-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KvMIkOJ0M7BlZwiIFPT3y6n8hyqpt6JGn0C1tK6r+2xScHhfnbt1K/iTARHeLKlT yD6TUXP9MEZVF8P+X2/s7A== 0000950134-09-011632.txt : 20090601 0000950134-09-011632.hdr.sgml : 20090601 20090529183011 ACCESSION NUMBER: 0000950134-09-011632 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 20081231 FILED AS OF DATE: 20090601 DATE AS OF CHANGE: 20090529 FILER: COMPANY DATA: COMPANY CONFORMED NAME: QUICKSILVER RESOURCES INC CENTRAL INDEX KEY: 0001060990 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752756163 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-14837 FILM NUMBER: 09863084 BUSINESS ADDRESS: STREET 1: 777 WEST ROSEDALE STREET CITY: FORT WORTH STATE: TX ZIP: 76104 BUSINESS PHONE: 817-665-5000 MAIL ADDRESS: STREET 1: 777 WEST ROSEDALE STREET CITY: FORT WORTH STATE: TX ZIP: 76104 10-K/A 1 d67831e10vkza.htm AMENDMENT TO FORM 10-K e10vkza
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
(Amendment No. 2)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
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
incorporation or organization)   Identification No.)
     
777 West Rosedale St., Fort Worth, Texas   76104
(Address of principal executive offices)   (Zip Code)
817-665-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
     
Title of each class   Name of each exchange on which registered
     
Common Stock, $0.01 par value per share   New York Stock Exchange
Preferred Share Purchase Rights,    
$0.01 par value per share   New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ       No o
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes o       No þ
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ       No o
     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
     Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o      No þ
     As of June 30, 2008, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $4,067,732,259 based on the closing sale price of $38.64 as reported on the New York Stock Exchange.
     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
     
Class
  Outstanding at February 13, 2009
     
Common Stock, $0.01 par value per share   168,752,835 shares
DOCUMENTS INCORPORATED BY REFERENCE
     
Document   Parts Into Which Incorporated
     
Proxy Statement for the Registrant’s May 20,   Part III
2009 Annual Meeting of Stockholders    
 
 

 


 

Explanatory Note
This Amendment No. 2 to the Annual Report on Form 10-K of Quicksilver Resources Inc. (“Quicksilver”) for the year ended December 31, 2008, originally filed on March 3, 2009 (“Original Form 10-K”) is being filed to provide audited financial statements and footnotes in accordance with SEC Rule 3-16 of Regulation S-X for the following entities:
         
 
    Quicksilver Resources Canada Inc. (“QRCI”);
 
       
 
    Cowtown Pipeline Funding, Inc.; and
 
       
 
    Quicksilver Gas Services Holdings LLC.
In addition, this Amendment No. 2 includes the audited financial statements and related footnotes of BreitBurn Energy Partners L.P. (“BBEP”), which were filed as an exhibit under “Item 15. Exhibits and Financial Statement Schedules” of Amendment No. 1 to the Original Form 10-K. The management of BBEP is solely responsible for the form and content of the BBEP financial statements. Quicksilver has no responsibility for the form or content of the BBEP financial statements since it does not control BBEP and is not involved in the management of BBEP. The consents of Schlumberger Data and Consulting Services, Netherland, Sewell & Associates, Inc., Deloitte and Touche LLP and PricewaterhouseCoopers LLP and new certifications of Quicksilver’s principal chief executive officer and principal financial officer are also filed as exhibits to this Amendment No. 2 under Item 15.
This Amendment No. 2 does not reflect events occurring after March 3, 2009. This Amendment also does not update or modify in any way Quicksilver’s results of operations, financial position, cash flows or other disclosures in the Original Form 10-K.

(i)


 

PART IV
ITEM 15. Exhibits and Financial Statement Schedules
Financial Statement Schedules
The following Consolidated Financial Statements and related footnotes are filed as part of this report:
         
 
  i.)   Audited financial statements and related footnotes of Quicksilver Resources Canada Inc. (“QRCI”) for the years ended December 31, 2008, 2007 and 2006. (1)
 
       
 
  ii.)   Consolidated audited financial statements and related footnotes of Cowtown Pipeline Funding Inc. for the years ended December 31, 2008, 2007 and 2006. (1)
 
       
 
  iii.)   Consolidated audited financial statements and related footnotes of Quicksilver Gas Services Holdings LLC for the years ended December 31, 2008, 2007 and 2006. (1)
 
       
 
  iv.)   Consolidated audited financial statements and related footnotes of Quicksilver’s equity method investment in BreitBurn Energy Partners L.P. (“BBEP”). (2)
 
(1)   The audited financial statements of QRCI, Cowtown Pipeline Funding, Inc. and Quicksilver Gas Services Holdings LLC are being filed in accordance with SEC Rule 3-16 of Regulation S-X.
 
(2)   The audited financial statements and related footnotes of Quicksilver’s equity method investment in BreitBurn Energy Partners L.P. are being filed in accordance with SEC Rule 3-09 of Regulation S-X.

(ii)


 


 

INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Stockholder of
Quicksilver Resources Canada Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of Quicksilver Resources Canada Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income and comprehensive income, stockholder’s equity and of cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Quicksilver Resources Canada Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared from the separate records maintained by Quicksilver Resources Inc. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, Quicksilver Resources Inc. as a whole.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
May 29, 2009

2


 

QUICKSILVER RESOURCES CANADA INC.
CONSOLIDATED BALANCE SHEETS
As of December 31, 2008 and 2007
In thousands
                 
    2008     2007  
ASSETS
Current assets
               
Cash and cash equivalents
  $ 866     $ 89  
Accounts receivable — net of allowance for doubtful accounts
    29,169       38,648  
Advances to Quicksilver
    30       118  
Derivative assets at fair value
    59,245       419  
Other current assets
    13,063       18,739  
 
           
Total current assets
    102,373       58,013  
Investment in equity affiliate at cost
    68,604        
Property, plant and equipment
               
Oil and gas properties, full cost method (including unevaluated costs of $9,832 and $21,170, respectively)
    437,563       533,401  
Other property and equipment
    42,585       38,566  
 
           
Property, plant and equipment — net
    480,148       571,967  
Other assets
    910       1,205  
 
           
 
  $ 652,035     $ 631,185  
 
           
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
               
Accounts payable
  $ 19,587     $ 9,396  
Accrued liabilities
    7,612       21,679  
Derivative liabilities at fair value
    1,865        
Deferred income taxes
    15,843       62  
 
           
Total current liabilities
    44,907       31,137  
 
           
Long-term debt
    252,868       310,710  
Asset retirement obligations
    17,608       14,278  
Deferred income taxes
    56,948       46,572  
Stockholder’s equity
               
Common stock
    1,817       1,817  
Paid in capital in excess of par value
    28,118       28,118  
Accumulated other comprehensive income
    33,809       43,870  
Retained earnings
    215,960       154,683  
 
           
Total stockholder’s equity
    279,704       228,488  
 
           
 
  $ 652,035     $ 631,185  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

3


 

QUICKSILVER RESOURCES CANADA INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Years Ended December 31, 2008, 2007 and 2006
In thousands
                         
    2008     2007     2006  
Revenue
                       
Natural gas, NGL and crude oil
  $ 181,994     $ 154,372     $ 117,831  
Other
    4,840       6,174       721  
 
                 
Total revenue
    186,834       160,546       118,552  
 
                 
 
                       
Operating expenses
                       
Oil and gas production expense
    38,153       35,931       26,237  
Depletion, depreciation and accretion
    44,821       39,287       29,012  
General and administrative
    3,673       2,499       1,790  
 
                 
Total expenses
    86,647       77,717       57,039  
 
                 
Operating income
    100,187       82,829       61,513  
Other income (expense) — net
    (2,994 )     (427 )     108  
Interest expense
    (13,978 )     (14,773 )     (12,593 )
 
                 
Income before income taxes
    83,215       67,629       49,028  
Income tax expense
    (21,938 )     (11,129 )     (8,777 )
 
                 
Net income
  $ 61,277     $ 56,500     $ 40,251  
 
                 
Other comprehensive income
                       
Reclassification adjustments related to settlements of derivative contracts — net of income tax
    160       (18,043 )     (6,030 )
Net change in derivative fair value — net of income tax
    38,478       5,012       33,747  
Foreign currency translation adjustment
    (48,699 )     29,018       (1,236 )
 
                 
Comprehensive income
  $ 51,216     $ 72,487     $ 66,732  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

4


 

QUICKSILVER RESOURCES CANADA INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
For the Years Ended December 31, 2008, 2007 and 2006
In thousands
                                         
                    Accumulated              
            Additional     Other              
    Common     Paid-in     Comprehensive     Retained        
    Stock     Capital     Income     Earnings     Total  
Balances at December 31, 2005
  $ 1,817     $ 28,118     $ 1,402     $ 57,932     $ 89,269  
Net income
                      40,251       40,251  
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $3,636
                (6,030 )           (6,030 )
Net change in derivative fair value, net of income tax benefit of $17,884
                33,747             33,747  
Foreign currency translation adjustment
                (1,236 )           (1,236 )
 
                             
Balances at December 31, 2006
  $ 1,817     $ 28,118     $ 27,883     $ 98,183     $ 156,001  
Net income
                      56,500       56,500  
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax of $7,550
                (18,043 )           (18,043 )
Net change in derivative fair value, net of income tax benefit of $2,229
                5,012             5,012  
Foreign currency translation adjustment
                29,018             29,018  
 
                             
Balances at December 31, 2007
  $ 1,817     $ 28,118     $ 43,870     $ 154,683     $ 228,488  
Net income
                      61,277       61,277  
Hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income, net of income tax benefit of $65
                160             160  
Net change in derivative fair value, net of income tax of $15,715
                38,478             38,478  
Foreign currency translation adjustment
                (48,699 )           (48,699 )
 
                             
Balances at December 31, 2008
  $ 1,817     $ 28,118     $ 33,809     $ 215,960     $ 279,704  
 
                             
The accompanying notes are an integral part of these consolidated financial statements.

5


 

QUICKSILVER RESOURCES CANADA INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2008, 2007 and 2006
In thousands
                         
    2008     2007     2006  
Operating activities:
                       
Net income
  $ 61,277     $ 56,500     $ 40,251  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depletion, depreciation and accretion
    44,821       39,287       29,012  
Deferred income tax expense
    21,938       11,129       8,777  
Non-cash loss from hedging and derivative activities
    (2,544 )     (193 )      
Loss from the sale of equipment
                936  
Non-cash interest expense
    295       297       316  
Changes in assets and liabilities
 
Accounts receivable
    9,479       9,763       2,503  
Advances to/from Quicksilver
    88       (446 )     (8,326 )
Other assets
    2,324       (3,318 )     487  
Accounts payable
    1,977       (78 )     (2,928 )
Accrued liabilities
    (2,650 )     (447 )     3,567  
 
                 
Net cash provided by operating activities
    137,005       112,494       74,595  
 
                 
 
                       
Investing activities:
                       
Purchases of property, plant and equipment
    (136,057 )     (147,195 )     (131,470 )
Proceeds from sales of property, plant and equipment
    618             3,778  
 
                 
Net cash used for investing activities
    (135,439 )     (147,195 )     (127,692 )
 
                 
 
                       
Financing activities:
                       
Issuance of debt
    208,161       218,321       56,182  
Repayment of debt
    (209,734 )     (190,691 )     (9,908 )
Debt issuance costs
          (664 )      
 
                 
Net cash (used for) provided by financing activities
    (1,573 )     26,966       46,274  
 
                 
 
Effect of exchange rate changes in cash
    784       5,423       (514 )
 
                 
 
Net increase (decrease) in cash
    777       (2,312 )     (7,337 )
 
                       
Cash and cash equivalents at beginning of period
    89       2,401       9,738  
 
                 
 
Cash and cash equivalents at end of period
  $ 866     $ 89     $ 2,401  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

6


 

QUICKSILVER RESOURCES CANADA INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2008, 2007 and 2006
1. SIGNIFICANT ACCOUNTING POLICIES
Nature of Business and Basis of Presentation
     Quicksilver Resources Canada Inc. (“QRCI “or the “Company”) was previously called MGV Energy Inc., which was formed upon the amalgamation of MGV Energy Inc., Gatens Holdings Inc. and Voneiff Holdings Inc. on August 19, 1999 under the Alberta Business Corporations Act. The name was changed to Quicksilver Resources Canada Inc. on April 10, 2006. QRCI is a wholly-owned subsidiary of Quicksilver Resources Inc. (“Quicksilver” or the “parent company”). QRCI is engaged in the exploration, development and production of petroleum and natural gas reserves.
Basis of Presentation
     A wholly-owned subsidiary of QRCI was dissolved December 15, 2006. The subsidiary did not hold any assets at the time of dissolution. Prior to this date, the financial statements of QRCI were consolidated and included the accounts of the Company and its subsidiary. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. QRCI accounts for its ownership in unincorporated partnerships and companies under the cost method as it has significant influence over those entities, but because of terms of the ownership agreements, it does not meet the criteria for control which would trigger consolidation of the entities. QRCI also consolidates its share of oil and gas joint ventures.
     The QRCI financial statements presented herein have been translated from Canadian dollars to U.S. dollars as QRCI uses the Canadian dollar as its functional currency. Unless otherwise noted, all financial information presented herein is reported in U.S. dollars.
Use of Estimates
     The preparation of financial statements in conformity with GAAP in the U.S. requires QRCI’s management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses, including stock compensation expense, during each reporting period. QRCI’s management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from QRCI’s estimates. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas, NGL and crude oil reserves used to compute depletion expense and future net cash flows from reserve production, estimates of current revenue based upon expectations for actual deliveries and prices received, the estimated fair value of financial derivative instruments and the estimated fair value of asset retirement obligations.
Cash and Cash Equivalents
     Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.
Accounts Receivable
     The Company’s customers are natural gas, NGL and crude oil purchasers. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although the Company does not require collateral, appropriate credit ratings are required and, in some instances, parental guarantees are obtained. Receivables are generally due in 30-60 days. When collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established.
Hedging and Derivatives
     Quicksilver enters into financial derivative instruments on behalf of QRCI to mitigate risk associated with the prices received from its natural gas, NGL and crude oil production. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates. For derivatives instruments that qualify as cash flow hedges, the effective portions of gains and losses are deferred in other comprehensive income and recognized in revenue or interest expense in the period in which the hedged transaction is recognized. Gains or losses on derivative instruments terminated prior to their original expiration date are deferred and

7


 

recognized as earnings during the period in which the hedged transaction is recognized. If the hedged transaction becomes probable of not occurring, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue.
Parts and Supplies
     Parts and supplies consist of well equipment, spare parts and supplies carried on a first-in, first-out basis at the lower of cost or market.
Investments in Equity Affiliates
     QRCI accounts for its preferred interests in 1373159 Alberta Ltd. using the cost method. QRCI carries the investment at historical cost and reviews the investment for impairment whenever circumstances or events indicate that the investment’s carrying value will not be recoverable.
Property, Plant, and Equipment
     QRCI follows the full cost method in accounting for its oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in a country-wide cost center. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.
     Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge QRCI’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required.
     All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years.
Revenue Recognition
     Revenue is recognized when title to the products transfer to the purchaser. QRCI uses the “sales method” to account for its production revenue, whereby QRCI recognizes revenue on all natural gas, NGL or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2008 and 2007, QRCI’s aggregate production imbalances were not material.
Environmental Compliance and Remediation
     Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Environmental remediation costs, which improve the condition of a property, are capitalized.
Income Taxes
     Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates expected to be in effect in years in which the temporary differences reverse.
Stock-based Compensation
     The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value. At the discretion of Quicksilver’s board of directors, QRCI may issue awards payable in cash. For all awards, QRCI recognizes the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense.

8


 

Disclosure of Fair Value of Financial Instruments
     QRCI’s financial instruments include cash, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated at the present value of future cash flows discounted at rates consistent with comparable maturities for credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities are recorded at cost which approximates fair value. SFAS No. 157, Fair Value Measurements, was adopted on January 1, 2008 and applied to fair value measurements of the Company’s financial instruments, including its financial derivative instruments. Additional information regarding the Company’s implementation of the accounting standard is found under “Recently Issued Accounting Standards” in this Note.
Foreign Currency Translation
     The Company uses the Canadian dollar as its functional currency. All balance sheet accounts of QRCI are translated into U.S. dollars at the period-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the period. The resulting translation adjustments are made directly to a component of accumulated other comprehensive income within stockholder’s equity. Gains and losses from foreign currency transactions are included in the statement of income.
Recently Issued Accounting Standards
  Pronouncements Implemented During 2008
     Adoption of SFAS No. 157 SFAS No. 157, Fair Value Measurements, was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. On February 12, 2008, the FASB issued FASB Staff Position 157-2 (“FSP 157-2”) which delayed the effective date of SFAS No. 157 for non-financial assets and liabilities. The delay allows companies additional time to consider the effect of various implementation issues that have arisen, or that may arise, from the application of SFAS No. 157. FSP FAS 157-3 was issued by the FASB on October 10, 2008 to clarify application of SFAS No. 157 when determining the fair value of a financial asset when the market for that financial asset is not active. QRCI adopted SFAS No. 157 on January 1, 2008 for new fair value measurements of financial instruments, including its derivative instruments, and recurring fair value measurements of non-financial assets and liabilities. All financial instruments are measured using inputs from three levels of fair value hierarchy. The three levels are as follows:
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that we have the ability to access at the measurement date.
Level 2 inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
Level 3 inputs are unobservable inputs that reflect the Company’s assumptions about the assumptions that market participants would use in pricing an asset or liability.
     Adoption of SFAS No. 159 — In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, QRCI did not elect the fair value measurement option for any of its financial assets or liabilities.
     Adoption of FSP FIN 39-1 — On April 30, 2007, the FASB issued FASB Staff Position (“FSP”) FIN 39-1, Amendment of FASB Interpretation No. (“FIN”) 39. The FSP amends GAAP to replace the terms “conditional contracts” and “exchange contracts” with the term “derivative instruments” as defined in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. It also amends paragraph 10 of Interpretation 39 to permit a reporting entity to offset fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. QRCI adopted FSP FIN 39-1 on January 1, 2008 without significant impact.

9


 

     Adoption of SFAS No. 162 — In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008, but had no impact on QRCI’s financial statements or related disclosures.
  Pronouncements Not Yet Implemented
     SFAS No. 141 (revised 2007), Business Combinations, “SFAS No. 141(R)” was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, while retaining its 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. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. SFAS No. 141(R) applies to all transactions and events in which one entity obtains control over one or more other businesses. The Statement also requires an acquirer 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 as period expenses as incurred. The Statement will apply to any acquisition entered into after January 1, 2009, but otherwise had no effect on QRCI’s financial statements upon adoption.
     The FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, in March 2008. Under SFAS No. 161, the Company will be required to disclose the fair value of all derivative and hedging instruments and their gains or losses 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. SFAS No. 161 was adopted with prospective application by the Company on January 1, 2009. The adoption of SFAS No. 161 will change the Company’s disclosures about its derivative and hedging instruments, but had no impact on the Company’s previously reported results or financial position.

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2. ACCOUNTS RECEIVABLE
     Accounts receivable consisted of the following:
                 
    As of December 31,  
    2008     2007  
    (In thousands)  
Accrued production receivables
  $ 13,435     $ 19,728  
Joint interest receivables
    15,386       16,150  
Other receivables
    348       2,770  
 
           
 
  $ 29,169     $ 38,648  
 
           
3. DERIVATIVES AND FAIR VALUE MEASUREMENTS
     In accordance with the fair value hierarchy described in SFAS No. 157, the following table shows the fair value of QRCI’s financial assets and liabilities that are required to be measured at fair value as of December 31, 2008.
                                         
    Fair Value Measurements as of December 31, 2008  
                                    Balance Sheet  
    Level 1     Level 2     Level 3     Other(1)     Total  
    (in thousands)  
Derivative assets
  $     $ 61,746     $     $ (2,501 )   $ 59,245  
 
                             
 
                                       
Derivative liabilities
  $     $ 4,366     $     $ (2,501 )   $ 1,865  
 
                             
 
(1)   Represents amounts netted under master netting arrangements
     The change in carrying value of QRCI’s derivatives and the contractual fixed-price sale commitments in the Company’s balance sheet since December 31, 2007 principally resulted from the decrease in market prices for natural gas to the prices in our derivative instruments and, to a lesser degree, from settlements made during 2008. The change in fair value of the effective portion of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. QRCI recognized $2.5 million and $0.2 million of net gains in other revenue as the result of derivative hedge ineffectiveness for the years ended 2008 and 2007, respectively. QRCI had no gains or losses resulting from derivative hedge ineffectiveness during 2006.
     The estimated fair values of all derivatives of QRCI as of December 31, 2008 and 2007 are provided below. The associated carrying values of these derivatives are equal to the estimated fair values for each period presented. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party where rights of offset exists.
                                   
    Asset Derivatives       Liability Derivatives  
    December 31,       December 31,  
    2008     2007       2008     2007  
    (in thousands)       (in thousands)  
Derivatives designated as hedging instruments under SFAS 133
                                 
Commodity contracts reported in:
                                 
Current derivative assets
  $ 61,746     $ 1,643       $ 2,501     $ 1,224  
Current derivative liabilities
                  1,865        
 
                         
Total derivatives designated as hedging instruments under SFAS 133
  $ 61,746     $ 1,643       $ 4,366     $ 1,224  
 
                         

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     All hedge derivative assets and liabilities have been classified as current at December 31, 2008 based on the maturity of the derivative instruments, resulting in $38.8 million of after-tax gains expected to be reclassified from accumulated other comprehensive income in 2009.
     The following table summarizes the open derivative positions that hedged QRCI’s natural gas production as of December 31, 2008:
                                           
                          Weighted Avg Price Per      
Product     Type   Contract Period   Volume     MMBtu (1)     Fair Value  
                      (MMBtud)           (In thousands)  
Gas
    Swap   Jan 2009-Dec 2009     10,000     $ 8.45     $ 8,536  
Gas
    Swap   Jan 2009-Dec 2009     20,000       8.46       17,110  
Gas
    Collar   Jan 2009-Dec 2009     10,000       8.25-10.45       8,290  
Gas
    Collar   Jan 2009-Dec 2009     10,000       8.25-10.45       8,290  
Gas
    Collar   Jan 2009-Dec 2009     10,000       11.50-14.48       19,520  
Gas
    Basis   Jan 2009-Dec 2009     20,000       (2 )     (1,865 )
Gas
    Basis   Jan 2009-Dec 2009     20,000       (2 )     (932 )
Gas
    Basis   Jan 2009-Dec 2009     15,000       (2 )     (799 )
Gas
    Basis   Jan 2009-Dec 2009     15,000       (2 )     (770 )
 
                                       
 
                            Total   $ 57,380  
 
                                       
 
(1)   “MMBtu” means million British Thermal Units, a measure of heating value
 
(2)   Basis swaps for 60,000 MMBtu per day hedge the AECO (a natural gas reference price for gas delivered onto NOVA Gas Transmission Ltd. System in Alberta, Canada) basis adjustment at a weighted average deduction of $0.84 per MMBtu from the New York Mercantile Exchange price for 2009.
4. OTHER CURRENT ASSETS
     Other current assets consisted of the following:
                 
    As of December 31,  
    2008     2007  
    (In thousands)  
Spare parts and supplies
  $ 11,399     $ 14,751  
Prepaid expenses
    1,664       3,988  
 
           
 
  $ 13,063     $ 18,739  
 
           
5. INVESTMENT IN EQUITY AFFILIATE
     On February 4, 2008, QRCI sold its rights and interest in certain oil and gas leases, purchased by QRCI in November 2007, to 1373159 Alberta Ltd. (“1373159”) for consideration of 10 million fully paid, non-assessable, non-voting Series 1 Preferred Shares of 1373159 having an aggregate redemption price of approximately Canadian $30 million. In June 2008, QRCI sold its rights and interests in additional oil and gas leases, purchased by QRCI in March 2008, to 1373159 for consideration of 10 million fully paid, non-assessable, non-voting Series 2 Preferred Shares of 1373159, having an aggregate redemption price of approximately Canadian $53 million. Quicksilver owned 100% of 1373159, which was subsequently amalgamated by QRCI, effective January 1, 2009.

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6. PROPERTY, PLANT AND EQUIPMENT
     Property and equipment consisted of the following:
                 
    December 31,     December 31,  
    2008     2007  
    (In thousands)  
Oil and gas properties
 
Subject to depletion
  $ 547,249     $ 616,192  
Unevaluated costs
    9,832       21,170  
Accumulated depletion
    (119,518 )     (103,961 )
 
           
Net oil and gas properties
    437,563       533,401  
Other plant and equipment
 
Pipelines and processing facilities
    51,005       45,213  
General properties
    3,722       4,240  
Accumulated depreciation
    (12,142 )     (10,887 )
 
           
Net other property and equipment
    42,585       38,566  
 
           
Property, plant and equipment, net of accumulated depletion and depreciation
  $ 480,148     $ 571,967  
 
           
Unevaluated Natural Gas and Crude Oil Properties Excluded From Depletion
     Under full cost accounting, QRCI excludes certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of QRCI’s unevaluated properties excluded from natural gas and crude oil properties being amortized at December 31, 2008 and 2007 and the year in which they were incurred is as follows:
                                                                 
    December 31, 2008     December 31, 2007  
    Costs Incurred During     Costs Incurred During  
    2008     Prior     Total     2007     2006     2005     Prior     Total  
    (In thousands)     (In thousands)  
Acquisition costs
  $     $     $     $ 626     $ 720     $ 575     $ 7,085     $ 9,006  
Exploration costs
    9,218             9,218       12,164                         12,164  
Capitalized interest
    614             614                                
 
                                               
Total
  $ 9,832     $     $ 9,832     $ 12,790     $ 720     $ 575     $ 7,085     $ 21,170  
 
                                               
     Costs are transferred into the amortization base on an ongoing basis, as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, QRCI cannot assess the future impact on the amortization rate.
Capitalized Costs
     Capitalized overhead costs that directly relate to QRCI’s exploration and development activities were $4.4 million, $4.6 million and $1.4 million for the years ended December 31, 2008, 2007 and 2006, respectively.

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7. ACCRUED LIABILITIES
     Accrued liabilities consisted of the following:
                 
    As of December 31,  
    2008     2007  
    (In thousands)  
Accrued operating expenses
  $ 3,881     $ 5,985  
Accrued capital expenditures
          11,417  
Revenue payable
    2,887       3,545  
Prepayments from partners
    844       732  
 
           
 
  $ 7,612     $ 21,679  
 
           
8. LONG-TERM DEBT
     Quicksilver’s Senior Secured Credit Facility matures February 9, 2012, but has the option for Quicksilver to extend the maturity up to two additional years with lender approval. The facility provides for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base, which is calculated based on several factors. The borrowing base is subject to at least annual redeterminations. In September 2008, the lenders agreed to a borrowing base of $1.2 billion. The lenders also agreed to $1.2 billion of revolving credit commitments and, with lender approval, the Company has an option to increase the facility to $1.45 billion. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. currency available for borrowing by U.S. subsidiaries and either U.S. or Canadian currency available for borrowing by QRCI. QRCI borrowings under the facility are guaranteed by Quicksilver and most of Quicksilver’s domestic subsidiaries and are secured by, among other things, QRCI’s, Quicksilver’s and certain of Quicksilver’s domestic subsidiaries’ oil and gas properties and quantities of proved reserves of natural gas, NGLs and crude oil attributable to them.
     At December 31, 2008, QRCI’s allocated borrowing base was $300 million with approximately $45 million of available borrowing capacity. All interest accrued on the facility must be paid quarterly, but there is no fixed payment schedule. Borrowings under the facility bear interest at the lender’s prime rate. In April 2009, the lenders affirmed Quicksilver’s borrowing base at $1.2 billion and the interest spreads under the facility were revised upward. QRCI’s portion of the borrowing base remained at $300 million.

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9. ASSET RETIREMENT OBLIGATIONS
     QRCI records the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted fair value to its estimated settlement value.
     The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2007 through December 31, 2008.
                 
    December 31,     December 31,  
    2008     2007  
    (In thousands)  
Beginning asset retirement obligations
  $ 14,278     $ 10,117  
Incremental liability incurred
    1,651       1,586  
Accretion expense
    830       664  
Change in estimates
    3,928        
Currency translation adjustment
    (3,079 )     1,911  
 
           
Ending asset retirement obligations
  $ 17,608     $ 14,278  
 
           
10. INCOME TAXES
     Tax rate reductions were enacted during 2007 and 2006 by the Canadian federal government and by Alberta Province. The Company’s Canadian deferred income tax balances were revalued to reflect the changes in these tax rates. The Company recorded $6.3 million and $3.2 million of income tax benefits in 2007 and 2006, respectively, as a result of the enactment of Canadian rate reductions. No further rate changes were enacted in 2008. Significant components of the QRCI’s deferred tax assets and liabilities as of December 31, 2008 and 2007 are as follows:
                 
    As of December 31,  
    2008     2007  
    (In thousands)  
Current
               
Deferred tax liability on cash flow hedge gains
  $ 15,843     $ 62  
 
           
 
               
Non-current
               
Deferred tax assets
               
Net operating loss carry forwards
  $ 1,644     $ 2,033  
 
           
Total deferred tax assets
    1,644       2,033  
 
           
Deferred tax liabilities
               
Property, plant and equipment
    57,858       48,498  
Other
    734       107  
 
           
Total deferred tax liabilities
    58,592       48,605  
 
           
Net deferred tax liabilities
  $ 56,948     $ 46,572  
 
           

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     The components of income tax expense for 2008, 2007 and 2006 are as follows:
                         
    2008     2007     2006  
    (In thousands)  
Current income tax expense
  $     $     $  
Deferred income tax expense
    21,938       11,129       8,777  
 
                 
Total income tax expense
  $ 21,938     $ 11,129     $ 8,777  
 
                 
     The following table reconciles the statutory federal income tax rate to the effective tax rate for 2008, 2007 and 2006
                         
    2008     2007     2006  
Income taxes at statutory rate
    29.00 %     32.12 %     34.12 %
Enacted future federal rate reductions
    (3.96 %)     (7.08 %)     (5.12 %)
Enacted future rate reductions effects for prior years
          (9.35 %)     (6.62 %)
Permanent differences
    1.44 %     0.77 %     (4.48 %)
Other
    (0.12 %)            
 
                 
Effective income tax rate
    26.36 %     16.46 %     17.90 %
 
                 
11. RELATED PARTY TRANSACTIONS
     QRCI pays Quicksilver for allocations of general and administrative expenses and salary, travel costs and other invoices paid by Quicksilver on the Company’s behalf. During 2008, 2007 and 2006, QRCI paid Quicksilver $3.7 million, $2.5 million and $1.8 million for its portion of general and administrative expenses allocated by Quicksilver. Amounts required for settlement of QRCI’s financial derivatives are paid or received and subsequently settled between Quicksilver and the Company. During 2008, QRCI paid Quicksilver $0.2 million for settlement of derivatives. For 2007 and 2006, Quicksilver paid QRCI $25.6 million and $9.7 million for these settlements. In 2007, QRCI received $11.5 million for the sales of natural gas to Quicksilver. All related party transactions occur in the normal course of business.
12. EMPLOYEE BENEFITS
     QRCI has a retirement plan available to all Canadian employees. The plan provides for a match of employees’ contributions by the Company and a fixed annual contribution. Expenses associated with QRCI contributions were $0.8 million, $0.7 million and $0.5 million for 2008, 2007 and 2006, respectively.
13. COMMITMENTS AND CONTINGENCIES
     QRCI leases office space and other property under operating leases. Future minimum lease payments, for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 2008, were as follows:
         
in thousands
2009
  $ 1,246  
2010
    369  
2011
    41  
Thereafter
     
 
     
 
  $ 1,656  
 
     
     Rent expense for operating leases with terms exceeding one month was $1.8 million in 2008, $1.5 million in 2007 and $0.9 million in 2006.
     QRCI had approximately $2.6 million in letters of credit to fulfill contractual, legal or regulatory requirements. All letters of credit have annual renewable options.
     QRCI is involved in various claims arising in the normal course of business. While the outcome of these matters is uncertain there can be no assurance that such matter will be resolved in the Company’s favor. QRCI does not currently believe that a material adverse outcome is likely related to these matters.

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14. STOCKHOLDER’S EQUITY
                 
    Shares     Book  
    Issued     Value  
            (In thousands)  
Unlimited number of Class A common voting shares
        $  
Unlimited number of Class B common voting shares
    2,495,646       1,785  
Unlimited number of Class C common non-voting, exchangeable shares
    394,482       32  
 
           
Balance at December 31, 2008 and 2007
    2,890,128     $ 1,817  
 
           
     QRCI Class C common shares are exchangeable on a one-for-one basis for Quicksilver common shares. Class C common shares are entitled to preference over the Class B common shares upon certain events of liquidation or distribution of the assets of the Company.
     Paid in capital in excess of par value at December 31, 2008 and 2007 is comprised of $2.1 million relating to the acquisition of the remaining non-controlling interest in the Company (10.2%) by Quicksilver in 2000, and cash of $26.0 million contributed by Quicksilver.
15. SUPPLEMENTAL CASH FLOW INFORMATION
     Cash paid for interest and income taxes is as follows:
                         
    Years Ended December 31,
    2008   2007   2006
    (In thousands)
Interest
  $ 14,374     $ 15,547     $ 13,004  
Income taxes
                 
     Other significant non-cash transactions are as follows:
                         
    Years Ended December 31,
    2008   2007   2006
    (In thousands)
Working capital related to acquisition of property, plant and equipment
    16,450     $ 19,653     $ 39,189  
Preferred interests in 1373159 Alberta Ltd.
    82,542              
16. SUBSEQUENT EVENT
     Under the full cost method in accounting for oil and gas properties, QRCI must perform a quarterly ceiling test for its country-wide cost center. In determining the ceiling limitation, the ceiling test incorporates pricing, costs and discount rates over which management has no influence. The 2009 first quarter Canadian ceiling amount was computed using a natural gas benchmark price of $2.92 per MMBtu and the mandated 10% discount rate. Upon calculation of the present value of QRCI’s natural gas reserves, including its hedge derivatives, the carrying value of its oil and gas properties exceeded the ceiling limit by $109.6 million (pre-tax) which was recorded in the first quarter of 2009.

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INDEPENDENT AUDITORS’ REPORT
To the Stockholders of
Cowtown Pipeline Funding, Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of Cowtown Pipeline Funding, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows and changes in stockholder’s equity for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cowtown Pipeline Funding, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared from the separate records maintained by Quicksilver Resources Inc. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, Quicksilver Resources Inc. as a whole.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
May 29, 2009

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COWTOWN PIPELINE FUNDING, INC.
CONSOLIDATED STATEMENTS OF INCOME
In thousands
                         
    Year Ended December 31,  
    2008     2007     2006  
Revenues
                       
Gathering and transportation revenue — Quicksilver
  $ 36,061     $ 15,089     $ 6,460  
Gathering and transportation revenue
    6,118       1,773       53  
Gas processing revenue — Quicksilver
    30,127       16,564       7,342  
Gas processing revenue
    5,366       1,990       63  
Other revenue — Quicksilver
    900       525        
 
                 
Total revenues
    78,572       35,941       13,918  
 
                 
 
                       
Expenses
                       
Operations and maintenance — Quicksilver
    21,638       12,037       7,567  
General and administrative — Quicksilver
    6,407       3,379       1,278  
Depreciation and accretion
    15,134       8,146       2,999  
 
                 
Total expenses
    43,179       23,562       11,844  
 
                 
 
Impairment Expense
    9,200              
 
                 
Operating income
    26,193       12,379       2,074  
 
Other income
    11       236       12  
Interest expense
    4,154       2,022        
 
                 
 
Income before income taxes
    22,050       10,593       2,086  
 
                       
Income tax provision
    7,861       3,591       730  
Minority interest
    4,716       1,092       99  
 
                 
 
Net income
  $ 9,473     $ 5,910     $ 1,257  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

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COWTOWN PIPELINE FUNDING, INC.
CONSOLIDATED BALANCE SHEETS
In thousands
                 
    December 31,     December 31,  
    2008     2007  
ASSETS
Current assets
               
Cash and cash equivalents
  $ 303     $ 1,125  
Accounts receivable
    2,245       882  
Accounts receivable from Quicksilver
          3,494  
Prepaid expenses and other current assets
    594       690  
 
           
Total current assets
    3,142       6,191  
 
               
Properties, plant and equipment, net
    489,893       284,885  
Deferred tax asset
    1,303       6,625  
Other assets
    1,916       965  
 
           
 
  $ 496,254     $ 298,666  
 
           
 
               
LIABILITIES AND EQUITY
Current liabilities
               
Current maturities of debt
  $ 1,375     $ 1,100  
Accounts payable to Quicksilver
    12,173       9,079  
Accrued additions to property, plant and equipment
    17,433       23,624  
Accounts payable and other
    1,930       2,425  
Current tax payable
    10,844       10,844  
 
           
Total current liabilities
    43,755       47,072  
 
               
Long-term debt
    174,900       5,000  
Note payable to Quicksilver
    52,271       50,569  
Asset retirement obligations
    5,234       2,793  
Deferred gain on sale of subsidiary equity
    79,316       79,316  
Minority interest
    31,287       31,487  
 
               
Commitments and contingent liabilities (Note 7)
               
 
               
Common stock
    1       1  
Additional paid in capital
    91,834       74,245  
Retained earnings
    17,656       8,183  
 
           
Total equity
    109,491       82,429  
 
           
 
  $ 496,254     $ 298,666  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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COWTOWN PIPELINE FUNDING, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
                         
    Year Ended December 31,  
    2008     2007     2006  
Operating activities:
                       
Net income
  $ 9,473     $ 5,910     $ 1,257  
Items included in net income not affecting cash:
                       
Depreciation
    14,950       8,063       2,978  
Impairment of midstream assets
    9,200              
Accretion of asset retirement obligation
    184       83       21  
Deferred income taxes
    7,861       3,591       730  
Equity-based compensation
    1,017       130        
Amortization of debt issuance costs
    243       88        
Non-cash interest expense
    2,802       1,669        
Minority interest expense
    4,716       1,092       99  
Changes in assets and liabilities:
                       
Accounts receivable
    (1,363 )     (815 )     (66 )
Prepaid expenses and other assets
    (612 )     (543 )     (146 )
Accounts receivable from Quicksilver
    4,707       (6,046 )      
Accounts payable and other
    (495 )     1,131       1,138  
 
                 
Net cash provided by operating activities
    52,683       14,353       6,011  
 
                 
 
                       
Investing activities:
                       
Capital expenditures
    (148,079 )     (74,064 )     (77,539 )
Other
                (821 )
 
                 
Net cash used in investing activities
    (148,079 )     (74,064 )     (78,360 )
 
                 
 
                       
Financing activities:
                       
Proceeds from revolving credit facility borrowings
    169,900       5,000        
Debt issuance costs
    (486 )     (1,041 )      
Repayment of subordinated note payable to Quicksilver
    (829 )            
Net proceeds from issuance of equity units
          112,298        
Issuance costs of equity units paid
          (2,933 )      
Distribution to Quicksilver
    (65,367 )     (115,074 )      
Contributions by Quicksilver
          68,416       67,855  
Contributions by minority interests
          167       7,291  
Distributions to minority interests
    (8,644 )     (8,794 )      
 
                 
Net cash provided by financing activities
    94,574       58,039       75,146  
 
                 
 
                       
Net increase (decrease) in cash
    (822 )     (1,672 )     2,797  
 
                       
Cash at beginning of period
    1,125       2,797        
 
                 
 
                       
Cash at end of period
  $ 303     $ 1,125     $ 2,797  
 
                 
 
                       
Cash paid for interest
  $ 2,341              
Cash paid for income taxes
  $ 332              
Non-cash transactions:
                       
Working capital related to capital expenditures
  $ 31,920     $ 30,809     $ 6,608  
Debt issuance costs
          (12 )      
Cost in connection with the initial public offering
          (275 )      
Issuance of subordinated note payable to Quicksilver
          50,000        
The accompanying notes are an integral part of these consolidated financial statements.

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COWTOWN PIPELINE FUNDING, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
In thousands
                                 
                    Additional        
    Common     Retained     Paid In        
    Stock     Earnings     Capital     Total Equity  
Balance at January 1, 2006
  $ 1     $ 1,016     $ 48,595     $ 49,612  
Contributions
                71,685       71,685  
Cash distributions to Quicksilver
                (4,508 )     (4,508 )
Net income
          1,257             1,257  
 
                       
Balance at December 31, 2006
    1       2,273       115,772       118,046  
Contributions
                121,157       121,157  
Reclass Quicksilver’s equity balance to receivable from Quicksilver
                1,971       1,971  
Distribution of subordinated note payable to Quicksilver
                (50,000 )     (50,000 )
Cash distributions to Quicksilver
                (114,655 )     (114,655 )
Net income
          5,910               5,910  
 
                       
Balance at December 31, 2007
    1       8,183       74,245       82,429  
Contributions
                82,956       82,956  
Cash distributions to Quicksilver
                (65,367 )     (65,367 )
Net income
          9,473             9,473  
 
                       
Balance at December 31, 2008
  $ 1     $ 17,656     $ 91,834     $ 109,491  
 
                       
The accompanying notes are an integral part of these consolidated financial statements.

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COWTOWN PIPELINE FUNDING, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
     Description of Business — Cowtown Pipeline Funding, Inc. (“CPFI”) is a Delaware corporation that holds approximately 73% ownership of Quicksilver Resources Inc’s (“Quicksilver”) interest in Quicksilver Gas Services, LP (“KGS”).
     CPFI also owns 99% of both Cowtown Pipeline L.P. (CPLP) and Cowtown Gas Processing L.P. (CGPLP), consolidating both entities. CPLP and CGPLP, in addition to owning the majority of KGS, are engaged in performing gathering and processing services for unaffiliated companies in the Delaware Basin in West Texas. Operations in West Texas accounted for less than 1% of CPFI consolidated revenues for all periods presented and are also immaterial to CPFI’s assets and cash flows. CPFI has no discrete operations but controls KGS and therefore the financials are consolidated and recognizes a minority interest.
     KGS is engaged in gathering and processing natural gas and NGLs, produced from the Barnett Shale formation in the Fort Worth Basin located in North Texas. KGS provides services under contracts, whereby it receives fees for performing the gathering and processing services. KGS does not take title to the natural gas or associated NGLs that it gathers and processes therefore avoids direct commodity price exposure.
     KGS’ assets include:
    The Cowtown System, which includes:
    the Cowtown Pipeline, which consists of a pipeline gathering system and gas compression facilities in the southern portion of the Fort Worth Basin and gathers natural gas produced by KGS’ customers and delivers it for processing;
 
    the Cowtown Plant, in Hood County, Texas, which consists of two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas to unaffiliated pipelines for transport and sale downstream; and
 
    the Corvette Plant in Hood County, Texas, which was placed in service during the first quarter 2009, and consists of a natural gas processing unit that extracts NGLs from the natural gas stream and delivers KGS customers’ residue gas to unaffiliated pipelines for transport and sale downstream.
    The Lake Arlington Dry System, located in Tarrant County, Texas, which consists of a gathering system and a gas compression facility, which KGS purchased from Quicksilver in the fourth quarter of 2008. This system is connected to affiliated pipelines for transport and sale downstream.
 
    The West Texas System, which consists of a 12 mile gathering system and a dehydration facility with capacity up to 6MMcfd.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
     Basis of Presentation — The accompanying consolidated financial statements and related notes of CPFI present the financial position, results of operations, cash flows and changes in equity of CPFI. CPFI eliminates all inter-company balances and transactions in preparing consolidated financial statements.
     Use of Estimates — The preparation of the financial statements in accordance with GAAP in the United States requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Although management believes the estimates are appropriate, actual results can differ from those estimates.
     Cash and Cash Equivalents — CPFI considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash or cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.

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     Accounts receivable — Accounts receivable are due from Quicksilver and other independent natural gas producers. Each customer of CPFI is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although CPFI does not require collateral, appropriate credit ratings are required. Receivables are generally due within 60 days. At December 31, 2008 and 2007, CPFI recorded no allowance for uncollectible accounts receivable. During 2008, CPFI experienced no non-payment for its services.
     Property, Plant and Equipment — Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
     The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use.
     Asset Retirement Obligations — CPFI records the discounted fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to the initial measurement, the asset retirement cost is allocated to expense using a straight line method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the estimated cash flows.
     Impairment of Long-Lived Assets — CPFI reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for the asset to its estimated fair value if such carrying amount exceeds the fair value. At December 31, 2008, CPFI’s analysis of its estimated future cash flows resulted in CPFI recording an impairment of $9.2 million for the midstream assets in West Texas.
     Other Assets — Other assets as of December 31, 2008 consist of costs associated with debt issuance and pipeline license agreements net of amortization. Other assets at December 31, 2007 consisted of cost associated with debt issuance net of amortization. Debt issuance costs are amortized over the term of the associated debt. Pipeline license agreements provide CPFI the right to construct, operate and maintain certain pipelines with local municipalities. The pipeline license agreements are amortized over the term of the agreement.
     Environmental Liabilities — Liabilities for environmental loss contingencies, including environmental remediation costs, are charged to expense when it is probable that a liability has been incurred and the amount of the assessment or remediation can be reasonably estimated.
     Revenue Recognition — CPFI’s primary service offerings are the gathering and processing of natural gas. CPFI’s subsidiaries have contracts under which they receive revenues based on the volume of natural gas gathered and processed. CPFI recognizes revenue when all of the following criteria are met:
    persuasive evidence of an exchange arrangement exists;
 
    services have been rendered;
 
    the price for its services is fixed or determinable; and
 
    collectability is reasonably assured.
     Income Taxes — CPFI is subject to federal income taxes and recognizes the impact of tax on temporary differences between the book and the tax basics of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. Net operating loss carry forwards and other deferred tax assets are reviewed annually for recoverability, and if necessary, are recorded net of a valuation allowance.
     Segment Information — CPFI operates solely in the midstream segment in Texas where it provides natural gas gathering, transportation and processing services.
     Fair Value of Financial Instruments — The fair value of accounts receivable, accounts payable, long-term debt and the note payable to Quicksilver approximate their carrying amounts.
     Equity Based Compensation — At time of issuance of phantom units, the Board of Directors of KGS determines whether they will be settled in cash or settled in KGS units. For awards payable in cash, CPFI amortizes the expense associated with the award over the vesting period. The liability for fair value is reassessed at every balance sheet date,

25


 

such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. Phantom unit awards payable in units are valued at the closing market price of KGS common units on the date of grant. The unearned compensation is amortized to compensation expense over the vesting period of the phantom unit award.
     Recently Issued Accounting Standards
    Pronouncements Implemented
     In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurements. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. CPFI adopted SFAS No. 157 on January 1, 2008 with no impact.
     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that were not previously required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, CPFI did not elect the fair value measurement option for any of its financial assets or liabilities.
     In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008 and was adopted by CPFI with no significant impact on our financial statements or related disclosures.
    Pronouncements Not Yet Implemented
     SFAS No. 141(R) (revised 2007), Business Combinations, was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, while retaining its 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. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. The Statement also requires an acquirer 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 as period expenses as incurred. The Statement will apply to any acquisition completed by CPFI after January 1, 2009, but otherwise had no effect on our financial statements upon adoption.
          SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 was issued in December 2007. The Statement amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary (previously referred to as “minority interest”) and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as a component of its equity. The Statement also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both Quicksilver and noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in Quicksilver’s ownership interest in a subsidiary that do not result in deconsolidation. CPFI adopted SFAS No. 160 on January 1, 2009 which resulted in the reclassification of the minority interest liability of $31.3 million to stockholder’s equity. Also, the adoption resulted in the 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.
          In May 2008, the FASB issued Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”), which indicates that issuers of convertible debt instruments generally should separately account for the liability component at its fair value and may result in amounts previously reported as debt being reclassified to equity. Furthermore, interest expense in periods subsequent to issuance may increase if the amount of reported debt changes. We adopted FSP APB 14-1 on January 1, 2009 with no impact to 2009 or previously reported results.

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3. PROPERTY, PLANT AND EQUIPMENT
     Property, plant and equipment consist of the following:
                         
            December 31,  
    Depreciable Life     2008     2007  
            (in thousands)  
Gathering and transportation systems
  20 years   $ 187,832     $ 114,618  
Processing plants
  20-25 years     160,404       120,477  
Construction in progress — plant
            106,563       12,636  
Construction in progress — pipeline
            27,994       20,046  
Rights-of-way and easements
  20 years     39,834       26,905  
Land
            1,239       952  
Buildings and other
  20-40 years     1,836       910  
 
                   
 
            525,702       296,544  
Accumulated Depreciation
            (35,809 )     (11,659 )
 
                   
Net property, plant and equipment
          $ 489,893     $ 284,885  
 
                   
     Construction in progress – plant reflects the construction of the Corvette Plant, a processing plant and compression facility attached to the Cowtown Pipeline, which was placed in service during the first quarter of 2009.
4. ACCOUNTS PAYABLE AND OTHER
     Accounts payable and other consists of the following:
                 
    December 31,  
    2008     2007  
    (in thousands)  
Accrued operating expenses
  $ 957     $ 882  
Accrued property taxes
          895  
Equity compensation payable
    116       275  
Interest payable
    734       147  
Other
    123       226  
 
           
 
  $ 1,930     $ 2,425  
 
           
5. LONG-TERM DEBT
     The following table summarizes our long-term debt payments due by period:
                                         
    Payments Due by Period  
Long-Term Debt   Total     2009     2010-2012     2013-2014     Thereafter  
                    (in millions)                  
Credit Agreement
  $ 174.9     $     $ 174.9     $     $  
Subordinated Note to Quicksilver
    53.6       1.4       3.3       48.9        
 
                             
Total long-term debt
  $ 228.5     $ 1.4     $ 178.2     $ 48.9     $  
 
                             
     Credit Agreement — On August 10, 2007, KGS entered into a five-year $150 million senior secured revolving credit facility (“Credit Agreement”). The Credit Agreement featured an accordion option that with lenders approval increases the facility up to $250 million. On October 10, 2008, the lenders approved an increase of the facility to $235 million. Also, the revised Credit Agreement permits the future expansion of the facility to $350 million, with lender approval. The facility, which matures August 10, 2012, can be extended up to two additional years with requisite lender consent.
     The Credit Agreement provides for revolving credit loans, swingline loans and letters of credit. Borrowings under the facility are guaranteed by KGS’ subsidiaries and are secured by substantially all of the assets of KGS and its subsidiaries. KGS has both LIBOR and U.S. prime rate options for revolving loans and a specified rate for swingline loans.

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     The Credit Agreement contains certain covenants which can limit KGS’ borrowing capacity. All of the covenants exclude the subordinated note payable to Quicksilver and KGS’ obligations to Quicksilver and related non-cash interest. These financial covenants are summarized below:
         
Quarters Ended   Maximum Debt to EBITDA   Minimum EBITDA to Interest
December 31, 2008 and thereafter
  4.50 to 1   2.50 to 1
     At December 31, 2008, the lenders’ commitments under our credit agreement were $235 million and may be further increased to as much as $350 million. Based on our results through December 31, 2008, our total borrowing capacity is $235 million and our borrowings were $174.9 million, and the weighted average interest rate was 2.9%. The Credit Agreement contains restrictive covenants that prohibit the declaration or payment of distributions by KGS if a default then exists or would result therefrom, and otherwise limits the amount of distributions that KGS can make. In the event of default, the Credit Agreement allows for the acceleration of the loans, the termination of the credit agreement and foreclosure on collateral.
     Subordinated Note — On August 10, 2007, KGS executed a subordinated promissory note (the “Subordinated Note”) payable to Quicksilver in the principal amount of $50.0 million.
     The Subordinated Note accrues interest based upon the rate applicable to borrowings under the Credit Agreement plus 1%, which is locked at the time of borrowing. The interest rate at December 31, 2008 was 4.485%. Accrued and unpaid interest is payable quarterly on the last business day of each calendar quarter, beginning on March 31, 2008, and on the Subordinated Note’s maturity date described below. Quarterly interest may be paid in cash or by adding it to the outstanding principal balance of the Subordinated Note. Subject to certain restrictions, quarterly installments of $275,000 are payable on the last business day of each calendar quarter. The final payment is due on February 10, 2013. However, if the maturity date of the Credit Agreement is extended, the maturity date of the Subordinated Note will also be automatically extended to the date that is six months after the revised Credit Agreement maturity date. Amounts payable under the Subordinated Note may at all times, at Quicksilver’s election, be paid, in whole or in part, using KGS units. The Subordinated Note contains events of default that permit, among other things, the acceleration of the debt (unless otherwise prohibited pursuant to the subordination provisions described below). Such events of default include, but are not limited to, payment defaults under the Subordinated Note, the breach of certain covenants after applicable grace periods and the occurrence of an event of default under the Credit Agreement.
     Amounts due under the Subordinated Note are subordinated in right of payment to all of our obligations under the Credit Agreement. KGS is precluded from making any payments under the Subordinated Note if any of the following events exist or would result as of the date of the proposed Subordinated Note payment:
    an event of default under the revolving credit agreement;
 
    the existence of a pending judicial proceeding with respect to any event of default under the revolving credit agreement; or
 
    our ratio of total indebtedness (which includes the $50.0 million Subordinated Note) to EBITDA as of the end of the fiscal quarter immediately preceding the date of such payment was equal to or greater than 3.5 or would be greater than 3.5 after consideration of such payment.
     Through December 31, 2008, we have made all scheduled quarterly interest payments at the end of each quarter by adding them to the principal of the Subordinated Note in accordance with its terms. Accordingly, interest expense of $2.8 million recognized during 2008 was added to the Subordinated Note. In 2008, we made three quarterly principal payments of the Subordinated Note for a total of $0.8 million. The fourth quarter principal payment was prevented by the indebtedness limitation on EBITDA described above.

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6. ASSET RETIREMENT OBLIGATIONS
     The following table provides a reconciliation of the changes in the asset retirement obligation:
                 
    Year Ended December 31,  
    2008     2007  
    (in thousands)  
Beginning asset retirement obligations
  $ 2,793     $ 503  
Additional liability incurred
    2,257       2,207  
Accretion expense
    184       83  
 
           
Ending asset retirement obligations
  $ 5,234     $ 2,793  
 
           
     As of December 31, 2008, no assets are legally restricted for use in settling asset retirement obligations.
7. COMMITMENTS AND CONTINGENT LIABILITIES
     Litigation — In February 2009, McGuffy Energy Services, L.P. (“McGuffy”) filed a lawsuit against KGS and subsequently added Quicksilver as a party. McGuffy alleges, among other things, claims for breach of contract, fraud and negligent misrepresentation arising from a written agreement by which McGuffy was retained to provide certain engineering and construction services for KGS’ Corvette Plant. McGuffy further seeks to foreclose on a $3.2 million lien that it filed on the Corvette Plant. KGS disputes the amounts claimed by McGuffy and asserts a number of defenses to McGuffy’s claims, including that payments to McGuffy must be withheld as demanded by McGuffy’s unpaid subcontractors. In March 2009, KGS filed a lawsuit against McGuffy seeking damages and declaratory relief for the disputes between KGS and McGuffy. The McGuffy subcontractors that made demands on KGS were also named as parties. Several of the subcontractor defendants have filed counterclaims against KGS seeking to foreclose on their purported liens. Through March 31, 2009 KGS had recognized $2.0 million of the disputed amounts as a part of the Corvette Plant construction costs. KGS intends to vigorously defend this matter and does not expect its outcome to have a material adverse effect on our financial condition or results of operation.
     Casualties or Other Risks — Quicksilver maintains coverage in various insurance programs on CPFI’s behalf, which provides it with property damage, business interruption and other coverage’s which are customary for the nature and scope of its operations.
     Management of the general partner believes that Quicksilver and CPFI has adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Quicksilver may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. KGS maintains its own general partners’ liability insurance policy separate from the directors and officers policy maintained by Quicksilver.
     If CPFI or its subsidiaries were to incur a significant loss for which they were was not fully insured, the loss could have a material impact on the consolidated financial position and results of operations. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by CPFI, or which causes CPFI to make significant expenditures not covered by insurance, could reduce its ability to meet its financial obligations.
     Regulatory Compliance — In the ordinary course of business, CPFI and it subsidiaries are subject to various laws and regulations. In the opinion of CPFI’s management, compliance with current laws and regulations will not have a material adverse effect on CPFI’s financial position or results of operations.
     Environmental Compliance — The operation of CPFI’ pipelines, plants and other facilities is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, CPFI must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating CPFI’ facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2008, CPFI had no liabilities recorded for environmental matters.

29


 

     Commitments — CPFI, through its subsidiaries, has entered into agreements with third parties providing for natural gas compression equipment and the construction of the Corvette plant, which was placed in service during the first quarter of 2009.
     The following table summarizes CPFI’ contractual obligations:
                                         
    Payments Due by Period  
Contractual Obligations   Total     2009     2010-2012     2013-2014     Thereafter  
                    (in millions)                  
Construction commitments
  $ 13.8     $ 13.8     $     $     $  
 
                             
Total contractual obligations
  $ 13.8     $ 13.8     $     $     $  
 
                             
8. INCOME TAXES
     CPFI recognized income tax at the federal statutory income tax rate of 35%. CPFI is also subject to the Texas margin tax rate of 1% beginning in 2007. As the tax base for computing Texas margin tax is derived from an income-based measure, the Company recognizes this tax as an income tax. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2008 and 2007 are as follows:
                 
    As of December 31,  
    2008     2007  
    (In thousands)  
Non-current
               
Deferred tax assets
               
Deferred tax benefit on minority interest
  $ 3,185     $ 646  
Deferred tax benefit (liability) on partnership income
    (1,882 )     5,979  
 
           
Total deferred tax assets
  $ 1,303     $ 6,625  
 
           
 
The components of income tax expense for 2008, 2007 and 2006 are as follows:
                         
    2008     2007     2006  
            (In thousands)          
Current state income tax expense
  $     $ 371     $  
Current U.S. federal income tax expense
          10,273        
 
                 
                         
Total current income tax expense
          10,644        
 
                 
 
                       
Deferred state income tax expense (benefit)
    221       (265      
Deferred U.S. federal income tax expense (benefit)
    7,640       (6,788 )     730  
 
                 
                         
Total deferred income tax expense (benefit)
    7,861       (7,053 )     730  
 
                 
Total income tax expense
  $ 7,861     $ 3,591     $ 730  
 
                 
 
The following table reconciles the statutory federal income tax rate to the effective tax rate for 2008, 2007 and 2006:
                         
    2008     2007     2006  
U.S. federal statutory tax rate
    35.00 %     35.00 %     35.00 %
State income taxes net of federal deduction
    0.65 %     (1.10 )%     0.00 %
 
                 
                         
Effective income tax rate
    35.65 %     33.90 %     35.00 %
 
                 

30


 

9. EQUITY PLAN
     Awards of phantom units have been granted under KGS’ 2007 Equity Plan, which permits the issuance of up to 750,000 units. The following table summarizes information regarding the phantom unit activity:
                                 
    Payable in cash   Payable in units
            Weighted           Weighted
            Average           Average
            Grant Date           Grant Date
    Units   Fair Value   Units   Fair Value
Unvested phantom units — January 1, 2008
    84,961     $ 21.36       9,833     $ 21.36  
 
                               
Vested
    (28,247 )     21.43       (6,089 )     21.36  
Issued
    6,605       24.12       137,148       25.25  
Cancelled
    (3,000 )     21.36       (974 )     25.25  
 
                               
Unvested phantom units — December 31, 2008
    60,319     $ 21.63       139,918     $ 25.15  
 
                               
     At January 1, 2008, total unvested compensation cost was $1.9 million related to unvested phantom units. Compensation expense of approximately $1.4 million was recognized during 2008, including $0.4 million for remeasuring the vested portion of awards to be settled in cash to their revised fair value. Grants of phantom units during the year ended December 31, 2008 had an estimated grant date fair value of $3.6 million. Unearned compensation expense of $2.3 million at December 31, 2008 will be recognized in expense over the next 1.9 years. Phantom units that vested during the year ended December 31, 2008 had a fair value of $0.7 million on their vesting date.
10. MINORITY INTEREST AND DEFERRED GAIN ON SALE
     Minority Interest - As a result of the KGS IPO, the outside ownership of KGS increased and therefore consolidated KGS’ financial position and results of operations and recognized a minority interest liability for that portion of KGS that is owned by entities not affiliated with Quicksilver.
     Deferred Gain on sale of subsidiary equity - As a result of the KGS IPO, a deferred gain of approximately $79 million was recognized in the consolidated financial statements. The proceeds received from the IPO exceeded CPFI’s carrying value, which resulted in the gain. The absence of parity between the common and subordinated units prevents the culmination of the earnings process. CPFI deferred the gain until such time that the common units have equal standing to the units held by the public. The gain will be recognized when the subordination period ends and the equality of the shares are achieved.
11. TRANSACTIONS WITH RELATED PARTIES
     Upon completion of, or in connection with, its IPO, KGS entered into a number of agreements with related parties. A description of those agreements follows:
     Omnibus Agreement — On August 10, 2007, KGS entered into an omnibus agreement (the “Omnibus Agreement”) with Quicksilver, which addresses, among other matters:
    restrictions on Quicksilver’s ability to engage in midstream business activities in Quicksilver Counties;
 
    Obligation to reimburse Quicksilver for all general and administrative expenses incurred by them on behalf of KGS; and
 
    Quicksilver’s obligation to provide cross-indemnification for certain liabilities.
     Secondment Agreement — On August 10, 2007, Quicksilver and KGS’ general partner entered into a services and secondment agreement (the “Secondment Agreement”) pursuant to which specified employees of Quicksilver have been seconded to KGS’ general partner to provide operating, routine maintenance and other services with respect to the assets owned or operated by KGS. Under the Secondment Agreement, the general partner reimburses Quicksilver for the services provided by the seconded employees. The initial term of the Secondment Agreement is 10 years, but will extend for additional annual periods unless cancelled by either party with 180 days’ written notice.

31


 

     Gas Gathering and Processing Agreement — On August 10, 2007, Quicksilver, Cowtown Gas Processing Partners LP (“Processing Partners”) and Cowtown Pipeline Partners LP (“Pipeline Partners”) together with Processing Partners (the “Cowtown Partnerships”) entered into the Fifth Amended and Restated Gas Gathering and Processing Agreement. In connection with the IPO, Processing Partners and Pipeline Partners became indirect wholly-owned subsidiaries of KGS. Under the Gas Gathering and Processing Agreement, Quicksilver has agreed, for an initial term of 10 years, to dedicate and deliver for processing all of the natural gas produced on properties operated by Quicksilver within the Quicksilver Counties. The dedication does not oblige Quicksilver to develop the reserves subject to the Gas Gathering and Processing Agreement.
     Effective September 1, 2008, Quicksilver and KGS entered into the Sixth Amended and Restated Gas Gathering and Processing Agreement, which amended the previous agreement by specifying that Quicksilver has agreed to pay $0.4163 per MMBtu gathered and $0.5204 per MMBtu processed and a compression fee of up to $0.30 per MMBtu on the Cowtown System. The compression fee payable by Quicksilver at a gathering system delivery point shall never be less than KGS’ actual cost to perform such compression service. Quicksilver may also pay KGS a treating fee based on carbon dioxide content at the pipeline entry point. The rates above are each subject to an annual inflationary escalation.
     If KGS determines that the gathering or processing of Quicksilver’s production becomes uneconomical, KGS may cease gathering and processing Quicksilver’s production as long as the uneconomical conditions exist. If KGS is unable to provide either gathering or processing services, Quicksilver may use other providers. If KGS is unable to provide either gathering or processing services for a period of 60 consecutive days, for reasons other than force majeure, causing Quicksilver’s wells to be shut-in (in the case of gathering) or resulting in Quicksilver’s inability to by-pass the Cowtown Plant and deliver its natural gas production to an alternative pipeline (in the case of processing), Quicksilver has the right to terminate the Gas Gathering and Processing Agreement as it relates to the affected gas.
     Absent written notice of termination, the Gas Gathering and Processing Agreement is automatically renewed for one year periods. In addition, if the Gas Gathering and Processing Agreement, or performance under this agreement, becomes subject to FERC jurisdiction, the agreement would be terminated unless both parties agree to continue the agreement.
     During the second quarter of 2008, KGS agreed to purchase land and a warehouse located in Hood County, Texas, from Quicksilver for a purchase price of $0.3 million and the reimbursement to Quicksilver of $0.6 million of costs. KGS also obtained additional easement rights for a total cost of $0.2 million from an affiliate of an entity that beneficially owns a small portion of KGS’ outstanding units.
     Contribution, Conveyance and Assumption Agreement — On August 10, 2007 KGS entered into a contribution, conveyance, and assumption agreement (“Contribution Agreement”) with its general partner, certain other affiliates of Quicksilver and the private investors. The following transactions, among others, occurred just prior to the KGS IPO pursuant to the Contribution Agreement:
    the transfer of all of the interests of certain entities to KGS and its subsidiaries;
 
    the issuance of the incentive distribution rights to the general partner and the continuation of its 2% general partner interest in KGS;
 
    KGS’ issuance of 5,696,752 common units, 11,513,625 subordinated units and the right to receive $162.1 million, to Holdings in exchange for the contributed interests; and
 
    KGS’ issuance of 816,873 common units and the right to receive $7.7 million to private investors in exchange for their contributed interests.
     Centralized cash management — As of December 31, 2008 revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of KGS, are reflected as a receivable from or a payable to Quicksilver on the consolidated balance sheets and as a reduction of net cash provided by or used by operating activities on the consolidated statements of cash flows.
     Services to affiliates — KGS routinely conducts business with Quicksilver and its affiliates. The related transactions result primarily from fee-based arrangements for gathering and processing of natural gas. Fees were determined based on fees to third parties and reflect the cost of providing such services. Quicksilver has engaged us to operate midstream assets owned by it for a monthly fee of $75,000.
     Allocation of costs — The individuals supporting CPFI’s operating subsidiaries are employees of Quicksilver. CPFI’s consolidated financial statements include costs allocated to KGS by Quicksilver for centralized general and administrative services performed by Quicksilver, as well as depreciation of assets utilized by Quicksilver’s centralized general and administrative functions. Costs allocated to KGS are based on identification of Quicksilver’s resources which directly benefit KGS and its estimated usage of shared resources and functions. All of the allocations are based on assumptions that management believes are reasonable.

32


 


 

INDEPENDENT AUDITORS’ REPORT
To the Members of
Quicksilver Gas Services Holdings LLC
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of Quicksilver Gas Services Holdings LLC and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, cash flows and changes in members’ capital for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Quicksilver Gas Services Holdings LLC and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared from the separate records maintained by Quicksilver Resources Inc. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to, Quicksilver Resources Inc. as a whole.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
May 29, 2009

34


 

QUICKSILVER GAS SERVICES HOLDINGS LLC
CONSOLIDATED STATEMENTS OF INCOME
In thousands
                         
    Year Ended December 31,  
    2008     2007     2006  
Revenues
                       
Gathering and transportation revenue — Quicksilver
  $ 36,061     $ 15,089     $ 6,460  
Gathering and transportation revenue
    5,612       1,773       53  
Gas processing revenue — Quicksilver
    30,127       16,564       7,342  
Gas processing revenue
    5,358       1,990       63  
Other revenue — Quicksilver
    900       525        
 
                 
Total revenues
    78,058       35,941       13,918  
 
                 
 
                       
Expenses
                       
Operations and maintenance — Quicksilver
    20,250       11,512       7,475  
General and administrative — Quicksilver
    6,407       3,379       937  
Depreciation and accretion
    14,566       8,070       2,963  
 
                 
Total expenses
    41,223       22,961       11,375  
 
                 
 
                       
Operating income
    36,835       12,980       2,543  
 
                       
Other income
    11       236       13  
Interest expense
    10,177       4,647        
 
                 
 
                       
Income before income taxes
    26,669       8,569       2,556  
 
                       
Income tax provision
    253       313       135  
Minority interest expense
    7,160       1,304       140  
 
                 
 
                       
Net income
  $ 19,256     $ 6,952     $ 2,281  
 
                 
The accompanying notes are an integral part of these consolidated financial statements.

35


 

QUICKSILVER GAS SERVICES HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS
In thousands
                 
    December 31,     December 31,  
    2008     2007  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $ 303     $ 1,125  
Accounts receivable
    2,082       882  
Accounts receivable from Quicksilver
          800  
Prepaid expenses and other current assets
    594       690  
 
           
Total current assets
    2,979       3,497  
 
               
Properties, plant and equipment, net
    488,120       273,948  
Other assets
    1,916       965  
 
           
 
  $ 493,015     $ 278,410  
 
           
 
               
LIABILITIES AND MEMBERS’ CAPITAL
               
Current liabilities
               
Current maturities of debt
  $ 1,375     $ 1,100  
Accounts payable to Quicksilver
    10,502        
Accrued additions to property, plant and equipment
    17,433       23,624  
Accounts payable and other
    1,930       2,700  
 
           
Total current liabilities
    31,240       27,424  
 
               
Long-term debt
    174,900       5,000  
Note payable to Quicksilver
    52,271       50,569  
Repurchase obligations to Quicksilver
    123,298       82,251  
Asset retirement obligations
    5,234       2,793  
Deferred income tax liability
    369       173  
Deferred gain on sale of subsidiary equity
    79,316       79,316  
 
               
Commitments and contingent liabilities (Note 7)
 
Minority interest
    29,867       30,338  
 
           
Net members’ capital (deficit)
    (3,480 )     546  
 
           
 
  $ 493,015     $ 278,410  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

36


 

QUICKSILVER GAS SERVICES HOLDINGS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
                         
    Year Ended December 31,  
    2008     2007     2006  
Operating activities:
                       
Net income
  $ 19,256     $ 6,952     $ 2,281  
Items included in net income not affecting cash:
                       
Depreciation
    14,382       7,987       2,942  
Accretion of asset retirement obligation
    184       83       21  
Deferred income taxes
    196       38       135  
Equity-based compensation
    1,017       130        
Amortization of debt issuance costs
    243       88        
Non-cash interest expense
    8,825       4,294        
Minority interest expense
    7,160       1,304       140  
Changes in assets and liabilities:
                       
Accounts receivable
    (1,200 )     (815 )     (66 )
Prepaid expenses and other assets
    (612 )     (543 )     (146 )
Accounts receivable from Quicksilver
    4,002       (5,975 )      
Accounts payable and other
    (770 )     1,406       1,138  
 
                 
Net cash provided by operating activities
    52,683       14,949       6,445  
 
                 
 
                       
Investing activities:
                       
Capital expenditures
    (148,079 )     (73,797 )     (77,539 )
Other
                (821 )
 
                 
Net cash used in investing activities
    (148,079 )     (73,797 )     (78,360 )
 
                 
 
                       
Financing activities:
                       
Proceeds from sale of assets to Quicksilver
          29,508        
Proceeds from revolving credit facility borrowings
    169,900       5,000        
Debt issuance costs
    (486 )     (1,041 )      
Repayment of repurchase obligation to Quicksilver
    (42,085 )            
Repayment of subordinated note payable to Quicksilver
    (829 )            
Net proceeds from sale of KGS units
          112,298        
Costs paid for sale of KGS units
          (2,933 )      
Distributions to Quicksilver
    (23,282 )     (115,074 )      
Contributions by Quicksilver
          38,045       67,421  
Contributions by minority interests
          167       7,291  
Distributions to minority interests
    (8,644 )     (8,794 )      
 
                 
Net cash provided by financing activities
    94,574       57,176       74,712  
 
                 
 
                       
Net increase (decrease) in cash
    (822 )     (1,672 )     2,797  
 
                       
Cash at beginning of period
    1,125       2,797        
 
                 
 
                       
Cash at end of period
  $ 303     $ 1,125     $ 2,797  
 
                 
 
                       
Cash paid for interest
  $ 2,341              
Cash paid for income taxes
  $ 332              
Non-cash transactions:
                       
Working capital related to capital expenditures
  $ 31,920     $ 30,809     $ 6,608  
Debt issuance costs
          (12 )      
Cost in connection with the initial public offering
          (275 )      
Issuance of subordinated note payable to Quicksilver
          50,000        
Acquisition of property, plant and equipment under repurchase obligation
  $ (77,108 )   $ (50,118 )   $  
The accompanying notes are an integral part of these consolidated financial statements.

37


 

QUICKSILVER GAS SERVICES HOLDINGS LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ CAPITAL
In thousands
         
    Net Members’ Capital  
Balance at January 1, 2006
  $ 48,949  
Contributions
    71,930  
Cash distributions to Quicksilver
    (4,508 )
Net income
    2,281  
 
     
Balance at December 31, 2006
    118,652  
Contributions
    38,045  
Distribution of subordinated note payable to Quicksilver
    (50,000 )
Reclass Quicksilver’s equity balance to receivable from Quicksilver
    1,971  
Cash distributions to Quicksilver
    (115,074 )
Net income
    6,952  
 
     
Balance at December 31, 2007
    546  
Cash distributions to Quicksilver
    (23,282 )
Net income
    19,256  
 
     
Balance at December 31, 2008
  $ (3,480 )
 
     
The accompanying notes are an integral part of these consolidated financial statements.

38


 

QUICKSILVER GAS SERVICES HOLDINGS LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND DESCRIPTION OF BUSINESS
     Organization — Quicksilver Gas Services Holdings LLC (“KGSH”) is a Delaware limited liability corporation formed in January 2007 for the purpose of maintaining approximately 73% ownership of Quicksilver Resources Inc’s (“Quicksilver”) interest in Quicksilver Gas Services, LP (“KGS”). KGSH is owned 50% by each of two entities which are each indirectly owned by Quicksilver.
     KGSH has no discrete operations but controls KGS and therefore consolidates KGS’ financial position and results of operations and recognizes a minority interest for that portion of KGS that is owned by entities not affiliated with Quicksilver.
     Description of Business — KGS is engaged in gathering and processing natural gas and NGLs, produced from the Barnett Shale formation in the Fort Worth Basin located in North Texas. KGS provides services under contracts, whereby it receives fees for performing the gathering and processing services. KGS does not take title to the natural gas or associated NGLs that it gathers and processes therefore avoids direct commodity price exposure.
     KGSH’s assets consist solely of assets owned by KGS, whose assets include:
    The Cowtown System, which includes:
    the Cowtown Pipeline, which consists of a pipeline gathering system and gas compression facilities in the southern portion of the Fort Worth Basin and gathers natural gas produced by KGS’ customers and delivers it for processing;
 
    the Cowtown Plant, in Hood County, Texas, which consists of two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas to unaffiliated pipelines for transport and sale downstream; and
 
    the Corvette Plant in Hood County, Texas, which was placed in service during the first quarter 2009, and consists of a natural gas processing unit that extracts NGLs from the natural gas stream and delivers KGS customers’ residue gas to unaffiliated pipelines for transport and sale downstream.
    The Lake Arlington Dry System, located in Tarrant County, Texas, which consists of a gathering system and a gas compression facility, which KGS purchased from Quicksilver in the fourth quarter of 2008. This system is connected to affiliated pipelines for transport and sale downstream.
     As more fully described in Note 2, KGSH’ financial statements also include the operations of a gathering system in Hill County, Texas (“Hill County Dry System”) that gathers production from the Fort Worth Basin and delivers it to unaffiliated pipelines for transport and sale downstream.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
     Basis of Presentation — The accompanying consolidated financial statements and related notes of KGSH present the financial position, results of operations, cash flows and changes in partners’ capital of KGS’ natural gas gathering and processing assets. The financial statements include historical cost-basis accounts of the assets of KGS Predecessor which were contributed to KGS through KGSH by Quicksilver and two private investors in connection with the KGS IPO.
     Use of Estimates — The preparation of the financial statements in accordance with GAAP in the United States requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Although management believes the estimates are appropriate, actual results can differ from those estimates.
     Cash and Cash Equivalents — KGSH considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash or cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.
     Accounts receivable — Accounts receivable are due from Quicksilver and other independent natural gas producers. Each customer of KGSH is reviewed as to credit worthiness prior to the extension of credit and on a regular basis

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thereafter. Although KGSH does not require collateral, appropriate credit ratings are required. Receivables are generally due within 60 days. At December 31, 2008 and 2007, KGSH recorded no allowance for uncollectible accounts receivable. During 2008, KGSH experienced no non-payment for their services.
     Property, Plant and Equipment — Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
     The cost of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets or enhance their productivity or efficiency from their original design are capitalized over the expected remaining period of use.
     Asset Retirement Obligations — KGSH records the discounted fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to the initial measurement, the asset retirement cost is allocated to expense using a straight line method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the estimated cash flows.
     Repurchase Obligations to Quicksilver — On June 5, 2007, KGSH sold several pipeline and gathering assets to Quicksilver. These assets consist of:
    a portion of the gathering lines in the Cowtown Pipeline;
 
    the Lake Arlington Dry System; and
 
    the Hill County Dry System.
     At June 5, 2007, the assets were either constructed and in service or partially constructed. The selling price for these assets was approximately $29.5 million, which represented KGS Predecessor’s historical cost. KGS Predecessor collected the $29.5 million on August 9, 2007. All assets conveyed are or were subject to repurchase by KGS from Quicksilver as follows:
Cowtown Pipeline repurchase — KGS has the option to purchase portions of the Cowtown Pipeline from Quicksilver at their original cost in or before 2011 based upon the expected timing of their commerciality.
Lake Arlington Dry System repurchase — KGS was obligated to purchase the Lake Arlington Dry System from Quicksilver at its fair market value within two years after it was completed and commercial service commenced. During the fourth quarter 2008, KGS completed the acquisition of the Lake Arlington Dry System from Quicksilver for approximately $42 million. The purchase was financed through the use of the credit agreement and resulted in the reduction of the repurchase obligation. In conjunction with the purchase of the Lake Arlington Dry System, Quicksilver assigned its gas gathering agreement to KGS. Under the terms of that agreement, Quicksilver agreed to allow KGS to gather all of the natural gas produced by wells that it operated and from future wells operated by it within the Lake Arlington area through August 2017. Quicksilver’s fee of $0.62 per Mcf gathered by KGS in the Lake Arlington Dry System is subject to annual inflationary escalation.
Hill County Dry System repurchase — KGS is obligated to purchase the Hill County Dry System from Quicksilver at its fair market value in or before 2011 based upon the system’s expected timing of commerciality.
The following table summarizes the assets subject to KGS’ repurchase rights and obligations (in millions):
                                         
            Estimate of     Construction              
            Construction     Costs Recognized     Repurchase        
            Costs as of     through     obligation at        
    June 5, 2007     December 31,     December 31,     December        
    Sales Price     2008(1)     2008     31, 2008     KGS Repurchase
Cowtown Pipeline
  $ 22.9     $ 62.6     $ 67.0     $ 67.0     Optional at Cost
Lake Arlington Dry System
    3.6       (2)     42.1           Repurchased at FV in 2008
Hill County Dry System
    3.0       78.0       56.3       56.3     Obligatory at FV
 
                             
 
  $ 29.5     $ 140.6     $ 165.4     $ 123.3          
 
                             

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(1)   Estimates may change based on changes in producers’ drilling progress, material and labor costs, easement costs and other factors
 
(2)   Excludes any estimated costs after completion of purchase
     The assets’ conveyance was not treated as a sale for accounting purposes because KGS operates them and intends to purchase them. Accordingly, the original cost and subsequently incurred costs are recognized in both KGSH’s consolidated property, plant and equipment and its consolidated repurchase obligations to Quicksilver. Similarly, KGSH’s consolidated results of operations include the revenues and expenses for these operations. For 2008, KGSH recognized $6.0 million of interest expense associated with the repurchase obligations to Quicksilver based on a weighted-average interest rate of 5.2%.
     Impairment of Long-Lived Assets — KGSH reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for the asset to its estimated fair value if such carrying amount exceeds the fair value. At December 31, 2008, KGSH performed an analysis of its estimated future cash flows and determined that there was no impairment on its long-lived assets.
     Other Assets — Other assets as of December 31, 2008 consist of costs associated with debt issuance and pipeline license agreements net of amortization. Other assets at December 31, 2007 consisted of cost associated with debt issuance net of amortization. Debt issuance costs are amortized over the term of the associated debt. Pipeline license agreements provide KGSH the right to construct, operate and maintain certain pipelines with local municipalities. The pipeline license agreements are amortized over the term of the agreement.
     Environmental Liabilities — Liabilities for environmental loss contingencies, including environmental remediation costs, are charged to expense when it is probable that a liability has been incurred and the amount of the assessment or remediation can be reasonably estimated.
     Revenue Recognition — KGSH’s primary service offerings are the gathering and processing of natural gas. KGSH has contracts under which it receives revenues based on the volume of natural gas gathered and processed. KGSH recognizes revenue when all of the following criteria are met:
    persuasive evidence of an exchange arrangement exists;
 
    services have been rendered;
 
    the price for its services is fixed or determinable; and
 
    collectability is reasonably assured.
     Income Taxes — KGSH is subject to a margin tax that requires tax payments at a maximum effective rate of 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires KGSH to recognize currently the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis. Under the margin tax, taxable entities that are part of an affiliated group engaged in a unitary business must file a combined group report. As a result, KGSH is included in a combined group report with Quicksilver and are allocated their proportionate share of the tax liability.
     Segment Information — KGSH operates solely in the midstream segment in Texas where it provides natural gas gathering, transportation and processing services.
     Fair Value of Financial Instruments — The fair value of accounts receivable, accounts payable, long-term debt, the note payable to Quicksilver and repurchase obligations to Quicksilver approximate their carrying amounts.
     Equity Based Compensation — At time of issuance of phantom units, the Board of Directors of KGS determines whether they will be settled in cash or settled in KGS units. For awards payable in cash, KGSH amortizes the expense associated with the award over the vesting period. The liability for fair value is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. Phantom unit awards payable in units are valued at the closing market price of KGS common units on the date of grant. The unearned compensation is amortized to compensation expense over the vesting period of the phantom unit award.
     Recently Issued Accounting Standards
    Pronouncements Implemented

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     In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value under GAAP and expands disclosures about fair value measurements. The Statement applies under other accounting pronouncements that require or permit fair value measurements. No new requirements are included in SFAS No. 157, but application of the Statement has changed current practice. KGSH adopted SFAS No. 157 on January 1, 2008 with no impact.
     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that were not previously required to be measured at fair value. While SFAS No. 159 became effective on January 1, 2008, KGSH did not elect the fair value measurement option for any of its financial assets or liabilities.
     In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP in the United States. This Statement is generally viewed as a necessary step in the ultimate convergence of global accounting rules. This Statement became effective on November 15, 2008 and was adopted by KGSH with no significant impact on our financial statements or related disclosures.
    Pronouncements Not Yet Implemented
     SFAS No. 141(R) (revised 2007), Business Combinations, was issued in December 2007. SFAS No. 141(R) replaces SFAS No. 141, Business Combinations, while retaining its 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. SFAS No. 141(R) defines the acquirer as the entity that obtains control in the business combination and it establishes the criteria to determine the acquisition date. The Statement also requires an acquirer 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 as period expenses as incurred. The Statement will apply to any acquisition completed by KGSH after January 1, 2009, but otherwise had no effect on our financial statements upon adoption.
     SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51 was issued in December 2007. The Statement amends ARB 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary (previously referred to as “minority interest”) and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as a component of its equity. The Statement also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both Quicksilver and noncontrolling interest. Additionally, SFAS No. 160 establishes a single method for accounting for changes in Quicksilver’s ownership interest in a subsidiary that do not result in deconsolidation. KGSH adopted SFAS No. 160 on January 1, 2009 which resulted in the reclassification of the minority interest liability of $29.9 million to stockholder’s equity. Also, the adoption resulted in the 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.
     In May 2008, the FASB issued Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (“FSP APB 14-1”), which indicates that issuers of convertible debt instruments generally should separately account for the liability component at its fair value and may result in amounts previously reported as debt being reclassified to equity. Furthermore, interest expense in periods subsequent to issuance may increase if the amount of reported debt changes. We adopted FSP APB 14-1 on January 1, 2009 with no impact to 2009 or previously reported results.

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3. PROPERTY, PLANT AND EQUIPMENT
     Property, plant and equipment consist of the following:
                         
            December 31,  
    Depreciable Life     2008     2007  
            (in thousands)  
Gathering and transportation systems
  20 years   $ 179,594     $ 106,478  
Processing plants
  20-25 years     157,353       117,571  
Construction in progress — plant
            106,563       12,636  
Construction in progress — pipeline
            27,994       20,046  
Rights-of-way and easements
  20 years     39,473       26,905  
Land
            1,239       952  
Buildings and other
  20-40 years     1,836       910  
 
                 
 
            514,052       285,498  
Accumulated Depreciation
            (25,932 )     (11,550 )
 
                 
Net property, plant and equipment
          $ 488,120     $ 273,948  
 
                 
     Construction in progress – plant reflects the construction of the Corvette Plant, a processing plant and compression facility attached to the Cowtown Pipeline, which was placed in service during the first quarter of 2009.
4. ACCOUNTS PAYABLE AND OTHER
     Accounts payable and other consists of the following:
                 
    December 31,  
    2008     2007  
    (in thousands)  
Accrued operating expenses
  $ 957     $ 882  
Accrued property taxes
          895  
State income taxes
          276  
Equity compensation payable
    116       275  
Interest payable
    734       147  
Other
    123       225  
 
           
 
  $ 1,930     $ 2,700  
 
           
5. LONG-TERM DEBT
     The following table summarizes our long-term debt payments due by period:
                                         
    Payments Due by Period  
Long-Term Debt   Total     2009     2010-2012     2013-2014     Thereafter  
                    (in millions)                  
Credit Agreement
  $ 174.9     $     $ 174.9     $     $  
Subordinated Note to Quicksilver
    53.6       1.4       3.3       48.9        
 
                             
Total long-term debt
  $ 228.5     $ 1.4     $ 178.2     $ 48.9     $  
 
                             
     Credit Agreement — On August 10, 2007, KGS entered into a five-year $150 million senior secured revolving credit facility (“Credit Agreement”). The Credit Agreement featured an accordion option that with lenders approval increases the facility up to $250 million. On October 10, 2008, the lenders approved an increase of the facility to $235 million. Also, the revised Credit Agreement permits the future expansion of the facility to $350 million, with lender approval. The facility, which matures August 10, 2012, can be extended up to two additional years with requisite lender consent.
     The Credit Agreement provides for revolving credit loans, swingline loans and letters of credit. Borrowings under the facility are guaranteed by KGS’ subsidiaries and are secured by substantially all of the assets of KGS and its subsidiaries. KGS has both LIBOR and U.S. prime rate options for revolving loans and a specified rate for swingline loans.

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     The Credit Agreement contains certain covenants which can limit KGS’ borrowing capacity. All of the covenants exclude the subordinated note payable to Quicksilver and KGS’ obligations to Quicksilver and related non-cash interest. These financial covenants are summarized below:
         
Quarters Ended   Maximum Debt to EBITDA   Minimum EBITDA to Interest
December 31, 2008 and thereafter
  4.50 to 1   2.50 to 1
     At December 31, 2008, the lenders’ commitments under our credit agreement were $235 million and may be further increased to as much as $350 million. Based on our results through December 31, 2008, our total borrowing capacity is $235 million and our borrowings were $174.9 million, and the weighted average interest rate was 2.9%. The Credit Agreement contains restrictive covenants that prohibit the declaration or payment of distributions by KGS if a default then exists or would result therefrom, and otherwise limits the amount of distributions that KGS can make. In the event of default, the Credit Agreement allows for the acceleration of the loans, the termination of the credit agreement and foreclosure on collateral.
     Subordinated Note — On August 10, 2007, KGS executed a subordinated promissory note (the “Subordinated Note”) payable to Quicksilver in the principal amount of $50.0 million.
     The Subordinated Note accrues interest based upon the rate applicable to borrowings under the Credit Agreement plus 1%, which is locked at the time of borrowing. The interest rate at December 31, 2008 was 4.485%. Accrued and unpaid interest is payable quarterly on the last business day of each calendar quarter, beginning on March 31, 2008, and on the Subordinated Note’s maturity date described below. Quarterly interest may be paid in cash or by adding it to the outstanding principal balance of the Subordinated Note. Subject to certain restrictions, quarterly installments of $275,000 are payable on the last business day of each calendar quarter. The final payment is due on February 10, 2013. However, if the maturity date of the Credit Agreement is extended, the maturity date of the Subordinated Note will also be automatically extended to the date that is six months after the revised Credit Agreement maturity date. Amounts payable under the Subordinated Note may at all times, at Quicksilver’s election, be paid, in whole or in part, using KGS units. The Subordinated Note contains events of default that permit, among other things, the acceleration of the debt (unless otherwise prohibited pursuant to the subordination provisions described below). Such events of default include, but are not limited to, payment defaults under the Subordinated Note, the breach of certain covenants after applicable grace periods and the occurrence of an event of default under the Credit Agreement.
     Amounts due under the Subordinated Note are subordinated in right of payment to all of our obligations under the Credit Agreement. KGS is precluded from making any payments under the Subordinated Note if any of the following events exist or would result as of the date of the proposed Subordinated Note payment:
    an event of default under the revolving credit agreement;
 
    the existence of a pending judicial proceeding with respect to any event of default under the revolving credit agreement; or
 
    our ratio of total indebtedness (which includes the $50.0 million Subordinated Note) to EBITDA as of the end of the fiscal quarter immediately preceding the date of such payment was equal to or greater than 3.5 or would be greater than 3.5 after consideration of such payment.
     Through December 31, 2008, we have made all scheduled quarterly interest payments at the end of each quarter by adding them to the principal of the Subordinated Note in accordance with its terms. Accordingly, interest expense of $2.8 million recognized during 2008 was added to the Subordinated Note. In 2008, we made three quarterly principal payments of the Subordinated Note for a total of $0.8 million. The fourth quarter principal payment was prevented by the indebtedness limitation on EBITDA described above.
6. ASSET RETIREMENT OBLIGATIONS
     The following table provides a reconciliation of the changes in the asset retirement obligation:

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    Year Ended December 31,  
    2008     2007  
    (in thousands)  
Beginning asset retirement obligations
  $ 2,793     $ 503  
Additional liability incurred
    2,257       2,207  
Accretion expense
    184       83  
 
           
Ending asset retirement obligations
  $ 5,234     $ 2,793  
 
           
     As of December 31, 2008, no assets are legally restricted for use in settling asset retirement obligations.
7. COMMITMENTS AND CONTINGENT LIABILITIES
     Litigation — In February 2009, McGuffy Energy Services, L.P. (“McGuffy”) filed a lawsuit against KGS and subsequently added Quicksilver as a party. McGuffy alleges, among other things, claims for breach of contract, fraud and negligent misrepresentation arising from a written agreement by which McGuffy was retained to provide certain engineering and construction services for KGS’ Corvette Plant. McGuffy further seeks to foreclose on a $3.2 million lien that it filed on the Corvette Plant. KGS disputes the amounts claimed by McGuffy and asserts a number of defenses to McGuffy’s claims, including that payments to McGuffy must be withheld as demanded by McGuffy’s unpaid subcontractors. In March 2009, KGS filed a lawsuit against McGuffy seeking damages and declaratory relief for the disputes between KGS and McGuffy. The McGuffy subcontractors that made demands on KGS were also named as parties. Several of the subcontractor defendants have filed counterclaims against KGS seeking to foreclose on their purported liens. Through March 31, 2009 KGS had recognized $2.0 million of the disputed amounts as a part of the Corvette Plant construction costs. KGS intends to vigorously defend this matter and does not expect its outcome to have a material adverse effect on our financial condition or results of operation.
     Casualties or Other Risks — Quicksilver maintains coverage in various insurance programs on KGS’ and KGSH’s behalf, which provides them with property damage, business interruption and other coverage’s which are customary for the nature and scope of their operations.
     Management of KGSH believes that there exists adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Quicksilver or KGSH may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. KGS maintains its own general partners’ liability insurance policy separate from the directors and officers policy maintained by Quicksilver.
     If KGSH were to incur a significant loss for which they were not fully insured, the loss could have a material impact on KGSH’s consolidated financial position and results of operations. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by KGSH, or which causes KGSH to make significant expenditures not covered by insurance, could reduce its ability to meet its financial obligations.
     Regulatory Compliance — In the ordinary course of business, KGSH is subject to various laws and regulations. In the opinion of management of the general partner, compliance with current laws and regulations will not have a material adverse effect on KGSH’ financial condition or results of operations.
     Environmental Compliance — The operation of pipelines, plants and other facilities is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, KGSH must comply with laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating KGSH’s facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2008, KGSH had no liabilities recorded for environmental matters.
     Commitments — KGSH, through KGS, has entered into agreements with third parties providing for natural gas compression equipment and the construction of the Corvette plant, which was placed in service during the first quarter of 2009.

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     The following table summarizes KGSH’s consolidated contractual obligations:
                                         
    Payments Due by Period  
Contractual Obligations   Total     2009     2010-2012     2013-2014     Thereafter  
                    (in millions)                  
Construction commitments
  $ 13.8     $ 13.8     $     $     $  
 
                             
Total contractual obligations
  $ 13.8     $ 13.8     $     $     $  
 
                             
8. INCOME TAXES
     No provision for federal income taxes related to KGSH’s results of operations is included in the consolidated financial statements as such income is taxable only by KGSH’s partners and their owners.
     Temporary differences relating to KGSH’ consolidated assets and liabilities will impact the provision for the Texas margin tax and a deferred tax liability has been recorded in the amount of $0.4 million and $0.2 million as of December 31, 2008 and 2007, respectively. KGSH derives all of its revenue from operations in Texas.
     During the third quarter of 2008, KGSH paid $0.3 million related to its 2007 liability for Texas margin tax. Quicksilver does not expect to owe consolidated Texas margin tax for 2008 and, accordingly, KGSH does not expect to make a cash payment for its 2008 liability for Texas margin tax, based upon Texas filing rules. All effects of the 2008 Texas margin tax calculation are captured in deferred income taxes.
9. EQUITY PLAN
     Awards of phantom units have been granted under KGS’ 2007 Equity Plan, which permits the issuance of up to 750,000 units. The following table summarizes information regarding the phantom unit activity:
                                 
    Payable in cash   Payable in units
            Weighted           Weighted
            Average           Average
            Grant Date           Grant Date
    Units   Fair Value   Units   Fair Value
Unvested phantom units — January 1, 2008
    84,961     $ 21.36       9,833     $ 21.36  
 
                               
Vested
    (28,247 )     21.43       (6,089 )     21.36  
Issued
    6,605       24.12       137,148       25.25  
Cancelled
    (3,000 )     21.36       (974 )     25.25  
 
                               
Unvested phantom units — December 31, 2008
    60,319     $ 21.63       139,918     $ 25.15  
 
                               
     At January 1, 2008, total unvested compensation cost was $1.9 million related to unvested phantom units. Compensation expense of approximately $1.4 million was recognized during 2008, including $0.4 million for remeasuring the vested portion of awards to be settled in cash to their revised fair value. Grants of phantom units during the year ended December 31, 2008 had an estimated grant date fair value of $3.6 million. Unearned compensation expense of $2.3 million at December 31, 2008 will be recognized in expense over the next 1.9 years. Phantom units that vested during the year ended December 31, 2008 had a fair value of $0.7 million on their vesting date.
10. MINORITY INTEREST AND DEFERRED GAIN ON SALE
     Minority Interest — As a result of the KGS IPO, the outside ownership of KGS increased and therefore consolidated KGS’ financial position and results of operations and recognized a minority interest liability for that portion of KGS that is owned by entities not affiliated with Quicksilver.
     Deferred Gain on sale of subsidiary equity — As a result of the KGS IPO, a deferred gain of approximately $79 million was recognized in the consolidated financial statements. The proceeds received from the IPO exceeded KGSH’s carrying value, which resulted in the gain. The absence of parity between the common and subordinated units prevents the culmination of the earnings process. KGSH deferred the gain until such time that the common units have equal standing to the units held by the public. The gain will be recognized when the subordination period ends and the equality of the shares are achieved.

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11. TRANSACTIONS WITH RELATED PARTIES
     Upon completion of, or in connection with, its IPO, KGS entered into a number of agreements with related parties. A description of those agreements follows:
     Omnibus Agreement — On August 10, 2007, KGS entered into an omnibus agreement (the “Omnibus Agreement”) with Quicksilver, which addresses, among other matters:
    restrictions on Quicksilver’s ability to engage in midstream business activities in Quicksilver Counties;
 
    Quicksilver’s construction of the Lake Arlington Dry System and the Hill County Dry System and the obligations to repurchase those assets from Quicksilver at their fair market value;
 
    Obligation to reimburse Quicksilver for all general and administrative expenses incurred by them on behalf of KGS; and
 
    Quicksilver’s obligation to provide cross-indemnification for certain liabilities.
     Secondment Agreement — On August 10, 2007, Quicksilver and KGS’ general partner entered into a services and secondment agreement (the “Secondment Agreement”) pursuant to which specified employees of Quicksilver have been seconded to KGS’ general partner to provide operating, routine maintenance and other services with respect to the assets owned or operated by KGS. Under the Secondment Agreement, the general partner reimburses Quicksilver for the services provided by the seconded employees. The initial term of the Secondment Agreement is 10 years, but will extend for additional annual periods unless cancelled by either party with 180 days’ written notice.
     Gas Gathering and Processing Agreement — On August 10, 2007, Quicksilver, Cowtown Gas Processing Partners LP (“Processing Partners”) and Cowtown Pipeline Partners LP (“Pipeline Partners”) together with Processing Partners (the “Cowtown Partnerships”) entered into the Fifth Amended and Restated Gas Gathering and Processing Agreement. In connection with the IPO, Processing Partners and Pipeline Partners became indirect wholly-owned subsidiaries of KGS. Under the Gas Gathering and Processing Agreement, Quicksilver has agreed, for an initial term of 10 years, to dedicate and deliver for processing all of the natural gas produced on properties operated by Quicksilver within the Quicksilver Counties. The dedication does not oblige Quicksilver to develop the reserves subject to the Gas Gathering and Processing Agreement.
     Effective September 1, 2008, Quicksilver and KGS entered into the Sixth Amended and Restated Gas Gathering and Processing Agreement, which amended the previous agreement by specifying that Quicksilver has agreed to pay $0.4163 per MMBtu gathered and $0.5204 per MMBtu processed and a compression fee of up to $0.30 per MMBtu on the Cowtown System. The compression fee payable by Quicksilver at a gathering system delivery point shall never be less than KGS’ actual cost to perform such compression service. Quicksilver may also pay KGS a treating fee based on carbon dioxide content at the pipeline entry point. The rates above are each subject to an annual inflationary escalation.
     If KGS determines that the gathering or processing of Quicksilver’s production becomes uneconomical, KGS may cease gathering and processing Quicksilver’s production as long as the uneconomical conditions exist. If KGS is unable to provide either gathering or processing services, Quicksilver may use other providers. If KGS is unable to provide either gathering or processing services for a period of 60 consecutive days, for reasons other than force majeure, causing Quicksilver’s wells to be shut-in (in the case of gathering) or resulting in Quicksilver’s inability to by-pass the Cowtown Plant and deliver its natural gas production to an alternative pipeline (in the case of processing), Quicksilver has the right to terminate the Gas Gathering and Processing Agreement as it relates to the affected gas.
     Absent written notice of termination, the Gas Gathering and Processing Agreement is automatically renewed for one year periods. In addition, if the Gas Gathering and Processing Agreement, or performance under this agreement, becomes subject to FERC jurisdiction, the agreement would be terminated unless both parties agree to continue the agreement.
     During the second quarter of 2008, KGS agreed to purchase land and a warehouse located in Hood County, Texas, from Quicksilver for a purchase price of $0.3 million and the reimbursement to Quicksilver of $0.6 million of costs. KGS also obtained additional easement rights for a total cost of $0.2 million from an affiliate of an entity that beneficially owns a small portion of KGS’ outstanding units.

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     Contribution, Conveyance and Assumption Agreement — On August 10, 2007 KGS entered into a contribution, conveyance, and assumption agreement (“Contribution Agreement”) with its general partner, certain other affiliates of Quicksilver and the private investors. The following transactions, among others, occurred just prior to the KGS IPO pursuant to the Contribution Agreement:
    the transfer of all of the interests of certain entities to KGS and its subsidiaries;
 
    the issuance of the incentive distribution rights to the general partner and the continuation of its 2% general partner interest in KGS;
 
    KGS’ issuance of 5,696,752 common units, 11,513,625 subordinated units and the right to receive $162.1 million, to Holdings in exchange for the contributed interests; and
 
    KGS’ issuance of 816,873 common units and the right to receive $7.7 million to private investors in exchange for their contributed interests.
     Centralized cash management — Prior to the IPO, revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of KGS Predecessor, are reflected as equity activity on the consolidated balance sheets and as a reduction of net cash provided by financing activities on the consolidated statements of cash flows. Subsequent to the KGS IPO, revenues settled and expenses paid on behalf of KGS are settled in cash on a monthly basis utilizing KGS bank accounts. As of December 31, 2008 revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of KGS, are reflected as a receivable from or a payable to Quicksilver on the consolidated balance sheets and as a reduction of net cash provided by or used by operating activities on the consolidated statements of cash flows.
     Services to affiliates — KGS routinely conducts business with Quicksilver and its affiliates. The related transactions result primarily from fee-based arrangements for gathering and processing of natural gas. Fees were determined based on fees to third parties and reflect the cost of providing such services. Quicksilver has engaged us to operate midstream assets owned by it for a monthly fee of $75,000.
     Allocation of costs — The individuals supporting KGS operations are employees of Quicksilver. The consolidated financial statements include costs allocated to KGS by Quicksilver for centralized general and administrative services performed by Quicksilver, as well as depreciation of assets utilized by Quicksilver’s centralized general and administrative functions. Costs allocated to KGS are based on identification of Quicksilver’s resources which directly benefit KGS and its estimated usage of shared resources and functions. All of the allocations are based on assumptions that management believes are reasonable.

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Report of Independent Registered Public Accounting Firm
To the Board of Directors of BreitBurn GP, LLC
and Unitholders of BreitBurn Energy Partners L.P.
In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“the Partnership”) at December 31, 2008, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 14 to the financial statements, the Partnership changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008.
/s/ PricewaterhouseCoopers LLP

Los Angeles, California
March 2, 2009

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BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Operations
For the Year Ended December 31, 2008
         
       
       
Thousands of dollars, except per unit amounts
Revenues and other income items:
       
Oil, natural gas and natural gas liquid sales
  $ 467,381  
Gains on commodity derivative instruments, net (note 14)
    332,102  
Other revenue, net (note 10)
    2,920  
 
     
Total revenues and other income items
    802,403  
Operating costs and expenses:
       
Operating costs
    149,681  
Depletion, depreciation and amortization (note 5)
    179,933  
General and administrative expenses
    43,435  
 
     
Total operating costs and expenses
    373,049  
 
     
 
       
Operating income
    429,354  
 
       
Interest and other financing costs, net
    29,147  
Loss on interest rate swaps (note 14)
    20,035  
Other income, net
    (191 )
 
     
 
       
Income before taxes and minority interest
    380,363  
 
       
Income tax expense (note 6)
    1,939  
Minority interest (note 19)
    188  
 
     
 
       
Net income
    378,236  
 
       
 
       
General Partner’s interest in net income (loss)
    (2,019 )
 
     
 
       
Limited Partners’ interest in net income
  $ 380,255  
 
     
 
       
Basic net income per unit (note 2)
  $ 6.42  
 
     
Diluted net income per unit (note 2)
  $ 6.28  
 
     
The accompanying notes are an integral part of these consolidated financial statements.

50


 

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheet
As of December 31, 2008
         
       
Thousands of dollars, except unit amounts
ASSETS
       
Current assets:
       
Cash
  $ 2,546  
Accounts receivable, net (note 2)
    47,221  
Derivative instruments (note 14)
    76,224  
Related party receivables (note 7)
    5,084  
Inventory (note 8)
    1,250  
Prepaid expenses
    5,300  
Intangibles (note 9)
    2,771  
Other current assets
    170  
 
     
Total current assets
    140,566  
Equity investments (note 10)
    9,452  
Property, plant and equipment
       
Oil and gas properties (note 4)
    2,057,531  
Non-oil and gas assets (note 4)
    7,806  
 
     
 
    2,065,337  
Accumulated depletion and depreciation (note 5)
    (224,996 )
 
     
Net property, plant and equipment
    1,840,341  
Other long-term assets
       
Intangibles (note 9)
    495  
Derivative instruments (note 14)
    219,003  
Other long-term assets
    6,977  
 
     
 
       
Total assets
  $ 2,216,834  
 
     
LIABILITIES AND PARTNERS’ EQUITY
       
Current liabilities:
       
Accounts payable
  $ 28,302  
Book overdraft
    9,871  
Derivative instruments (note 14)
    10,192  
Revenue distributions payable
    16,162  
Derivative settlements payable
    50  
Salaries and wages payable
    6,249  
Accrued liabilities
    9,164  
 
     
Total current liabilities
    79,990  
Long-term debt (note 11)
    736,000  
Deferred income taxes (note 6)
    4,282  
Asset retirement obligation (note 12)
    30,086  
Derivative instruments (note 14)
    10,058  
Other long-term liabilities
    2,987  
 
     
Total liabilities
    863,403  
Minority interest (note 19)
    539  
Partners’ equity (note 13)
       
Limited partners’ interest (a)
    1,352,892  
 
     
Total liabilities and partners’ equity
  $ 2,216,834  
 
     
 
       
(a) Limited partner units outstanding
    52,635,634  
The accompanying notes are an integral part of these consolidated financial statements.

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BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Cash Flows
For the Year Ended December 31, 2008
         
Thousands of dollars
Cash flows from operating activities
       
Net income
  $ 378,236  
Adjustments to reconcile net income to cash flow from operating activities:
       
Depletion, depreciation and amortization
    179,933  
Unit-based compensation expense
    6,907  
Unrealized gain on derivative instruments
    (370,734 )
Distributions greater than income from equity affiliates
    1,198  
Deferred income tax
    1,207  
Minority interest
    188  
Amortization of intangibles
    3,131  
Other
    2,643  
Changes in net assets and liabilities:
       
Accounts receivable and other assets
    258  
Inventory
    4,454  
Net change in related party receivables and payables
    32,688  
Accounts payable and other liabilities
    (13,413 )
 
     
Net cash provided by operating activities
    226,696  
 
     
Cash flows from investing activities
       
Capital expenditures
    (131,082 )
Property acquisitions
    (9,957 )
 
     
Net cash used by investing activities
    (141,039 )
 
     
Cash flows from financing activities
       
Purchase of common units
    (336,216 )
Distributions (1)
    (121,349 )
Proceeds from the issuance of long-term debt
    803,002  
Repayments of long-term debt
    (437,402 )
Book overdraft
    7,951  
Long-term debt issuance costs
    (5,026 )
 
     
Net cash used by financing activities
    (89,040 )
 
     
Decrease in cash
    (3,383 )
Cash beginning of period
    5,929  
 
     
Cash end of period
  $ 2,546  
 
     
 
(1)   Includes distributions on equivalent units of $2.3 million
The accompanying notes are an integral part of these consolidated financial statements.

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BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statement of Partners’ Equity
For the Year Ended December 31, 2008
                         
    Limited     General        
Thousands of dollars   Partners     Partner     Total  
Balance, January 1, 2008
  $ 1,423,418     $ 1,390     $ 1,424,808  
Redemption of common units from predecessors (a)
    (336,216 )           (336,216 )
Distributions
    (118,580 )     (427 )     (119,007 )
Distributions paid on unissued units under incentive plans
    (2,335 )     (7 )     (2,342 )
Unit-based compensation
    7,383             7,383  
Net income (loss) (b)
    380,255       (2,019 )     378,236  
Contribution of general partner interest to the partnership
    (1,063 )     1,063        
Other
    30             30  
 
                 
Balance, December 31, 2008
  $ 1,352,892     $     $ 1,352,892  
 
                 
 
(a)   Reflects the purchase of 14.405 million Common Units from subsidiaries of Provident.
 
(b)   General partner interests were purchased as of June 17, 2008.
The accompanying notes are an integral part of these consolidated financial statements.

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Notes to Consolidated Financial Statements
Note 1. Organization and Operations
     BreitBurn Energy Partners L.P.
     The Partnership is a Delaware limited partnership formed on March 23, 2006. In October 2006, we completed an initial public offering of 6,000,000 Common Units and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit, after deducting the underwriting discount. On May 24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets located in Florida from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility. On May 25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were used to acquire a 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) from TIFD X-III LLC which owned interests in the Sawtelle and East Coyote oil fields located in California, and to terminate existing hedges related to future production from BEPI. On November 1, 2007, we sold 16,666,667 Common Units in a private placement at $27.00 per unit, resulting in proceeds of approximately $450 million. The net proceeds from this private placement were used to fund a portion of the cash consideration for our acquisition from Quicksilver of properties located in Michigan, Indiana and Kentucky (the “Quicksilver Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.
     Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BOLP and BOLP’s general partner BOGP. We own all of the ownership interests in BOLP and BOGP.
     Our wholly owned subsidiary BreitBurn Management manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 7 for information regarding our relationship with BreitBurn Management.
     On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million (the “Common Unit Purchase”). These units have been cancelled and are no longer outstanding. This purchase was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. It increased debt by $336.2 million and decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs.
     On June 17, 2008, we also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of approximately $10 million (the “BreitBurn Management Purchase”). See Note 4 for the purchase price allocation for this transaction. Also on June 17, 2008, we entered into a contribution agreement (the “Contribution Agreement”) with the General Partner, BreitBurn Management and BreitBurn Corporation, which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45 percent interest in BreitBurn Management, and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners holding Common Units were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner. As a result of these transactions (collectively, the “Purchase, Contribution and Partnership Transactions”), the General Partner and BreitBurn Management became our wholly owned subsidiaries.
     On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into the First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.
     On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects.
     As of December 31, 2008, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the Common Units. BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent limited partner interest. We own 100 percent of the General Partner, BreitBurn Management and BOLP.

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     On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident, and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of the our senior management. BEC was a separate U.S. subsidiary of Provident and was our Predecessor.
     In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management has entered into a five-year Administrative Services Agreement to manage BEC’s properties. In addition, we have entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.
2. Summary of Significant Accounting Policies
Principles of consolidation
     The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20 percent or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20 percent ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50 percent interest are consolidated. Investments in which we own less than a 50 percent interest but are deemed to have control or where we have a variable interest in an entity where we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.
Use of estimates
     The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.
     We account for business combinations using the purchase method, in accordance with SFAS No. 141 Accounting for Business Combinations. We use estimates to record the assets and liabilities acquired. All purchase price allocations are finalized within one year from the acquisition date.
Basis of Presentation
     Our financial statements are prepared in conformity with U.S. generally accepted accounting principles.
Business segment information
     SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, establishes standards for reporting information about operating segments. Segment reporting is not applicable because our oil and gas operating areas have similar economic characteristics and meet the criteria for aggregation as defined in SFAS No. 131. We acquire, exploit, develop and explore for and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.
Revenue recognition
     Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (“entitlement” method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.

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Cash and cash equivalents
     We consider all investments with original maturities of three months or less to be cash equivalents. At December 31, 2008 we had no such investments.
Accounts Receivable
Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. During 2008 we terminated our crude oil derivative instruments with Lehman Brothers due to their bankruptcy, and at December 31, 2008, we had an allowance of $4.6 million related to these contracts.
Inventory
     Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.
Investments in Equity Affiliates
     Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.
Property, plant and equipment
Oil and gas properties
     We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred, including internal acquisition costs, relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.
     Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization (“DD&A”) are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are computed on a property-by-property basis and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.
Non-oil and gas assets
     Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from 3 to 30 years.
Oil and natural gas reserve quantities
     Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.
Asset retirement obligations
     We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The computation of our asset retirement obligations (“ARO”) is prepared in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO

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estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.
Impairment of assets
     Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5 percent. For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately ten percent. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Because of the low commodity prices that existed at year end 2008, and the uncertainty surrounding future commodity prices and costs, we performed impairment tests on our long-lived assets at December 31, 2008.
     We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. In 2008, we recorded $51.9 million in impairments and $34.5 million in price related depletion and depreciation adjustments. See Note 5 — Impairments and Price Related Depletion and Depreciation Adjustments. The charge was included in DD&A on the consolidated statement of operations.
Debt issuance costs
     The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.
Equity-based compensation
     BreitBurn Management had various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 15.
     Effective January 1, 2006, the Predecessor adopted the fair value recognition provisions of SFAS No. 123 (revised 2004) (SFAS No. 123(R)), Share Based Payments, using the modified-prospective transition method. Under this transition method, unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities are charged to compensation expense based on the fair value provisions of SFAS No. 123(R). We and the Predecessor recognized these compensation costs on a graded-vesting method. Under the graded-vesting method a company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards.
     Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.
Fair market value of financial instruments
     The carrying amount of our cash, accounts receivable, accounts payable, and accrued expenses, approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt approximates fair value; however, changes in the credit markets at year-end may impact our ability to enter into future credit facilities at similar terms.
Accounting for business combinations
     We have accounted for all business combinations using the purchase method, in accordance with SFAS No. 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and

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liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. We have not recognized any goodwill from any business combinations.
Concentration of credit risk
We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings.
Derivatives
     SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets or liabilities in our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income, to the extent the hedge is effective, until the hedged item is recognized in earnings. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS No.133, is recognized immediately in earnings. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. We currently do not designate any of our derivatives as hedges for accounting purposes.
     Effective January 1, 2008, we adopted SFAS No. 157,“Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability. The objective of fair value measurement as defined in SFAS No. 157 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.
Income taxes
     Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.
     We have three wholly owned subsidiaries, which are subject to corporate income taxes. We account for the taxes associated with one entity in accordance with SFAS No. 109, “Accounting for Income Taxes.” Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.
     Effective January 1, 2007, we implemented FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.
     We performed an evaluation as of December 31, 2008 and concluded that there were no uncertain tax positions requiring recognition in the financial statements. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

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Net Income per unit
     Weighted average units outstanding for computing basic and diluted net income per unit were:
         
    Year Ended  
    December 31,  
    2008  
Weighted average number of Common Units used to calculate basic and diluted net income or loss per unit:
       
Basic
    59,238,588  
Dilutive
    1,322,107  
 
     
Diluted
    60,560,695  
 
     
We had 6,700,000 Common Units authorized for issuance under our long-term incentive compensation plans and there were approximately 1,422,171 partnership-based units outstanding that are eligible for receiving Common Units upon vesting at December 31, 2008.
Environmental expenditures
     We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. At December 31, 2008, we had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which we assumed in the Quicksilver Acquisition.
3. Accounting Pronouncements
     SFAS No. 157, Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 12, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. Effective January 1, 2008, we adopted SFAS No. 157, as amended by FSP 157-2. Adoption of SFAS No. 157 did not have a material impact on our results from operations or financial position.
     SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115” (“SFAS No. 159”). In February 2007, the FASB issued SFAS No. 159 which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS No. 159 became effective for us on January 1, 2008. We have elected not to adopt the fair value option allowed by SFAS No. 159, and, therefore, it had no impact on our financial position, results from operations or cash flows.
SFAS No. 141(revised 2007) “Business Combinations” (“SFAS No. 141R”). In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141R was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141R also impacts the goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141R. The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141R is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141R.

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     SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS No. 160”). In December 2007, the FASB issued SFAS No. 160 which requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS No. 160 is not expected to have a material impact on our results from operations or financial position.
     SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS No. 161”). In March 2008, the FASB issued SFAS No. 161 which requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 has the same scope as Statement 133, and, accordingly, applies to all entities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This statement will require the additional disclosures detailed above.
     FSP 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”). In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combination” and other U.S. generally accepted accounting principles. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of FSP 142-3 to have a material impact on our financial position, results of operations or cash flows.
     SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). In May 2008, the FASB issued SFAS No. 162 which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). SFAS No. 162 became effective November 13, 2008. The adoption of SFAS No. 162 did not have an impact on our results from operations or financial position.
     FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). In June 2008, the FASB issued FSP EITF 03-6-1. Under this FSP, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. We are currently evaluating the impact adoption of FSP EITF 03-6-1 may have on our earnings per share disclosures.
     On December 31, 2008, the SEC issued Release No. 33-8995 for guidelines on new reserves estimate calculations and related disclosures. The new reserve estimate disclosures apply to all annual reports for fiscal years ending on or after December 31, 2009 and thereafter, and to all registration statements filed after that date. It does not permit companies to voluntarily comply at an earlier date. The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90 percent recovery probability for probabilistic methods used in estimating proved reserves. The guideline also permits a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well. For reserve reporting purposes, it also replaces the end-of-the-year oil and gas reserve pricing with an unweighted average first-day-of-the-month pricing for the past 12 fiscal months. This would impact depletion calculations. Costs associated with reserves will continue to be measured on the last day of the fiscal year. A revised tabular presentation of reserves by development category, final product type, and oil and gas activity disclosure by geographic regions and significant fields and a general disclosure of the internal controls a company uses to assure objectivity in reserves estimation will be required. The adoption of SEC release No. 33-8995 is expected to have a material impact, which cannot be quantified at this point, on the calculation of our crude oil and natural gas reserves.

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4. Acquisitions
On June 17, 2008, we purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management for a purchase price of approximately $10.0 million. This transaction resulted in BreitBurn Management becoming our wholly owned subsidiary and was accounted for as a business combination. The following table presents the purchase price allocation of the BreitBurn Management Purchase:
         
Thousands of dollars
Related party receivables — current, net
  $ 10,662  
Other current assets
    21  
Oil and gas properties
    8,451  
Non-oil and gas assets
    4,343  
Related party receivables — non-current
    6,704  
Current liabilities
    (13,510 )
Long-term liabilities
    (6,704 )
 
     
 
  $ 9,967  
 
     
     Certain of the current and long-term related party receivables are with the Partnership, so they are now eliminated in consolidation.
5. Impairments and Price Related Depletion and Depreciation Adjustments
Because of the low commodity prices at year end 2008, and the uncertainty surrounding future commodity prices as well as future costs, we performed impairment tests on our long-lived assets at December 31, 2008. For the year ended December 31, 2008, we recorded approximately $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense.
We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.
Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. The impairment reviews and calculations are based on assumptions that are consistent with our business plans. See “Impairment of Assets” in Note 2. The low commodity price environment that existed at December 31, 2008 influenced our future commodity price projections. As a result, the expected discounted cash flows for many of our fields (i.e., fair values) were negatively impacted resulting in a charge to depletion and depreciation expense of approximately $51.9 million for field impairments for the year ended December 31, 2008.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.
Lower commodity prices also negatively impacted our oil and gas reserves in the fourth quarter of 2008 resulting in significant price related adjustments to our depletion and depreciation expense in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These price

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related reserve reductions in 2008 resulted in additional depletion and depreciation charges of approximately $34.5 million for the fourth quarter and for the year ended December 31, 2008.
6. Income Taxes
     We, and all of our subsidiaries, with the exception of Phoenix Production Company, Alamitos Company and BreitBurn Management, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities. State income tax expenses are recorded for certain operations that are subject to state taxation in various states, primarily Michigan, California and Texas. The total state taxes paid were $0.5 million in 2008.
     Our wholly-owned subsidiary, Phoenix Production Company, is a tax-paying corporation. We record an income tax provision in accordance with SFAS No. 109 “Accounting for Income Taxes.” In 2008, Phoenix Production Company recorded $0.1 million for alternative minimum taxes. Phoenix Production Company also recorded a deferred federal income tax expense of $1.2 million in 2008. The following is a reconciliation for Phoenix Production Company of federal income taxes at the statutory rates to federal income tax expense or benefit as reported in the consolidated statements of operations.
         
    Year Ended  
    December 31,  
Thousands of dollars   2008  
Income  before taxes and minority interest
  $ 380,363  
Partnership income not subject to tax
    376,459  
 
     
Income subject to tax
    3,904  
Federal income tax rate
    34  
 
     
Income tax at statutory rate
    1,327  
Other
     
 
     
Income tax expense
  $ 1,327  
 
     
     At December 31, 2008, a net deferred federal income tax liability of $4.3 million was included in our consolidated balance sheet for Phoenix Production Company. As shown in the table below, the net deferred federal income tax liability primarily consisted of the tax effect of book and tax basis differences of certain assets and liabilities and the deferred federal income tax asset for net operating loss carry forwards. Management expects to utilize $2.3 million of estimated unused operating loss carry forwards to offset future taxable income. As such, no valuation allowance has been recorded against the deferred federal income tax asset.
         
    December 31,  
Thousands of dollars   2008  
Deferred tax assets:
       
Net operating loss carryforwards
  $ 767  
Asset retirement obligation
    337  
Unrealized hedge loss
     
Other
    103  
Deferred tax liabilities:
       
Depreciation, depletion and intangible drilling costs
    (3,404 )
Other
    (2,085 )
 
     
Net deferred tax liability
  $ (4,282 )
 
     
     In 2008, our other wholly-owned tax-paying corporation, Alamitos Company, incurred a current federal tax expense of $0.1 million. No deferred federal or state income tax is recognized for this company as the temporary differences between the tax basis and the reported financial amounts of its assets and liabilities are immaterial. BreitBurn Management became our wholly-owned subsidiary and a taxable entity on June 17, 2008. However, no federal or state income tax expense is expected due to the nature of its business as expenses incurred are essentially offset by amounts recovered for services provided to the operating companies.
     Cash paid for federal and state income taxes was $0.6 million in 2008.

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New Accounting Pronouncement
     Effective January 1, 2007, we implemented FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.
     We performed an evaluation as of December 31, 2008 and concluded that there were no uncertain tax positions requiring recognition in the financial statements. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.
7. Related Party Transactions
     BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of the costs charged to BOLP are consolidated with our results.
     On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark, Greenhill and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. BEC was an indirectly owned subsidiary of Provident.
     In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five year Administrative Services Agreement to manage BEC’s properties. The monthly fee charged to BEC remained $775,000 for indirect expenses through December 31, 2008. We expect this fee to be renegotiated annually during the term of the agreement and expect a monthly fee of less than $775,000 in 2009. In addition, we have entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.
     At December 31, 2008, we had current receivables of $4.4 million due from BEC related to the Administrative Services Agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties. In 2008, total oil and gas sales made on our behalf for these properties were approximately $2.1 million.
     Mr. Greg L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner until March 26, 2008 when his resignation became effective. We sell all of the crude oil produced from our Florida properties to Plains Marketing, L.P., a wholly owned subsidiary of PAA. In 2008, prior to Mr. Armstrong’s resignation on March 26, 2008, we sold $19.3 million of our crude oil to Plains Marketing, L.P.
     Through a transition services agreement through March 2008, Quicksilver provided services to us for accounting, land administration, and marketing and charged us $0.9 million for the first three months of 2008. These charges were included in general and administrative expenses on the consolidated statements of operations. Quicksilver also buys natural gas from us in Michigan. For the year ended

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December 31, 2008, total net gas sales to Quicksilver were approximately $8.0 million and the related receivable was $0.6 million as of December 31, 2008.
     At December 31, 2008, we had a receivable of $0.1 million for management fees due from equity affiliates and operational expenses incurred on behalf of equity affiliates.
     On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects and Provident is no longer considered a related party.
8. Inventory
     Our crude oil inventory from our Florida operations at December 31, 2008 was $1.3 million. For the year ended December 31, 2008, we sold 762 MBbls of crude oil and produced 707 MBbls from our Florida operations. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.
     We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. During the fourth quarter of 2008, commodity prices decreased substantially. As a result, we assessed our crude oil inventory for possible write-down, and recorded $1.2 million to write-down the Florida crude oil inventory to our net realizable value at December 31, 2008.
     For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.
9. Intangibles
     In May 2007, we acquired certain interests in oil leases and related assets through the acquisition of a limited liability company from Calumet Florida, L.L.C. As part of this acquisition, we assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. A $3.4 million intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation. Realized gains or losses from these contracts are recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts. As of December 31, 2008, our intangible asset related to the crude oil sales contracts was $1.6 million.
     In November 2007, we acquired oil and gas properties and facilities from Quicksilver. Included in the Quicksilver purchase price was a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, we entered into an agreement with Quicksilver which provides for Quicksilver to fund retention bonuses payable to 139 former Quicksilver employees in the event these employees remain continuously employed by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death. The amortization expense of $2.1 million for 2008 is included in the total operating expenses line on the consolidated statement of operations. As of December 31, 2008, our intangible asset related to Quicksilver retention bonuses was $1.7 million.
10. Equity Investments
     We had equity investments at December 31, 2008 of $9.5 million. These investments are reported in the “Equity investments” line caption on the consolidated balance sheet and primarily represent investments in natural gas processing facilities. For the year ended December 31, 2008, we recorded $0.8 million in earnings from equity investments. Earnings from equity investments are reported in the “Other Revenue” line caption on the consolidated statement of operations.
     At December 31, 2008, our equity investments consisted primarily of a 24.5 percent limited partner interest and a 25.5 percent general partner interest in Wilderness Energy Services LP, with a combined carrying value of $8.2 million. The remaining $1.3 million consists of smaller interests in several other investments.

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11. Long-Term Debt
     On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into a four year, $1.5 billion amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the “Amended and Restated Credit Agreement”).
     The initial borrowing base of the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008. Under the Amended and Restated Credit Agreement, borrowings were allowed to be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition, (ii) for standby letters of credit, (iii) for working capital purposes, (iv) for general company purposes and (v) for certain permitted acquisitions and payments enumerated by the credit facility. Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of the Partnership’s and certain of its subsidiaries’ assets, representing not less than 80 percent of the total value of their oil and gas properties.
     The Amended and Restated Credit Agreement contains (i) financial covenants, including leverage, current assets and interest coverage ratios, and (ii) customary covenants, including restrictions on the Partnership’s ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of its borrowing base; make dispositions; or enter into a merger or sale of its property or assets, including the sale or transfer of interests in its subsidiaries.
     The events that constitute an Event of Default (as defined in the Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against the Partnership in excess of a specified amount; changes in management or control; loss of permits; failure to perform under a material agreement; certain insolvency events; assertion of certain environmental claims; and occurrence of a material adverse effect. At December 31, 2008, the Partnership was in compliance with the credit facility’s covenants.
     On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent (the “Agent”). Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement, from $750 million to $900 million. In addition, Amendment No. 1 to the Credit Agreement enacted certain additional amendments, waivers and consents to the Amended and Restated Credit Agreement and the related Security Agreement, dated November 1, 2007, among BOLP, certain of its subsidiaries and the Agent, necessary to permit the Amendment No. 1 to the First Amended and Restated Limited Partnership Agreement and the transactions consummated in the Purchase, Contribution and Partnership Transactions. Under Amendment No. 1 to the Credit Agreement, the interest margins applicable to borrowings, the letter of credit fee and the commitment fee under the Amended and Restated Credit Agreement were increased by amounts ranging from 12.5 to 25 basis points.
     As of December 31, 2008, approximately $736.0 million in indebtedness was outstanding under the Amended and Restated Credit Agreement. The credit facility will mature on November 1, 2011. At December 31, 2008, the LIBOR interest rate, a weighted average interest rate of our four outstanding LIBOR loans, was 2.350 percent on the LIBOR portion of $736.0 million.
     The credit facility contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders (including the restriction in our ability to make distributions if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.
     As of December 31, 2008, we were in compliance with the credit facility’s covenants. At December 31, 2008, we had $0.3 million in letters of credit outstanding.

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     Our interest expense is detailed in the following table:
         
    Year Ended  
    December 31,  
Thousands of dollars   2008  
Credit facility
  $ 25,487  
Commitment fees
    1,047  
Amortization of discount and deferred issuance costs
    2,613  
 
     
Total
  $ 29,147  
Cash paid for interest on Credit facility (including realized losses on interest rate swaps)
  $ 29,767  
12. Asset Retirement Obligation
     Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities as well as our estimate of the future timing of the costs to be incurred. The total undiscounted amount of future cash flows required to settle our asset retirement obligations is estimated to be $256.8 million at December 31, 2008. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from 7 to 50 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 7 percent and adjusted for inflation using a rate of 2 percent. Changes in the asset retirement obligation for the year ended December 31, 2008 are presented in the following table:
         
    Year Ended December 31,  
Thousands of dollars   2008  
Carrying amount, beginning of period
  $ 27,819  
Liabilities settled in the current period
    (1,054 )
Revisions (1)
    1,363  
Acquisitions
     
Accretion expense
    1,958  
 
     
 
Carrying amount, end of period
  $ 30,086  
 
     
 
(1)   Increased cost estimates and revisions to reserve life.
13. Partners’ Equity
     At December 31, 2008, we had 52,635,634 Common Units outstanding.
     On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million. These units have been cancelled and are no longer outstanding. This transaction was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. This transaction decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs. We also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner. Also on June 17, 2008, we entered into a Contribution Agreement with the General Partner, BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated. As a result of these transactions, the General Partner and BreitBurn Management became our wholly owned subsidiaries.
     On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent. Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.

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     The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable. The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.
     The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.
     Cash Distributions
     The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.
     Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.
     Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.
     We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.
     On February 14, 2008, we paid a cash distribution of approximately $30.5 million to our General Partner and common unitholders of record as of the close of business on February 11, 2008. The distribution that was paid to unitholders was $0.4525 per Common Unit.
     On May 15, 2008, we paid a cash distribution of approximately $33.7 million to our General Partner and common unitholders of record as of the close of business on May 9, 2008. The distribution that was paid to unitholders was $0.50 per Common Unit.
     On August 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on August 11, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.
     On November 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on November 10, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.
     During the year ended December 31, 2008, we made payments equivalent to the distributions made to unitholders of $2.3 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.
     2007 Private Placements
     On May 24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”). We used $108 million from such sale to fund the cash consideration for the Calumet Acquisition and the remaining $22 million of the proceeds was used to repay indebtedness under our credit facility. Most of the debt repaid was associated with our first quarter 2007 acquisition of the Lazy JL Field properties in West Texas.

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     On May 25, 2007, we sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit. We used the proceeds of approximately $92 million to fund the BEPI Acquisition, including the termination of existing hedge contracts related to future production from BEPI.
     On November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors in a third private placement. We used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition. Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.
     In connection with the private placements of Common Units to finance the Quicksilver Acquisition, we entered into registration rights agreements with the institutional investors in our private placements and Quicksilver to file shelf registration statements to register the resale of the Common Units sold or issued in the Private Placements and to use our commercially reasonable efforts to cause the registration statements to become effective with respect to the Common Units sold to the institutional investors not later than August 2, 2008 and, with respect to the Common Units issued to Quicksilver, within one year from November 1, 2007. Quicksilver is prohibited from selling any of the Common Units issued to it prior to the first anniversary of November 1, 2007 or more than 50 percent of such Common Units prior to eighteen months after November 1, 2007. In addition, the agreements give the institutional investors and Quicksilver piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the institutional investors and Quicksilver and, in certain circumstances, to third parties.
     On July 31, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to the institutional investors was declared effective. On October 28, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to Quicksilver was declared effective.
14. Financial Instruments
Fair Value of Financial Instruments
     Our commodity price risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flow and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. During 2008, there has been extreme volatility and disruption in the capital and credit markets which has reached unprecedented levels and may adversely affect the financial condition of our derivative counterparties. Although each of our derivative counterparties carried an S&P credit rating of A or above at December 31, 2008, we could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.
     Commodity Activities
     The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under SFAS No. 133. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges and instead recognize changes in the fair value immediately in earnings. For the year ended December 31, 2008 we had realized losses of $55.9 million and unrealized gains of $388.0 million relating to our market based commodity contracts. We had net financial instruments receivable relating to our commodity contracts of $292.3 million at December 31, 2008.
     On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude oil derivative instruments with Lehman Brothers. Our derivative contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was for oil volumes of 1,000 Bbls/d for the full year 2011. This represented approximately 8 percent of our total 2011 oil and natural gas hedge portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling price was $174.50 per Bbl. This contract was replaced with contracts by substantially similar terms, with different counterparties, for oil volumes of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011 to December 31, 2011.

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     We had the following contracts in place at December 31, 2008:
                                 
    Year   Year   Year   Year
    2009   2010   2011   2012
Gas Positions:
                               
Fixed Price Swaps:
                               
Hedged Volume (MMBtu/d)
    45,802       43,869       25,955       19,129  
Average Price ($/MMBtu)
  $ 8.14     $ 8.20     $ 9.21     $ 10.12  
Collars:
                               
Hedged Volume (MMBtu/d)
    1,740       3,405       16,016       19,129  
Average Floor Price ($/MMBtu)
  $ 9.00     $ 9.00     $ 9.00     $ 9.00  
Average Ceiling Price ($/MMBtu)
  $ 16.36     $ 12.79     $ 11.28     $ 11.89  
Total:
                               
Hedged Volume (MMMBtu/d)
    47,542       47,275       41,971       38,257  
Average Price ($/MMBtu)
  $ 8.17     $ 8.26     $ 9.13     $ 9.56  
 
                               
Oil Positions:
                               
Fixed Price Swaps:
                               
Hedged Volume (Bbls/d)
    1,838       2,308       2,116       1,939  
Average Price ($/Bbl)
  $ 75.51     $ 83.12     $ 88.26     $ 90.00  
Participating Swaps: (a)
                               
Hedged Volume (Bbls/d)
    2,847       1,993       1,439        
Average Price ($/Bbl)
  $ 62.86     $ 64.40     $ 61.29     $  
Average Part. %
    60.9 %     55.5 %     53.2 %      
Collars:
                               
Hedged Volume (Bbls/d)
    594       1,279       2,048       3,077  
Average Floor Price ($/Bbl)
  $ 92.31     $ 102.84     $ 103.43     $ 110.00  
Average Ceiling Price ($/Bbl)
  $ 122.92     $ 136.16     $ 152.61     $ 145.39  
Floors:
                               
Hedged Volume (Bbls/d)
    500       500              
Average Floor Price ($/Bbl)
  $ 100.00     $ 100.00     $     $  
Total:
                               
Hedged Volume (Bbls/d)
    5,778       6,080       5,603       5,016  
Average Price ($/Bbl)
  $ 73.12     $ 82.52     $ 86.88     $ 102.27  
 
(a)   A participating swap combines a swap and a call option with the same strike price.
Interest Rate Activities
     We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of December 31, 2008, our total debt outstanding was $736.0 million. In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2008, to fix a portion of floating LIBOR-base debt on our credit facility:
                 
Notional amounts in thousands of dollars   Notional Amount   Fixed Rate
Period Covered
               
January 1, 2009 to January 8, 2009
  $ 50,000       3.6200 %
January 1, 2009 to January 20, 2009
    200,000       3.6825 %
January 1, 2009 to July 8, 2009
    50,000       3.0450 %
January 1, 2009 to January 8, 2010
    100,000       3.3873 %
January 20, 2009 to July 20, 2009
    250,000       3.6825 %
July 20, 2009 to December 20, 2010
    300,000       3.6825 %
December 20, 2010 to October 20, 2011
    200,000       2.9900 %

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     On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no cost, our interest rate swap with Lehman Brothers on $50 million at a fixed rate of 3.438 percent, which covered the period from January 8, 2008 to July 8, 2009. On October 2, 2008, we entered into a new interest rate swap on $50 million at a fixed rate of 3.0450 percent, for the period from September 8, 2008 to July 8, 2009. These transactions are reflected in the table above.
     For the year ended December 31, 2008, we had realized losses of $2.7 million and unrealized losses of $17.3 million relating to our interest rate swaps. We had net financial instruments payable related to our interest rate swaps of $17.3 million at December 31, 2008.
     Balance Sheet presentation of commodity and interest derivatives is as follows:
                                 
    Oil     Natural Gas              
    Commodity     Commodity     Interest Rate     Total Financial  
Thousands of dollars   Derivatives     Derivatives     Derivatives     Instruments  
Balance, December 31, 2008
                               
Short-term assets
  $ 44,086     $ 32,138     $     $ 76,224  
Long-term assets
    145,061       73,942             219,003  
 
                       
Total assets
    189,147       106,080             295,227  
 
                               
Short-term liabilities
    (1,115 )           (9,077 )     (10,192 )
Long-term liabilities
    (1,820 )           (8,238 )     (10,058 )
 
                       
Total liabilities
    (2,935 )           (17,315 )     (20,250 )
 
                       
 
                               
Net assets (liabilities)
  $ 186,212     $ 106,080     $ (17,315 )   $ 274,977  
 
                       
     While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.
     Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability. The objective of fair value measurement as defined in SFAS No. 157 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.
     SFAS No. 157 requires valuation techniques consistent with the market approach, income approach or the cost approach to be used to measure fair value. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future cash flows or earnings to a single present value amount and is based upon current market expectations about those future amounts. The cost approach, sometimes referred to as the current replacement cost approach, is based upon the amount that would currently be required to replace the service capacity of an asset.
     We principally use the income approach for our recurring fair value measurements and strive to use the best information available. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements.
     SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 is given to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs as defined in SFAS No. 157 are described further as follows:
     Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are markets in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. An example of a Level 1 input would be quoted prices for exchange traded commodity futures contracts.
     Level 2 — Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. These models include industry standard models that consider standard assumptions

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such as quoted forward prices for commodities, interest rates, volatilities, current market and contractual prices for underlying assets as well as other relevant factors. Substantially all of these inputs are evident in the market place throughout the terms of the financial instruments and can be derived by observable data, including third party data providers. These inputs may also include observable transactions in the market place. We consider the over the counter (OTC) commodity and interest rate swaps in our portfolio to be Level 2. These are assets and liabilities that can be bought and sold in active markets and quoted prices are available from multiple potential counterparties.
     Level 3 — Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. These inputs generally reflect management’s estimates of the assumptions market participants would use when pricing the instruments. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Level 3 instruments primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Level 3 also includes complex structured transactions that sometimes require the use of non-standard models.
     Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. We include these assets and liabilities in Level 3 as required by current interpretations of SFAS 157. As of December 31, 2008, our Level 3 assets and liabilities consisted entirely of OTC commodity put and call options.
     Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of Level 2 criteria is modified in practice to include non-binding market corroborated data.
     As mentioned in Note 7, our wholly owned subsidiary BreitBurn Management provides us with general management services, including risk management activities. Pursuant to a transition services agreement that terminated on December 31, 2008, BreitBurn Management contracted with Provident for the risk management services provided to us.
     Provident’s risk management group calculated the fair values of our commodity swaps using risk management software that marks to market monthly fixed price delivery swap volumes using forward commodity price curves and market interest rates. This pricing approach is commonly used by market participants to value commodity swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., NYMEX).
     Fair value measurements for our interest rate swaps were also provided by Provident. Monthly outstanding notional amounts are marked to market for each specific swap using forward interest rate curves. This pricing approach is commonly used by market participants to value interest rate swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., LIBOR).
     Provident’s risk management group used industry standard option pricing models contained in their risk management software to calculate the fair values associated with our commodity options. Inputs to the option pricing models included fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs were obtained from third party data providers and are verified to published data where available (e.g., NYMEX).
     We reviewed the fair value calculations for our derivative instruments that we received from Provident’s risk management group on a monthly basis. We also compared these fair value amounts to the fair value amounts that we receive from the counterparties to our derivative instruments. We investigated differences and resolved and recorded any required changes prior to the issuance of our financial statements.
     Financial assets and liabilities carried at fair value on a recurring basis are presented in the table below. Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are categorized.
     Recurring fair value measurements were:
                                 
    As of December 31, 2008  
Thousands of dollars   Level 1     Level 2     Level 3     Total  
Assets (Liabilities):
                               
Commodity Derivatives (swaps, put and call options)
  $     $ 139,074     $ 153,218     $ 292,292  
Other Derivatives (interest rate swaps)
          (17,315 )           (17,315 )
 
                       
Total
  $     $ 121,759     $ 153,218     $ 274,977  
 
                       

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     The following table sets forth a reconciliation of our derivative instruments classified as Level 3:
         
    Year Ended  
Thousands of dollars   December 31, 2008  
Assets (Liabilities):
       
Beginning balance
  $ 44,236  
Realized and unrealized gains, net
    106,154  
Purchases and issuances
    7,452  
Settlements
    (4,624 )
 
     
Balance at December 31, 2008
  $ 153,218  
 
     
Following the termination of the Lehman Brothers interest rate swap and crude oil zero cost collar, we entered into similar contracts with other counterparties. Our net cost to replicate the terminated Lehman contracts was $4.2 million and we have recorded a provision related to the contract default in 2008. We have a claim of approximately $4.6 million in the Lehman bankruptcy case relating to the terminations.
Unrealized gains of $112.2 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are included in gains on commodity derivative instruments, net on the consolidated statements of operations. Realized losses of $6.0 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are also included in gains on commodity derivative instruments, net on the consolidated statements of operations. Determination of fair values incorporates various factors as required by SFAS No. 157 including but not limited to the credit standing of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities.
15. Unit and Other Valuation-Based Compensation Plans
BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of BMC’s costs that were not charged to BEC are consolidated with our results.
     Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. We were managed by our General Partner, the executive officers of which were and are employees of BreitBurn Management. We had entered into an Administrative Services Agreement with BreitBurn Management. Under the Administrative Services Agreement, we reimbursed BreitBurn Management for all direct and indirect expenses it incurred in connection with the services it performed on our behalf (including salary, bonus, certain incentive compensation and other amounts paid to executive officers and other employees).
     Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.
     We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, its termination by us.

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Unit Based Compensation
     Effective January 1, 2006, our predecessor adopted the fair value recognition provisions of SFAS No. 123(R), Share-Based Payments , using the modified-prospective transition method. BreitBurn Management as successor is following the same method as BEC, our predecessor. Unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). For the liability-based plans, we recognize these compensation expenses on a graded-vesting method. Under the graded-vesting method, a company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. For our RPU and CPU equity-based plans, we recognize our compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.
     Awards classified as liabilities are revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period(s). Option awards outstanding at the end of 2008 are liability-classified because the awards are settled in cash or have the option of being settled in cash or units at the choice of the holder, and they are indexed to either our Common Units or to Provident Trust Units. The liability-classified option awards are distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders receive cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units. In the Black-Scholes option pricing model, the expected volatilities are based primarily on the historical volatility of Provident’s units for Provident indexed units and the Alerian MLP Index for Partnership indexed units. We and our predecessor use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates. Due to the distribution protection provision of the plans, zero distribution yield is assumed in the pricing model; however, compensation cost is recognized based on the units adjusted for the Adjustment Ratio and for certain plans, it includes distribution amounts accumulated to the reporting date.

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Founders Plan
     Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.
     Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first award represented 2.2 million unit appreciation rights at a weighted average grant price of $0.76 per unit with respect to the operations of the properties that were not transferred to us. The value of these unit appreciation rights at year-end 2006 was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid. The second award represented 309,570 unit appreciation rights at a weighted average grant price of $4.70 per unit with respect to the operations of the properties that were transferred to us for the period from the original date of grant to the initial public offering date of October 10, 2006. The value of the unit appreciation rights was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid.
     The third award represented 309,570 Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule. The value of the outstanding Partnership unit appreciation rights is remeasured each period using a Black-Scholes option pricing model. A market prices of $7.05 was used in the model for the period ending December 31, 2008. Expected volatility ranged from 9 percent to 21 percent and had a weighted average volatility of 9.8 percent. The average risk free rate used was approximately 3.3 percent. The expected option terms ranged from one half year to two and one half years.
     We recorded approximately $(0.3) million of compensation expense/(income) under the plan for the year ended December 31, 2008. The aggregate value of the vested unit appreciation rights was $0.4 million and the unvested obligation was zero at December 31, 2008.
     The following table summarizes information about Appreciation Rights Units issued under the Founders Plan:
                 
    December 31, 2008  
    Number of     Weighted  
    Appreciation     Average  
    Rights Units     Exercise Price  
Outstanding, beginning of period
    214,107     $ 18.50  
Exercised
    (91,463 )     18.50  
 
           
Outstanding, end of period
    122,644     $ 18.50  
 
           
 
               
Exercisable, end of period
        $  
BreitBurn Management LTIP and the Partnership LTIP
     In September 2005, certain employees of the predecessor were granted restricted units (RTUs) and/or performance units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units indexed to Provident Energy Trust Units. The grants are based on personal performance objectives. This plan replaced the Unit Appreciation Right Plan for Employees and Consultants for the period after September 2005 and subsequent years. RTUs vest one third at the end of year one, one third at end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the

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underlying notional units were made on the anniversary dates of the RTU to the employees entitled to receive them. PTUs vest three years from the end of third year after grant and payout can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of selected peer companies. The total return of the Provident Energy Trust unit is compared with the return of 25 selected Canadian trusts and funds. The Provident indexed PTUs granted in 2005 and 2006 entitle employees to receive cash payments equal to the market price of the underlying notional units. Under our LTIP, Partnership indexed PTUs were granted in 2007 and are payable in cash or may be paid in Common Units of the Partnership if elected at least 60 days prior to vesting by the grantees. The total return of the Partnership unit is compared with the return of 49 companies in the Alerian MLP Index for the payout multiplier. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.
     On June 17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro LP and Pro GP. The BreitBurn Management Purchase Agreement contains certain covenants of the parties relating to the allocation of responsibility for liabilities and obligations under certain pre-existing equity-based compensation plans adopted by BreitBurn Management, BEC and us. The pre-existing compensation plans include the outstanding 2005 and 2006 LTIP grants which are indexed to the Provident Trust Units. As a result, we paid $0.9 million for our share of the 2005 LTIP grants that vested in June 2008 in accordance with the agreed allocation of liability.
     In September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP grants to cash out their Provident-indexed units at $10.32 per share before the normal vesting date of December 31, 2008. By the end of September 2008, the offer was accepted by all employees who had outstanding 2006 LTIP grants. Consequently, compensation expense was recognized for the full amount of the remaining unvested liability during 2008. BreitBurn Management paid employees $0.6 million in 2008 for its share of the 2006 LTIP grants in accordance with the agreed allocation of liability.
     Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date. For PTUs, a performance multiplier is applied and is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.
     We recognized $(0.5) of compensation expense/(income) for the year ended December 31, 2008. Our share of the aggregate liability under the BreitBurn Management LTIP was $0.8 million at December 31, 2008. The aggregate value of the vested and unvested units under the plan was $0.6 million and $0.2 million respectively, at December 31, 2008.
The following table summarizes information at December 31, 2008 about the restricted/performance units granted in 2005 and 2006:
                 
            Weighted  
    Number of     Average  
    Units     Grant Price  
Outstanding, beginning of period
    267,702     $ 10.77  
Granted
           
Exercised
    (267,351 )     10.77  
Cancelled
    (351 )     10.73  
 
           
Outstanding, end of period
        $ 10.77  
 
           
 
               
Exercisable, end of period
        $  
     The following table summarizes information about the restricted/performance units granted in 2007. A market price of $7.05 was used in the model for the period ending December 31, 2008. Expected volatility ranged from 9

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percent to 15 percent and had a weighted average volatility of 9.8 percent. The average risk free rate ranged from 2 to 3.3 percent. The expected option terms ranged from one year to two years.
                 
    PTUs and RTUs  
    December 31, 2008  
            Weighted  
    Number of     Average  
    Units     Grant Price  
Outstanding, beginning of period
    108,717     $ 23.64  
Granted
           
Exercised
    (20,645 )     20.39  
Cancelled
    (1,080 )     24.10  
 
           
Outstanding, end of period
    86,992     $ 24.10  
 
           
 
               
Exercisable, end of period
        $  
Unit Appreciation Right Plan
     In 2004, the predecessor adopted the Unit Appreciation Right Plan for Employees and Consultants (the “UAR Plan”). Under the UAR Plan, certain employees of the predecessor were granted unit appreciation rights (“UARs”). The UARs entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units of Provident (“Phantom Units”). The exercise price and the vesting terms of the UARs were determined at the sole discretion of the Plan Administrator at the time of the grant. The UAR Plan was replaced with the BreitBurn Management LTIP at the end of September 2005. The grants issued prior to the replacement of the UAR Plan fully vested in 2008.
     UARs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. Upon vesting, the employee is entitled to receive a cash payment equal to the excess of the market price of Provident Energy Trust’s units (PVE units) over the exercise price of the Phantom Units at the grant date, adjusted for an additional amount equal to any Excess Distributions, as defined in the plan. The predecessor settles rights earned under the plan in cash.
     The total compensation expense for the UAR plan is allocated between us and our predecessor. Our share of expense was an immaterial amount in 2008 under the UAR Plan. Our share of the aggregate liability under the UAR Plan was approximately $0.1 million at December 31, 2008. The liability primarily represents accrued expense related to unpaid distributions on the fully vested UARs. In the Black-Scholes option pricing model for this plan, the expected volatility used was 29 percent and the risk rate was 3.3 percent. The expected option term is less than one half year.
     The following table summarizes the information about UARs:
                 
    BreitBurn Management Company  
    PVE indexed units  
    December 31, 2008  
    Number of     Weighted  
    Appreciation     Average  
    Rights     Exercise Price  
Outstanding, beginning of period
    154,323     $ 9.16  
Exercised
    (69,994 )     9.18  
Cancelled
           
 
           
Outstanding, end of period
    84,329     $ 9.96  
 
           
 
               
Exercisable, end of period
    84,329     $ 9.96  
Director Performance Units
     Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of

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phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in equity and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.
     We recorded compensation expense for the director’s phantom units of approximately $0.1 million in 2008. Our aggregate liability under the outstanding grants was $0.8 million at December 31, 2008 of which $0.4 million represents the unvested portion.
The following table summarizes information about the Director Performance Units:
                 
    December 31, 2008  
    Number of     Weighted  
    Performance     Average  
    Units     Grant Price  
Outstanding, beginning of period
    37,473     $ 21.11  
Granted
    20,146       27.35  
Exercised
    (22,190 )     23.05  
 
           
Outstanding, end of period
    35,429     $ 23.44  
 
           
 
               
Exercisable, end of period
        $  
Restricted Phantom Units and Convertible Phantom Units
     In connection with the changes to BreitBurn Management’s executive compensation program, the board of directors of our General Partner has approved two new types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs). In December 2007, seven executives of our General Partner received 188,545 units of RPUs and 681,500 units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. In November 2007, the Co-Chief Executive Officers also received 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per Common Unit under our Long-Term Incentive Plan. Those executive officers received CPU grants because they are in the best position to influence our operating results and, therefore, the amount of distributions we make to holders of our Common Units. As discussed below, payments under CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives is based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the board’s discretion at a future date after the present CPU grants have vested. A holder of an RPU is entitled to receive payments equal to quarterly distributions in cash at the time they are made. As a result, we believe that RPUs better incentivize holders of these awards to grow stable distributions for our common unitholders than do performance units. In 2008, the board of directors of the General Partner granted 245,290 RPUs to employees at a weighted average price of $20.44.
     Restricted Phantom Units (RPUs). RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.
     Convertible Phantom Units (CPUs). CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.
     Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution. Initially, one Common Unit equivalent underlies each CPU at the time it was awarded to the grantee. However, the number of Common Unit equivalents underlying the CPUs increase at a compounded rate of 25 percent upon the achievement of each 5 percent compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of Common Unit equivalents underlying the CPUs decrease at a compounded rate of 25 percent if the distributions paid by us to our common unitholders decreases at a compounded rate of 5 percent.

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     In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).
     In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the death or disability occurred. First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis. Then, this number would be pro rated by multiplying it by a percentage equal to:
    if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;
 
    if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;
 
    if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and
 
    if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.
     In 2008, we recognized compensation expense of $7.5 million related to its CPUs and RPUs.
     The following table summarizes information about the CPUs and RPUs for the year ended December 31, 2008:
                 
    Number of     Weighted  
    RPU     Average  
    Units     Grant Price  
Outstanding, beginning of period (a)
    372,945     $ 30.98  
Granted
    245,290       20.44  
Cancelled
    (10,972 )     20.83  
 
           
Outstanding, end of period
    607,263     $ 26.91  
 
           
 
               
Exercisable, end of period
        $  
16. Commitments and Contingencies
     Lease Rental Obligations
     We had operating leases for office space and other property and equipment having initial or remaining noncancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2008 are presented below:
                                                         
    Payments Due by Year
Thousands of dollars   2009   2010   2011   2012   2013   after 2013   Total
Operating leases
  $ 2,232     $ 2,126     $ 1,989     $ 1,656     $ 1,272     $ 2,143     $ 11,418  
     BreitBurn Management, our wholly owned subsidiary, has office, vehicle (primarily work vehicles used in our field operations) and office equipment leases. Net rental payments made under non-cancelable operating leases were $2.88 million in 2008.
     Surety Bonds and Letters of Credit
     In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2008, we had $10.1 million in surety bonds and we had $0.3 million in letters of credit outstanding.

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     Other
     On October 31, 2008, Quicksilver, an owner of more than five percent of our Common Units, instituted a lawsuit in the District Court of Tarrant County, Texas naming us as a defendant along with BreitBurn GP, BOLP, BOGP, Randall H. Breitenbach, Halbert S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall J. Findlay, Thomas W. Buchanan, Grant D. Billing and Provident. On December 12, 2008, Quicksilver filed an Amended Petition and asserted twelve different counts against the various defendants. The primary claims are as follows: Quicksilver alleges that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to its relationship with Provident. Quicksilver also alleges common law and statutory fraud claims against all of the defendants by contending that the defendants made false and misleading statements to induce Quicksilver to acquire Common Units in us. Finally, Quicksilver alleges claims for breach of the Partnership’s First Amended and Restated Agreement of Limited Partnership, dated as of October 10, 2006 (“Partnership Agreement”), and other common law claims relating to certain transactions and an amendment to the Partnership Agreement that occurred in June 2008. Quicksilver seeks a temporary and permanent injunction, a declaratory judgment relating primarily to the interpretation of the Partnership Agreement and the voting rights in that agreement, indemnification, punitive or exemplary damages, avoidance of BreitBurn GP’s assignment to us of all of its economic interest in us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary damages. The parties to the lawsuit are engaged in discovery pursuant to an agreed scheduling order. On February 17, 2009, we filed a motion for summary judgment which is scheduled to be heard on March 26, 2009. A hearing on Quicksilver’s request for a temporary injunction is scheduled for April 6, 2009.
     We are defending ourselves vigorously in connection with the allegations in the lawsuit. Because this lawsuit still is at an early stage, we cannot predict the manner and timing of the resolution of the lawsuit or its outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in the lawsuit.
     Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings other than as mentioned above. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.

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17. Retirement Plan
     BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees who have completed at least three months of service. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. BEC is charged for a portion of the matching contributions made by BreitBurn Management. For the year ended December 31, 2008, the matching contribution paid by us was $0.4 million.
18. Significant Customers
     We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2008, our purchasers which accounted for 10 percent or more of net sales were ConocoPhillips which accounted for 25 percent of net sales and Marathon Oil Company which accounted for 13 percent of net sales.
19. Minority Interest
      On May 25, 2007, BOLP entered into a Purchase and Sale Agreement with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a total purchase price of approximately $82 million (the “BEPI Acquisition”). As such, we are fully consolidating the results of BEPI and thus are recognizing a minority interest liability representing the book value of the general partner’s interests. At December 31, 2008, the amount of this minority interest liability was $0.5 million. The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties. Based on year end price and cost projections, the reversionary interest payout is not expected to occur.
20. Subsequent Events
     On January 22, 2009, we terminated a portion of our 2011 and 2012 crude oil swaps (1,939 Bbls/d at $90.00 per Bbl) and replaced them with new contracts with the same counterparty for the same volumes at market prices ($63.30 per Bbl). We realized $32.3 million from this termination. On January 26, 2009, we terminated a portion of our 2011 and 2012 natural gas swaps and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized $13.3 million from this termination. Proceeds from these contracts were used to pay down debt.
     On February 13, 2009, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on February 9, 2009. The distribution that was paid to unitholders was $0.52 per Common Unit. In February 2009 we also made payments equivalent to the distribution made to unitholders of $0.7 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.
     On February 19, 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan, increasing our outstanding Common Units to 52,770,011. See Note 15 for information regarding our unit based compensation plans.
21. Oil and Natural Gas Activities (Unaudited)
Costs incurred
     Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us for the year ended December 31, 2008:
         
Thousands of dollars
Property acquisition costs
       
Proved
  $  
Unproved
     
Development costs
    129,503  
Asset retirement costs
    1,363  
Pipelines and processing facilities
     
 
     
Total
  $ 130,866  
 
     

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Capitalized costs
     The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance for the year ended December 31, 2008.
         
       
Thousands of dollars
Proved properties and related producing assets
  $ 1,734,932  
Pipelines and processing facilities
    112,726  
Unproved properties
    209,873  
Accumulated depreciation, depletion and amortization
    (223,575 )
 
     
 
  $ 1,833,956  
 
     
     The average DD&A rate per equivalent unit of production for the year ended December 31, 2008 was $26.42 per Boe.
Results of operations for oil and gas producing activities
     The results of operations from oil and gas producing activities below exclude non-oil and gas revenues and expenses, general and administrative expenses, interest expenses and interest income for the year ended December 31, 2008.
         
       
       
Thousands of dollars
Oil, natural gas and NGL sales
  $ 467,381  
Realized loss on derivative instruments
    (55,946 )
Unrealized gain  on derivative instruments
    388,048  
Operating costs
    (149,681 )
Depreciation, depletion, and amortization
    (178,657 )
Pre-tax Income
    471,145  
Income tax expense
    1,939  
 
     
Results of producing operations
  $ 469,206  
 
     
Supplemental reserve information
     The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the year ended December 31, 2008. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. The estimates are prepared in accordance with SEC regulations.
     Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are

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ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.
     The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the year ended December 31, 2008.
                 
    Oil   Gas
In Thousands   (MBbl)   (MMcf)
Proved Reserves
               
Beginning balance
    58,095       505,069  
Revision of previous estimates (a)
    (29,106 )     (16,251 )
Production  
    (3,079 )     (22,384 )
 
               
 
               
Ending balance
    25,910       466,434  
 
               
Proved Developed Reserves
               
 
               
Beginning balance
    52,103       457,444  
Ending balance
    23,346       433,780  
 
(a)   Additions due to infill drilling are classified in Revisions and were approximately 741 MBbl for oil and 35,834 MMcf for natural gas in 2008.
Standardized measure of discounted future net cash flows
     The Standardized Measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2008 is presented below:
         
Thousands of dollars
Future cash inflows
    3,523,524  
Future development costs
    (212,951 )
Future production expense
    (1,843,986 )
 
     
Future net cash flows
    1,466,587  
Discounted at 10% per year
    (874,327 )
 
     
Standardized measure of discounted future net cash flows
  $ 592,260  

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     The standardized measure of discounted future net cash flows discounted at ten percent from production of proved reserves was developed as follows:
  1.   An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
 
  2.   In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various arrangements to fix or limit the prices relating to a portion of our oil and gas production. Arrangements in effect at December 31, 2008 are discussed in Note 14. Such risk management arrangements are not reflected in the reserve reports. Representative market prices at the as-of date for the reserve reports as of December 31, 2008 were $44.60 ($20.12 for Wyoming), per barrel of oil, and $5.71, per MMBTU of gas.
 
  3.   The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for two tax paying corporations whose future income tax liabilities on a discounted basis are insignificant.
     The principal sources of changes in the Standardized Measure of the future net cash flows for the year ended December 31, 2008 is presented below:
         
Thousands of dollars
Beginning balance
  $ 1,912,467  
Sales, net of production expense
    (317,700 )
Net change in sales and transfer prices, net of production expense
    (1,306,752 )
Previously estimated development costs incurred during year
    57,694  
Changes in estimated future development costs
    (98,064 )
Extensions, discoveries and improved recovery, net of costs
     
Purchase of reserves in place
     
Revision of quantity estimates and timing of estimated production
    153,368  
Accretion of discount
    191,247  
 
     
Ending balance
  $ 592,260  
 
     
22. Quarterly Financial Data (Unaudited)
                                 
    Year Ended December 31, 2008  
    First     Second     Third     Fourth  
Thousands of dollars   Quarter     Quarter     Quarter     Quarter  
Oil, natural gas and natural gas liquid sales
  $ 115,849     $ 139,962     $ 130,249     $ 81,321  
Gains (losses) on derivative instruments
    (83,387 )     (353,282 )     407,441       361,330  
Other revenue, net
    875       643       806       596  
 
                       
Total revenue
  $ 33,337     $ (212,677 )   $ 538,496     $ 443,247  
 
                               
Operating income (loss) (1)
    (34,455 )     (282,267 )     468,625       277,451  
 
                               
Net income (loss) (1)
    (41,140 )     (286,240 )     454,454       251,162  

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    Year Ended December 31, 2008  
    First     Second     Third     Fourth  
Thousands of dollars   Quarter     Quarter     Quarter     Quarter  
Limited Partners’ interest in loss (1)
    (40,867 )     (284,494 )     454,454       251,162  
 
                       
 
                               
Basic net loss per limited partner unit (2)
    (0.61 )     (4.39 )     8.63       4.77  
Diluted net loss per limited partner unit (2)
    (0.61 )     (4.39 )     8.41       4.65  
 
                       
 
                               
Basic units outstanding
    67,020,641       64,807,563       52,635,634       52,635,634  
Diluted units outstanding
    67,020,641       64,807,563       54,062,291       54,019,830  
 
                       
 
(1)   Fourth quarter 2008 includes $86.4 million for total impairments and price related adjustments and depreciation expense.
 
(2)   Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.


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Exhibits  
 
         
Exhibit No.
 
Sequential Description
 
  **2 .1   Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
  **2 .2   Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
  **2 .3   Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
  3 .1   Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
  3 .2   Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.3 to the Company’s Form 10-Q filed May 6, 2006 and included herein by reference).
  3 .3   Amended and Restated Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 8-K filed November 16, 2007 and included herein by reference).
  4 .1   Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed November 1, 2004 and included herein by reference).
  4 .2   Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.7 to the Company’s Form S-3, File No. 333-130597, filed December 22, 2005 and included herein by reference).
  4 .3   First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2006 and included herein by reference).
  4 .4   Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 10-Q filed November 7, 2006 and included herein by reference).
  4 .5   Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 530, 2008 and included herein by reference).
  4 .6   Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).

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Exhibit No.
 
Sequential Description
 
  4 .7   Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).
  10 .1   Master Gas Purchase and Sale Agreement, dated March 1, 1999, between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1, File No. 333-89229, filed November 1, 2004 and included herein by reference).
  10 .2   Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company (filed as Exhibit 10.5 to the Company’s Predecessor, MSR Exploration Ltd.’s Form S-4/A, File No. 333-29769, filed August 21, 1997 and included herein by reference).]
  + 10 .3   Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .4   Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
  + 10 .5   Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
  + 10 .6   Form of Retention Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
  + 10 .7   Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
  + 10 .8   Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
  + 10 .9   Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
  + 10 .10   Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference).
  + 10 .11   Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .12   Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .13   Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .14   Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .15   Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).

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Exhibit No.
 
Sequential Description
 
  + 10 .16   Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .17   Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .18   Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .19   Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.5 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .20   Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .21   Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
  + 10 .22   Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.11 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .23   Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).
  + 10 .24   Description of 2007 Cash Bonus (filed as Exhibit 10.3 to the Company’s Form 10-Q filed May 9, 2007 and included herein by reference).
  + 10 .25   Quicksilver Resources Inc. 2008 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 14, 2007 and included herein by reference).
  + 10 .26   Quicksilver Resources Inc. 2009 Executive Bonus Plan (filed as Exhibit 10.10 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .27   Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan (filed as Exhibit 10.9 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .28   Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .29   Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .30   Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference).
  10 .31   Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).
  10 .32   Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).

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Exhibit No.
 
Sequential Description
 
  10 .33   Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 and included herein by reference).
  10 .34   Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 5, 2008 and included herein by reference).
  10 .35   Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 2008 and included herein by reference).
  10 .36   Registration Rights Agreement, dated as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Energy L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference).
  +10 .37   2007 Equity Plan (filed as Exhibit 99.1 to Quicksilver Gas Services LP’s Form S-8, File No. 333-145326, filed August 10, 2007 and included herein by reference).
  +10 .38   Form of Phantom Unit Award Agreement for Non-Directors (Cash) (filed as Exhibit 10.10 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
  +10 .39   Form of Phantom Unit Award Agreement for Non-Directors (Units) (filed as Exhibit 10.11 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference).
  +10 .40   Quicksilver Gas Services LP Annual Bonus Plan (filed as Exhibit 10.1 to Quicksilver Gas Services LP’s Form 8-K, File No. 001-33631, filed December 13, 2007 and included herein by reference).
  +10 .41   Form of Indemnification Agreement by and between Quicksilver Gas Services GP LLC and its officers and directors (filed as Exhibit 10.7 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
  *** 21 .1   List of subsidiaries of Quicksilver Resources Inc.
  *** 23 .1   Consent of Deloitte & Touche LLP.
  *** 23 .2   Consent of Schlumberger Data and Consulting Services.
  *** 23 .3   Consent of LaRoche Petroleum Consultants, Ltd.
  * 23 .4   Consent of Schlumberger Data and Consulting Services
  * 23 .5   Consent of Netherland, Sewell & Associates, Inc.
  * 23 .6   Consent of PricewaterhouseCoopers LLP
  * 23 .7   Consent of Deloitte & Touche LLP.
  * 23 .8   Consent of Deloitte & Touche LLP.
  * 23 .9   Consent of Deloitte & Touche LLP.
  *** 24 .1   Power of Attorney
  * 31 .1   Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  * 31 .2   Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  * 32 .1   Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
* Filed herewith.
 
** Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.
 
*** Filed with the Company’s original Annual Report on Form 10-K filed on March 3, 2009.
 
+ Identifies management contracts and compensatory plans or arrangements.
     

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SIGNATURES
     Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
                 
 
          Quicksilver Resources Inc.    
 
             
 
               
 
      By:   /s/ Philip Cook
 
   
 
          Philip Cook    
 
  Dated: May 29, 2009       Senior Vice President — Chief Financial Officer    

89


 

Exhibit Index
 
         
Exhibit No.
 
Sequential Description
 
  **2 .1   Contribution Agreement, dated September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference.)
  **2 .2   Purchase and Sale Agreement, dated as of July 3, 2008, among Nortex Minerals, L.P., Petrus Investment, L.P., Petrus Development, L.P., and Perot Investment Partners, Ltd., as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.1 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
  **2 .3   Purchase and Sale Agreement, dated as of July 3, 2008, among Hillwood Oil & Gas, L.P., Burtex Minerals, L.P., Chief Resources, LP, Hillwood Alliance Operating Company, L.P., Chief Resources Alliance Pipeline LLC, Chief Oil & Gas LLC, Berry Barnett, L.P., Collins and Young, L.L.C. and Mark Rollins, as Sellers, and Quicksilver Resources Inc., as Purchaser (filed as Exhibit 10.2 to the Company’s Form 8-K filed July 7, 2008 and included herein by reference).
  3 .1   Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008 (filed as Exhibit 4.1 to the Company’s Form S-3, File No. 333-151847, filed June 23, 2008 and included herein by reference).
  3 .2   Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.3 to the Company’s Form 10-Q filed May 6, 2006 and included herein by reference).
  3 .3   Amended and Restated Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 8-K filed November 16, 2007 and included herein by reference).
  4 .1   Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed November 1, 2004 and included herein by reference).
  4 .2   Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.7 to the Company’s Form S-3, File No. 333-130597, filed December 22, 2005 and included herein by reference).
  4 .3   First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 8-K filed March 21, 2006 and included herein by reference).
  4 .4   Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association) (filed as Exhibit 4.1 to the Company’s Form 10-Q filed November 7, 2006 and included herein by reference).
  4 .5   Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed June 530, 2008 and included herein by reference).
  4 .6   Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K filed July 10, 2008 and included herein by reference).
 
  4 .7   Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A/A (Amendment No. 1) filed December 21, 2005 and included herein by reference).

 


 

         
Exhibit No.
 
Sequential Description
  10 .1   Master Gas Purchase and Sale Agreement, dated March 1, 1999, between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1, File No. 333-89229, filed November 1, 2004 and included herein by reference).
  10 .2   Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company (filed as Exhibit 10.5 to the Company’s Predecessor, MSR Exploration Ltd.’s Form S-4/A, File No. 333-29769, filed August 21, 1997 and included herein by reference).]
  + 10 .3   Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .4   Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
  + 10 .5   Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
  + 10 .6   Form of Retention Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
  + 10 .7   Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference).
  + 10 .8   Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
  + 10 .9   Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed January 28, 2005 and included herein by reference).
  + 10 .10   Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference).
  + 10 .11   Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .12   Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .13   Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .14   Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .15   Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .16   Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.5 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).


 

         
Exhibit No.
 
Sequential Description
 
  + 10 .17   Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (filed as Exhibit 10.6 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .18   Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.8 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .19   Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.5 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .20   Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (One-Year Vesting) (filed as Exhibit 10.7 to the Company’s Form 8-K filed May 25, 2006 and included herein by reference).
  + 10 .21   Form of Non-Employee Director Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Second Amended and Restated 2006 Equity Plan (Three-Year Vesting) (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 25, 2007 and included herein by reference).
  + 10 .22   Description of Non-Employee Director Compensation for Quicksilver Resources Inc. (filed as Exhibit 10.11 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .23   Quicksilver Resources Inc. 2007 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 16, 2007 and included herein by reference).
  + 10 .24   Description of 2007 Cash Bonus (filed as Exhibit 10.3 to the Company’s Form 10-Q filed May 9, 2007 and included herein by reference).
  + 10 .25   Quicksilver Resources Inc. 2008 Executive Bonus Plan (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 14, 2007 and included herein by reference).
  + 10 .26   Quicksilver Resources Inc. 2009 Executive Bonus Plan (filed as Exhibit 10.10 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .27   Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan (filed as Exhibit 10.9 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .28   Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan (filed as Exhibit 10.8 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .29   Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan (filed as Exhibit 10.7 to the Company’s Form 8-K filed November 24, 2008 and included herein by reference).
  + 10 .30   Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 26, 2005 and included herein by reference).
  10 .31   Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).
  10 .32   Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed February 12, 2007 and included herein by reference).
 
  10 .33   Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 25, 2008 and included herein by reference).


 

         
Exhibit No.
 
Sequential Description
 
  10 .34   Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 5, 2008 and included herein by reference).
  10 .35   Credit Agreement, dated as of August 8, 2008, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse, Cayman Islands Branch, as administrative agent (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 8, 2008 and included herein by reference).
  10 .36   Registration Rights Agreement, dated as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Energy L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 7, 2007 and included herein by reference).
  +10 .37   2007 Equity Plan (filed as Exhibit 99.1 to Quicksilver Gas Services LP’s Form S-8, File No. 333-145326, filed August 10, 2007 and included herein by reference).
  +10 .38   Form of Phantom Unit Award Agreement for Non-Directors (Cash) (filed as Exhibit 10.10 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
  +10 .39   Form of Phantom Unit Award Agreement for Non-Directors (Units) (filed as Exhibit 10.11 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference).
  +10 .40   Quicksilver Gas Services LP Annual Bonus Plan (filed as Exhibit 10.1 to Quicksilver Gas Services LP’s Form 8-K, File No. 001-33631, filed December 13, 2007 and included herein by reference).
  +10 .41   Form of Indemnification Agreement by and between Quicksilver Gas Services GP LLC and its officers and directors (filed as Exhibit 10.7 to Quicksilver Gas Services LP’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference).
  *** 21 .1   List of subsidiaries of Quicksilver Resources Inc.
  *** 23 .1   Consent of Deloitte & Touche LLP.
  *** 23 .2   Consent of Schlumberger Data and Consulting Services.
  *** 23 .3   Consent of LaRoche Petroleum Consultants, Ltd.
  * 23 .4   Consent of Schlumberger Data and Consulting Services
  * 23 .5   Consent of Netherland, Sewell & Associates, Inc.
  * 23 .6   Consent of PricewaterhouseCoopers LLP
  * 23 .7   Consent of Deloitte & Touche LLP.
  * 23 .8   Consent of Deloitte & Touche LLP.
  * 23 .9   Consent of Deloitte & Touche LLP.
  *** 24 .1   Power of Attorney
  * 31 .1   Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  * 31 .2   Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  * 32 .1   Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
* Filed herewith.
 
** Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request.
 
*** Filed with the Company’s original Annual Report on Form 10-K filed on March 3, 2009.
 
+ Identifies management contracts and compensatory plans or arrangements.
     
EX-23.4 2 d67831exv23w4.htm EX-23.4 exv23w4
Exhibit 23.4
Data & Consulting Service
Division of Schlumberger Technology Corporation
     
1310 Commerce Drive
Park Ridge 1
   (SCHLUMBERGER LOGO)
Pittsburgh, PA 15275-1011
   
Tel: 412-787-5403
   
Fax: 412-787-2906
   
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
     Data & Consulting Services Division of Schlumberger Technology Corporation consents to the references to our firm in the form and context in which they appear in this Amendment No. 2 to the Form 10-K (“Amendment No. 2”) of Quicksilver Resources Inc. (the “Company”) for the year ended 31 December 2008 and to the use of information contained in our report, as of 31 December 2008 setting forth the estimates of revenues from BreitBurn Energy Partners L.P. oil and gas reserves in such Amendment No. 2. We further consent to the incorporation by reference of such information into Registration Statement No. 333-152898 on Form S-3 and Registration Statement Nos. 333-91526, 333-94387, 333-113617, 333-116180 and 333-134430 on Form S-8 of the Company.
DATA & CONSULTING SERVICES
DIVISION OF SCHLUMBERGER TECHNOLOGY
CORPORATION
         
 
  By:   -s- Charles M. Boyer
 
      Charles M. Boyer II, P.G., C.P.G., C.C.G.
 
      Advisor — Unconventional Reservoirs
29 May 2009

EX-23.5 3 d67831exv23w5.htm EX-23.5 exv23w5
Exhibit 23.5
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
     Netherland, Sewell & Associates, Inc. consents to the references to our firm in the form and context in which they appear in this Amendment No. 2 to the Form 10-K (“Amendment No. 2”) of Quicksilver Resources Inc. (the “Company”) for the year ended December 31, 2008 and to the use of information contained in our reports, as of December 31, 2008 and 2007, setting forth the estimates of revenues from BreitBurn Energy Partners L.P. oil and gas reserves in such Amendment No. 2. We further consent to the incorporation by reference of such information into Registration Statement No. 333-152898 on Form S-3 and Registration Statement Nos. 333-91526, 333-94387, 333-113617, 333-116180 and 333-134430 on Form S-8 of the Company.
         
  NETHERLAND, SEWELL & ASSOCIATES, INC.
 
 
  By:   /s/ J. Carter Henson, Jr.    
    J. Carter Henson, Jr., P.E.   
    Senior Vice President  
 
Houston, Texas
May 29, 2009

 

EX-23.6 4 d67831exv23w6.htm EX-23.1 exv23w6
Exhibit 23.6
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-152898) and on Form S-8 (File Nos. 333-134430, 333-94387, 333-91526, 333-113617 and 333-116180) of Quicksilver Resources Inc. of our report dated March 2, 2009 relating to the consolidated financial statements of BreitBurn Energy Partners L.P., which appears in this Amendment No. 2 to the Form 10-K of Quicksilver Resources Inc. for the year ended December 31, 2008.
/s/ PricewaterhouseCoopers LLP
Los Angeles, California
May 29, 2009

EX-23.7 5 d67831exv23w7.htm EX-23.7 exv23w7
Exhibit 23.7
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No. 333-152898 on Form S-3 and Registration Statement Nos. 333-134430, 333-94387, 333-91526, 333-113617, and 333-116180 on Form S-8 of our report dated May 29, 2009 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the preparation of the consolidated financial statements of Cowtown Pipeline Funding, Inc. from the separate records maintained by Quicksilver Resources Inc.), relating to the consolidated financial statements of Cowtown Pipeline Funding, Inc., appearing in this Amendment No. 2 to Form 10-K of Quicksilver Resources Inc. and subsidiaries for the year ended December 31, 2008.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
May 29, 2009

 

EX-23.8 6 d67831exv23w8.htm EX-23.8 exv23w8
Exhibit 23.8
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No. 333-152898 on Form S-3 and Registration Statement Nos. 333-134430, 333-94387, 333-91526, 333-113617, and 333-116180 on Form S-8 of our report dated May 29, 2009 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the preparation of the consolidated financial statements of Quicksilver Gas Services Holdings LLC from the separate records maintained by Quicksilver Resources Inc.), relating to the consolidated financial statements of Quicksilver Gas Services Holdings LLC, appearing in this Amendment No. 2 to Form 10-K of Quicksilver Resources Inc. and subsidiaries for the year ended December 31, 2008.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
May 29, 2009

 

EX-23.9 7 d67831exv23w9.htm EX-23.9 exv23w9
Exhibit 23.9
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No. 333-152898 on Form S-3 and Registration Statement Nos. 333-134430, 333-94387, 333-91526, 333-113617, and 333-116180 on Form S-8 of our report dated May 29, 2009 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the preparation of the consolidated financial statements of Quicksilver Resources Canada Inc. from the separate records maintained by Quicksilver Resources Inc.), relating to the consolidated financial statements of Quicksilver Resources Canada Inc., appearing in this Amendment No. 2 to Form 10-K of Quicksilver Resources Inc. and subsidiaries for the year ended December 31, 2008.
/s/ DELOITTE & TOUCHE LLP
Fort Worth, Texas
May 29, 2009

 

EX-31.1 8 d67831exv31w1.htm EX-31.1 exv31w1
Exhibit 31.1
CERTIFICATION
I, Glenn Darden, certify that:
  1.   I have reviewed this annual report on Form 10-K/A of Quicksilver Resources Inc.;
 
  2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
  3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
Date: May 29, 2009
         
     
  /s/ Glenn Darden    
  Glenn Darden   
  President and Chief Executive Officer   
 

 

EX-31.2 9 d67831exv31w2.htm EX-31.2 exv31w2
Exhibit 31.2
CERTIFICATION
I, Philip Cook, certify that:
  1.   I have reviewed this annual report on Form 10-K/A of Quicksilver Resources Inc.;
 
  2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
  3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
Date: May 29, 2009
         
     
  /s/ Philip Cook    
  Philip Cook   
  Senior Vice President — Chief Financial Officer   
 

 

EX-32.1 10 d67831exv32w1.htm EX-32.1 exv32w1
Exhibit 32.1
CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, in connection with the Annual Report of Quicksilver Resources Inc. (the “Company”) on Form 10-K/A for the year ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Philip Cook, Senior Vice President — Chief Financial Officer of the Company, and Glenn Darden, President and Chief Executive Officer of the Company, each certifies that, to his knowledge:
  (1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.
Date: May 29, 2009
                 
By:
  /s/ Philip Cook
 
Philip Cook
Senior Vice President — Chief Financial Officer
  By:   /s/ Glenn Darden
 
Glenn Darden
President and Chief Executive Officer
   

 

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