )     (35,441 )
Accumulated other comprehensive income
    156,973       185,104  
Retained earnings (deficit)
    (213,523 )     376,488  
 
           
Quicksilver stockholders’ equity
    581,356       1,184,826  
Noncontrolling interests
    25,032       26,737  
 
           
Total equity
    606,388       1,211,563  
 
           
 
  $ 3,615,555     $ 4,498,208  
 
           
The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUICKSILVER RESOURCES INC.
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
In thousands — Unaudited
                                                         
    Quicksilver Resources Inc. Stockholders              
                            Accumulated                    
            Additional             Other     Retained              
    Common     Paid-in     Treasury     Comprehensive     Earnings     Noncontrolling        
    Stock     Capital     Stock     Income     (Deficit)     Interests     Total  
Balances at December 31, 2007
  $ 1,606     $ 378,622     $ (12,304 )   $ 40,066     $ 754,764     $ 29,714     $ 1,192,468  
Net income
                            88,714       2,621       91,335  
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $20,770
                      40,396                   40,396  
Net change in derivative fair value, net of income tax of $23,846
                      46,847                   46,847  
Foreign currency translation adjustment
                      (17,858 )                 (17,858 )
Stock issuance — Alliance Acquistion
    104       261,988                               262,092  
Issuance and vesting of stock compensation
    5       11,050       (3,235 )                 755       8,575  
Stock option exercises
    2       1,238                               1,240  
Distributions paid on KGS common units
                                  (6,343 )     (6,343 )
 
                                         
Balances at September 30, 2008
  $ 1,717     $ 652,898     $ (15,539 )   $ 109,451     $ 843,478     $ 26,747     $ 1,618,752  
 
                                         
 
                                                       
Balances at December 31, 2008
  $ 1,717     $ 656,958     $ (35,441 )   $ 185,104     $ 376,488     $ 26,737     $ 1,211,563  
Net income (loss)
                            (590,011 )     4,411       (585,600 )
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax benefit of $74,629
                      (160,183 )                 (160,183 )
Net change in derivative fair value, net of income tax of $52,317
                      113,333                   113,333  
Foreign currency translation adjustment
                      18,719                   18,719  
Issuance and vesting of stock compensation
    23       14,695       (868 )                 1,228       15,078  
Stock option exercises
          822                               822  
Distributions paid on KGS common units
                                  (7,344 )     (7,344 )
 
                                         
Balances at September 30, 2009
  $ 1,740     $ 672,475     $ (36,309 )   $ 156,973     $ (213,523 )   $ 25,032     $ 606,388  
 
                                         
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 Nine Months Ended  
    September 30,  
    2009     2008  
Operating activities:
               
Net income (loss)
  $ (585,600 )   $ 91,335  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Impairment related to oil and gas properties
    967,126        
Depletion, depreciation and accretion
    155,210       125,756  
Deferred income tax expense (benefit)
    (313,556 )     43,322  
Loss from BBEP in excess of cash distributions, net of impairment
    35,770       93,864  
Non-cash interest expense
    40,553       8,085  
Stock-based compensation
    16,007       11,810  
Non-cash (gain) loss from hedging and derivative activities
    2,845       (2,065 )
Other
    684       1,288  
Changes in assets and liabilities
               
Accounts receivable
    67,555       (16,532 )
Derivative assets at fair value
    54,896        
Other assets
    4,490       (4,819 )
Accounts payable
    (34,543 )     (9,619 )
Income taxes payable
    5,542       (46,414 )
Accrued and other liabilities
    33,614       (21,891 )
 
           
Net cash provided by operating activities
    450,593       274,120  
 
           
Investing activities:
               
Purchases of property, plant and equipment
    (561,120 )     (985,124 )
Alliance Acquisition
          (990,649 )
Proceeds from sales of property, plant and equipment
    221,038       818  
Return of investment from BBEP
          31,435  
 
           
Net cash used for investing activities
    (340,082 )     (1,943,520 )
 
           
Financing activities:
               
Issuance of debt
    1,377,525       2,472,119  
Repayment of debt
    (1,507,137 )     (781,988 )
Debt issuance costs
    (30,995 )     (24,545 )
Gas Purchase Commitment — net
    54,488        
Noncontrolling interest distributions
    (7,344 )     (6,343 )
Other
    (107 )     (1,995 )
 
           
Net cash provided by (used for) financing activities
    (113,570 )     1,657,248  
 
           
Effect of exchange rate changes in cash
    1,779       (2,609 )
 
           
Net decrease in cash
    (1,280 )     (14,761 )
Cash and cash equivalents at beginning of period
    2,848       28,226  
 
           
Cash and cash equivalents at end of period
  $ 1,568     $ 13,465  
 
           
The accompanying notes are an integral part of these condensed consolidated financial statements.

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QUICKSILVER RESOURCES INC.
NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
Unaudited
1. ACCOUNTING POLICIES AND DISCLOSURES
     The accompanying condensed consolidated interim financial statements have not been audited. In our management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly our financial position as of September 30, 2009 and our results of operations for the three and nine months ended September 30, 2009 and 2008 and cash flows for the nine months ended September 30, 2009 and 2008.   All such adjustments are of a normal recurring nature.   The results for interim periods are not necessarily indicative of annual results.
     Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period.   We believe our estimates and assumptions are reasonable, but actual results could differ from our estimates.
     Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States 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 2008 Annual Report on Form 10-K, as amended.
Earnings per Share
     The following is a reconciliation of the weighted average common shares used in the basic and diluted earnings (loss) per common share calculations for the periods presented.   The basic and diluted earnings (loss) per common share for each of the periods presented includes unvested share-based payment awards that contain nonforfeitable rights to dividends.   For the three months ended September 30, 2009 and 2008, approximately 9.8 million and 10.7 million potentially dilutive securities, respectively, were excluded from the diluted net loss per share calculation because they were antidilutive.   Approximately 11.1 million potentially dilutive securities were excluded from the diluted net loss per share calculation for the nine months ended September 30, 2009.   The excluded potentially dilutive securities include 9.8 million for the convertible debentures.   No potentially dilutive securities were excluded from the diluted net income per share calculation for the nine months ended September 30, 2008.
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2009     2008     2009     2008  
    (In thousands, except per     (In thousands, except per  
    share data)     share data)  
 
                               
Net income (loss) attributable to Quicksilver
  $ 730     $ (3,755 )   $ (590,011 )   $ 88,714  
 
                               
Impact of assumed conversions — interest on 1.875% convertible debentures, net of income taxes
          1,578             3,137  
 
                       
Income (loss) available to stockholders assuming conversion of convertible debentures
  $ 730     $ (2,177 )   $ (590,011 )   $ 91,851  
 
                       
 
                               
Weighted average common shares — basic
    169,021       164,439       168,917       160,293  
Effect of dilutive securities:
                               
Employee stock options
    1,452                   676  
Employee stock unit awards
    184                   314  
Contingently convertible debentures
                      9,816  
 
                       
Weighted average common shares — diluted
    170,657       164,439       168,917       171,099  
 
                       
 
                               
Earnings (loss) per common share — basic
  $     $ (0.02 )   $ (3.49 )   $ 0.55  
Earnings (loss) per common share — diluted
  $     $ (0.02 )   $ (3.49 )   $ 0.55  

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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.   Below we present a discussion of only those pronouncements that have an impact to our financial statements.
  Pronouncements Impacting Quicksilver That Have Been Implemented
     In June 2009, the FASB issued guidance that identified the FASB Accounting Standards Codification as the single source of authoritative U.S. GAAP not promulgated by the SEC.   The FASB also issued various technical corrections in Updates No. 2009-01 through No. 2009-03 and Update No. 2009-07.   The FASC retains existing GAAP and had no effect on our financial statements upon its adoption by us on September 30, 2009, although all references to GAAP herein have been converted to the codified reference.
     The FASB issued revised guidance for business combinations in December 2007, which retained fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination.   The acquirer is the entity that obtains control in the business combination and the guidance establishes the criteria to determine the acquisition date.   An acquirer is also required to recognize the assets acquired and liabilities assumed measured at their fair values as of the acquisition date.   In addition, acquisition costs are required to be recognized separately from the acquisition.   Additional clarifications were issued on April 1, 2009 that address application issues regarding initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination.   We will apply this guidance, found in FASC Topic 805, Business Combinations, to any acquisition we enter into after January 1, 2009, but otherwise adoption had no effect on our financial statements.
     The FASB issued new guidance in December 2007 which governs accounting and reporting standards for the noncontrolling interest in a subsidiary (previously referred to as “minority interest”) and for the deconsolidation of a subsidiary.   The new guidance, found in FASC Section 810-10, Consolidation, amends prior standards to clarify that a noncontrolling interest should be reported as a component of consolidated equity.   The consolidated income statement is now required to report consolidated net income at amounts that include the amounts attributable to both the parent and noncontrolling interest.   Additionally, the guidance established a single method for accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation.   We adopted the new accounting guidance on January 1, 2009, which resulted in the reclassification of the minority interest liability of $29.9 million and deferred tax benefit of $3.2 million, or $26.7 million, to stockholders’ equity.   In addition, our adoption resulted in reclassification of the $79.3 million deferred gain related to the KGS IPO to “paid in capital in excess of par value” within stockholders’ equity.   We have also retrospectively presented our consolidated balance sheet as of December 31, 2008 and our results of operations for 2008 to reflect a comparable presentation.
     In February 2008, the FASB issued guidance which allowed for a one-year deferral of the effective date of the accounting guidance in FASC Topic 820, Fair Value Measurements and Disclosures, as it applies to non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis.   Beginning January 1, 2009, we applied the accounting guidance for all fair value measurements to non-financial assets and liabilities.
     The FASB issued accounting guidance in March 2008, also found in FASC Section 815-10, Derivatives and Hedging, requiring enhanced disclosures of the fair value and other aspects of all derivative and hedging instruments in tabular format and information about credit risk-related features in derivative agreements, counterparty credit risk, and its strategies and objectives for using derivative instruments.   We adopted the guidance on January 1, 2009 and have provided the prescribed disclosures for all periods presented that may be found in Note 4.
     In May 2008, the FASB issued guidance indicating that issuers of convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) generally should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in periods subsequent to issuance.   We adopted the new guidance found at FASC Section 470-20-15, Debt with Conversion and Other Options, on January 1, 2009, which resulted in recognition of a $26.8 million addition to “paid in capital in excess of par value,” additional deferred tax liability of $5.8 million and decreases to other assets, long-term debt and retained earnings of $2.4 million, $19.0 million and $16.0 million, respectively.   We have also presented all comparable prior period information in conformity with this guidance.

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     The FASB issued additional guidance in June 2008 regarding unvested share-based payment awards that contain nonforfeitable rights to dividends.   The guidance was effective and adopted by us on January 1, 2009.   Under this guidance, found at FASC Subtopic 260-10, Earnings per Share, unvested share-based payment awards that contain nonforfeitable rights to dividends (whether paid or unpaid) are participating securities and should be included in the computation of basic earnings per share pursuant to the two-class method.   Based upon the characteristics of our equity awards, approximately 2.5 million restricted shares have been identified as participating securities and are included in the basic earnings per share calculation for the three and nine months ended September 30, 2009.   Basic earnings per share for the three and nine months ended September 30, 2008 have been retrospectively adjusted to reflect those restricted shares as participating securities.
     On April 9, 2009, the FASB issued guidance, found at FASC Subtopic 825-10, Financial Instruments, requiring disclosures about fair value of financial instruments for interim reporting periods.   We adopted the disclosure requirements with our quarterly report on Form 10-Q for the period ending March 31, 2009.
     The FASB issued guidance in May 2009 for disclosure of events that occur after the balance sheet date but before financial statements are issued by public entities.   It mirrors the longstanding existing guidance for subsequent events that was promulgated by the American Institute of Certified Public Accountants.   We adopted the guidance found in FASC Subtopic 855-10, Subsequent Events, for the quarter ended June 30, 2009 when the guidance became effective without effect.   We have carried out our evaluation for subsequent disclosure through November 9, 2009 except for our evaluation for impairment of our oil and gas properties, which was carried out through November 3, 2009.
     The FASB issued Update No. 2009-05 in August 2009, which updated FASC Topic 820, Fair Value Measurements and Disclosures, for the fair value measurement of liabilities.   We have adopted all guidance found in FASC Topic 820 for the quarter ended September 30, 2009.
     The following table summarizes the impact of implementing the previously discussed accounting pronouncements on the 2008 periods presented in these financial statements:
                                                 
    For the Three Months Ended September 30, 2008     For the Nine Months Ended September 30, 2008  
    As Originally             Effect of     As Originally             Effect of  
    Reported     As Adjusted     Change     Reported     As Adjusted     Change  
    (In thousands, except for per share data)     (In thousands, except for per share data)  
Operating income
  $ 119,990     $ 119,990     $     $ 297,816     $ 297,816     $  
Loss from earnings of BBEP
    (89,814 )     (89,814 )           (93,864 )     (93,864 )      
Interest expense and other
    (36,440 )     (38,101 )     (1,661 )     (61,680 )     (66,576 )     (4,896 )
 
                                   
Income before income tax
    (6,264 )     (7,925 )     (1,661 )     142,272       137,376       (4,896 )
Income tax (expense) benefit
    4,714       5,295       581       (47,754 )     (46,041 )     1,713  
Minority interest expense
    (1,125 )           (1,125 )     (2,621 )           (2,621 )
Net income attributable to noncontrolling interests
          (1,125 )     1,125             (2,621 )     2,621  
 
                                   
Net income attributable to Quicksilver
  $ (2,675 )   $ (3,755 )   $ (1,080 )   $ 91,897     $ 88,714     $ (3,183 )
 
                                   
Earnings per share — basic
  $ (0.02 )   $ (0.02 )   $     $ 0.57     $ 0.55     $ (0.02 )
Earnings per share — diluted
  $ (0.02 )   $ (0.02 )   $     $ 0.54     $ 0.55     $ 0.01  
Basic weighted average shares outstanding
    164,087       164,439       352       159,914       160,293       379  
Diluted weighted average shares outstanding
    164,087       164,439       352       171,759       171,099       (660 )
  Pronouncements Not Yet Implemented
     The SEC adopted revisions to its required oil and gas reporting disclosures in December 2008.   The revisions affecting us include: 1) use of 12-month average of the first-day-of-the-month prices for determination of proved reserve values included in calculating full cost ceiling limitations and for annual proved reserve disclosures; 2) limitations on the types of technologies that may be relied upon to establish the levels of certainty required to classify reserves; and 3) ability to disclose “probable” and “possible” reserves as defined by the SEC.   The SEC also updated the required disclosure requirements and eliminated use of price recoveries subsequent to period end for use in the ceiling test.   We will adopt these changes for reporting our proved reserves

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beginning with annual disclosures in our 2009 Annual Report on Form 10-K.   We are still reviewing the implications of this adoption on our previous reserve disclosures.
2. ENI TRANSACTION
     On June 19, 2009, we completed the Eni Transaction whereby we entered into a strategic alliance with Eni and sold a 27.5% interest in our Alliance Leasehold.   The assets were sold to Eni for $280 million in cash, inclusive of the Gas Purchase Commitment assumed, and subject to normal post-closing adjustments.   We used the proceeds generated to repay a portion of the Senior Secured Second Lien Facility.
     In connection with the sale, one of our wholly owned subsidiaries entered into a gas gathering agreement with Eni covering Eni’s production from the Alliance Leasehold.   Under the agreement, we will gather, treat and deliver Eni’s Alliance Leasehold production.   Eni also committed to pay approximately $19.2 million by March 2010 to us (of which $9.5 million has been paid through September 30, 2009) for construction and installation of the facilities required to gather Eni’s production from future Alliance wells.   We will be the sole owner of these facilities and, upon completion of the Gas Purchase Commitment, will recognize gathering revenue for the volumes of gas that are gathered.
     Also as part of the sale, we entered into a joint development agreement with Eni.   The joint development agreement includes a schedule of wells that we agreed to drill and complete with participation by Eni during the development period.   In connection with the scheduled drilling of these wells, we have committed to drill and complete a minimum number of lateral feet each year.   Eni agreed to pay us a turnkey drilling and completion cost of $994 per linear foot attributable to Eni.   The net linear footage requirements to be drilled and completed attributable to Eni are summarized below:
         
    Total Aggregate
Year   Linear Feet
 
       
2009
    28,215  
2010
    58,448  
2011
    44,080  
2012
    26,974  
2013
    34,102  
     Under the joint development agreement, we may be subject to pay Eni for damages at the end of the development period should we fail to meet the linear footage requirements and certain production requirements have not been satisfied.   We currently expect to satisfy these requirements and have recognized no liability for our non-performance.
3. ALLIANCE ACQUISITION
     On August 8, 2008, we completed the Alliance Acquisition, whereby we acquired leasehold, royalty and midstream assets associated with the Barnett Shale formation in northern Tarrant and southern Denton counties of Texas.   The purchase price was funded as follows:
         
(In thousands)
Purchase Price:
       
Cash paid
  $ 1,000,000  
Cash received from post-closing settlement
    (9,086 )
Cash paid for acquisition-related expenses
    1,368  
 
     
Total cash
    992,282  
Issuance of 10,400,468 common shares
    262,092  
 
     
 
  $ 1,254,374  
 
     

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     The purchase price allocation is presented below:
         
(In thousands)        
 
Allocation of Purchase Price:
       
Oil and gas properties — proved
  $ 788,457  
Oil and gas properties — unproved
    440,372  
Midstream assets
    27,652  
Liabilities assumed
    (1,035 )
Asset retirement obligations
    (1,072 )
 
     
 
  $ 1,254,374  
 
     
     The purchase price allocation was based on estimates of oil and gas reserves and other valuations and estimates by our management.
Pro Forma Information
     The following table reflects Quicksilver’s unaudited consolidated pro forma statements of income as though the Alliance Acquisition, associated borrowings and issuance of our common stock had taken place on January 1, 2008.   The actual revenue and expenses for the acquisition are included in our 2008 consolidated results beginning on August 8, 2008 and for all of 2009.   The following pro forma information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective on January 1, 2008.
                 
    For the Three     For the Nine  
    Months Ended     Months Ended  
    September 30, 2008     September 30, 2008  
    (In thousands, except for per share data)  
Revenues
  $ 249,956     $ 667,762  
 
           
Net income attributable to Quicksilver
  $ (112 )   $ 85,544  
 
           
Earnings per share — basic
  $     $ 0.51  
Earnings per share — diluted
  $     $ 0.50  
4. DERIVATIVES AND FAIR VALUE MEASUREMENTS
     We use derivatives to mitigate price risk associated with the sale of our natural gas, NGL and crude oil production.   Prices for these products are capable of wide fluctuations that may negatively affect profitability and cash flow from operations but may also increase them.   We mitigate the risk of adverse price movements with swaps and collars, which also limit future gains from favorable price movements.   We also use derivatives, in the form of swaps, to monetize the fair value of our fixed-rate long-term debt in periods of low interest rates, thereby reducing our current levels of interest payments.
     We enter into financial derivatives with counterparties who are lenders under our credit facility.   The credit facility provides for collateralization of amounts outstanding from our derivative instruments in addition to amounts outstanding under the facility.   Additionally, default on any of our obligations under derivative instruments with counterparty lenders could result in acceleration of the amounts outstanding under the credit facility.   The credit facility and our internal credit policies require that any counterparties, including facility lenders, with whom we enter into commodity financial derivatives have credit ratings that meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively.   The fair value for each derivative takes into consideration credit risk, whether it be our counterparties’ or our own.   Derivatives are recorded in the balance sheet as current and non-current derivative assets and liabilities as determined by the expected timing of settlements.
Commodity Price Derivatives
     As of September 30, 2009, we had price collars or fixed price swaps hedging 190 MMcfd of our anticipated natural gas production for the remainder of 2009.   We have also hedged approximately 120 MMcfd of our anticipated 2010 U.S. natural gas production using natural gas price collars.   In March 2009, we executed the early settlement of a price collar that hedged the sale of 40 MMcfd of our

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forecasted 2010 natural gas production, whereby we received $54.9 million.   The settlement was recorded to AOCI and will be reclassified into natural gas revenue as we sell the associated hedged production volumes during 2010.   Excluded from the amounts presented in the tables below are price collars and swaps entered into during October 2009.
Interest Rate Derivatives
     In June 2009, we entered into interest rate swaps on our $475 million Senior Notes due 2015 and our $350 million Senior Subordinated Notes effectively converting the interest on those issues from a fixed to a floating rate indexed to a one-month LIBOR base rate.   The maturity dates and all other significant terms are the same as those of the underlying debt.   Under these swaps, we pay a variable interest rate and receive the fixed rate applicable to the underlying debt.   The interest income or expense is accrued as earned and recorded as an adjustment to the interest expense accrued on the fixed-rate debt.   The interest rate swaps are designated as fair value hedges of the underlying debt.   The value of the contracts, excluding the net interest accrual, amounted to a net asset of $16.0 million as of September 30, 2009.   The offsetting fair value adjustment to the debt hedged resulted in an increase of long-term debt by $16.0 million as of September 30, 2009.   No ineffectiveness was recorded in connection with the fair value hedges.   The average effective interest rates on the 2015 Senior Notes and Senior Subordinated Notes, since we entered into the hedges in June 2009, were approximately 5.12% and 3.74%, respectively.
Other Derivatives
     Based on information available on June 19, 2009, we recognized a liability pursuant to the Gas Purchase Commitment based on the estimated production volumes attributable to Eni through December 31, 2010, which then totaled 22.2 Bcf.   The Gas Purchase Commitment contains an embedded derivative that is adjusted to fair value throughout the period of the commitment, which expires on December 31, 2010.   We recognized a $1.2 million increase in the fair value of the embedded derivative liability between June 19 and September 30, 2009 and recorded a valuation loss in costs of purchased natural gas.   At September 30, 2009, we have a remaining liability of $55.7 million, including the $1.2 million liability for the embedded derivative.   The following summarizes activity to the Gas Purchase Commitment:
         
(In thousands)        
 
Initial valuation of liability (1)
  $ 58,294  
Decrease due to gas volumes purchased
    (3,806 )
Embedded derivative increase (decrease) due to:
       
Price changes
    1,667  
Volume changes
    (479 )
 
     
Total embedded derivative
    1,188  
 
     
Balance at September 30, 2009
  $ 55,676  
 
     
 
(1)   Initial valuation of the Gas Purchase Commitment was estimated using estimated Eni production volumes from June 19, 2009 through December 2010 and published future market prices and risk-adjusted interest rates as of June 19, 2009.

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     The estimated fair value of our derivatives at September 30, 2009 and December 31, 2008 were as follows:
                                   
    Asset Derivatives       Liability Derivatives  
    September 30,     December 31,       September 30,     December 31,  
    2009     2008       2009     2008  
    (In thousands)       (In thousands)  
Derivatives designated as hedges:
                                 
Commodity contracts reported in:
                                 
Current derivative assets
  $ 145,180     $ 179,079       $     $ 2,500  
Noncurrent derivative assets
    20,763       116,006                
Current derivative liabilities
                  871       1,865  
Interest rate contracts reported in:
                                 
Current derivative assets
    2,635                      
Noncurrent derivative assets
    13,407                      
Current derivative liabilities
                           
Noncurrent derivative liabilities
                         
 
                         
Total derivatives designated as hedges
  $ 181,985     $ 295,085       $ 871     $ 4,365  
 
                         
Derivatives not designated as hedges:
                                 
Gas Purchase Commitment reported in:
                                 
Accrued liabilities
  $     $       $ 1,146     $  
Other liabilities
                    42        
Michigan Sales Contract natural gas purchase derivatives (1) reported in current derivative assets
                        4,839  
Michigan Sales Contract (1) reported in current derivative liabilities
                        8,063  
 
                         
Total derivatives not designated as hedges
  $     $       $ 1,188     $ 12,902  
 
                         
Total derivatives
  $ 181,985     $ 295,085       $ 2,059     $ 17,267  
 
                         
 
(1)   During 2009, our net cash payments were $16.5 million, including derivative settlements, to complete our obligations under the Michigan Sales Contract
     The following table shows the inputs used in our fair value calculations of our derivative instruments at September 30, 2009 and December 31, 2008:
                         
    Fair Value Measurements as of September 30, 2009(1)  
                  Balance Sheet  
    Level 2     Other (2)     Total  
    (In thousands)  
Derivative assets
  $ 181,985     $     $ 181,985  
 
                 
Derivative liabilities
  $ 2,059     $     $ 2,059  
 
                 

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    Fair Value Measurements as of December 31, 2008(1)  
                    Balance Sheet  
    Level 2     Other(2)     Total  
    (In thousands)  
Derivative assets
  $ 295,085     $ (7,339 )   $ 287,746  
 
                 
Derivative liabilities
  $ 17,267     $ (7,339 )   $ 9,928  
 
                 
 
(1)   No Level 1 or Level 3 measurements
(2)   Represents amounts netted under master netting arrangements with counterparties
     The decrease in carrying value of our commodity price derivatives since December 31, 2008 principally resulted from monthly settlements received during 2009 and the $54.9 million early settlement of a natural gas collar that hedged 2010 natural gas production.   These decreases were partially offset by the overall decline in market prices for natural gas relative to the prices in our open derivative instruments at September 30, 2009.
     The changes in the carrying value of our derivatives for the three and nine months ended September 30, 2009 and 2008 are presented below:
                                         
    For the Three Months Ended September 30, 2009  
    Michigan     Gas Purchase     Fair Value     Cash Flow        
    Contract     Commitment     Derivatives     Derivatives     Total  
    (In thousands)  
Derivative fair value at June 30, 2009
  $     $ (3,818 )   $ (266 )   $ 257,548     $ 253,464  
Net settlements reported in revenue
                      (92,687 )     (92,687 )
Net settlements reported in interest expense
                (6,537 )           (6,537 )
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas
          2,630                   2,630  
Change in fair value of effective interest swaps
                22,845             22,845  
Ineffectiveness reported in other revenue
                      77       77  
Unrealized gains reported in OCI
                      134       134  
 
                             
Derivative fair value at September 30, 2009
  $     $ (1,188 )   $ 16,042     $ 165,072     $ 179,926  
 
                             
                                         
    For the Three Months Ended September 30, 2008  
    Michigan     Gas Purchase     Fair Value     Cash Flow        
    Contract     Commitment     Derivatives     Derivatives     Total  
    (In thousands)  
Derivative fair value at June 30, 2008
  $ (46,138 )   $     $     $ (372,842 )   $ (418,980 )
Change in amounts due from Quicksilver
    4,443                   (612 )     3,831  
Net settlements
    16,072                         16,072  
Net settlements reported in revenue
                      26,614       26,614  
Ineffectiveness reported in other revenue
    (357 )                 13,912       13,555  
Unrealized gains reported in OCI
                      462,130       462,130  
 
                             
Derivative fair value at September 30, 2008
  $ (25,980 )   $     $     $ 129,202     $ 103,222  
 
                             

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    For the Nine Months Ended September 30, 2009  
    Michigan     Gas Purchase     Fair Value     Cash Flow        
    Contract     Commitment     Derivatives     Derivatives     Total  
    (In thousands)  
Derivative fair value at December 31, 2008
  $ (12,901 )   $     $     $ 290,719     $ 277,818  
Change in amounts due from Quicksilver
    (3,518 )                       (3,518 )
Net settlements
    16,479                         16,479  
Net settlements reported in revenue
                      (234,812 )     (234,812 )
Net settlements reported in interest expense
                (7,200 )           (7,200 )
Change in fair value of Gas Purchase Commitment reported in costs of purchased gas
          (1,188 )                 (1,188 )
Change in fair value of effective interest swaps
                23,242             23,242  
Ineffectiveness reported in other revenue
    (60 )                 (1,589 )     (1,649 )
Cash settlement reported in OCI
                      (54,896 )     (54,896 )
Unrealized gains reported in OCI
                      165,650       165,650  
 
                             
Derivative fair value at September 30, 2009
  $     $ (1,188 )   $ 16,042     $ 165,072     $ 179,926  
 
                             
                                         
    For the Nine Months Ended September 30, 2008  
    Michigan     Gas Purchase     Fair Value     Cash Flow        
    Contract     Commitment     Derivatives     Derivatives     Total  
    (In thousands)  
Derivative fair value at December 31, 2007
  $ (63,777 )   $     $     $ (5,503 )   $ (69,280 )
Change in amounts due from Quicksilver
    4,436                   (1,663 )     2,773  
Net settlements
    34,198                         34,198  
Net settlements reported in revenue
                      61,167       61,167  
Ineffectiveness reported in other revenue
    (837 )                 4,508       3,671  
Unrealized gains reported in OCI
                      70,693       70,693  
 
                             
Derivative fair value at September 30, 2008
  $ (25,980 )   $     $     $ 129,202     $ 103,222  
 
                             
     Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings over the next twelve months would result in a gain of $94.2 million net of income taxes.   An additional $27.4 million, net of income taxes, will be reclassified from AOCI from the realized gain on the natural gas collar settled in March 2009.   Gains from the effective portion of non-current derivative assets and realized gains will be reclassified to earnings from AOCI over the three months ending December 31, 2010.   Hedge derivative ineffectiveness resulted in losses of $1.7 million (including an immaterial amount in the third quarter) and $3.7 million (including a gain of $13.6 million in the third quarter) recorded in other revenue for the nine months ended September 30, 2009 and 2008, respectively.
5.   INVESTMENT IN BREITBURN ENERGY PARTNERS L.P.
     We own approximately 21.3 million common units of BBEP, a publicly traded limited partnership, which we acquired in connection with the BreitBurn Transaction.   On June 17, 2008, BBEP announced that it had repurchased and retired 14.4 million units, which represented approximately 22% of the units previously outstanding.   The resulting reduction in the number of BBEP common units outstanding increased our ownership from approximately 32% to approximately 41%.   At September 30, 2009, we owned approximately 40% of BBEP’s outstanding common units.
     During the first quarter of 2009, we evaluated our investment in BBEP for impairment in response to further decreases in prevailing commodity prices and BBEP’s unit price since December 31, 2008.   As a result of these decreases and the outlook for petroleum prices and broad limitations on available capital, we made the determination that the decline in value was other-than-temporary.   Accordingly, our impairment analysis utilized the March 31, 2009 closing price of $6.53 per BBEP unit, which resulted in an aggregate fair value of $139.4 million for the portion of BBEP units owned by Quicksilver.   The $139.4 million aggregate fair value was compared to an aggregate carrying value of $241.5 million.   We recorded the difference of $102.1 million as a pre-tax impairment charge during the first quarter of 2009.   No subsequent impairment of our investment has occurred as the value derived

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from the September 30, 2009 closing price of $11.37 per BBEP unit exceeded our carrying value of approximately $5.37 per unit.   Additional impairment of our investment in BBEP units could occur during the remainder of 2009 depending upon the performance of BBEP’s unit price, which itself is dependent upon numerous factors.
     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     For the  
    For the Three Months Ended     Nine Months     Eight Months  
    June 30,     Ended     Ended  
    2009     2008     June 30, 2009     June 30, 2008  
    (In thousands)  
Revenues (1)
  $ (36,994 )   $ (212,677 )   $ 534,192     $ (118,175 )
Operating expenses (2)
    67,352       69,590       307,391       181,747  
 
                       
Operating income (loss)
    (104,346 )     (282,267 )     226,801       (299,922 )
Interest and other (3)
    4,988       4,994       37,458       16,274  
Income tax (benefit) expense
    (809 )     (1,091 )     336       (2,006 )
Noncontrolling interests
    (5 )     70       15       155  
 
                       
Net income (loss) available to BBEP
  $ (108,520 )   $ (286,240 )   $ 188,992     $ (314,345 )
 
                       
Net income (loss) available to common unitholders
  $ (108,520 )   $ (284,494 )   $ 188,992     $ (312,794 )
 
                       
 
(1)   Unrealized losses on commodity derivatives of $148.7 million and $319.9 million were included for the three months ended June 30, 2009 and 2008, respectively.   Unrealized gains of $193.5 million and unrealized losses of $392.2 million on commodity derivatives were included for the nine months ended June 30, 2009 and the eight months ended June 30, 2008, respectively.   Realized gains on commodity derivatives of $25.0 million and $70.6 million for the early settlement of derivative positions were included for the three and nine months ended June 30, 2009, respectively.
 
(2)   An impairment of BBEP’s oil and gas properties of $86.4 million was included for the nine months ended June 30, 2009
 
(3)   The three months ended June 30, 2009 included $0.3 million for unrealized gains on interest rate swaps and the nine months ended June 30, 2009 included $17.9 million for unrealized losses on interest rate swaps
                 
    As of   As of
    June 30, 2009   December 31, 2008
    (In thousands)
Current assets
  $ 126,473     $ 140,566  
Property, plant and equipment
    1,799,124       1,840,341  
Other assets
    123,248       235,927  
Current liabilities
    64,887       79,990  
Long-term debt
    640,000       736,000  
Other non-current liabilities
    73,986       47,413  
Partners’ equity
    1,269,972       1,353,431  
     For the nine months ended September 30, 2009, we recognized income of $77.4 million for our share of BBEP’s income for the nine months ended June 30, 2009.   For the comparable 2008 period, we recognized a loss of $93.9 million for the eight months ended June 30, 2008.

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     Changes in the balance of our investment in BBEP for the first nine months of 2009 were as follows:
         
(In thousands)        
 
Balance at December 31, 2008
  $ 150,503  
Equity income in BBEP
    77,415  
Distributions from BBEP
    (11,101 )
Non-cash impairment of BBEP
    (102,084 )
 
     
Balance at September 30, 2009
  $ 114,733  
 
     
6.   PROPERTY, PLANT AND EQUIPMENT
     Property, plant and equipment consisted of the following:
                 
    September 30,     December 31,  
    2009     2008  
    (In thousands)  
Oil and gas properties
               
Subject to depletion
  $ 3,780,855     $ 3,621,831  
Unevaluated costs
    497,301       543,533  
Accumulated depletion
    (2,016,226 )     (1,022,756 )
 
           
Net oil and gas properties
    2,261,930       3,142,608  
Other plant and equipment
               
Pipelines and processing facilities
    753,213       529,555  
General properties
    68,118       57,941  
Construction in progress
    6,269       134,557  
Accumulated depreciation
    (95,730 )     (66,946 )
 
           
Net other property and equipment
    731,870       655,107  
 
           
Property, plant and equipment, net of accumulated depletion and depreciation
  $ 2,993,800     $ 3,797,715  
 
           
Ceiling Test Analysis
     Under the full cost method of accounting for our oil and gas properties, we must perform a quarterly ceiling test for each of our cost centers.   In determining the ceiling limitation, the ceiling test incorporates pricing, costs and discount rates over which management has no influence.   Additionally, the ceiling test requires us to evaluate the ceiling using only information for our exploration and production segment, thus we do not include the benefits associated with our ownership and consolidation of KGS.
     The 2009 first quarter U.S. ceiling amount was computed using benchmark prices of $3.63 per Mcf of natural gas, $24.12 per barrel of NGL and $49.66 per barrel of crude oil.   When we determined the present value of our U.S. reserves, the carrying value of our U.S. oil and gas properties exceeded the ceiling limit by $786.9 million (pre-tax).   We computed the 2009 first quarter Canadian ceiling amount using an AECO benchmark price of $2.92 per Mcf. Upon calculation of the present value of our Canadian reserves, the carrying value of our Canadian oil and gas properties exceeded the ceiling limit by $109.6 million (pre-tax).   We recorded a total impairment charge of $896.5 million in the first quarter of 2009.
     The second quarter 2009 ceiling test for our U.S. oil and gas properties resulted in no further recognition of impairment to those oil and gas properties due principally to price recoveries during the second quarter; however, the second quarter ceiling test for our Canadian oil and gas properties resulted in an additional charge for impairment.   We computed the 2009 second quarter Canadian ceiling amount using an AECO benchmark price of $2.87 per Mcf. The carrying value of our Canadian oil and gas reserves exceeded the present value of our Canadian proved reserves at June 30, 2009 by $70.6 million (pre-tax), which we recorded as an impairment charge in the second quarter of 2009.   The second quarter impairment charge primarily resulted from reductions in the capital forecast for the remainder of 2009 and 2010 for our Canadian oil and gas properties.
     At September 30, 2009, the unamortized cost of our Canadian oil and gas properties exceeded the full cost ceiling limitation by approximately $38.8 million (pre-tax).   The full cost ceiling limitation included $25.7 million (pre-tax) for hedge valuations.   The

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natural gas price for September 30, 2009 referenced an AECO price of $3.41 per Mcf adjusted for appropriate price differentials.   As permitted by full cost accounting rules, improvements in AECO spot natural gas prices subsequent to September 30, 2009 eliminated the necessity to record a charge for impairment.   The third quarter 2009 ceiling test for our U.S. oil and gas properties resulted in no further recognition of impairment.   Because of the volatility of oil and natural gas prices, no assurance can be given that we will not experience a charge for impairment in future periods.
     The impairment charges recorded in the first and second quarters of 2009 are summarized below:
                         
    Net             Pre-tax  
    Capitalized     Ceiling     Charge for  
    Costs(1)     Limitation(2)     Impairment  
            (In thousands)          
First Quarter
                       
United States
  $ 2,727,130     $ 1,940,263     $ 786,867  
Canada
    458,135       348,519       109,616  
 
                 
Total
  $ 3,185,265     $ 2,288,782     $ 896,483  
 
                       
Second Quarter
                       
Canada
  $ 400,696     $ 330,053     $ 70,643  
 
                       
Year to Date
                       
United States
  $ 2,727,130     $ 1,940,263     $ 786,867  
Canada
    858,831       678,572       180,259  
 
                 
Total
  $ 3,585,961     $ 2,618,835     $ 967,126  
 
                 
 
(1)   Net capitalized costs before impairment includes all costs associated with development, exploration and acquisition of oil and gas properties net of accumulated depletion and impairment, reduced by the related deferred income tax liability
 
(2)   The ceiling limitation is the sum of (i) estimated future net cash flows, discounted at 10% per annum, from proved reserves, based on unescalated period-end prices and costs, adjusted for financial derivatives that qualify as cash flow hedges of our oil and gas revenue, (ii) the costs of properties not being amortized, (iii) the lower of cost or market value of unproved properties not included in the costs being amortized, less (iv) income tax effects related to differences between book and tax bases of the oil and gas properties
7. LONG-TERM DEBT
     Long-term debt consisted of the following:
                 
    September 30,     December 31,  
    2009     2008  
    (In thousands)  
Senior secured credit facility
  $ 480,873     $ 827,868  
Senior secured second lien facility, net of unamortized discount
          641,555  
Senior notes due 2015, net of unamortized discount
    479,218       469,062  
Senior notes due 2016, net of unamortized discount
    580,830        
Senior notes due 2019, net of unamortized discount
    292,892        
Senior subordinated notes due 2016
    356,563       350,000  
Convertible debentures, net of unamortized discount
    134,356       129,240  
KGS credit agreement
    206,900       174,900  
 
           
Total debt
    2,531,632       2,592,625  
Less current maturities
          (6,579 )
 
           
Long-term debt
  $ 2,531,632     $ 2,586,046  
 
           

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Senior Secured Credit Facility
     Upon completion of the Eni Transaction, our borrowing base was adjusted to $1.125 billion. Approximately $633 million was available under the Senior Secured Credit Facility at September 30, 2009 based upon the $1.125 billion borrowing base.   The October 2009 scheduled redetermination resulted in a revised borrowing base of $1.0 billion.
Senior Secured Second Lien Facility and Senior Notes Due 2016
     On June 25, 2009, we issued our senior notes due 2016 with a principal amount of $600 million. The notes were issued at 96.717% of par, which resulted in proceeds of $580.3 million.   The notes bear interest at the rate of 11.75%.   The proceeds from these notes and from the Eni Transaction were used to fully repay and terminate the remaining indebtedness under our Senior Secured Second Lien Facility, with the remaining proceeds used to reduce amounts outstanding under the Senior Secured Credit Facility.   Upon termination of the Senior Secured Second Lien Facility, Quicksilver’s and its domestic subsidiaries’ guarantee obligations, which were secured by a second lien on substantially all the assets of Quicksilver and its domestic subsidiaries, terminated.   Furthermore, the financial covenants regarding the present value of the cash flows of our oil and gas reserves under our Senior Secured Credit Facility were eliminated.
Senior Notes Due 2019
     On August 14, 2009, we issued our senior notes due 2019 with a principal amount of $300 million.   The notes were issued at 97.612% of par and bear interest at the rate of 9.125%.   The proceeds from these notes were used to reduce amounts outstanding under the Senior Secured Credit Facility.
Convertible Debentures
     The convertible debentures are contingently convertible into shares of Quicksilver common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment.   Upon conversion, we have the option to deliver any combination of Quicksilver common stock and cash.   Should all debentures be converted to Quicksilver common stock, an additional 9,816,270 shares would become outstanding; however, as of October 1, 2009, the debentures were not convertible.
     On January 1, 2009, Quicksilver adopted the FASB’s new accounting guidance for contingent convertible securities as described in Note 1.   The fair value of the equity component of our convertible debentures at the time of issuance was determined to be $26.8 million, net of deferred tax liabilities based upon an interest rate of 6.75%.   The remaining unamortized discount on the debentures at September 30, 2009 was $15.6 million and $20.8 million at December 31, 2008, resulting in a carrying value of $134.4 million and $129.2 million at September 30, 2009 and December 31, 2008, respectively.   The remaining discount will be accreted to face value through October 2011.   For the nine months ended September 30, 2009 and 2008, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $7.2 million and $6.9 million, respectively, including contractual interest of $2.1 million for each period.
KGS Credit Agreement
     At September 30, 2009, KGS’ borrowing capacity remained at the December 31, 2008 level of $235 million, with approximately $28 million of available capacity.   In October 2009, KGS lenders increased their commitments to a total of $320 million.   The KGS Credit Agreement permits further expansion to as much as $350 million, subject to consents and additional commitments.

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Summary of All Outstanding Debt
     For a more complete description of our long-term debt, see Note 14, Long-Term Debt, to the consolidated financial statements in our 2008 Annual Report on Form 10-K, as amended.   The following table summarizes significant aspects of our long-term debt:
                                                         
    Priority on Collateral and Structural Seniority (7)   Recourse only to
    Highest priority       Lowest priority   KGS assets
            Equal priority            
    Senior Secured   2015   2016   2019   Senior   Convertible   KGS Credit
    Credit Facility   Senior Notes   Senior Notes   Senior Notes   Subordinated Notes   Debentures   Agreement
Maturity date
  February 9, 2012   June 27, 2015   January 1, 2016   September 1, 2019   March 16, 2016   November 1, 2024   August 10, 2012
     
Interest rate at
September 30, 2009 (1)
    3.067 %     8.25 %     11.75 %     9.125 %     7.125 %     1.875 %     1.50 %
     
Base interest rate options(2)
  LIBOR, ABR or specified(3)     N/A       N/A       N/A       N/A       N/A     LIBOR, ABR or specified(4)
     
Financial covenants (5)
  - Minimum current ratio of 1.0     N/A       N/A       N/A       N/A       N/A     - Maximum debt to EBITDA ratio of 4.5
 
  - Minimum EBITDA to interest expense ratio of 2.5                                           - Minimum EBITDA to interest expense ratio of 2.5
     
Significant non-financial
  - Incurrence of debt   - Incurrence of debt   - Incurrence of debt   - Incurrence of debt   - Incurrence of debt     N/A     - Incurrence of debt
covenants (5)
  - Incurrence of liens   - Incurrence of liens   - Incurrence of liens   - Incurrence of liens   - Incurrence of liens         - Incurrence of liens
 
  - Payment of   - Payment of   - Payment of   - Payment of   - Payment of                
 
  dividends   dividends   dividends   dividends   dividends           - Equity purchases
 
  - Equity purchases   - Equity purchases   - Equity purchases   - Equity purchases   - Equity purchases           - Asset sales
 
  - Asset sales   - Asset sales   - Asset sales   - Asset sales   - Asset sales           - Limitations on
 
  - Affiliate transactions   - Affiliate   - Affiliate   - Affiliate   - Affiliate           derivatives
 
          transactions   transactions   transactions   transactions                
 
  - Limitations on derivatives                                                
     
Estimated fair value (6)
  $480.9 million   $463.1 million   $658.5 million   $298.5 million   $301.6 million   $173.9 million   $206.9 million
 
(1)   Represents the weighted average borrowing rate payable to lenders and excludes effects of interest rate derivatives
 
(2)   Interest rate options include a base rate plus a spread
 
(3)   The Senior Secured Credit Facility was amended in August 2009 to add a floor to ABR of one-month LIBOR plus a 1%, increase in the ABR margin to a range of 1.375% to 2.375% and an increase in the Eurodollar and specified rate margins to a range of 2.25% to 3.25%
 
(4)   The KGS Credit Agreement was amended in October 2009 to add a floor to ABR of one-month LIBOR plus a 1%, increase in the ABR margin to a range of 2.00% to 3.00% and an increase in the Eurodollar and specified rate margins to a range of 3.00% to 4.00%
 
(5)   The covenant information presented in this table is qualified in all respects by reference to the full text of the covenants and related definitions contained in the documents governing the various components of our debt
 
(6)   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.
 
(7)   The Senior Secured Credit Facility is secured by a first perfected lien on substantially all the assets.   The other debt presented is based upon structural seniority.

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8. ASSET RETIREMENT OBLIGATIONS
     The following table provides information about our estimated asset retirement obligations for the nine months ended September 30, 2009.
         
(In thousands)        
 
Beginning asset retirement obligations
  $ 35,193  
Incremental liability incurred
    6,000  
Accretion expense
    1,722  
Change in estimates
    157  
Sale of properties
    (380 )
Asset retirement costs incurred
    (153 )
Gain on settlement of liability
    208  
Currency translation adjustment
    2,595  
 
     
Ending asset retirement obligations
    45,342  
Less current portion
    (440 )
 
     
Long-term asset retirement obligations
  $ 44,902  
 
     
9. INCOME TAXES
     The effective tax rate for the 2009 quarter was almost 88% primarily due to changes in our estimated annual effective tax rate for 2009, which had been forecasted as a 35% income tax benefit through June 30, 2009.   We now expect a 34% income tax benefit based on changes to the expected earnings allocation between the U.S. and Canada.   This change in the expected rate for 2009 required recognition during the third quarter of the cumulative amount to bring the year to date income tax provision to the 34% level.   The 2009 quarter includes an estimated $9.6 million of changes to the income tax provision for earnings recognized through the period ended June 30, 2009.
     At September 30, 2009, our unrecognized tax benefits remain at $9.3 million and we do not anticipate the total amount of unrecognized tax benefits will significantly increase or decrease within the next 12 months.   We have not recognized any unrecognized tax benefits for state income taxes.
     During March 2009, we filed the U.S. federal income tax return for 2008 reporting a taxable loss for the year.   We also filed a net operating loss carryback from 2008 to 2007 to claim a federal tax refund of $41.1 million.   We received the refund in April 2009.
     During October 2009, the Internal Revenue Service commenced an audit of our 2007 and 2008 consolidated U.S. federal income tax returns.   Although no significant adjustments are expected, any required adjustments will be made upon completion of the audit.
10. COMMITMENTS AND CONTINGENCIES
     For a more complete description of our commitments and contingencies see Note 17, Commitments and Contingencies, to the consolidated financial statements in our 2008 Annual Report on Form 10-K, as amended.
     In October 2009, a jury awarded $22 million to the plaintiffs in our litigation originally brought against us by the plaintiffs, Rod and Richard Thornton and Eagle Drilling, LLC.   We are actively seeking an appeal in this matter.
     In June 2009, the appellate court in the CMS litigation reversed the original district court judgment.   Pursuant to a settlement agreement, we paid CMS $5 million during July 2009, which we accrued during the quarter ended June 30, 2009.

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Commitments
     In connection with the Eni Transaction, we entered into the Gas Purchase Commitment.   Note 4 contains further information regarding this commitment.
     We had approximately $11.4 million in letters of credit outstanding against the Senior Secured Credit Facility and approximately $10.1 million of surety bonds outstanding at September 30, 2009 to fulfill contractual, legal or regulatory requirements.   All letters of credit and surety bonds have an annual renewal option.   Additionally, we had commitments outstanding of approximately $13.9 million related to our 2009 and 2010 capital programs as of September 30, 2009.
11. STOCK-BASED COMPENSATION
     On May 20, 2009, stockholders approved an amendment to the 2006 Equity Plan, which increased the number of shares available for issuance to 15 million.   Note 20, Stockholders’ Equity, in the consolidated financial statements in our 2008 Annual Report on Form 10-K, as amended, contains additional information about our equity-based compensation plans.
Quicksilver Stock Options
     Options to purchase shares of common stock were granted in 2009 with an estimated fair value of $8.7 million.   We recognized expense of $3.4 million for stock options in the first nine months of 2009.   At September 30, 2009, we had unearned compensation cost of $8.3 million remaining, which will be recognized in expense through January 2011.
     We estimated the fair value of stock options granted in 2009 on the dates of grant using the Black-Scholes option pricing model with the following assumptions:
         
    Stock  
    Options  
    Issued  
Wtd avg grant date fair value
  $ 6.21  
Wtd avg grant date
  Jan 2, 2009
Wtd avg risk-free interest rate
    1.90 %
Expected life (in years)
    6.0  
Wtd avg volatility
    56.76 %
Expected dividends
     
     The following table summarizes stock option activity during the nine months ended September 30, 2009:
                                 
            Wtd Avg     Wtd Avg        
            Exercise     Remaining     Aggregate  
    Shares     Price     Contractual Life     Intrinsic Value  
                    (In years)     (In thousands)  
Outstanding at December 31, 2008
    1,103,336     $ 14.20                  
Granted
    2,605,699       6.21                  
Exercised
    (147,510 )     5.58                  
Cancelled
    (79,504 )     9.01                  
 
                             
Outstanding at September 30, 2009
    3,482,021     $ 8.70       7.6     $ 24,668  
 
                       
Exercisable at September 30, 2009
    803,128     $ 10.25       2.4     $ 5,046  
 
                       
Vested at September 30, 2009 or expected to vest in the future
    3,303,418     $ 7.18                  
 
                           
     Cash received from the exercise of stock options was $0.8 million and $1.2 million for the nine months ended September 30, 2009 and 2008, respectively.

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Quicksilver Restricted Stock and Restricted Stock Units
     The following table summarizes information regarding our restricted stock and RSU activity:
                                 
    Payable in stock   Payable in cash
            Wtd Avg           Wtd Avg
            Grant Date           Grant Date
    Shares   Fair Value   Stock Units   Fair Value
 
                               
Outstanding at December 31, 2008
    1,336,111     $ 24.01           $  
Granted
    2,264,679       6.23       339,835       6.22  
Vested
    (715,431 )     22.32              
Cancelled
    (156,900 )     14.12       (5,795 )     6.21  
 
                               
Outstanding at September 30, 2009
    2,728,459     $ 9.91       334,040     $ 6.22  
 
                               
     At January 1, 2009, we had total unvested compensation cost of $17.6 million.   During the first nine months of 2009, we recognized expense of $12.4 million.   Grants of restricted stock and stock-settled RSUs during the nine months ended September 30, 2009, had an estimated grant date fair value of $16.2 million, which will be recognized as expense over the vesting period.   Unrecognized compensation cost remaining at September 30, 2009 for restricted stock and stock-settled RSUs was $19.3 million, which will be recognized through January 2011.   The fair value of RSUs settled in cash was $4.7 million at September 30, 2009.   The total fair value of restricted shares and RSUs vested during the nine months ended September 30, 2009 was $5.8 million.
KGS Phantom Units
     On October 7, 2009, unitholders approved an amendment to the 2007 Equity Plan, which increased the number of units available for issuance to 750,000 as of November 4, 2009.
     The following table summarizes information regarding KGS phantom unit activity:
                                 
    Payable in units   Payable in cash
            Wtd Avg           Wtd Avg
            Grant Date           Grant Date
    Units   Fair Value   Units   Fair Value
 
                               
Outstanding at December 31, 2008
    139,918     $ 25.15       60,319     $ 21.63  
Granted
    405,428       10.06       920       13.40  
Vested
    (49,789 )     25.25       (25,609 )     13.53  
Cancelled
    (9,885 )     15.90       (5,973 )     21.36  
 
                               
Outstanding at September 30, 2009
    485,672     $ 12.73       29,657     $ 28.42  
 
                               
     At January 1, 2009, KGS had total unrecognized compensation cost of $2.3 million related to unvested phantom unit awards.   KGS recognized compensation expense of approximately $1.9 million during the nine months ended September 30, 2009, including $0.3 million related to Quicksilver equity grants issued to employees seconded to KGS.   Grants of phantom units during the nine months ended September 30, 2009 had an estimated grant date fair value of $4.1 million.   KGS has unearned compensation expense of $3.1 million at September 30, 2009 that will be recognized in expense through May 2012.   Phantom units that vested during the nine months ended September 30, 2009 had a fair value of $1.6 million on their vesting date.

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12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
     Note 21 to our 2008 Annual Report on Form 10-K, as amended, contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries.
     The following condensed consolidating financial information includes information about the Company and our restricted subsidiaries:
                                                                 
    September 30, 2009  
                    Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor     Consolidating     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
                            (In thousands)                          
ASSETS
                                                               
Current assets
  $ 362,105     $ 198     $ 48,680     $ (119,055 )   $ 291,928     $ 6,490     $ (16,744 )   $ 281,674  
Property and equipment
    1,924,744       142,984       470,411             2,538,139       455,661             2,993,800  
Investment in subsidiaries (equity method)
    473,186       91,957             (358,453 )     206,690             (91,957 )     114,733  
Other assets
    275,033       67,238       1,643             343,914       1,635       (120,201 )     225,348  
 
                                               
Total assets
  $ 3,035,068     $ 302,377     $ 520,734     $ (477,508 )   $ 3,380,671     $ 463,786     $ (228,902 )   $ 3,615,555  
 
                                               
 
                                                               
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                                               
Current liabilities
  $ 338,369     $ 131,449     $ 21,782     $ (119,055 )   $ 372,545     $ 10,241     $ (16,744 )   $ 366,042  
Long-term liabilities
    2,115,343       11,458       299,969             2,426,770       336,556       (120,201 )     2,643,125  
Stockholders’ equity
    581,356       159,470       198,983       (358,453 )     581,356       91,957       (91,957 )     581,356  
Noncontrolling interests
                                  25,032             25,032  
 
                                               
Total liabilities and stockholders’ equity
  $ 3,035,068     $ 302,377     $ 520,734     $ (477,508 )   $ 3,380,671     $ 463,786     $ (228,902 )   $ 3,615,555  
 
                                               
                                                                 
    December 31, 2008  
            Restricted     Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor     Consolidating     Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
                            (In thousands)                          
ASSETS
                                                               
Current assets
  $ 424,862     $ 163     $ 102,384     $ (123,071 )   $ 404,338     $ 2,613     $ (13,615 )   $ 393,336  
Property and equipment
    2,756,915       1,774       550,906             3,309,595       488,120             3,797,715  
Investment in subsidiaries (equity method)
    513,706       79,316             (363,203 )     229,819             (79,316 )     150,503  
Other assets
    206,099       123,298       910             330,307       1,916       (175,569 )     156,654  
 
                                               
Total assets
  $ 3,901,582     $ 204,551     $ 654,200     $ (486,274 )   $ 4,274,059     $ 492,649     $ (268,500 )   $ 4,498,208  
 
                                               
 
                                                               
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                                               
Current liabilities
  $ 357,077     $ 122,677     $ 44,907     $ (123,071 )   $ 401,590     $ 30,524     $ (13,615 )   $ 418,499  
Long-term liabilities
    2,359,679             327,964             2,687,643       356,072       (175,569 )     2,868,146  
Stockholders’ equity
    1,184,826       81,874       281,329       (363,203 )     1,184,826       79,316       (79,316 )     1,184,826  
Noncontrolling interests
                                    26,737             26,737  
 
                                               
Total liabilities and stockholders’ equity
  $ 3,901,582     $ 204,551     $ 654,200     $ (486,274 )   $ 4,274,059     $ 492,649     $ (268,500 )   $ 4,498,208  
 
                                               
                                                                 
    For the Three Months Ended September 30, 2009  
            Restricted     Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues
  $ 157,407     $ (11 )   $ 47,648     $ 91     $ 205,135     $ 24,298     $ (22,776 )   $ 206,657  
Operating expenses
    90,053       2,190       20,224       91       112,558       13,172       (22,776 )     102,954  
Equity in net earnings of subsidiaries
    23,685       7,224             (23,685 )     7,224             (7,224 )      
 
                                               
Operating income (loss)
    91,039       5,023       27,424       (23,685 )     99,801       11,126       (7,224 )     103,703  
Income from earnings of BBEP
    (43,685 )                       (43,685 )                 (43,685 )
Interest expense and other
    (38,525 )     814       (2,315 )           (40,026 )     (2,238 )           (42,264 )
Income tax (expense) benefit
    (8,099 )     (2,043 )     (5,218 )           (15,360 )     (235 )           (15,595 )
 
                                               
Net income (loss)
  $ 730     $ 3,794     $ 19,891     $ (23,685 )   $ 730     $ 8,653     $ (7,224 )   $ 2,159  
Net income attributable to noncontrolling interests
                                  (1,429 )           (1,429 )
 
                                               
Net income attributable Quicksilver
  $ 730     $ 3,794     $ 19,891     $ (23,685 )   $ 730     $ 7,224     $ (7,224 )   $ 730  
 
                                               

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    For the Three Months Ended September 30, 2008  
            Restricted     Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues
  $ 171,639     $     $ 61,266     $     $ 232,905     $ 19,304     $ (15,947 )   $ 236,262  
Operating expenses
    100,488       376       21,244             122,108       10,111       (15,947 )     116,272  
Equity in net earnings of subsidiaries
    29,851       5,263             (29,851 )     5,263             (5,263 )      
 
                                               
Operating income
    101,002       4,887       40,022       (29,851 )     116,060       9,193       (5,263 )     119,990  
Loss from earnings of BBEP
    (89,814 )                       (89,814 )                 (89,814 )
Interest expense and other
    (31,948 )     1,736       (5,190 )           (35,402 )     (2,699 )           (38,101 )
Income tax (expense) benefit
    17,005       (2,317 )     (9,287 )           5,401       (106 )           5,295  
 
                                               
Net income
  $ (3,755 )   $ 4,306     $ 25,545     $ (29,851 )   $ (3,755 )   $ 6,388     $ (5,263 )   $ (2,630 )
 
                                                               
Net income attributable to noncontrolling interests
                                  (1,125 )           (1,125 )
 
                                               
Net income (loss) attributable to Quicksilver
  $ (3,755 )   $ 4,306     $ 25,545     $ (29,851 )   $ (3,755 )   $ 5,263     $ (5,263 )   $ (3,755 )
 
                                               
                                                                 
    For the Nine Months Ended September 30, 2009  
                    Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues
  $ 452,403     $ 689     $ 140,786     $ (394 )   $ 593,484     $ 72,993     $ (67,847 )   $ 598,630  
Operating expenses
    1,094,552       4,547       240,063       (394 )     1,338,768       39,125       (67,847 )     1,310,046  
Equity in net earnings of subsidiaries
    (65,113 )     21,088             65,113       21,088             (21,088 )      
 
                                               
Operating income (loss)
    (707,262 )     17,230       (99,277 )     65,113       (724,196 )     33,868       (21,088 )     (711,416 )
Income from earnings of BBEP
    (24,669 )                       (24,669 )                 (24,669 )
Interest expense and other
    (139,682 )     3,389       (6,424 )           (142,717 )     (7,923 )           (150,640 )
Income tax (expense) benefit
    281,602       (7,217 )     27,186             301,571       (446 )           301,125  
 
                                               
Net income (loss)
  $ (590,011 )   $ 13,402     $ (78,515 )   $ 65,113     $ (590,011 )   $ 25,499     $ (21,088 )   $ (585,600 )
Net income attributable to noncontrolling interests
                                  (4,411 )           (4,411 )
 
                                               
Net income (loss) attributable to Quicksilver
  $ (590,011 )   $ 13,402     $ (78,515 )   $ 65,113     $ (590,011 )   $ 21,088     $ (21,088 )   $ (590,011 )
 
                                               
                                                                 
    For the Nine Months Ended September 30, 2008  
                    Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Revenues
  $ 437,512     $     $ 145,238     $     $ 582,750     $ 52,694     $ (43,664 )   $ 591,780  
Operating expenses
    240,274       1,389       65,790             307,453       30,175       (43,664 )     293,964  
Equity in net earnings of subsidiaries
    59,469       12,257             (59,469 )     12,257             (12,257 )      
 
                                               
Operating income
    256,707       10,868       79,448       (59,469 )     287,554       22,519       (12,257 )     297,816  
Loss from earnings of BBEP
    (93,864 )                       (93,864 )                 (93,864 )
Interest expense and other
    (50,601 )     4,664       (13,107 )           (59,044 )     (7,532 )           (66,576 )
Income tax (expense) benefit
    (23,528 )     (5,436 )     (16,968 )           (45,932 )     (109 )           (46,041 )
 
                                               
Net income
  $ 88,714     $ 10,096     $ 49,373     $ (59,469 )   $ 88,714     $ 14,878     $ (12,257 )   $ 91,335  
Net income attributable to noncontrolling interests
                                  (2,621 )           (2,621 )
 
                                               
Net income attributable to Quicksilver
  $ 88,714     $ 10,096     $ 49,373     $ (59,469 )   $ 88,714     $ 12,257     $ (12,257 )   $ 88,714  
 
                                               

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Table of Contents

                                                                 
    For the Nine Months Ended September 30, 2009  
            Restricted     Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
      (In thousands)  
Net cash flow provided by operating activities
  $ 260,402     $ 47,666     $ 121,102     $     $ 429,170     $ 51,268     $ (29,845 )   $ 450,593  
Purchases of property, plant and equipment
    (387,938 )     (47,666 )     (79,745 )           (515,349 )     (50,067 )     4,296       (561,120 )
Assets purchased under Repurchase Obligation
                                (5,645 )     5,645        
Proceeds from sales of property, plant and equipment
    220,270             768             221,038                   221,038  
 
                                               
Net cash flow used for investing activities
    (167,668 )     (47,666 )     (78,977 )           (294,311 )     (55,712 )     9,941       (340,082 )
Issuance of debt
    1,278,138             52,887             1,331,025       46,500             1,377,525  
Repayments of debt
    (1,396,105 )           (96,532 )           (1,492,637 )     (14,500 )           (1,507,137 )
Debt issuance costs
    (29,870 )           (1,125 )           (30,995 )                 (30,995 )
Gas Purchase Commitment — net
    54,488                         54,488                   54,488  
Distributions to parent
                                  (19,904 )     19,904        
Distributions to noncontrolling interests
                                  (7,344 )           (7,344 )
Other
    (44 )                       (44 )     (63 )           (107 )
 
                                               
Net cash flow provided by (used for) financing activities
    (93,393 )           (44,770 )           (138,163 )     4,689       19,904       (113,570 )
Effect of exchange rates on cash
                1,779             1,779                   1,779  
 
                                               
Net decrease in cash and equivalents
    (659 )           (866 )           (1,525 )     245             (1,280 )
Cash and equivalents at beginning of period
    1,679             866             2,545       303             2,848  
 
                                               
Cash and equivalents at end of period
  $ 1,020     $     $     $     $ 1,020     $ 548     $     $ 1,568  
 
                                               
                                                                 
    For the Nine Months Ended September 30, 2008  
            Restricted     Restricted     Restricted     Quicksilver     Unrestricted             Quicksilver  
    Quicksilver     Guarantor     Non-Guarantor     Subsidiary     and Restricted     Non-Guarantor             Resources Inc.  
    Resources Inc.     Subsidiaries     Subsidiaries     Eliminations     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
Net cash flow provided by operations
  $ 138,736     $ 2,483     $ 113,616     $     $ 254,835     $ 36,365     $ (17,080 )   $ 274,120  
Purchases of property, plant and equipment
    (1,744,219 )     (2,483 )     (116,871 )           (1,863,573 )     (112,200 )           (1,975,773 )
Return of investment from BBEP
    31,435                         31,435                   31,435  
Proceeds from sales of property, plant and equipment
    1,025             618             1,643             (825 )     818  
 
                                               
Net cash flow used for investing activities
    (1,711,759 )     (2,483 )     (116,253 )           (1,830,495 )     (112,200 )     (825 )     (1,943,520 )
Issuance of debt
    2,169,611             203,208             2,372,819       99,300             2,472,119  
Repayments of debt
    (583,782 )           (198,206 )           (781,988 )                 (781,988 )
Debt issuance costs
    (24,545 )                       (24,545 )                 (24,545 )
Payments to parent
                                  (825 )     825        
Distributions to parent
                                  (17,080 )     17,080        
Distributions to noncontrolling interests
                                  (6,343 )           (6,343 )
Other
    (1,995 )                       (1,995 )                 (1,995 )
 
                                               
Net cash flow provided by (used for) financing activities
    1,559,289             5,002             1,564,291       75,052       17,905       1,657,248  
Effect of exchange rates on cash
    (155 )           (2,454 )           (2,609 )                 (2,609 )
 
                                               
Net decrease in cash and equivalents
    (13,889 )           (89 )           (13,978 )     (783 )           (14,761 )
Cash and equivalents at beginning of period
    27,012             89             27,101       1,125             28,226  
 
                                               
Cash and equivalents at end of period
  $ 13,123     $     $     $     $ 13,123     $ 342     $     $ 13,465  
 
                                               
13. SUPPLEMENTAL CASH FLOW INFORMATION
     Cash paid (received) for interest and income taxes is as follows:
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Interest
  $ 111,549     $ 58,762  
Income taxes
    (41,267 )     49,775  

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     Other non-cash transactions include:
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Working capital related to acquisition of property, plant and equipment
  $ 126,520     $ 191,959  
Issuance of common stock as consideration for the Alliance Acquisition
          262,092  
14. RELATED-PARTY TRANSACTIONS
     As of September 30, 2009, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock.   Thomas F. Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.
     Quicksilver and its associated entities paid $0.6 million and $1.6 million in the first nine months of 2009 and 2008, respectively, for rent on buildings owned by entities affiliated with Mercury.   Rental rates have been determined based on comparable rates charged by third parties.
     We paid $0.2 million and $0.7 million during the first nine months of 2009 and 2008, respectively, for use of an airplane owned by an entity controlled by members of the Darden family.   Usage rates are determined based on comparable rates charged by third parties.
     We paid $0.2 million in the first nine months of 2009 for delay rentals under leases for over 5,000 acres held by a related party entity.   The lease terms were determined based on comparable prices and terms granted to third parties with respect to similar leases in the area.
     Payments received from Mercury for sublease rentals, employee insurance coverage and administrative services during the first nine months of 2009 and 2008 totaled $0.2 million and $0.1 million, respectively.
15. SEGMENT INFORMATION
     We operate in two geographic segments, the United States and Canada, where we are engaged in the exploration and production segment of the oil and gas industry.   Additionally, we operate in the midstream segment, where we provide natural gas processing and gathering services in the United States, predominantly through KGS.   Revenue earned by KGS for the processing and gathering of Quicksilver gas are eliminated on a consolidated basis as are the costs of these services recognized by Quicksilver’s producing properties.   We evaluate performance based on operating income and property and equipment costs incurred.
                                                 
    Exploration & Production     Processing &     Corporate             Quicksilver  
    United States     Canada     Gathering     and Other     Elimination     Consolidated  
    (in thousands)  
For the Three Months Ended September 30, :
                                               
2009
                                               
Revenues
  $ 157,407     $ 47,648     $ 24,287     $     $ (22,685 )   $ 206,657  
Depletion, depreciation and accretion
    27,957       9,321       6,836       434             44,548  
Operating income
    82,747       28,354       10,718       (18,116 )           103,703  
Property and equipment costs incurred
    80,852       13,925       43,946       362             139,085  
 
                                               
2008
                                               
Revenues
  $ 171,421     $ 61,484     $ 19,304     $     $ (15,947 )   $ 236,262  
Depletion, depreciation and accretion
    36,178       11,337       3,990       272             51,777  
Operating income
    94,650       40,927       8,817       (24,404 )           119,990  
Property and equipment costs incurred
    1,484,080       21,208       97,525       215             1,603,028  

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    Exploration & Production     Processing &     Corporate             Quicksilver  
    United States     Canada     Gathering     and Other     Elimination     Consolidated  
                    (in thousands)                  
For the Nine Months Ended September 30, :
                                               
2009
                                               
Revenues
  $ 452,403     $ 140,786     $ 73,682     $     $ (68,241 )   $ 598,630  
Depletion, depreciation and accretion
    106,338       29,284       18,346       1,242             155,210  
Operating income
    (589,707 )     (96,487 )     35,472       (60,694 )           (711,416 )
Property and equipment costs incurred
    308,905       70,440       92,226       2,018             473,589  
 
                                               
2008
                                               
Revenues
  $ 436,925     $ 145,825     $ 52,694     $     $ (43,664 )   $ 591,780  
Depletion, depreciation and accretion
    79,731       34,353       10,874       798             125,756  
Operating income
    247,311       81,862       21,130       (52,487 )           297,816  
Property and equipment costs incurred
    1,938,667       108,482       204,330       769             2,252,248  
 
                                               
Property, Plant and Equipment-net
                                               
September 30, 2009
  $ 1,912,941     $ 470,411     $ 598,645     $ 11,803     $     $ 2,993,800  
December 31, 2008
    2,723,103       550,413       519,447       4,752             3,797,715  

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ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion and analysis of our consolidated financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements, and notes thereto, and the other financial data included elsewhere in this quarterly report.   The following discussion should also be read in conjunction with our audited consolidated financial statements, and notes thereto, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2008 Annual Report on Form 10-K, as amended.
EXECUTIVE OVERVIEW
     We are an independent energy company engaged primarily in exploration, development and production of unconventional natural gas onshore in North America.   We own producing oil and natural gas properties in the United States, principally in Texas, and in Alberta, Canada, where we had total estimated aggregate proved reserves of approximately 2.2 Tcfe at December 31, 2008.   We also have properties in the Horn River Basin of Northeast British Columbia, the Greater Green River Basin of Colorado and the Delaware Basin of West Texas where we are exploring for additional reserves, but have recognized only immaterial proved reserves based upon exploration to date.   In addition, we own approximately 73% of KGS, a publicly traded midstream master limited partnership controlled and consolidated by us, and we own approximately 40% of the limited partner units of BBEP, a publicly traded oil and natural gas exploration and production master limited partnership, which we account for using the equity method.
2009 HIGHLIGHTS
Eni Transaction
     On June 19, 2009, we completed the Eni Transaction whereby we entered into a strategic alliance with Eni and sold a 27.5% interest in our Alliance Leasehold.   The total proceeds for the Eni Transaction were $280 million in cash, inclusive of the Gas Purchase Commitment, and subject to normal post-closing adjustments.   We used the proceeds from the transaction to repay a portion of the Senior Secured Second Lien Facility.   Notes 2 and 4 in the condensed consolidated financial statements contains further information regarding the Eni Transaction and the Gas Purchase Commitment.
Long-Term Debt
     Upon completion of the Eni Transaction, the borrowing base under the Senior Secured Credit Facility was adjusted to $1.125 billion.   The October 2009 redetermination resulted in a revised borrowing base of $1.0 billion.   The credit facility provides us an option to increase the commitment by up to $250 million, with a maximum of $1.45 billion with lenders consents and additional commitments.   We can also extend the facility, which matures on February 9, 2012, up to two additional years with lender approval.   Note 7 to the condensed consolidated financial statements contains additional information about our long-term debt.
     On June 25, 2009, we issued Senior Notes due 2016 with a principal amount of $600 million for proceeds of $580.3 million.   The notes bear interest at the rate of 11.75%.   The proceeds of these notes, in addition to proceeds from the Eni Transaction, were used to repay and terminate the remaining indebtedness under our Senior Secured Second Lien Facility and to make repayments under the Senior Secured Credit Facility.
     On August 14, 2009, we issued Senior Notes due 2019 with a principal amount of $300 million for proceeds of $292.8 million.   The notes bear interest at the rate of 9.125%. The proceeds of these notes were used to make repayments under the Senior Secured Credit Facility.
Increase in Production
     Daily production increased 34% during the nine months ended September 30, 2009 from the corresponding period in 2008.   The production increase is discussed further in Results of Operations below.
Horn River Basin Discovery
     During the first nine months of 2009, we spent $44 million for exploration and facilities in the Horn River Basin where we have drilled and cased two wells, one of which was placed into service in the third quarter of 2009 with an initial production rate of 13 Mcfd.   Our capital expenditures include costs related to infrastructure development, such as construction of roads and production laterals.

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     We also entered into a nine-year agreement with a third party that began in May 2009 for the firm transportation of natural gas out of the Horn River Basin with initial volumes of 3 MMcfd and increasing to 100 MMcfd in May 2013.   We expect that the second well will be completed and commence production during the late fourth quarter of 2009 or early first quarter of 2010.
BBEP Update
     In April 2009, BBEP announced that it was suspending its distributions to remain in compliance with certain provisions of its credit facility and to redirect cash flow to reduce its debt.   BBEP management stated that the future resumption of distributions may be at levels below the recent distribution rate, but it cannot forecast or predict when distributions will resume.   In February 2009, we received a quarterly distribution of $11.1 million for the quarter ended December 31, 2008.   During the nine months ended September 30, 2009, we recognized $77.4 million of equity earnings in BBEP and an impairment of $102.1 million.
Litigation Update
     In October 2009, a jury awarded $22 million to the plaintiffs in our litigation originally brought against us by the plaintiffs Rod and Richard Thornton and Eagle Drilling, LLC.   We are actively seeking an appeal in this matter.
     In June 2009, the appellate court in the CMS litigation reversed the original district court judgment.   Pursuant to a settlement agreement, we paid CMS $5 million during July 2009, which we accrued during the quarter ended June 30, 2009.
2009 — 2010 OUTLOOK
     Commodity prices, drilling and well completion costs and access to capital and services are the most significant drivers of our business.   As of the date of this report, the credit markets remain tight and natural gas prices, both in the near-term and intermediate future, remain at low levels due to the global recession and the level of natural gas supply relative to its demand.   As a result, we continue to focus on ways to optimize our 2009 capital program and prepare for our 2010 program.   We currently expect that the 2009 capital program will total approximately $550 million, net of midstream capital contributed by Eni and working capital changes.   Our focus remains on the continued development of our properties in the Barnett Shale and exploration in the Horn River and Greater Green River Basins.   For the remainder of 2009, we expect to spend approximately $63 million for exploration and development activities, $26 million for midstream facilities (including approximately $7 million to be funded directly by KGS) and approximately $7 million for other property and equipment.   On a regional basis, approximately $52 million is forecasted in Texas to drill approximately 32 net wells on operated properties, to complete and tie-in approximately 14 of those net wells and to further develop our midstream infrastructure.   Canadian spending for the remainder of 2009 is forecasted to be approximately $6 million chiefly to explore the Horn River Basin and, to a lesser extent, limit decreases to current production levels.   The remaining capital budget is spread among our other operating areas.   We expect the final 2009 capital program to be less than the cash flows generated by our internal funding sources.
     Our remaining 2009 program described above is dynamic and there are a number of factors that could affect our decision to invest capital.   Commodity prices, well costs, hedging programs and program performance are a few factors that individually or in combination could change the scale or relative allocation of our remaining capital program for 2009.   We are currently developing our capital budget for 2010 and have yet to determine the exact allocation geographically or by expenditure type.   However, we do expect capital expenditures in 2010 to be less than cash flows generated by our internal funding sources.

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RESULTS OF OPERATIONS — Three Months Ended September 30, 2009 and 2008
     The following discussion compares the results of operations for the three months ended September 30, 2009 and 2008, or the 2009 quarter and 2008 quarter, respectively.
Natural Gas, NGL and Crude Oil Revenue
Production Revenue:
                                                                 
    Natural Gas     NGL     Oil and Condensate     Total  
    2009     2008     2009     2008     2009     2008     2009     2008  
    (In millions)  
Texas
  $ 45.7     $ 117.4     $ 36.1     $ 61.6     $ 3.3     $ 9.1     $ 85.1     $ 188.1  
Other U.S.
    0.1       0.2       0.2       0.4       2.2       4.7       2.5       5.3  
Hedging
    63.2       (15.1 )           (4.9 )           (3.4 )     63.2       (23.4 )
 
                                               
Total U.S.
    109.0       102.5       36.3       57.1       5.5       10.4       150.8       170.0  
Canada
    18.0       51.6                               18.0       51.6  
Hedging
    29.5       (3.4 )                             29.5       (3.4 )
 
                                               
Total Canada
    47.5       48.2                               47.5       48.2  
 
                                               
Total Company
  $ 156.5     $ 150.7     $ 36.3     $ 57.1     $ 5.5     $ 10.4     $ 198.3     $ 218.2  
 
                                               
Average Daily Production Volumes:
                                                                 
    Natural Gas     NGL     Oil and Condensate     Equivalent Total  
    2009     2008     2009     2008     2009     2008     2009     2008  
    (MMcfd)     (Bbld)     (Bbld)     (MMcfed)  
Texas
    153.0       137.1       13,973       11,485       565       865       240.2       211.2  
Other U.S.
    0.4       0.2       48       49       416       469       3.2       3.3  
 
                                               
Total U.S.
    153.4       137.3       14,021       11,534       981       1,334       243.4       214.5  
Canada
    67.8       62.5       3                         67.8       62.5  
 
                                               
Total Company
    221.2       199.8       14,024       11,534       981       1,334       311.2       277.0  
 
                                               
Average Realized Prices:
                                                                 
    Natural Gas     NGL     Oil and Condensate     Equivalent Total  
    2009     2008     2009     2008     2009     2008     2009     2008  
    (per Mcf)     (per Bbl)     (per Bbl)     (per Mcfe)  
Texas
  $ 3.25     $ 9.31     $ 28.11     $ 58.30     $ 62.46     $ 114.11     $ 3.85     $ 9.68  
Other U.S.
    3.22       3.77       34.43       88.26       57.96       107.59       8.52       16.69  
Hedging — U.S.
    4.48       (1.19 )           (4.61 )           (27.01 )     2.82       (1.18 )
Total U.S.
    7.73       8.11       28.15       53.82       60.55       84.80       6.73       8.61  
Canada
    2.89       8.97       116.68                         2.89       8.97  
Hedging — Canada
    4.73       (0.58 )                             4.73       (0.58 )
Total Canada
    7.61       8.39       116.68                         7.61       8.39  
Total Company
  $ 7.69     $ 8.20     $ 28.15     $ 53.82     $ 60.55     $ 84.80     $ 6.93     $ 8.56  

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     The following table summarizes the changes in our production revenues during the 2009 quarter compared with the 2008 quarter:
                                 
    Natural                    
    Gas     NGL     Oil     Total  
            (In thousands)          
Revenue for the quarter ended September 30, 2008
  $ 150,697     $ 57,108     $ 10,409     $ 218,214  
Volume variance
    16,100       12,326       (2,757 )     25,669  
Hedge settlement variance
    111,179       4,944       3,395       119,518  
Price variance
    (121,476 )     (38,055 )     (5,583 )     (165,114 )
 
                       
Revenue for the quarter ended September 30, 2009
  $ 156,500     $ 36,323     $ 5,464     $ 198,287  
 
                       
     Natural gas revenue increased as a result of increases in production and the effect of hedge settlements which were nearly offset by a decrease in prices for the 2009 quarter as compared to the 2008 quarter.   The 16.1 MMcfd increase in U.S. natural gas volumes was due to wells placed into service in the Fort Worth Basin subsequent to September 30, 2008.   Natural production declines from existing Fort Worth Basin wells partially offset the volume increases for the 2009 quarter.   Canadian natural gas production increased 5.3 MMcfd from new wells placed into service subsequent to September 30, 2008, which includes the Horn River well placed into service during the 2009 quarter.
     The decrease in NGL revenue was because of a 52% decrease in Fort Worth Basin prices for the 2009 quarter compared to the 2008 quarter.   Partially offsetting the price decrease were a production increase from the Fort Worth Basin and the absence of outlays for hedge settlements.   The 22% increase in Fort Worth Basin production was due to new wells placed into production subsequent to September 30, 2008, lower field pressures and improved NGL recoveries from the Corvette Plant, which was placed into service by KGS during the first quarter of 2009.
     Oil and condensate revenue for the 2009 quarter decreased due to both a 45% decrease in prices for the 2009 quarter as compared to the 2008 quarter and a 353 Bbld decrease in production for the 2009 quarter.   An absence of outlays for hedge settlements partially offset these decreases.
     Utilization of our hedging program may result in natural gas, NGL and crude oil realized prices varying from market prices that we receive from the sale of natural gas, NGL and crude oil.   Our revenue from natural gas, NGL and crude oil production was $92.8 million higher and $26.8 million lower because of our hedging programs for 2009 quarter and 2008 quarter, respectively.
     We expect our average production for the fourth quarter of 2009 to range between 330 MMcfed to 340 MMcfed.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
                 
    Three Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Sales of purchased natural gas
  $ 5,964     $  
 
           
Costs of purchased natural gas sold
    (5,594 )      
Gain on valuation of Gas Purchase Commitment
    2,630        
 
           
Costs of purchased natural gas
    (2,964 )        
 
           
Net sales and purchases of natural gas
  $ 3,000     $  
 
           
     Our marketing activities related to the purchase and sale of natural gas have increased in Texas because of natural gas sales and purchases made under the Gas Purchase Commitment.   The Gas Purchase Commitment is more fully described in Note 4 in the condensed consolidated financial statements.

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Other Revenue
     Other revenue of $2.4 million for the 2009 period decreased $15.6 million from the 2008 quarter.   The decrease was primarily because of the absence of $13.5 million in gains from Canadian hedge ineffectiveness recognized in the 2008 quarter.   The 2008 quarter gains were the result of the recovery of losses from Canadian hedge derivative ineffectiveness recognized in the 2008 second quarter.   Additionally, KGS third-party processing and transportation revenue for the 2009 quarter decreased $1.9 million as compared to the 2008 quarter.
Oil and Gas Production Expense
                                 
    Three Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Texas
                               
Cash expense
  $ 18,051     $ 0.82     $ 21,644     $ 1.11  
Equity compensation
    270       0.01       301       0.02  
 
                       
 
  $ 18,321     $ 0.83     $ 21,945     $ 1.13  
 
                               
Other U.S.
                               
Cash expense
  $ 1,633     $ 5.53     $ 1,639     $ 5.31  
Equity compensation
    49       0.17       42       0.14  
 
                       
 
  $ 1,682     $ 5.70     $ 1,681     $ 5.45  
 
                               
Total U.S.
                               
Cash expense
  $ 19,684     $ 0.88     $ 23,283     $ 1.18  
Equity compensation
    319       0.01       343       0.02  
 
                       
 
  $ 20,003     $ 0.89     $ 23,626     $ 1.20  
 
                               
Canada
                               
Cash expense
  $ 8,594     $ 1.38     $ 8,837     $ 1.54  
Equity compensation
    467       0.07       605       0.10  
 
                       
 
  $ 9,061     $ 1.45     $ 9,442     $ 1.64  
 
                               
Total Company
                               
Cash expense
  $ 28,278     $ 0.99     $ 32,120     $ 1.26  
Equity compensation
    786       0.03       948       0.04  
 
                       
 
  $ 29,064     $ 1.02     $ 33,068     $ 1.30  
 
                           
     U.S. production expense decreased $3.6 million because of cost containment efforts in the Fort Worth Basin during the 2009 quarter when compared to the 2008 quarter despite higher production levels.   Our daily production from the Fort Worth Basin increased approximately 14% for the 2009 quarter compared to the 2008 quarter while Fort Worth Basin production expense per Mcfe for the 2009 quarter decreased 27% from the 2008 quarter.   Fort Worth Basin production expense of $0.83 per Mcfe for the 2009 quarter also reflected a 23% decrease from $1.08 per Mcfe for the fourth quarter of 2008 and a 6% decrease from the $0.88 per Mcfe for the second quarter of 2009.   These decreases resulted from lower saltwater disposal costs, vendor price reductions, and our ongoing stringent efforts to contain costs through vendor bidding processes, bulk purchasing and additional automation of well operations.
     Canadian production expense for the 2009 quarter was down $0.4 million, or $0.19 per Mcfe, as compared to the 2008 quarter.   Decreases in Canadian production expense were primarily the result of changes in U.S.-Canadian exchange rates for the 2009 quarter when compared to the 2008 quarter.   Canadian production expense on a Canadian dollar basis increased approximately 2% primarily due to higher Canadian production levels.

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Production and Ad Valorem Taxes
                                 
    Three Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
 
                           
Production and ad valorem taxes
                               
U.S.
  $ 5,718     $ 0.26     $ 5,166     $ 0.26  
Canada
    912       0.15       (222 )     (0.04 )
 
                           
Total production and ad valorem taxes
  $ 6,630     $ 0.23     $ 4,944     $ 0.19  
 
                           
     Ad valorem taxes in the Fort Worth Basin increased approximately $1.3 million from the 2008 quarter to the 2009 quarter because of the addition of wells and midstream facilities placed into service over the past twelve months.   Partially offsetting this increase was a $0.7 million decrease in U.S. production taxes from the 2008 quarter.   Lower sales prices received for production in the 2009 quarter as compared to the 2008 quarter resulted in lower production taxes.   Lower Canadian taxes for the 2008 quarter were the result of recoupment of 2006 and 2007 taxes.
Other Operating Costs
     Other operating costs increased $1.2 million from the 2008 quarter primarily due to additional KGS operating expenses associated with the operation of its Corvette Plant that commenced operations in the first quarter of 2009.   These KGS expenses are associated with its third-party gathering and processing revenues.
Depletion, Depreciation and Accretion
                                 
    Three Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Depletion
                               
U.S.
  $ 26,365     $ 1.18     $ 34,348     $ 1.74  
Canada
    7,985       1.28       10,120       1.76  
 
                           
Total depletion
    34,350       1.20       44,468       1.74  
Depreciation of other fixed assets
                               
U.S.
  $ 8,576     $ 0.38     $ 5,928     $ 0.30  
Canada
    1,039       0.17       1,006       0.17  
 
                           
Total depreciation
    9,615       0.34       6,934       0.27  
Accretion
    583       0.02       375       0.02  
 
                           
Total depletion, depreciation and accretion
  $ 44,548     $ 1.56     $ 51,777     $ 2.03  
 
                           
     Lower depletion for the 2009 quarter when compared with the 2008 quarter was due to a decrease in depletion rates.   Our U.S. depletion expense decreased $8.0 million due primarily to a 32% decrease in our U.S. depletion rate that was partially offset by a 13% increase in U.S. production volumes.   Lower Canadian depletion expense for the 2009 quarter was the result of a 27% decrease in the Canadian depletion rate partially offset by the 8% increase in Canadian production volumes, as compared to the 2008 quarter.   Both the U.S. and Canadian depletion rates have decreased because of impairment charges.   U.S. impairment charges were recognized in the fourth quarter of 2008 and the first quarter of 2009.   Canadian impairment charges were recognized in the first and second quarters of 2009.   The $2.6 million increase in U.S. depreciation for the 2009 quarter as compared to the 2008 quarter was primarily associated with additions of Fort Worth Basin field compression and the KGS gathering system in addition to KGS’ Corvette Plant that was placed into service in the first quarter of 2009.

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General and Administrative Expense
                                 
    Three Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
General and administrative expense
                               
Cash expense
  $ 12,968     $ 0.46     $ 12,674     $ 0.49  
Litigation settlement
    1,000       0.03       9,633       0.38  
Equity compensation
    3,714       0.13       3,298       0.13  
 
                       
Total general and administrative expense
  $ 17,682     $ 0.62     $ 25,605     $ 1.00  
 
                       
     General and administrative expense decreased $7.9 million because of the absence of a $9.6 million charge for a legal settlement incurred for the 2008 quarter partially offset by a $1.0 million charge in the 2009 quarter for the Eagle litigation.   Accrued bonuses for the 2009 quarter were $1.1 million lower, but were partially offset by a $0.5 million increase stock-based compensation expense when compared to the 2008 quarter.   Additional expenses for legal and accounting fees increased general and administrative expense by approximately $0.9 million for the 2009 quarter as compared to the 2008 quarter.
BBEP-Related Income
     During the 2009 quarter, we recognized a loss of $43.7 million for equity earnings from our investment in BBEP based upon its reported earnings for the quarter ended June 30, 2009 as compared to a loss of $89.8 million that we recognized for the 2008 quarter.   BBEP continues to experience significant volatility in its net earnings due to changes in value of its derivative instruments for which it does not employ hedge accounting.   Note 5 to the condensed consolidated financial statements contains additional information regarding our investment in BBEP.
Interest Expense
                 
    Three Months Ended September 30,  
    2009     2008  
    (in thousands)  
Interest costs
  $ 38,676     $ 35,209  
Add: Non-cash interest (1)
    4,705       3,553  
Less: Interest capitalized
    (1,762 )     (2,774 )
 
           
Interest expense
  $ 41,619     $ 35,988  
 
           
 
  (1)   Amortization of deferred financing costs and original issue discount
     Interest costs for the 2009 quarter were higher than the 2008 quarter primarily because of higher outstanding debt balances partially offset by slightly lower interest rates.   Additionally, proceeds from our interest rate swaps, initiated in June 2009, reduced interest expense $6.5 million.
Income Tax Expense
                 
    Three Months Ended  
    September 30,  
    2009     2008  
Income tax (benefit) expense (in thousands)
  $ 15,595     $ (5,295 )
Effective tax rate
    87.8 %     66.8 %
     Our provision for income taxes for the 2009 quarter changed from the 2008 quarter due to higher income before taxes for the 2009 quarter as compared to the 2008 quarter.   The effective tax rate for the 2009 quarter was almost 88% primarily due to changes in our estimated annual effective tax rate for 2009, which had been forecasted as a 35% income tax benefit through June 30, 2009.   We now expect a 34% income tax benefit based on changes to the expected earnings allocation between the U.S. and Canada.   This change in the expected rate for 2009 required third quarter recognition of the cumulative amount to bring the year to date income tax provision to the 34% level.   The 2009 quarter includes an estimated $9.6 million change to the income tax provision for earnings recognized through the period ended June 30, 2009.

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RESULTS OF OPERATIONS — Nine Months Ended September 30, 2009 and 2008
     The following discussion compares the results of operations for the nine months ended September 30, 2009 and 2008, or the 2009 period and 2008 period, respectively.
Natural Gas, NGL and Crude Oil Revenue
Production Revenue:
                                                                 
    Natural Gas     NGL     Oil and Condensate     Total  
    2009     2008     2009     2008     2009     2008     2009     2008  
    (In millions)  
Texas
  $ 170.5     $ 272.8     $ 94.2     $ 171.5     $ 10.5     $ 25.8     $ 275.2     $ 470.1  
Other U.S.
    0.3       0.4       0.1       1.0       5.5       13.2       5.9       14.6  
Hedging
    159.3       (28.5 )           (13.4 )           (8.6 )     159.3       (50.5 )
 
                                               
Total U.S.
    330.1       244.7       94.3       159.1       16.0       30.4       440.4       434.2  
Canada
    65.0       151.1       0.1                         65.1       151.1  
Hedging
    75.6       (10.6 )                             75.6       (10.6 )
 
                                               
Total Canada
    140.6       140.5       0.1                         140.7       140.5  
 
                                               
Total Company
  $ 470.7     $ 385.2     $ 94.4     $ 159.1     $ 16.0     $ 30.4     $ 581.1     $ 574.7  
 
                                               
Average Daily Production Volumes:
                                                                 
    Natural Gas   NGL   Oil and Condensate   Equivalent Total
    2009   2008   2009   2008   2009   2008   2009   2008
    (MMcfd)   (Bbld)   (Bbld)   (MMcfed)
Texas
    166.3       104.6       14,038       10,976       794       864       255.3       175.6  
Other U.S.
    0.3       0.3       31       42       440       462       3.2       3.4  
 
                                                               
Total U.S.
    166.6       104.9       14,069       11,018       1,234       1,326       258.5       179.0  
Canada
    66.1       62.5       5             2             66.1       62.5  
 
                                                               
Total Company 
    232.7       167.4       14,074       11,018       1,236       1,326       324.6       241.5  
 
                                                               
Average Realized Prices:
                                                                 
    Natural Gas   NGL   Oil and Condensate   Equivalent Total
    2009   2008   2009   2008   2009   2008   2009   2008
    (per Mcf)   (per Bbl)   (per Bbl)   (per Mcfe)
Texas
  $ 3.76     $ 9.52     $ 24.57     $ 57.03     $ 48.33     $ 109.30     $ 3.95     $ 9.77  
Other U.S.
    0.56       4.45       26.08       86.32       45.82       103.65       6.98       16.11  
Hedging — U.S.
    3.50       (0.99 )           (4.46 )           (23.62 )     2.26       (1.03 )
Total U.S.
    7.26       8.51       24.56       52.69       47.44       83.70       6.24       8.85  
Canada
    3.61       8.83       70.67             47.25             3.61       8.83  
Hedging — Canada
    4.19       (0.62 )                             4.19       (0.62 )
Total Canada
    7.80       8.21       70.67             47.25             7.80       8.21  
Total Company
  $ 7.41     $ 8.40     $ 24.57     $ 52.69     $ 47.44     $ 83.70     $ 6.56     $ 8.69  

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     The following table summarizes the changes in our production revenues during the nine months ended September 30, 2009 compared with the comparable 2008 period:
                                 
    Natural                    
    Gas     NGL     Oil     Total  
    (In thousands)  
Revenue for the nine months ended September 30, 2008
  $ 385,244     $ 159,061     $ 30,412     $ 574,717  
Volume variance
    148,407       43,375       (2,159 )     189,623  
Hedge settlement variance
    273,967       13,448       8,583       295,998  
Price variance
    (336,894 )     (121,463 )     (20,825 )     (479,182 )
 
                       
Revenue for the nine months ended September 30, 2009
  $ 470,724     $ 94,421     $ 16,011     $ 581,156  
 
                       
     Natural gas revenue for the 2009 period increased from the 2008 period because of increases in production and the effect of hedge settlements partially offset by the decrease in prices.   The 61.7 MMcfd increase in U.S. natural gas volumes is due to new wells purchased or placed into service principally in the Fort Worth Basin subsequent to September 30, 2008.   These increases were partially offset by lower volumes resulting from the sale of 27.5% revenue interest in our Alliance properties in June and natural production declines from existing Fort Worth Basin wells.   Canadian natural gas production increased 3.6 MMcfd production from new wells placed into service subsequent to September 30, 2008, which includes the Horn River well placed into service during the third quarter of 2009.
     The decrease in NGL revenue was primarily due to a 57% decrease in Texas prices for the 2009 period as compared to the 2008 period.   Partially offsetting the price decrease were increases in production and the absence of outlays for hedge settlements.   Fort Worth Basin production increased 28% due to new wells placed into production subsequent to September 30, 2008, lower field pressures and improved NGL recoveries from the Corvette Plant, which was placed into service by KGS during the first quarter of 2009.
     Oil and condensate revenue for the 2009 period decreased because of a 56% decrease in prices and a 7% decrease in oil and condensate production for the 2009 period as compared to the 2008 period.   An increase in oil and condensate revenue from the absence of outlays for hedge settlements partially offset these decreases.
     Utilization of our hedging program may result in natural gas, NGL and crude oil realized prices varying from market prices that we receive from the sale of natural gas, NGL and crude oil.   Our revenue from natural gas, NGL and crude oil production was $234.8 million higher and $61.1 million lower because of our hedging programs for 2009 period and 2008 period, respectively.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (In thousands)  
Sales of purchased natural gas
  $ 11,181     $  
 
           
Costs of purchased natural gas sold
    (10,358 )      
Loss on valuation of Gas Purchase Commitment
    (1,188 )      
 
           
Costs of purchased natural gas
    (11,546 )        
 
           
Net sales and purchases of natural gas
  $ (365 )   $  
 
           
     Our marketing activities related to the purchase and sale of natural gas have increased in Texas because of natural gas sales and purchases made under the Gas Purchase Commitment.   The Gas Purchase Commitment is more fully described in Note 4 in the condensed consolidated financial statements.
Other Revenue
     Other revenue of $6.3 million for the 2009 period was $10.8 million lower than for the 2008 period.   Gains attributable to partial ineffectiveness of derivatives hedging our Canadian production were $5.3 million less for the 2009 period when compared to the 2008 period. Additionally, KGS third-party revenue for the 2009 period was $4.0 million less for the 2009 period when compared to the 2008 period.   Lastly, the absence of transition services revenue earned in the 2008 period further decreased other revenue for the 2009 period by $0.8 million.

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Oil and Gas Production Expense
                                 
    Nine Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Texas
                               
Cash expense
  $ 61,112     $ 0.88     $ 65,129     $ 1.35  
Equity compensation
    785       0.01       925       0.02  
 
                       
 
  $ 61,897     $ 0.89     $ 66,054     $ 1.37  
Other U.S.
                               
Cash expense
  $ 4,913     $ 5.70     $ 4,273     $ 4.64  
Equity compensation
    147       0.17       133       0.15  
 
                       
 
  $ 5,060     $ 5.87     $ 4,406     $ 4.79  
Total U.S.
                               
Cash expense
  $ 66,025     $ 0.94     $ 69,402     $ 1.42  
Equity compensation
    932       0.01       1,058       0.02  
 
                       
 
  $ 66,957     $ 0.95     $ 70,460     $ 1.44  
Canada
                               
Cash expense
  $ 24,399     $ 1.35     $ 26,440     $ 1.54  
Equity compensation
    1,582       0.09       1,543       0.09  
 
                       
 
  $ 25,981     $ 1.44     $ 27,983     $ 1.63  
Total Company
                               
Cash expense
  $ 90,424     $ 1.02     $ 95,842     $ 1.45  
Equity compensation
    2,514       0.03       2,601       0.04  
 
                       
 
  $ 92,938     $ 1.05     $ 98,443     $ 1.49  
 
                           
     U.S. production expense was $3.5 million lower for the 2009 period despite a 44% production increase from the 2008 period.   Cost containment efforts in the Fort Worth Basin during the 2009 period resulted in a production expense decrease of $4.2 million when comparing the 2009 period to the 2008 period.   Fort Worth Basin production expense of $0.89 per Mcfe for the 2009 period also reflected a 35% decrease from a rate of $1.37 per Mcfe for 2008.   These decreases resulted from lower saltwater disposal costs, price reductions, and our stringent efforts to contain costs through vendor bidding processes, bulk purchasing and additional reliance on automation of well operations.
     Canadian production expense for the 2009 period decreased $2.0 million, or $0.19 per Mcfe, from the 2008 period.   Decreased Canadian production expense was primarily the result of changes in U.S.-Canadian exchange rates during the 2009 period when compared to the 2008 period.   Canadian production expense on a Canadian dollar basis increased approximately C$1.8 million or 7% due primarily to the Canadian production increase.
Production and Ad Valorem Taxes
                                 
    Nine Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Production and ad valorem taxes
                               
U.S.
  $ 16,688     $ 0.24     $ 9,057     $ 0.18  
Canada
    1,749       0.10       1,627       0.10  
 
                           
Total production and ad valorem taxes
  $ 18,437     $ 0.21     $ 10,684     $ 0.16  
 
                           

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     Production and ad valorem taxes reflect the addition of wells and midstream facilities in the Fort Worth Basin over the past twelve months, which increased production and ad valorem taxes for Texas approximately $8.3 million during the 2009 period as compared to the 2008 period.
Other Operating Costs
     The $2.7 million increase in other operating costs for the 2009 period when compared to the 2008 period was primarily the result of additional KGS operating expenses associated with the operation of its Corvette Plant that began operations in the first quarter of 2009.   These KGS expenses are associated with its third-party gathering and processing revenues.
Depletion, Depreciation and Accretion
                                 
    Nine Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
Depletion
                               
U.S.
  $ 101,045     $ 1.43     $ 75,649     $ 1.54  
Canada
    25,494       1.41       30,967       1.81  
 
                           
Total depletion
    126,539       1.43       106,616       1.61  
Depreciation of other fixed assets:
                               
U.S.
  $ 24,092     $ 0.34     $ 15,293     $ 0.31  
Canada
    2,856       0.16       2,751       0.16  
 
                           
Total depreciation
    26,948       0.30       18,044       0.27  
Accretion
    1,723       0.02       1,096       0.02  
 
                           
Total depletion, depreciation and accretion
  $ 155,210     $ 1.75     $ 125,756     $ 1.90  
 
                           
     Higher depletion for the 2009 period was due to production increases partially offset by lower depletion rates.   Our U.S. depletion expense increased due primarily to a 44% increase in U.S. sales volumes.   Both our U.S. and Canadian depletion rates were impacted by impairment charges.   U.S. impairment charges were recognized in the fourth quarter of 2008 and the first quarter of 2009.   Canadian impairment charges were recognized in the first and second quarters of 2009.   Changes in the U.S.-Canadian dollar exchange rate also contributed to lower Canadian depletion expense and the Canadian depletion rate on a Mcfe-basis.   The change in the exchange rate decreased depletion $3.8 million when comparing the 2009 period to the 2008 period.   The $8.8 million increase in U.S. depreciation for the 2009 period as compared to the 2008 period was primarily associated with additions of Fort Worth Basin field compression and KGS’ gathering system in addition to KGS’ Corvette Plant that was placed into service in the first quarter of 2009.
Impairment of Oil and Gas Properties
     We recognized a non-cash pre-tax charge of $896.5 million ($593.7 million after tax) for impairment related to both our U.S. and Canadian oil and gas properties in March 2009.   Benchmark natural gas prices at March 31, 2009 for the U.S. and Canada decreased $2.08 per Mcf and $2.52 per Mcf, respectively, from December 31, 2008 and resulted in significant decreases to the estimated future net cash flows from our proved oil and gas reserves.
     We recognized an additional second quarter non-cash pre-tax charge of $70.6 million ($52.9 million after tax) for impairment of our Canadian oil and gas properties.   The impairment charge primarily resulted from reductions in the expected capital during the remainder of 2009 and in 2010 for our Canadian oil and gas properties.   Additionally, the Canadian AECO benchmark natural gas prices at June 30, 2009 decreased $0.05 per Mcf from March 31, 2009.
     As required under full cost accounting rules, we perform quarterly ceiling tests.   Net capitalized costs include the book value of our oil and gas properties net of accumulated depletion and impairment, reduced by the related deferred tax liability.   Net capitalized costs are compared to the period-end ceiling limitation, which is the sum of (i) estimated future net cash flows, discounted at 10% per annum, from proved reserves, based on unescalated period-end prices and costs, adjusted for financial derivatives that qualify as cash flow hedges of our oil and gas revenue, (ii) the costs of properties not being amortized, (iii) the lower of cost or market value of

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unproved properties not included in the costs being amortized, less (iv) income tax effects related to differences between book and tax bases of the oil and gas properties.   Note 6 to our condensed consolidated financial statements contains additional information about the ceiling test calculation.
General and Administrative Expense
                                 
    Nine Months Ended September 30,  
    2009     2008  
    (In thousands, except per unit amounts)  
            Per             Per  
            Mcfe             Mcfe  
General and administrative expense
                               
Cash expense
  $ 40,483     $ 0.45     $ 37,175     $ 0.55  
Litigation settlement
    6,000       0.07       9,633       0.15  
Equity compensation
    12,969       0.15       9,594       0.15  
 
                       
Total general and administrative expense
  $ 59,452     $ 0.67     $ 56,402     $ 0.85  
 
                           
     General and administrative expense for the 2009 period increased $3.0 million from the 2008 period.   The 2009 period expense increased $5.0 million for final settlement of the CMS Litigation and $1.0 million for the Eagle litigation judgment.   Legal and accounting fees increased general and administrative expense by approximately $4.5 million for the 2009 period as compared to the 2008 period and included approximately $0.8 million for the Eni Transaction and $3.7 million related to our litigation with BBEP and various other corporate matters.   Vesting of stock-based compensation in the 2009 period increased $3.4 million when compared to the 2008 period.   These items were partially offset by the absence of a $9.6 million charge for a legal settlement in 2008 and expense decreases of $1.3 million resulting from cost reduction efforts.
BBEP-Related Income and Expense
     During the 2009 period, we recognized $77.4 million for equity earnings from our investment in BBEP for the nine months ended June 30, 2009 as compared to a loss of $93.9 million based upon their reported earnings for the eight months ended June 30, 2008.   A portion of the increase in equity earnings is the result of an increase in our proportionate ownership of BBEP from 32% to 41% as a result of BBEP’s purchase and retirement of units in June 2008.   The remaining increase is primarily due to a significant reduction in unrealized losses from derivative instruments that BBEP experienced in the 2008 eight-month period.   BBEP continues to experience significant volatility in its net earnings due to changes in value of its derivative instruments for which it does not employ hedge accounting.
     During the first quarter of 2009, we evaluated our investment in BBEP for impairment in response to further decreases in prevailing commodity prices and BBEP’s unit price since December 31, 2008.   As a result of these decreases and the outlook for petroleum prices and broad limitations on available capital, we made the determination that the decline in value was other-than-temporary.   Accordingly, our impairment analysis, which utilized the March 31, 2009 closing price of $6.53 per BBEP unit, resulted in an aggregate fair value of $139.4 million for the portion of BBEP units that we owned.   The $139.4 million aggregate fair value was compared to the $241.5 million carrying value of our investment in BBEP.   We recorded the difference of $102.1 million as an impairment charge during the first quarter of 2009.   A similar analysis was performed as of September 30, 2009, which resulted in no further impairment.   Note 5 to our condensed consolidated financial statements contains additional information regarding our investment in BBEP for more information.

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Interest Expense
                 
    Nine Months Ended  
    September 30,  
    2009     2008  
    (in thousands)  
Interest costs
  $ 113,972     $ 63,837  
Add:
               
Non-cash interest (1)
    13,431       8,085  
Loss on early debt extinguishment
    27,122        
Less: Interest capitalized
    (4,624 )     (6,401 )
 
           
Interest expense
  $ 149,901     $ 65,521  
 
           
 
  (1)   Amortization of deferred financing costs and original issue discount
     Interest costs for the 2009 period were higher than the 2008 period primarily because of higher outstanding debt balances, which included the issuance of our Senior Notes due 2015 in June 2008 and our Senior Secured Second Lien Facility in August of 2008, as well as additional borrowings outstanding under our Senior Secured Credit Facility.   We recognized additional interest expense of $27.1 million for the remaining unamortized original issue discount and deferred financing costs upon the early repayment of the Senior Secured Second Lien Facility in June 2009. Interest rate swaps entered into in June 2009 partially offset increased interest expense by $7.2 million for the 2009 period.   We expect interest expense to increase during future quarters based on increases to base borrowing rates under our Senior Secured Credit Facility and higher interest rates incurred for our Senior Notes due 2016 and 2019.
Income Tax Expense
                 
    Nine Months Ended
    September 30,
    2009   2008
Income tax (benefit) expense (in thousands)
  $ (301,125 )   $ 46,041  
Effective tax rate
    34.0 %     33.5 %
     Our income tax provision for the 2009 period changed from the 2008 period due to a $1.0 billion reduction of pre-tax earnings that resulted primarily from the impairment charges for our oil and gas properties recognized during 2009.   The effective tax rate for the 2009 period was affected by the resulting taxable net loss in both the U.S. and Canada that were taxed at approximately 35% and approximately 25%, respectively.   We expect our effective income tax rate to be approximately 34% for all of 2009.
Quicksilver Resources Inc. and its Restricted Subsidiaries
     Note 21 to our consolidated financial statements included in our 2008 Annual Report on Form 10-K, as amended, contains information about the Company and its restricted and unrestricted subsidiaries.
     The combined results of operations for the Company and its restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under Results of Operations.   The combined financial position of the Company and its restricted subsidiaries and our consolidated financial position are materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries since the KGS initial public offering, the borrowings under the KGS credit facility and the equity of the unrestricted subsidiaries.   The other balance sheet items are discussed below in “Financial Position.” The combined operating cash flows, financing cash flows and investing cash flows for the Company and its restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in Liquidity, Capital Resources and Financial Condition.

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LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL CONDITION
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 determined 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 significantly affected by instability in the credit and financial markets, resulting in our and other industry participants’ planned lowering of capital expenditures and drilling activities year-over-year.
                 
    Nine Months Ended
    September 30,
    2009   2008
    (In thousands)
Net cash provided by operating activities
  $ 450,593     $ 274,120  
Net cash used for investing activities
    (340,082 )     (1,943,520 )
Net cash provided by financing activities
    (113,570 )     1,657,248  
Effect of exchange rate changes in cash
    1,779       (2,609 )
Operating Cash Flows
     Net cash provided by operations for the 2009 period increased $176.5 million from the comparable 2008 period because of increases from working capital including $54.9 million received from the March 2009 early settlement of a derivative hedging 40 MMcfd of 2010 natural gas production and receipt of a $41.1 million U.S. federal income tax refund.   Cash provided by operations increased because of significantly higher production and lower production expense partially offset by lower average realized natural gas, NGL and crude oil prices.   Additionally, the cash distributions we receive on our BBEP units decreased $20.3 million from the 2008 period to $11.1 million as BBEP ceased making distributions during the second quarter of 2009.
     For the nine months ended September 30, 2009, price collars and swaps covered approximately 190 MMcfd of our natural gas production and resulted in higher realized revenues from our production of $234.8 million.   These price collars and swaps remain in place to hedge our anticipated natural gas production for the remainder of 2009.   As of September 30, 2009, we also had approximately 120 MMcfd of our anticipated 2010 U.S. natural gas production hedged using natural gas price collars.   We recorded the receipt of the $54.9 million settlement of the previously discussed 40 MMcfd contract in AOCI.   As natural gas is produced and sold during 2010, we will reclassify the proportionate amount of the settlement into natural gas revenue.   In October 2009, we entered into additional price collars and swaps as summarized below:

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                Weighted Avg Price
Product   Type   Contract Period   Volume   Per Mcf of Bbl
 
                   
Gas
  Collar   Jan 2010-Dec 2011   40 MMcfd   $ 6.00-7.00  
Gas
  Collar   Jan 2010-Dec 2012   20 MMcfd     6.50-7.15  
Gas
  Collar   Jan 2010-Dec 2012   20 MMcfd