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Apache 10-Q 2010
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Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A

Amendment No. 1
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2010
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 1-4300
APACHE CORPORATION
(exact name of registrant as specified in its charter)
     
Delaware   41-0747868
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)
Registrant’s Telephone Number, Including Area Code: (713) 296-6000
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ     No o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ     No o
      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or 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.
Large accelerated filer þ Accelerated filer o
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o     No þ
Number of shares of registrant’s common stock outstanding as of July 31, 2010                                                                             364,278,514
 
 

 


Table of Contents

EXPLANATORY NOTE
     Apache Corporation (Apache or the Company) is filing this Amendment No. 1 on Form 10-Q/A to amend and restate in its entirety the following items of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, as originally filed with the Securities and Exchange Commission on August 6, 2010 (the “Original Form 10-Q”): (i) Item 1 of Part I “Financial Information,” and (ii) Item 2 of Part I, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and we have also updated the signature page, the certifications of our Chief Executive Officer and Chief Financial Officer in Exhibits 31.1, 31.2, and 32.1, and our financial statements formatted in Extensible Business Reporting Language (XBRL) in Exhibits 101. No other sections were affected, but for the convenience of the reader, this report on Form 10-Q/A restates in its entirety, as amended, our Original Form 10-Q.
     In light of the repeal of SEC Rule 436(g) by Congress in the Dodd-Frank Act, effective Thursday, July 22, 2010, we have deleted the reference to our credit ratings in Note 6 — Debt of Item 1 of Part I, “Financial Information” and have expanded our disclosure regarding our credit ratings in Item 2 of Part 1, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity”.
     This report on Form 10-Q/A is presented as of the filing date of the Original Form 10-Q and does not reflect events occurring after that date, or modify or update disclosures in any way other than as required to reflect the amendments described above.

 


 

TABLE OF CONTENTS

                    Page  
 
PART I — FINANCIAL INFORMATION    1  
 ITEM 1 — FINANCIAL STATEMENTS    1  
 ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS    29  
 ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK    50  
 ITEM 4 — CONTROLS AND PROCEDURES    53  
PART II — OTHER INFORMATION    54  
 ITEM 1. LEGAL PROCEEDINGS    54  
 ITEM 1A. RISK FACTORS    54  
 ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS    58  
 ITEM 3. DEFAULTS UPON SENIOR SECURITIES    58  
 ITEM 4. [REMOVED AND RESERVED]    58  
 ITEM 5. OTHER INFORMATION    58  
 ITEM 6. EXHIBITS    58  
SIGNATURES    60  
 EX-10.2
 EX-10.3
 EX-10.4
 EX-10.5
 EX-10.6
 EX-10.7
 EX-12.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

 


Table of Contents

PART I — FINANCIAL INFORMATION
ITEM 1 — FINANCIAL STATEMENTS
APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
                                 
    For the Quarter     For the Six Months  
    Ended June 30,     Ended June 30,  
    2010     2009     2010     2009  
    (In thousands, except per common share data)  
REVENUES AND OTHER:
                               
Oil and gas production revenues
  $ 2,968,765     $ 2,074,344     $ 5,662,390     $ 3,677,958  
Other
    3,145       19,034       (17,229 )     49,245  
 
                       
 
    2,971,910       2,093,378       5,645,161       3,727,203  
 
                       
 
                               
OPERATING EXPENSES:
                               
Depreciation, depletion and amortization
                               
Recurring
    729,751       573,359       1,368,249       1,153,976  
Additional
                      2,818,161  
Asset retirement obligation accretion
    24,760       26,483       48,762       53,221  
Lease operating expenses
    445,949       405,273       886,195       802,762  
Gathering and transportation
    43,038       33,479       83,403       66,818  
Taxes other than income
    186,833       115,941       363,771       203,280  
General and administrative
    91,829       90,905       178,979       175,951  
Financing costs, net
    55,757       61,155       115,024       119,742  
 
                       
 
    1,577,917       1,306,595       3,044,383       5,393,911  
 
                       
INCOME (LOSS) BEFORE INCOME TAXES
    1,393,993       786,783       2,600,778       (1,666,708 )
Current income tax provision
    339,151       218,247       682,125       220,741  
Deferred income tax provision (benefit)
    194,619       123,816       353,449       (575,229 )
 
                       
 
                               
NET INCOME (LOSS)
    860,223       444,720       1,565,204       (1,312,220 )
Preferred stock dividends
          1,420             2,840  
 
                       
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
  $ 860,223     $ 443,300     $ 1,565,204     $ (1,315,060 )
 
                       
 
                               
NET INCOME (LOSS) PER COMMON SHARE:
                               
Basic
  $ 2.55     $ 1.32     $ 4.64     $ (3.92 )
 
                       
Diluted
  $ 2.53     $ 1.31     $ 4.61     $ (3.92 )
 
                       
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
                 
    For the Six Months Ended
June 30,
 
    2010     2009  
    (In thousands)  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income (loss)
  $ 1,565,204     $ (1,312,220 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    1,368,249       3,972,137  
Asset retirement obligation accretion
    48,762       53,221  
Provision for (benefit from) deferred income taxes
    353,449       (575,229 )
Other
    66,939       104,734  
Changes in operating assets and liabilities:
               
Receivables
    (103,847 )     (173,502 )
Inventories
    (6,812 )     (4,049 )
Drilling advances
    21,827       (89,751 )
Deferred charges and other
    729       5,871  
Accounts payable
    49,573       (176,572 )
Accrued expenses
    (291,931 )     (376,981 )
Deferred credits and noncurrent liabilities
    13,299       (60,930 )
 
           
NET CASH PROVIDED BY OPERATING ACTIVITIES
    3,085,441       1,366,729  
 
           
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Additions to oil and gas property
    (1,937,613 )     (2,117,415 )
Additions to gas gathering, transmission and processing facilities
    (256,728 )     (164,723 )
Acquisition of Marathon properties
          (181,133 )
Acquisition of Devon properties
    (1,017,238 )      
Short-term investments
          791,999  
Restricted cash
          13,880  
Other, net
    (6,904 )     (85,399 )
 
           
NET CASH USED IN INVESTING ACTIVITIES
    (3,218,483 )     (1,742,791 )
 
           
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Commercial paper, credit facility and bank notes, net
    (55,384 )     147,666  
Payments on fixed-rate notes
          (100,000 )
Dividends paid
    (101,065 )     (103,331 )
Common stock activity
    21,346       9,971  
Treasury stock activity, net
    3,591       2,669  
Cost of debt and equity transactions
    (289 )     (403 )
Other
    22,073       9,597  
 
           
NET CASH USED IN FINANCING ACTIVITIES
    (109,728 )     (33,831 )
 
           
NET DECREASE IN CASH AND CASH EQUIVALENTS
    (242,770 )     (409,893 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    2,048,117       1,181,450  
 
           
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 1,805,347     $ 771,557  
 
           
 
               
SUPPLEMENTARY CASH FLOW DATA:
               
Interest paid, net of capitalized interest
  $ 113,099     $ 122,120  
Income taxes paid, net of refunds
    595,472       188,251  
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
ASSETS
               
 
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 1,805,347     $ 2,048,117  
Receivables, net of allowance
    1,647,952       1,545,699  
Inventories
    508,702       533,251  
Drilling advances
    205,965       230,733  
Prepaid taxes
    137,556       146,653  
Prepaid assets and other
    201,418       81,396  
 
           
 
    4,506,940       4,585,849  
 
           
 
               
PROPERTY AND EQUIPMENT:
               
Oil and gas, on the basis of full-cost accounting:
               
Proved properties
    47,078,456       44,267,037  
Unproved properties and properties under development, not being amortized
    1,968,079       1,479,008  
Gas gathering, transmission and processing facilities
    3,445,906       3,189,177  
Other
    524,642       492,511  
 
           
 
    53,017,083       49,427,733  
Less: Accumulated depreciation, depletion and amortization
    (27,893,628 )     (26,527,118 )
 
           
 
    25,123,455       22,900,615  
 
           
OTHER ASSETS:
               
 
               
Goodwill, net
    189,252       189,252  
Deferred charges and other
    612,760       510,027  
 
           
 
  $ 30,432,407     $ 28,185,743  
 
           
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
                 
    June 30,     December 31,  
    2010     2009  
    (In thousands)  
LIABILITIES AND SHAREHOLDERS’ EQUITY
               
 
               
CURRENT LIABILITIES:
               
Accounts payable
  $ 485,601     $ 396,564  
Accrued operating expense
    92,678       90,151  
Accrued exploration and development
    895,305       923,084  
Accrued compensation and benefits
    97,250       151,408  
Current debt
    116,205       117,326  
Asset retirement obligation
    147,374       146,654  
Other
    368,422       567,371  
 
           
 
    2,202,835       2,392,558  
 
           
LONG-TERM DEBT
    4,896,127       4,950,390  
 
           
 
               
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
               
Income taxes
    3,247,065       2,764,901  
Asset retirement obligation
    1,874,743       1,637,357  
Other
    535,877       661,916  
 
           
 
    5,657,685       5,064,174  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (Note 9)
               
 
               
SHAREHOLDERS’ EQUITY:
               
Common stock, $0.625 par, 430,000,000 shares authorized, 345,278,595 and 344,076,790 shares issued, respectively
    215,799       215,048  
Paid-in capital
    4,748,709       4,634,326  
Retained earnings
    12,900,582       11,436,580  
Treasury stock, at cost, 7,479,435 and 7,639,818 shares, respectively
    (212,280 )     (216,831 )
Accumulated other comprehensive income (loss)
    22,950       (290,502 )
 
           
 
    17,675,760       15,778,621  
 
           
 
  $ 30,432,407     $ 28,185,743  
 
           
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
(Unaudited)
                                                                   
                                                      Accumulated        
              Series B                                     Other     Total  
    Comprehensive       Preferred     Common                     Treasury     Comprehensive     Shareholders’  
    Income (Loss)       Stock     Stock     Paid-In Capital     Retained Earnings     Stock     Income (Loss)     Equity  
    (In thousands)  
BALANCE AT DECEMBER 31, 2008
            $ 98,387     $ 214,221     $ 4,472,826     $ 11,929,827     $ (228,304 )   $ 21,764     $ 16,508,721  
Comprehensive loss:
                                                                 
Net loss
  $ (1,312,220 )                         (1,312,220 )                 (1,312,220 )
Commodity hedges, net of income tax benefit of $108,393
    (194,508 )                                     (194,508 )     (194,508 )
 
                                                               
Comprehensive loss
  $ (1,506,728 )                                                          
 
                                                               
Dividends:
                                                                 
Preferred
                                (2,840 )                 (2,840 )
Common ($.30 per share)
                                (100,567 )                 (100,567 )
Common shares issued
                    537       (3,886 )                       (3,349 )
Treasury shares issued, net
                          (4,840 )           5,040             200  
Compensation expense
                          63,356                         63,356  
Other
                          (98 )                       (98 )
 
                                                   
BALANCE AT JUNE 30, 2009
            $ 98,387     $ 214,758     $ 4,527,358     $ 10,514,200     $ (223,264 )   $ (172,744 )   $ 14,958,695  
 
                                                   
 
                                                                 
BALANCE AT DECEMBER 31, 2009
            $     $ 215,048     $ 4,634,326     $ 11,436,580     $ (216,831 )   $ (290,502 )   $ 15,778,621  
Comprehensive income:
                                                                 
Net income
  $ 1,565,204                           1,565,204                   1,565,204  
Commodity hedges, net of income tax expense of $150,207
    313,452                                       313,452       313,452  
 
                                                               
Comprehensive income
  $ 1,878,656                                                            
 
                                                               
Common stock dividends ($.30 per share)
                                (101,204 )                 (101,204 )
Common shares issued
                    751       12,473                         13,224  
Treasury shares issued, net
                          (519 )           4,551             4,032  
Compensation expense
                          102,006                         102,006  
Other
                          423       2                   425  
 
                                                   
BALANCE AT JUNE 30, 2010
            $     $ 215,799     $ 4,748,709     $ 12,900,582     $ (212,280 )   $ 22,950     $ 17,675,760  
 
                                                   
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
     These financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Annual Report on Form 10-K for the fiscal year ended December 31, 2009, which contains a summary of the Company’s significant accounting policies and other disclosures. Additionally, the Company’s financial statements for prior periods include reclassifications that were made to conform to the current-period presentation.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
     As of June 30, 2010, Apache’s significant accounting policies are consistent with those discussed in Note 1 of its consolidated financial statements contained in the Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
Use of Estimates
     The preparation of financial statements in conformity with U.S. GAAP 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. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and related present value estimates of future net cash flow therefrom, asset retirement obligations and income taxes. Actual results could differ from those estimates.
2. ACQUISITIONS
Kitimat LNG Terminal
     In the first quarter of 2010, Apache announced an agreement to acquire a 51-percent interest in Kitimat LNG Inc’s proposed liquefied natural gas (LNG) export terminal (Kitimat) in British Columbia. The Company also reserved 51 percent of throughput capacity in the terminal. Planned plant gross capacity will be approximately 700 million cubic feet of natural gas per day (MMcf/d), or five million metric tons of LNG per year. This project has the potential to access new markets in the Asia-Pacific region and enable Apache to monetize gas from its Canadian region, including its interest in the Horn River Basin in northeast British Columbia. Kitimat is designed to be linked to the pipeline system servicing Western Canada’s natural gas producing regions proposed by Pacific Trail Pipelines. In association with the Company’s acquisition of interest in the Kitimat project, Apache also acquired a 25.5-percent interest in the proposed pipeline and 350 MMcf/d of net capacity rights. Preliminary gross construction cost of the Kitimat LNG export terminal, which will be refined upon completion of a front-end engineering and design (FEED) study, total C$3 billion and of the pipeline total C$1.1 billion. Apache projects that most of the costs for the LNG export terminal and pipeline will be incurred throughout a three and one-half year construction phase which is expected to begin in the second half of 2011.
     During the second quarter Apache received proposals from three contractors on the FEED study and expects to award the contract by the end of the third quarter of 2010. Memorandums of Understanding (MOUs) have been developed and discussions with LNG buyers have been ongoing to market the LNG. Also, negotiations for specific agreements required with First Nations and Canadian federal and provincial governments are underway with completion anticipated during the third quarter of 2010. A final investment decision is expected in 2011, with the first LNG shipments projected as early as the end of 2014.

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Gulf of Mexico Shelf Acquisition
     On June 9, 2010, Apache completed a $1.05 billion acquisition of oil and gas assets in the Gulf of Mexico shelf from Devon Energy Corporation (Devon). The acquisition was effective as of January 1, 2010. The acquired assets include 477,000 net acres across 150 blocks and estimated proved reserves of 41 million barrels of oil equivalent (MMboe). Approximately half of the estimated net proved reserves were liquid hydrocarbons and seven major fields account for 90 percent of the estimated proved reserves. Virtually all of the production is located in fields in water depths less than 500 feet and Apache operates 75 percent of the production. The acquisition was funded primarily from existing cash balances.
Mariner Energy, Inc. Merger Agreement
     On April 15, 2010, Apache and Mariner Energy, Inc., a Delaware corporation (Mariner), announced that we had entered into a definitive agreement pursuant to which Apache will acquire Mariner in a stock and cash transaction. The Agreement and Plan of Merger dated April 14, 2010 (as amended by amendment No. 1 dated August 2, 2010, referred to as the Merger Agreement), by and among Apache, Mariner and ZMZ Acquisitions LLC, a Delaware limited liability company and wholly owned subsidiary of Apache (Merger Sub), contemplates a merger (the Merger) whereby Mariner will be merged with and into Merger Sub, with Merger Sub surviving the Merger as a wholly owned subsidiary of Apache.
     The total amount of cash and shares of Apache common stock that will be paid and issued, respectively, pursuant to the Merger Agreement is fixed, and Mariner stockholders will be entitled to receive (on an aggregate basis) 0.17043 of a share of Apache common stock, par value $0.625 per share, and $7.80 in cash for each share of Mariner common stock (the Mixed Consideration). Mariner stockholders have the right to elect to receive all cash ($26.00 per share), all Apache common stock (0.24347 of a share of Apache common stock) or the Mixed Consideration, subject to proration procedures as provided in the Merger Agreement.
     Upon completion of the Merger, each outstanding option to purchase Mariner common stock will be converted into a fully vested option to purchase 0.24347 shares of Apache common stock.
     In connection with the Merger, Apache expects to issue approximately 17.5 million shares of common stock (an increase of approximately five percent of the Company’s outstanding common shares) and pay cash of approximately $800 million to Mariner stockholders. Apache intends to fund the cash portion of the consideration with existing cash balances and commercial paper. Upon consummation of the Merger, Apache will assume Mariner’s debt, which was approximately $1.2 billion at the time of the Merger Agreement.
     The Merger Agreement has been approved by the boards of directors of Apache, Mariner, and Merger Sub. The completion of the Merger is subject to certain conditions, including: (i) the adoption of the Merger Agreement by the stockholders of Mariner; (ii) with certain materiality exceptions, the accuracy of the representations and warranties made by Apache and Mariner; (iii) the effectiveness of a registration statement on Form S-4 associated with the issuance of its common stock in the Merger, and the approval of the listing of these shares on the New York Stock Exchange; (iv) the termination or expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (HSR Act); (v) the delivery of customary opinions from counsel to Apache and Mariner that the Merger will be treated as a tax-free reorganization for U.S. federal income tax purposes; (vi) compliance by Apache and Mariner with their respective obligations under the Merger Agreement; and (vii) the absence of legal impediments prohibiting the Merger. On May 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the HSR Act. Additional post-closing regulatory approvals are pending. Completion of the transaction is projected for the third quarter of 2010.
     The Merger Agreement contains customary representations and warranties that the parties have made to each other as of specific dates. Apache and Mariner have each agreed to certain covenants in the Merger Agreement. Among other covenants, Mariner has agreed, subject to certain exceptions, not to initiate, solicit, negotiate, provide information in furtherance of, approve, recommend or enter into an Acquisition Proposal (as defined in the Merger Agreement).
     The Merger Agreement also contains certain termination rights for both Apache and Mariner, including if the Merger is not completed by January 31, 2011. In the event of a termination of the Merger Agreement under certain circumstances, Mariner may be required to pay Apache a termination fee of $67 million. (less any Apache expenses previously reimbursed by Mariner). In connection with the settlement of two stockholder lawsuits, on August 2, 2010, Apache and Mariner amended the Merger Agreement to eliminate the termination fee for one of the events which would trigger the payment of the fee: in the event that Mariner terminates the Merger Agreement in order to enter into an unsolicited “superior proposal” with another party (refer to Note 9 – Commitments and Contingencies, of Item I of this form 10-Q for further discussion). In addition, under certain circumstances, the Merger Agreement requires each of Apache and Mariner to reimburse the other’s expenses, up to $7.5 million, in the event the Merger Agreement is terminated. Any reimbursement of expenses by Mariner to Apache will reduce the amount of any termination fee paid by Mariner to Apache.

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     At year-end 2009, Mariner had estimated proved reserves of 181 MMboe. Mariner’s oil and gas properties are primarily located in the Gulf of Mexico deepwater and shelf, the Permian Basin and onshore in the Gulf Coast, encompassing 541,000 net developed and 623,000 net undeveloped acres at December 31, 2009. Mariner’s current deepwater Gulf of Mexico portfolio includes over 99 blocks, seven discoveries in development and more than 50 drilling prospects. The Permian Basin and Gulf of Mexico Shelf assets fit well with Apache’s existing holdings and provide an inventory of future potential drilling locations, particularly in the Spraberry, Wolfcamp and Wolfberry formation oil plays of the Permian Basin. Additionally, Mariner has accumulated acreage in emerging unconventional shale oil resources in the U.S.
     Assuming the Merger is approved by Mariner stockholders and is cleared by regulatory authorities, the transaction will be accounted for as a business combination, with Mariner’s assets and liabilities reflected in Apache’s financial statements at fair value.
3. SUBSEQUENT EVENTS
Agreement to acquire Permian Basin, Egypt and Canada properties from BP
     On July 20, 2010, we announced the signing of three definitive purchase and sale agreements to acquire the properties described below (BP Properties) from subsidiaries of BP plc (collectively referred to as “BP”) for aggregate consideration of $7.0 billion, subject to customary adjustments (BP Acquisition).
     Permian Basin. All of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of West Texas and New Mexico. The assets include interests in 10 field areas in the Permian Basin, (including Block 16/Coy Waha, Block 31, Brown Basset, Empire/Yeso, Pegasus, Southeast Lea, Spraberry, Wilshire, North Misc and Delaware Penn), approximately 405,000 net mineral and fee acres, 358,000 leasehold acres, approximately 3,629 active wells and three gas processing plants, two of which are currently operated by BP. Based on our investigation and review of data provided by BP, these assets produced 15,110 barrels of liquid hydrocarbons (liquids) and 81 MMcf of gas per day in the first six months of 2010. The Permian Basin assets had estimated net proved reserves of 141 MMboe at June 30, 2010 (65 percent liquids).
     Western Canada Sedimentary Basin. Substantially all of BP’s Western Canadian upstream gas assets, including approximately 1,278,000 net mineral and leasehold acres, interests in approximately 1,600 active wells, and eight operated and 14 non-operated gas processing plants. The position includes many drilling opportunities ranging from conventional to several unconventional targets, including shale gas, tight gas and coal bed methane in historically productive formations including the Montney, Cadomin and Doig. Based on our investigation and review of data provided by BP, during the first half of 2010 these properties produced 6,529 barrels of liquids and 240 MMcf of gas per day and had estimated net proved reserves of 224 MMboe at June 30, 2010 (94 percent gas). We currently have operations in approximately half of these 13 field areas.
     Western Desert, Egypt. BP’s interests in four development licenses and one exploration concession (East Badr El Din), covering 394,000 net acres south of El Alamein in the Western Desert of Egypt. These properties are operated by Gulf of Suez Petroleum Company, a joint venture between BP and the Government of Egypt. The transaction includes BP’s interests in 65 active wells, a 24-inch gas line to Dashour, a liquefied petroleum gas plant in Dashour, a gas processing plant in Abu Gharadig and a 12-inch oil export line to the El Hamra Terminal on the Mediterranean Sea. Based on our investigation and review of data provided by BP, during the first six months of 2010 these properties produced 6,016 barrels of oil and 11 MMcf of gas per day of BP’s production, and had estimated net proved reserves of 20 MMboe at June 30, 2010 (59 percent liquids). The BP Properties in Egypt are complementary to the over 11 million gross acres in 21 separate concessions in the Western Desert we currently hold. The Merged Concession Agreement related to the development licenses runs through 2024, subject to a five year extension at the option of the operator.

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     The acquisition is subject to a number of closing conditions, including regulatory approvals in the U.S., Canada and Egypt. On August 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Additional regulatory approvals are pending. Also, some of the BP Properties are subject to preferential rights to purchase interests held by third parties, and those rights may be exercised before or after we close the acquisition. The acquisition is subject to certain post-closing requirements relating to, among other things, resolution of title, environmental and legal issues and any exercise of preferential purchase rights after closing.
     In conjunction with the acquisition, Apache issued 26.45 million shares of common stock and 25.3 million depositary shares, raising net proceeds of $3.5 billion (refer to Note 8 — Capital Stock, of Item 1 of this Form 10-Q for further discussion). The Company plans to fund the acquisition with the proceeds of these offerings and some combination of the following: cash on hand, our existing revolving credit and commercial paper facilities, a 364-day revolving credit facility, the issuance of term debt and the short term use of a bridge loan facility. The Company intends to increase its commercial paper program by $1 billion, the amount of the new 364-day revolving credit facility. We also secured a $5 billion bridge loan facility to backstop our financing requirements. The commitment under the bridge loan facility has been reduced by $3.5 billion, which is the amount of the net proceeds from the common stock and mandatory convertible preferred offerings discussed above. Depending on when the closing of the acquisition of the Permian Basin BP Properties occurs, we may fund a portion of the amount due for those properties by drawing under the bridge loan facility. Any such borrowing would be repaid from the Company’s next debt offering. Under the purchase and sale agreement, Apache advanced $5 billion of the purchase price to BP plc on July 30, 2010, ahead of the anticipated closings. This advance will be returned to Apache or applied to the purchase price at closing. BP plc provided a limited guarantee with respect to the purchase and sale agreements, principally as to the return of the advance.
4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies for Using Derivative Instruments
     The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Management occasionally manages the variability in cash flows by entering into hedges on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices. Derivative instruments typically entered into are designated as cash flow hedges.
Counterparty Risk
     The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of counterparties, primarily financial institutions, for its derivative transactions. As of June 30, 2010, Apache had positions with 16 counterparties, all but one of which were rated A or higher by Standard & Poor’s and A2 or higher by Moody’s. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should any or all of these counterparties not perform, Apache may not realize the benefit of some or all of its derivative instruments resulting from lower commodity prices.
     The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs a material deterioration in its credit ratings, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement.
Commodity Derivative Instruments
     As of June 30, 2010, Apache had the following open crude oil derivative positions:
                                         
    Fixed-Price Swaps   Collars
            Weighted           Weighted   Weighted
Production           Average           Average   Average
Period   Mbbls   Fixed Price(1)   Mbbls   Floor Price(1)   Ceiling Price(1)
 
                                       
2010
    1,840     $ 70.10       5,474     $ 67.37     $ 84.51  
2011
    3,650       70.12       8,575       69.09       90.12  
2012
    3,292       70.99       5,482       72.17       95.34  
2013
    1,451       72.01       2,416       78.02       103.06  
2014
    76       74.50                    
 
(1)   Crude oil prices represent a weighted average of several contracts entered into on a per barrel basis. Crude oil contracts are primarily settled against NYMEX WTI Cushing Index.

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     As of June 30, 2010, Apache had the following open natural gas derivative positions:
                                                         
    Fixed-Price Swaps   Collars
                    Weighted                   Weighted   Weighted
Production   MMBtu   GJ   Average   MMBtu   GJ   Average   Average
Period   (in 000’s)   (in 000’s)   Fixed Price(1)   (in 000’s)   (in 000’s)   Floor Price(1)   Ceiling Price(1)
 
                                                       
2010
    45,540           $ 5.72       14,720           $ 5.41     $ 6.91  
2010
          27,600     C$ 5.37                          
2011
    46,538           $ 6.13       9,125           $ 5.00     $ 8.85  
2011
          51,100     C$ 6.26             3,650     C$ 6.50     C$ 7.10  
2012
    19,215           $ 6.51       21,960           $ 5.54     $ 7.30  
2012
          43,920     C$ 6.61             7,320     C$ 6.50     C$ 7.27  
2013
    1,825           $ 7.05       6,825           $ 5.35     $ 6.67  
2014
    755           $ 7.23                          
 
(1)   U.S. natural gas prices represent a weighted average of several contracts entered into on a per million British thermal units (MMBtu) basis and are settled primarily against NYMEX Henry Hub and various Inside FERC indices. The Canadian natural gas prices represent a weighted average of AECO Index prices and are shown in Canadian dollars. The Canadian gas contracts are entered into on a per gigajoule (GJ) basis and are settled against AECO Index.
     As of June 30, 2010, Apache had the following open natural gas financial basis swap contracts:
                 
            Weighted
    MMBtu   Average
Production Period   (in 000’s)   Price Differential(1)
 
               
2010
    21,160     $ (0.54 )
2011
    18,250     $ (0.30 )
2012
    10,980     $ (0.36 )
 
(1)   Natural gas financial basis swap contracts represent a weighted average differential between prices primarily against Inside FERC PEPL and NYMEX Henry Hub prices.
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
     The Company accounts for derivative instruments and hedging activity in accordance with Accounting Standards Codification (ASC) Topic 815, “Derivatives and Hedging,” and all derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The fair market value of the Company’s derivative assets and liabilities are as follows:
                 
    June 30,     December 31,  
    2010     2009  
    (In millions)  
 
               
Current Assets: Prepaid assets and other
  $ 145     $ 13  
Other Assets: Deferred charges and other
    155       51  
 
           
Total Derivative Assets
  $ 300     $ 64  
 
           
 
               
Current Liabilities: Other
  $ 36     $ 128  
Noncurrent Liabilities: Other
    65       202  
 
           
Total Derivative Liabilities
  $ 101     $ 330  
 
           
     The methods and assumptions used to estimate the fair values of the Company’s commodity derivative instruments and gross amounts of commodity derivative assets and liabilities are more fully discussed in Note 10 — Fair Value Measurements.

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Commodity Derivative Activity Recorded in Statement of Consolidated Operations
     The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
                                         
    Gain (Loss) on Derivatives     For the Quarter
Ended
    For the Six Months
Ended
 
    Recognized In Income     June 30,     June 30,  
            2010     2009     2010     2009  
                    (In millions)          
Gain (loss) reclassified from accumulated other comprehensive income (loss)
  Oil and Gas Production                                
into operations (effective portion)
  Revenues   $ 52     $ 52     $ 51     $ 108  
Gain (loss) derivatives recognized in operations (ineffective portion and basis)
  Revenues and Other: Other   $     $ (1   $ (1   $ (4 )
Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)
     As of June 30, 2010, substantially all of the Company’s derivative instruments were designated as cash flow hedges in accordance with ASC Topic 815. A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders’ equity related to Apache’s cash flow hedges is presented in the table below:
                                 
    For the Six Months Ended June 30,  
    2010     2009  
    Before
tax
    After
tax
    Before
tax
    After
tax
 
    (In millions)  
 
Unrealized gain (loss) on derivatives at beginning of period
  $ (267 )   $ (170 )   $ 212     $ 138  
Realized amounts reclassified into earnings
    (51 )     (33 )     (108 )     (73 )
Net change in derivative fair value
    514       346       (196 )     (122 )
Ineffectiveness reclassified into earnings
    1       1       1        
 
                       
 
                               
Unrealized gain (loss) on derivatives at end of period
  $ 197     $ 144     $ (91 )   $ (57 )
 
                       
     Based on market prices as of June 30, 2010, the Company’s net unrealized income in accumulated other comprehensive income (loss) for commodity derivatives designated as cash flow hedges totaled a gain of $197 million ($144 million after tax). Gains and losses on hedges will be realized in future earnings through mid-2014, contemporaneously with the related sales of natural gas and crude oil production applicable to specific hedges. Included in accumulated other comprehensive income (loss) as of June 30, 2010 is a net gain of approximately $109 million ($77 million after tax) that applies to the next 12 months; however, estimated and actual amounts are likely to vary materially as a result of changes in market conditions.
5. ASSET RETIREMENT OBLIGATION
     The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the six months ended June 30, 2010:
         
 
  (In millions)
 
       
Asset retirement obligation at December 31, 2009
  $ 1,784  
Liabilities incurred
    314  
Liabilities settled
    (125 )
Accretion expense
    49  
 
       
 
     
Asset retirement obligation at June 30, 2010
    2,022  
 
       
Less current portion
    (147 )
 
     
Asset retirement obligation, long-term
  $ 1,875  
 
     

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     The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. To determine the current present value of this obligation, some key assumptions the Company must estimate include the ultimate productive life of the properties, a risk adjusted discount rate and an inflation factor. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. The period includes $233 million of liabilities incurred related to the Devon acquisition which closed in June, 2010.
6. DEBT
     As of June 30, 2010, the Company had unsecured committed revolving syndicated bank credit facilities totaling $2.3 billion, which mature in May 2013. These consist of a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. Since there are no outstanding borrowings or commercial paper at quarter-end, the full $2.3 billion of unsecured credit facilities are available to the Company.
     The Company has available a $1.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2013.
     One of the Company’s Australian subsidiaries has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The facility provides for total commitments of up to $350 million, with availability determined by a borrowing base formula. The borrowing base was initially set at $350 million and will be redetermined upon project completion, as defined in the facility, which is expected to occur in the fourth quarter of 2010, and semi-annually thereafter. The Company has agreed to guarantee the credit facility until project completion. In the event project completion does not occur by December 31, 2010, pursuant to the terms of the facility, the lenders may require repayment of outstanding amounts in the first quarter of 2011.
     The outstanding balance under the facility as of June 30, 2010 was $300 million in accordance with the terms of the facility, down from $350 million on December 31, 2009. Under the terms of the agreement, the facility amount was reduced initially on June 30, 2010 and will be further reduced semi-annually thereafter until maturity on March 31, 2014. As $60 million and $55 million of the existing balance will be repaid by December 31, 2010 and June 30, 2011, respectively, $115 million has been classified as current debt at June 30, 2010.
     At June 30, 2010 and December 31, 2009, there was $1.2 million and $7.3 million, respectively, borrowed on uncommitted overdraft lines in Argentina and the U.S.
Financing Costs, Net
     Financing costs incurred during the periods noted are composed of the following:
                                 
    For the Quarter Ended     For the Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
            (In millions)          
 
                               
Interest expense
  $ 75     $ 77     $ 151     $ 156  
Amortization of deferred loan costs
    1       1       3       3  
Capitalized interest
    (18 )     (15 )     (35 )     (31 )
Interest income
    (2 )     (2 )     (4 )     (8 )
 
                       
Financing costs, net
  $ 56     $ 61     $ 115     $ 120  
 
                       

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7. INCOME TAXES
     The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. There were no significant discrete tax events that occurred during the first six months of 2010. The 2009 year-to-date tax provision includes the impact of the non-cash write-down of proved oil and gas properties, which was recognized as a discrete item in the first quarter of 2009.
     Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is in Administrative Appeals with the United States Internal Revenue Service (IRS) regarding the 2004 through 2007 tax years and under audit for the 2008 tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.
8. CAPITAL STOCK
Net Income (Loss) per Common Share
     A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and six-month periods ended June 30, 2010 and 2009 is presented in the table below. The loss for the first six months of 2009 reflects a $1.98 billion after-tax write-down of the carrying value of the Company’s March 31, 2009, proved property balances in the U.S. and Canada.
                                                 
    For the Quarter Ended June 30,  
    2010     2009  
    Income     Shares     Per Share     Income     Shares     Per Share  
    (In millions, except per share amounts)  
Basic:
                                               
Income attributable to common stock
  $ 860       338     $ 2.55     $ 443       336     $ 1.32  
 
                                           
 
                                               
Effect of Dilutive Securities:
                                               
Stock options and other
          1                     1          
 
                                       
 
                                               
Diluted:
                                               
Income attributable to common stock, including assumed conversions
  $ 860       339     $ 2.53     $ 443       337     $ 1.31  
 
                                   
                                                 
    For the Six Months Ended June 30,  
    2010     2009  
    Income     Shares     Per Share     Loss     Shares     Per Share  
    (In millions, except per share amounts)  
Basic:
                                               
Income (loss) attributable to common stock
  $ 1,565       337     $ 4.64     $ (1,315 )     335     $ (3.92 )
 
                                           
 
                                               
Effect of Dilutive Securities:
                                               
Stock options and other
          2                              
 
                                       
 
                                               
Diluted:
                                               
Income (loss) attributable to common stock, including assumed conversions
  $ 1,565       339     $ 4.61     $ (1,315 )     335     $ (3.92 )
 
                                   
     The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 3.3 million and 4.1 million for the quarters ending June 30, 2010 and 2009 and 2.9 million and 3.9 million for the six months ended June 30, 2010 and 2009, respectively. The provisions of ASC Topic 260, “Earnings Per Share,” state that unvested share-based payment awards that contain rights to receive non-forfeitable dividends or dividend equivalents are participating securities prior to vesting and are required to be included in the earnings allocations in computing basic EPS under the two-class method. These participating securities had a negligible impact on earnings per share.

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Common and Preferred Stock Dividends
     For the quarter ending June 30, 2010 and 2009, Apache paid $51 million and $50 million, respectively, in dividends on its common stock. In both six-month periods ended June 30, 2010 and 2009, the Company paid $101 million in dividends on its common stock. In the three-and six-month periods ended June 30, 2009, Apache paid a total of $1.4 million and $2.8 million, respectively, in dividends on its Series B Preferred Stock issued in August 1998. The Company redeemed all outstanding shares of its Series B Preferred Stock on December 30, 2009.
Stock-Based Compensation
     Share Appreciation Plans
     The Company utilizes share appreciation plans from time to time to provide incentives for substantially all full-time employees to increase Apache’s share price within a stated measurement period. To achieve the payout under those plans, the Company’s stock price must close at or above a stated threshold for 10 out of any 30 consecutive trading days before the end of the stated period. Since 2005, two separate share appreciation plans have been approved. A summary of these plans follows:
    On May 7, 2008, the Stock Option Plan Committee of the Company’s Board of Directors, pursuant to the Company’s 2007 Omnibus Equity Compensation Plan, approved the 2008 Share Appreciation Program, with a target to increase Apache’s share price to $216 by the end of 2012 and an interim goal of $162 to be achieved by the end of 2010. Any awards under the plan would be payable in five equal annual installments. As of June 30, 2010, neither share price threshold had been met.
 
    On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan, with a target to increase Apache’s share price to $108 by the end of 2008 and an interim goal of $81 to be achieved by the end of 2007. Awards under the plan were payable in four equal annual installments to eligible employees remaining with the Company. Apache’s share price exceeded the interim $81 threshold for the 10-day requirement on June 14, 2007. The final installment was awarded in June 2010. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008. The third installment was awarded in March 2010.
     2010 Performance Program and Restricted Stock Awards
     To provide long-term incentives for Apache employees to deliver competitive returns to our stockholders, in November 2009, the Company’s Board of Directors approved the 2010 Performance Program, pursuant to the 2007 Omnibus Equity Compensation Plan. Eligible employees were granted initial conditional restricted stock units totaling 541,440 units. The ultimate number of restricted stock units to be awarded,will be based upon measurement of the total shareholder return of Apache common stock as compared to a designated peer group during a three-year performance period. Should any restricted stock units be awarded at the end of the three-year performance period, December 31, 2012, 50 percent of restricted stock units awarded will immediately vest, and an additional 25 percent will vest on the two succeeding anniversaries following the end of the performance period. In January 2010, the Company’s Board of Directors also approved one-time restricted stock unit awards totaling 502,470 shares to eligible Apache employees, with one-third of the units granted immediately vesting and an additional one-third vesting on each of the first and second anniversaries of the grant date.
Subsequent Events
     Common and Depositary Share Offerings
     In conjunction with the BP Acquisition, Apache issued 26.45 million shares of common stock at a public offering price of $88.00 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering were approximately $2.3 billion. The initial offering of 21 million shares was increased to 23 million shares and the underwriters exercised their option to purchase an additional 3.45 million shares. The Company also received proceeds of $1.2 billion, after underwriting discounts and before expenses, from the sale of 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00% Mandatory Convertible Preferred Stock, Series D, with an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). The Company offered 22 million depositary shares and the underwriters exercised their option to purchase an additional 3.3 million depositary shares. Net proceeds to the Company from the common stock and depositary share offerings totaled approximately $3.5 billion after underwriting discounts and before expenses.
9. COMMITMENTS AND CONTINGENCIES
Legal Matters
     Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $23 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position or results of operations after consideration of recorded accruals. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position or results of operations.
Argentine Environmental Claims
     In connection with the acquisition from Pioneer in 2006, the Company acquired a subsidiary of Pioneer in Argentina (PNRA) that is involved in various administrative proceedings with environmental authorities in the Neuquén Province relating to permits for and discharges from operations in that province. In addition, PNRA was named in a suit initiated against oil companies operating in the Neuquén basin entitled Asociación de Superficiarios de la Patagonia v YPF S.A., et. al., originally filed on August 21, 2003, in the Argentine National Supreme Court of Justice. The plaintiffs, a private group of landowners, have also named the national government and several provinces as third parties. The lawsuit alleges injury to the environment generally by the oil and gas industry. The plaintiffs principally seek from all defendants, jointly, (i) the remediation of contaminated sites, of the superficial and underground waters, and of soil that allegedly was degraded as a result of deforestation, (ii) if the remediation is not possible, payment of an indemnification for the material and moral damages claimed from defendants operating in the Neuquén basin, of which PNRA is a small portion, (iii) adoption of all the necessary measures to prevent future environmental damages, and (iv) the creation of a private restoration fund to provide coverage for remediation of potential future environmental damages. Much of the alleged damage relates to operations by the Argentine state oil company, which conducted oil and gas operations throughout Argentina prior to its privatization, which began in 1990. While the plaintiffs will seek to make all oil and gas companies operating in the Neuquén basin jointly liable for each others’ actions, PNRA will defend on an individual basis and attempt to require the plaintiffs to delineate damages by company. PNRA intends to defend itself vigorously in the case. It is not certain exactly how or what the court will do in this matter as it is the first of its kind. While it is possible PNRA may incur liabilities related to the environmental claims, no reasonable prediction can be made as PNRA’s exposure related to this lawsuit is not currently determinable.

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Louisiana Restoration
     Numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages from contamination and cleanup. Many of these lawsuits claim small amounts, while others assert claims in excess of one million dollars. Also, some lawsuits or claims are being settled or resolved, while others are still being filed. Any exposure, therefore, related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend the cases.
Hurricane Related Litigation
     In a case styled Ned Comer, et al vs. Murphy Oil USA, Inc., et al, Case No: 1:05-cv-00436; U.S.D.C., United States District Court, Southern District of Mississippi, Mississippi property owners allege that hurricanes’ meteorological effects increased in frequency and intensity due to global warming, and there will be continued future damage from increasing intensity of storms and sea level rises. They claim this was caused by the various defendants (oil and gas companies, electric and coal companies, and chemical manufacturers). Plaintiffs claim defendants’ emissions of “greenhouse gases” cause global warming, which they blame as the cause of their damages. They also claim that the oil company defendants artificially inflated and manipulated the prices of gasoline, diesel fuel, jet fuel, natural gas, and other end-use petrochemicals, and covered it up by misrepresentations. They further allege a conspiracy to disseminate misinformation and cover up the relationship between the defendants and global warming. Plaintiffs seek, among other damages, actual, consequential, and punitive or exemplary damages. The District Court dismissed the case on August 30, 2007. The plaintiffs appealed the dismissal. Prior to the dismissal, the plaintiffs filed a motion to amend the lawsuit to add additional defendants, including Apache. On October 16, 2009, the United States Court of Appeals for the Fifth Circuit reversed the judgment of the District Court and remanded the case to the District Court. The Fifth Circuit held that plaintiffs have pleaded sufficient facts to demonstrate standing for their public and private nuisance, trespass, and negligence claims, and that those claims are justifiable and do not present a political question. However, the Fifth Circuit declined to find standing for the unjust enrichment, civil conspiracy, and fraudulent misrepresentation claims, and therefore dismissed those claims. Several defendants filed a petition with the Fifth Circuit for a rehearing en banc. In granting an appeal for an en banc hearing, the U.S. Fifth Circuit Court of Appeals vacated an earlier ruling by its three-member panel. That decision reinstated the district judge’s dismissal of the lawsuit. Subsequently, the Fifth Circuit Court of Appeals could not form a quorum to hear the en banc appeal. Therefore, the court ruled that its earlier order (vacating the panel’s ruling) stood, which had the effect of dismissing the original lawsuit. An appeal by the plaintiffs to the U.S. Supreme Court is possible.
Australia Gas Pipeline Force Majeure
     The Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas to customers under various long-term contracts. Company subsidiaries believe that the event was a force majeure and as a result, the subsidiaries and their joint venture participants have declared force majeure under those contracts. On December 16, 2009, a customer, Burrup Fertilisers Pty Ltd, filed a lawsuit on behalf of itself and certain of its underwriters at Lloyd’s London and other insurers, against the Company and its subsidiaries in Texas state court, asserting claims for negligence, breach of contract, alter ego, single business enterprise, res ipsa loquitur, and gross negligence/exemplary damages. Other customers have threatened to file suit challenging the declaration of force majeure under their contracts. Contract prices under their contracts are significantly below current spot prices for natural gas in Australia. In the event it is determined that the pipeline explosion was not a force majeure, Company subsidiaries believe that liquidated damages should be the extent of the damages under those long-term contracts with such provisions. Approximately 90 percent of the natural gas volumes sold by Company subsidiaries under long-term contracts have liquidated damages provisions. Contractual liquidated damages under the long-term contracts with such provisions would not be expected to exceed $200 million AUD. In their Harris County petition, Burrup Fertilisers and its underwriters and insurers seek to recover unspecified actual damages, cost of repair and replacement, exemplary damages, lost profits, loss of business goodwill, value of the gas lost under the GSA, interest and court costs. No assurance can be given that Burrup Fertilisers and other customers would not assert claims in excess of contractual liquidated damages, and exposure related to such claims is not currently determinable. While an adverse judgment against Company subsidiaries (and Company, in the case of the Burrup Fertilisers lawsuit) is possible, Company and Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims.
     In December 2008, the Senate Economics Committee of the Parliament of Australia released its findings from public hearings concerning the economic impact of the gas shortage following the explosion on Varanus Island and the government’s response. The Committee concluded, among other things, that the macroeconomic impact to Western Australia will never be precisely known, but cited to a range of estimates from $300 million AUD to $2.5 billion AUD consisting in part of losses alleged by some parties who have long-term contracts with Company subsidiaries (as described above), but also losses alleged by third parties who do not have contracts with Company subsidiaries (but who may have purchased gas that was re-sold by customers or who may have paid more for energy following the explosion or who lost wages or sales due to the inability to obtain energy or the increased price of energy). A timber industry group, whose members do not have a contract with Company subsidiaries, has announced that it intends to seek compensation for its members and their subcontractors from Company subsidiaries for $20 million AUD in losses allegedly incurred as a result of the gas supply shortage following the explosion. In Johnson Tiles Pty Ltd v. Esso Australia Pty Ltd [2003] VSC 27 (Supreme Court of Victoria, Gillard J presiding), which concerned a 1998 explosion at an Esso natural gas processing plant at Longford in East Gippsland, Victoria, the Court held that Esso was not liable for $1.3 billion AUD of pure economic losses suffered by claimants that had no contract with Esso, but was liable to such claimants for reasonably foreseeable property damage which Esso settled for $32.5 million plus costs. In reaching this decision the Court held that third-party claimants should have protected themselves from pure economic losses, through the purchase of insurance or the installation of adequate backup measures, in case of an interruption in their gas supply from Esso. While an adverse judgment against Company subsidiaries is possible if litigation is filed, Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims. Exposure related to any such potential claims is not currently determinable.

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     On October 10, 2008, the Australia National Offshore Petroleum Safety Authority (NOPSA) released a self-titled “Final Report” of the findings of its investigation into the pipeline explosion, prepared at the request of the Western Australian Department of Industry and Resources (DoIR). NOPSA concluded in its report that the evidence gathered to date indicates that the main causal factors in the incident were: (1) ineffective anti-corrosion coating at the beach crossing section of the 12 inch sales gas pipeline, due to damage and/or dis-bondment from the pipeline; (2) ineffective cathodic protection of the wet-dry transition zone of the beach crossing section of the 12 inch sales gas pipeline; and (3) ineffective inspection and monitoring by Company subsidiaries of the beach crossing and shallow water section of the 12 inch sales gas pipeline. NOPSA further concluded that the investigation identified that Apache Northwest Pty Ltd and its co-licensees may have committed offences under the Petroleum Pipelines Act 1969, Sections 36A & 38(b) and the Petroleum Pipelines Regulations 1970, Regulation 10, and that some findings may also constitute non-compliance with pipeline license conditions. NOPSA states in its report that an application for renewal of the pipeline license covering the area of the Varanus Island facility was granted in May 1985 with 21 years validity, and an application for renewal of the license was submitted to DoIR by Company subsidiaries in December 2005 and remains pending.
     Company subsidiaries disagree with NOPSA’s conclusions and believe that the NOPSA report is premature, based on an incomplete investigation and misleading. In a July17, 2008, media statement, DoIR acknowledged, “The pipelines and Varanus Island facilities have been the subject of an independent validation report [by Lloyd’s Register] which was received in August 2007. NOPSA has also undertaken a number of inspections between 2005 and the present.” These and numerous other inspections, audits and reviews conducted by top international consultants and regulators did not identify any warnings that the pipeline had a corrosion problem or other issues that could lead to its failure. Company subsidiaries believe that the explosion was not reasonably foreseeable, and was not within the reasonable control of Company’s subsidiaries or able to be reasonably prevented by Company subsidiaries.
     On January 9, 2009, the governments of Western Australia and the Commonwealth of Australia announced a joint inquiry to consider the effectiveness of the regulatory regime for occupational health and safety and integrity that applied to operations and facilities at Varanus Island and the role of DoIR, NOPSA and the Western Australian Department of Consumer and Employment Protection (DoCEP). The joint inquiry’s report was published in June 2009.
     On May 8, 2009, the government of Western Australia announced that its Department of Mines and Petroleum (DMP) will carry out “the final stage of investigations into the Varanus Island gas explosion.” Inspectors were appointed under the Petroleum Pipelines Act to coordinate the final stage of the investigations. Their report has been delivered to the Minister for Mines and Petroleum, but neither the report nor its contents have been made available to Company subsidiaries for their review and comment.
     On May 28, 2009, the DMP filed a prosecution notice in the Magistrates Court of Western Australia, charging Apache Northwest Pty Ltd and its co-licensees with failure to maintain a pipeline in good condition and repair under the Petroleum Pipelines Act 1969, Section 38(b). The maximum fine associated with the alleged offense is $50,000 AUD. The Company subsidiary does not believe that the charge has merit and plans to vigorously pursue its defenses.
Seismic License
     In December 1996, the Company and Fairfield Industries Incorporated entered into a Master Licensing Agreement for the licensing of seismic data relating to certain blocks in the Gulf of Mexico. The Company and Fairfield also entered into supplemental agreements specifying the data to be licensed to the Company as well as the consideration due Fairfield. In February 2009, the Company filed an action in Texas state court seeking a declaration of the parties’ contractual obligations. The Company and its subsidiary, GOM Shelf LLC, have also asserted a claim to recover damages for certain overpayments to Fairfield under the parties’ agreements. Fairfield and a related entity, Fairfield Royalty Corporation, counterclaimed. As a result of a nonbinding mediation on July 21-22, 2010, the parties have resolved the matter amicably, which resolution did not have a material affect on the Company.
Mariner Stockholder Lawsuits
     In connection with the Merger, two shareholder lawsuits styled as class actions have been filed against Mariner and its board of directors. The lawsuits are entitled City of Livonia Employees’ Retirement System, Individually and on Behalf of All Others Similarly Situated vs. Mariner Energy, Inc, et al., (filed April 16, 2010 in the District Court of Harris County, Texas), and Southeastern Pennsylvania Transportation Authority, individually, and on behalf of all those similarly situated,vs. Scott D. Josey, et.al., (filed April 21, 2010 in the Court of Chancery in the State of Delaware). The Southeastern Pennsylvania Transportation Authority lawsuit also names Apache and its wholly owned subsidiary, ZMZ Acquisitions LLC (the Merger Sub) as defendants. The complaints generally allege that (1) Mariner’s directors breached their fiduciary duties in negotiating and approving the Merger and by administering a sale process that failed to maximize shareholder value and (2) Mariner, and in the case of the Southeastern Pennsylvania Transportation Authority complaint, Apache and the Merger Sub, aided and abetted Mariner’s directors in breaching their fiduciary duties. The City of Livonia Employees’ Retirement System complaint also alleges that Mariner’s directors and executives stand to receive substantial financial benefits if the transaction is consummated on its current terms. Pending court approval, these lawsuits have been settled, in principle and are not expected to have a material impact on Apache.
Marbob Energy Corporation and Concho Resources Lawsuits
     Marbob Energy Corporation, Concho Resources and other parties have filed lawsuits against BP America Inc, BP America Production Company (“BP”), and ZPZ Delaware I LLC (“ZPZ”), Apache’s wholly owned subsidiary, in New Mexico seeking a declaratory judgment that Plaintiffs are entitled to receive preferential rights to purchase (“PPR”) notices on certain of the properties that are included in the Purchase and Sale Agreement between BP and ZPZ and injunctive relief to force BP promptly to issue to Plaintiffs PPR notices on those properties. Plaintiffs do not seek monetary damages, other than fees and costs incurred in bringing these actions. Apache has agreed to indemnify BP for these actions.
Environmental Matters
     As of June 30, 2010, the Company had an undiscounted reserve for environmental remediation of approximately $24 million. The Company is not aware of any environmental claims existing as of June 30, 2010, which have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
10. FAIR VALUE MEASUREMENTS
     ASC 820, “Fair Value Measurements and Disclosures,” provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.
     The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Assets and Liabilities Measured at Fair Value on a Recurring Basis
     Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:
     Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable and Accounts Payable
     The carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.
     Commodity Derivative Instruments
     Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps and options. The Company uses a market approach to estimate the fair values of derivative instruments, utilizing published commodity futures price strips for the underlying commodities as of the date of the estimate. The fair values of the Company’s derivative instruments are not actively quoted in the open market and are valued using forward commodity price curves provided by a reputable third party. These valuations are Level 2 inputs. See Note 4 — Derivative Instruments and Hedging Activities of this Form 10-Q for further information.
     The following table presents the Company’s material assets and liabilities measured at fair value on a recurring basis for each hierarchy level:

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    Fair Value Measurements Using          
    Quoted Price in       Significant   Total        
    Active Markets   Significant Other   Unobservable Inputs   Fair       Carrying
    (Level 1)   Inputs (Level 2)   (Level 3)   Value   Netting (1)   Amount
                    (In millions)                
June 30, 2010
                                               
Assets:
                                               
Commodity Derivative Instruments
  $  —     $ 346     $  —     $ 346     $ (46 )   $ 300  
 
                                               
Liabilities:
                                               
Commodity Derivative Instruments
          147             147       (46 )     101  
 
                                               
December 31, 2009
                                               
Assets:
                                               
Commodity Derivative Instruments
  $     $ 75     $     $ 75     $ (11 )   $ 64  
 
                                               
Liabilities:
                                               
Commodity Derivative Instruments
          341             341       (11 )     330  
 
(1)   The derivative fair values above are based on analysis of each contract as required by ASC 820. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 4 — Derivative Instruments and Hedging Activities of this Form 10-Q for a discussion of net amounts recorded on the consolidated balance sheet at June 30, 2010 and December 31, 2009.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
     Certain assets and liabilities are reported at fair value on a nonrecurring basis in Apache’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:
     Asset Retirement Obligations Incurred in Current Period
     Apache uses an income approach to estimate the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. AROs incurred in the current period were Level 3 fair value measurements. A summary of changes in the ARO liability is provided in Note 5 — Asset Retirement Obligation of this Form 10-Q.
     Debt
     The Company’s debt is recorded at the carrying amount on its consolidated balance sheet. In accordance with ASC 825, “Financial Instruments,” disclosure of the fair value of total debt is required for interim reporting. Apache uses a market approach to determine the fair value of Apache’s fixed-rate debt using estimates provided by an independent investment banking firm, which is a Level 2 fair value measurement. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The following table presents the carrying amounts and estimated fair values of the Company’s debt at June 30, 2010 and December 31, 2009:
                                 
    June 30, 2010   December 31, 2009
    Carrying   Fair   Carrying   Fair
    Amount   Value   Amount   Value
    (In millions)  
 
                               
Total Debt, Net of Unamortized Discount
  $ 5,012     $ 5,774     $ 5,067     $ 5,635  

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11. COMPREHENSIVE INCOME (LOSS)
     The following table presents the components of Apache’s comprehensive income (loss) for the three-month and six-month periods ended June 30, 2010 and 2009.
                                 
    Three Months Ended     Six Months Ended  
    June 30,     June 30,  
    2010     2009     2010     2009  
            (In millions)          
Comprehensive Income (Loss)
                               
Net income (Loss)
  $ 860     $ 445     $ 1,565     $ (1,312 )
Other Comprehensive Income (Loss)
                               
Commodity hedges
    103       (323 )     464       (303 )
Income tax related to commodity hedges
    (39 )     113       (150 )     108  
 
                       
 
                               
Total
  $ 924     $ 235     $ 1,879     $ (1,507 )
 
                       

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12. BUSINESS SEGMENT INFORMATION
     Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. The Company has production in six countries: the United States, Canada, Egypt, Australia, the United Kingdom (U.K.) and Argentina. Apache also has exploration interests in Chile. Financial information for each country is presented below:
                                                                 
    United                                         Other        
    States     Canada     Egypt     Australia     U.K.     Argentina     International     Total  
                            (In millions)                          
For the Quarter Ended June 30, 2010
                                                               
 
                                                               
Oil and Gas Production Revenues
  $ 962     $ 240     $ 806     $ 452     $ 421     $ 88     $     $ 2,969  
 
                                               
 
                                                               
Operating Income (1)
  $ 452     $ 71     $ 548     $ 285     $ 165     $ 18     $     $ 1,539  
 
                                                 
 
                                                               
Other Income (Expense):
                                                               
Other
                                                            3  
General and administrative
                                                            (92 )
Financing costs, net
                                                            (56 )
 
                                                             
Income Before Income Taxes
                                                          $ 1,394  
 
                                                             
 
                                                               
For the Six Months Ended June 30, 2010
                                                               
 
                                                               
Oil and Gas Production Revenues
  $ 1,954     $ 493     $ 1,547     $ 676     $ 812     $ 180     $     $ 5,662  
 
                                               
 
                                                               
Operating Income (1)
  $ 963     $ 166     $ 1,041     $ 386     $ 313     $ 43     $     $ 2,912  
 
                                                 
 
                                                               
Other Income (Expense):
                                                               
Other
                                                            (17 )
General and administrative
                                                            (179 )
Financing costs, net
                                                            (115 )
 
                                                             
Income Before Income Taxes
                                                          $ 2,601  
 
                                                             
 
                                                               
Total Assets
  $ 12,473     $ 4,243     $ 5,910     $ 3,737     $ 2,526     $ 1,488     $ 55     $ 30,432  
 
                                               
 
                                                               
For the Quarter Ended June 30, 2009
                                                               
 
Oil and Gas Production Revenues
  $ 707     $ 215     $ 655     $ 87     $ 322     $ 88     $     $ 2,074  
 
                                               
 
                                                               
Operating Income (1)
  $ 243     $ 63     $ 441     $ 13     $ 140     $ 20     $     $ 920  
 
                                               
 
                                                               
Other Income (Expense):
                                                               
Other
                                                            19  
General and administrative
                                                            (91 )
Financing costs, net
                                                            (61 )
 
                                                             
Income Before Income Taxes
                                                          $ 787  
 
                                                             
 
                                                               
For the Six Months Ended June 30, 2009
                                                               
 
                                                               
Oil and Gas Production Revenues
  $ 1,303     $ 425     $ 1,075     $ 130     $ 565     $ 180     $     $ 3,678  
 
                                               
 
                                                               
Operating Income (Loss)(1)
  $ (857 )   $ (1,495 )   $ 664     $     $ 228     $ 40     $     $ (1,420 )
 
                                               
 
                                                               
Other Income (Expense):
                                                               
Other
                                                            49  
General and administrative
                                                            (176 )
Financing costs, net
                                                            (120 )
 
                                                             
Loss Before Income Taxes
                                                          $ (1,667 )
 
                                                             
 
                                                               
Total Assets
  $ 10,438     $ 4,435     $ 5,103     $ 3,005     $ 2,025     $ 1,396     $     $ 26,402  
 
                                               
 
(1)   Operating Income (Loss) consists of oil and gas production revenues less depreciation, depletion and amortization, asset retirement obligation accretion, lease operating expenses, gathering and transportation costs, and taxes other than income. The U.S. and Canada operating losses for the six-month period of 2009 include additional depletion of $1.2 billion and $1.6 billion, respectively, to write-down the carrying value of oil and gas properties in the first quarter of 2009.

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13. SUPPLEMENTAL GUARANTOR INFORMATION
     Apache Finance Canada Corporation (Apache Finance Canada) is a subsidiary of Apache and has issued approximately $300 million of publicly-traded notes due in 2029 and an additional $350 million of publicly-traded notes due in 2015 that are fully and unconditionally guaranteed by Apache. The following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.
     Apache Finance Canada has been fully consolidated in Apache’s consolidated financial statements. As such, these condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto, of which this note is an integral part.

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended June 30, 2010
                                         
                    All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
REVENUES AND OTHER:
                                       
Oil and gas production revenues
  $ 861,190     $     $ 2,107,575     $     $ 2,968,765  
Equity in net income (loss) of affiliates
    731,011       39,584       (9,370 )     (761,225 )      
Other
    2,090       14,739       (12,647 )     (1,037 )     3,145  
 
                             
 
    1,594,291       54,323       2,085,558       (762,262 )     2,971,910  
 
                             
 
                                       
OPERATING EXPENSES:
                                       
Depreciation, depletion and amortization
    234,416             495,335             729,751  
Asset retirement obligation accretion
    12,751             12,009             24,760  
Lease operating expenses
    172,185             273,764             445,949  
Gathering and transportation costs
    10,436             32,602             43,038  
Taxes other than income
    32,113             154,720             186,833  
General and administrative
    72,030             20,836       (1,037 )     91,829  
Financing costs, net
    49,141       14,116       (7,500 )           55,757  
 
                             
 
    583,072       14,116       981,766       (1,037 )     1,577,917  
 
                             
 
                                       
INCOME BEFORE INCOME TAXES
    1,011,219       40,207       1,103,792       (761,225 )     1,393,993  
Provision for income taxes
    150,996       9,993       372,781             533,770  
 
                             
 
                                       
NET INCOME
    860,223       30,214       731,011       (761,225 )     860,223  
Preferred stock dividends
                             
 
                             
INCOME ATTRIBUTABLE TO COMMON STOCK
  $ 860,223     $ 30,214     $ 731,011     $ (761,225 )   $ 860,223  
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended June 30, 2009
                                         
              All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
REVENUES AND OTHER:
                                       
Oil and gas production revenues
  $ 640,421     $     $ 1,433,923     $     $ 2,074,344  
Equity in net income of affiliates
    306,956       7,393       3,911       (318,260 )      
Other
    (1,184 )     14,630       6,625       (1,037 )     19,034  
 
                             
 
    946,193       22,023       1,444,459       (319,297 )     2,093,378  
 
                             
 
                                       
OPERATING EXPENSES:
                                       
Depreciation, depletion and amortization
    201,542             371,817             573,359  
Asset retirement obligation accretion
    16,166             10,317             26,483  
Lease operating expenses
    173,639             231,634             405,273  
Gathering and transportation costs
    7,217             26,262             33,479  
Taxes other than income
    20,861             95,080             115,941  
General and administrative
    73,286             18,656       (1,037 )     90,905  
Financing costs, net
    57,959       14,115       (10,919 )           61,155  
 
                             
 
    550,670       14,115       742,847       (1,037 )     1,306,595  
 
                             
 
                                       
INCOME BEFORE INCOME TAXES
    395,523       7,908       701,612       (318,260 )     786,783  
Provision (benefit) for income taxes
    (49,197 )     (3,396 )     394,656             342,063  
 
                             
 
                                       
NET INCOME
    444,720       11,304       306,956       (318,260 )     444,720  
Preferred stock dividends
    1,420                         1,420  
 
                             
INCOME ATTRIBUTABLE TO COMMON STOCK
  $ 443,300     $ 11,304     $ 306,956     $ (318,260 )   $ 443,300  
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2010
                                         
                    All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
REVENUES AND OTHER:
                                       
Oil and gas production revenues
  $ 1,750,315     $     $ 3,912,075     $     $ 5,662,390  
Equity in net income (loss) of affiliates
    1,195,270       63,603       (15,050 )     (1,243,823 )      
Other
    2,798       29,344       (47,298 )     (2,073 )     (17,229 )
 
                             
 
    2,948,383       92,947       3,849,727       (1,245,896 )     5,645,161  
 
                             
 
                                       
OPERATING EXPENSES:
                                       
Depreciation, depletion and amortization
    448,025             920,224             1,368,249  
Asset retirement obligation accretion
    24,720             24,042             48,762  
Lease operating expenses
    337,817             548,378             886,195  
Gathering and transportation costs
    21,050             62,353             83,403  
Taxes other than income
    67,473             296,298             363,771  
General and administrative
    144,496             36,556       (2,073 )     178,979  
Financing costs, net
    101,696       28,236       (14,908 )           115,024  
 
                             
 
    1,145,277       28,236       1,872,943       (2,073 )     3,044,383  
 
                             
 
                                       
INCOME BEFORE INCOME TAXES
    1,803,106       64,711       1,976,784       (1,243,823 )     2,600,778  
Provision for income taxes
    237,902       16,158       781,514             1,035,574  
 
                             
 
                                       
NET INCOME
    1,565,204       48,553       1,195,270       (1,243,823 )     1,565,204  
Preferred stock dividends
                             
 
                             
INCOME ATTRIBUTABLE TO COMMON STOCK
  $ 1,565,204     $ 48,553     $ 1,195,270     $ (1,243,823 )   $ 1,565,204  
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2009
                                         
                    All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
REVENUES AND OTHER:
                                       
Oil and gas production revenues
  $ 1,185,151     $     $ 2,492,807     $     $ 3,677,958  
Equity in net income (loss) of affiliates
    (638,787 )     (534,943 )     141,223       1,032,507        
Other
    392       29,314       21,574       (2,035 )     49,245  
 
                             
 
    546,756       (505,629 )     2,655,604       1,030,472       3,727,203  
 
                             
 
                                       
OPERATING EXPENSES:
                                       
Depreciation, depletion and amortization
    1,643,031             2,329,106             3,972,137  
Asset retirement obligation accretion
    32,475             20,746             53,221  
Lease operating expenses
    346,807             455,955             802,762  
Gathering and transportation costs
    15,696             51,122             66,818  
Taxes other than income
    42,288             160,992             203,280  
General and administrative
    146,177             31,809       (2,035 )     175,951  
Financing costs, net
    111,411       28,228       (19,897 )           119,742  
 
                             
 
    2,337,885       28,228       3,029,833       (2,035 )     5,393,911  
 
                             
 
                                       
LOSS BEFORE INCOME TAXES
    (1,791,129 )     (533,857 )     (374,229 )     1,032,507       (1,666,708 )
Provision (benefit) for income taxes
    (478,909 )     (140,137 )     264,558             (354,488 )
 
                             
 
                                       
NET LOSS
    (1,312,220 )     (393,720 )     (638,787 )     1,032,507       (1,312,220 )
Preferred stock dividends
    2,840                         2,840  
 
                             
LOSS ATTRIBUTABLE TO COMMON STOCK
  $ (1,315,060 )   $ (393,720 )   $ (638,787 )   $ 1,032,507     $ (1,315,060 )
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2010
                                         
                    All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
  $ 1,184,700     $ (36,071 )   $ 1,936,812     $     $ 3,085,441  
 
                             
 
                                       
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Additions to oil and gas property
    (529,851 )           (1,407,762 )           (1,937,613 )
Additions to gas gathering, transmission and processing facilities
                (256,728 )           (256,728 )
Acquisition of Devon properties
    (1,017,238 )                       (1,017,238 )
Short-term investments
                             
Restricted cash for acquisition settlement
                             
Proceeds from sale of oil & gas properties
                             
Investment in subsidiaries, net
    (79,990 )                 79,990        
Other, net
    (44,697 )           37,793             (6,904 )
 
                             
NET CASH USED IN INVESTING ACTIVITIES
    (1,671,776 )           (1,626,697 )     79,990       (3,218,483 )
 
                             
 
                                       
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
Debt borrowings
    1,696       2,403       18,715       (78,198 )     (55,384 )
Payments on debt
                             
Dividends paid
    (101,065 )                       (101,065 )
Common stock activity
    21,346       33,295       (31,503 )     (1,792 )     21,346  
Treasury stock activity, net
    3,591                         3,591  
Cost of debt and equity transactions
    (289 )                       (289 )
Other
    22,073                         22,073  
 
                             
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    (52,648 )     35,698       (12,788 )     (79,990 )     (109,728 )
 
                             
 
                                       
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (539,724 )     (373 )     297,327             (242,770 )
 
                                       
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    646,751       2,097       1,399,269             2,048,117  
 
                             
 
                                       
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 107,027     $ 1,724     $ 1,696,596     $     $ 1,805,347  
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2009
                                         
                    All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
  $ 659,679     $ (22,357 )   $ 729,407     $     $ 1,366,729  
 
                             
 
                                       
CASH FLOWS FROM INVESTING ACTIVITIES:
                                       
Additions to oil and gas property
    (666,421 )           (1,450,994 )           (2,117,415 )
Additions to gas gathering, transmission and processing facilities
                (164,723 )           (164,723 )
Acquisition of Marathon properties
    (181,133 )                       (181,333 )
Short-term investments
    791,999                         791,999  
Restricted cash for acquisition settlement
    13,880                         13,880  
Investment in subsidiaries, net
    (300,472 )                 300,472        
Other, net
    (26,759 )           (58,640 )           (85,399 )
 
                             
NET CASH USED IN INVESTING ACTIVITIES
    (368,906 )           (1,674,357 )     300,472       (1,742,791 )
 
                             
 
                                       
CASH FLOWS FROM FINANCING ACTIVITIES:
                                       
Debt borrowings
    652       40       448,985       (302,011 )     147,666  
Payments on debt
                (100,000 )           (100,000 )
Dividends paid
    (103,331 )                       (103,331 )
Common stock activity
    9,971       20,606       (22,145 )     1,539       9,971  
Treasury stock activity, net
    2,669                         2,669  
Cost of debt and equity transactions
    (403 )                       (403 )
Other
    9,597                         9,597  
 
                             
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    (80,845 )     20,646       326,840       (300,472 )     (33,831 )
 
                             
 
                                       
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    209,928       (1,711 )     (618,110 )           (409,893 )
 
                                       
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    142,026       1,714       1,037,710             1,181,450  
 
                             
 
                                       
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 351,954     $ 3     $ 419,600     $     $ 771,557  
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of June 30, 2010
                                         
                    All Other              
            Apache     Subsidiaries              
    Apache     Finance     of Apache     Reclassifications        
    Corporation     Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
 
                                       
CURRENT ASSETS:
                                       
Cash and cash equivalents
  $ 107,027     $ 1,724     $ 1,696,596     $     $ 1,805,347  
Receivables, net of allowance
    512,646             1,135,306             1,647,952  
Inventories
    42,468             466,234             508,702  
Drilling advances
    12,292       1,884       191,789             205,965  
Prepaid taxes
    102,341             35,215             137,556  
Prepaid assets and other
    (23,929 )           225,347             201,418  
 
                             
 
    752,845       3,608       3,750,487             4,506,940  
 
                             
 
                                       
PROPERTY AND EQUIPMENT, NET
    10,491,336             14,632,119             25,123,455  
 
                             
 
                                       
OTHER ASSETS:
                                       
Intercompany receivable, net
    2,051,441             (551,901 )     (1,499,540 )      
Equity in affiliates
    12,437,431       1,121,775       99,810       (13,659,016 )      
Restricted cash
                             
Goodwill, net
                189,252             189,252  
Deferred charges and other
    182,255       1,002,878       427,627       (1,000,000 )     612,760  
 
                             
 
  $ 25,915,308     $ 2,128,261     $ 18,547,394     $ (16,158,556 )   $ 30,432,407  
 
                             
 
                                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                                       
 
                                       
CURRENT LIABILITIES:
                                       
Accounts payable
  $ 328,438     $ 2,273     $ 1,654,430     $ (1,499,540 )   $ 485,601  
Current Debt
    1,000             115,205             116,205  
Accrued exploration and development
    239,972             655,333             895,305  
Asset retirement obligation
    147,374                         147,374  
Other accrued expenses
    248,793       2,883       306,674             558,350  
 
                             
 
    965,577       5,156       2,731,642       (1,499,540 )     2,202,835  
 
                                       
LONG-TERM DEBT
    4,063,036       647,194       185,897             4,896,127  
 
                             
 
                                       
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
                                       
Income taxes
    1,583,293       4,326       1,659,446             3,247,065  
Asset retirement obligation
    1,043,824             830,919             1,874,743  
Other
    583,818       250,000       702,059       (1,000,000 )     535,877  
 
                             
 
    3,210,935       254,326       3,192,424       (1,000,000 )     5,657,685  
 
                             
 
                                       
COMMITMENTS AND CONTINGENCIES
                                       
 
                                       
SHAREHOLDERS’ EQUITY
    17,675,760       1,221,585       12,437,431       (13,659,016 )     17,675,760  
 
                             
 
  $ 25,915,308     $ 2,128,261     $ 18,547,394     $ (16,158,556 )   $ 30,432,407  
 
                             

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2009
                                         
                    All Other              
                    Subsidiaries              
    Apache     Apache     of Apache     Reclassifications        
    Corporation     Finance Canada     Corporation     & Eliminations     Consolidated  
    (In thousands)  
ASSETS
                                       
CURRENT ASSETS:
                                       
Cash and cash equivalents
  $ 646,751     $ 2,097     $ 1,399,269     $     $ 2,048,117  
Receivables, net of allowance
    576,379             969,320             1,545,699  
Inventories
    50,946             482,305             533,251  
Drilling advances
    13,103       1,095       216,535             230,733  
Prepaid taxes
    142,675             3,978             146,653  
Prepaid assets and other
    8,876             72,520             81,396  
 
                             
 
    1,438,730       3,192       3,143,927             4,585,849  
 
                             
 
PROPERTY AND EQUIPMENT, NET
    9,009,753             13,890,862             22,900,615  
 
                             
OTHER ASSETS:
                                       
Intercompany receivable, net
    1,973,243             (482,366 )     (1,490,877 )      
Equity in affiliates
    11,132,891       980,709       98,615       (12,212,215 )      
Goodwill, net
                189,252             189,252  
Deferred charges and other
    133,557       1,003,037       373,433       (1,000,000 )     510,027  
 
                             
 
  $ 23,688,174     $ 1,986,938     $ 17,213,723     $ (14,703,092 )   $ 28,185,743  
 
                             
 
                                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                                       
CURRENT LIABILITIES:
                                       
Accounts payable
  $ 258,507     $ (88 )   $ 1,629,022     $ (1,490,877 )   $ 396,564  
Accrued exploration and development
    244,188             678,896             923,084  
Current debt
                117,326             117,326  
Asset retirement obligation
    146,654                         146,654  
Other accrued expenses
    347,104       6,121       455,705             808,930  
 
                             
 
    996,453       6,033       2,880,949       (1,490,877 )     2,392,558  
 
                             
 
LONG-TERM DEBT
    4,062,339       647,152       240,899             4,950,390  
 
                             
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
                                       
Income taxes
    1,347,642       4,429       1,412,830             2,764,901  
Asset retirement obligation
    817,507             819,850             1,637,357  
Other
    685,612       250,000       726,304       (1,000,000 )     661,916  
 
                             
 
    2,850,761       254,429       2,958,984       (1,000,000 )     5,064,174  
 
                             
COMMITMENTS AND CONTINGENCIES
                                       
SHAREHOLDERS’ EQUITY
    15,778,621       1,079,324       11,132,891       (12,212,215 )     15,778,621  
 
                             
 
  $ 23,688,174     $ 1,986,938     $ 17,213,723     $ (14,703,092 )   $ 28,185,743  
 
                             

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ITEM 2   – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     Apache Corporation, a Delaware corporation formed in 1954, together with its subsidiaries (collectively, Apache) is one of the world’s largest independent oil and gas companies with exploration and production interests in the United States, Canada, Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea) and Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego.
     This discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with our consolidated financial statements and accompanying notes included under Part I, Item 1, of this Quarterly Report on Form 10-Q, as well as our consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our most recent Annual Report on Form 10-K.
Earnings and Cash Flow
     Record production and higher relative prices drove second-quarter 2010 earnings to $860 million, or $2.53 per diluted common share, up from $443 million, or $1.31 per share, in the comparable year-ago period. Apache’s 2010 second-quarter adjusted earnings(1), which exclude certain items impacting the comparability of results, were $829 million, or $2.44 per diluted common share, compared to $474 million, or $1.41 per share in the year-earlier period. Net cash provided by operating activities increased to $1.9 billion from $824 million in the second quarter of 2009.
     For the first half of 2010, earnings totaled $1.57 billion, or $4.61 per share, compared to a loss of $1.32 billion, or $3.92 per share in 2009. The 2009 results reflect the impact of a $1.98 billion non-cash after-tax write-down of the carrying value of our U.S. and Canadian proved oil and gas properties. Apache’s 2010 first-half adjusted earnings(1) were $1.54 billion, or $4.54 per diluted common share, compared to $693 million, or $2.05 per share, in the year-earlier period. Net cash provided by operating activities increased to $3.1 billion from $1.4 billion in the first half of 2009.
     The improvement in 2010 second-quarter and six-month earnings and cash flow was driven by record second-quarter production, substantially higher oil price realizations and moderate increases in gas price realizations. Second-quarter 2010 production averaged a record 646,866 barrels of oil equivalent per day (boe/d), up 10 percent from 2009, led by Australia’s 60,680 barrels per day (b/d), a nearly six-fold increase over the 2009 flow rate. Australia’s production gains came from the Van Gogh and Pyrenees developments which were commissioned in the first quarter of 2010.
 
(1)   See Results of Operations – Non-GAAP Measures – Adjusted Earnings for a description of Adjusted Earnings, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and reconciliation to this measure from Income (Loss) Attributable to Common Stock, which is presented in accordance with GAAP.
BP Asset Acquisition
     On July 20, 2010, we announced the signing of three definitive purchase and sale agreements (BP Purchase Agreements) to acquire the properties described below (BP Properties) from subsidiaries of BP plc (collectively referred to as “BP”) for aggregate consideration of $7.0 billion, subject to customary adjustments in accordance with the BP Purchase Agreements (BP Acquisition).
     Permian Basin. All of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of West Texas and New Mexico. The assets include interests in 10 field areas in the Permian Basin, (including Block 16/Coy Waha, Block 31, Brown Basset, Empire/Yeso, Pegasus, Southeast Lea, Spraberry, Wilshire, North Misc and Delaware Penn), approximately 405,000 net mineral and fee acres, 358,000 leasehold acres, approximately 3,629 active wells and three gas processing plants, two of which are currently operated by BP. Based on our investigation and review of data provided by BP, these assets produced 15,110 barrels of liquid hydrocarbons (liquids) and 81 million cubic feet of natural gas per day (MMcf/d) in the first six months of 2010. The Permian Basin assets had estimated net proved reserves of 141 million barrels of oil equivalent (MMboe) at June 30, 2010 (65 percent liquids).
     Western Canada Sedimentary Basin. Substantially all of BP’s Western Canadian upstream gas assets, including approximately 1,278,000 net mineral and leasehold acres, interests in approximately 1,600 active wells, and eight operated and 14 non-operated gas processing plants. The position includes many attractive drilling opportunities ranging from conventional to several unconventional targets, including shale

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gas, tight gas and coal bed methane in historically productive formations including the Montney, Cadomin and Doig. Based on our investigation and review of data provided by BP, during the first half of 2010 these properties produced 6,529 barrels of liquids and 240 MMcf of gas per day and had estimated net proved reserves of 224 MMboe at June 30, 2010 (94 percent gas). We currently have operations in approximately half of these 13 field areas.
     Western Desert, Egypt. BP’s interests in four development licenses and one exploration concession (East Badr El Din) covering 394,000 net acres south of El Alamein in the Western Desert of Egypt. These properties are operated by Gulf of Suez Petroleum Company, a joint venture between BP and the Government of Egypt. The transaction includes BP’s interests in 65 active wells, a 24-inch gas line to Dashour, a liquefied petroleum gas plant in Dashour, a gas processing plant in Abu Gharadig and a 12-inch oil export line to the El Hamra Terminal on the Mediterranean Sea. Based on our investigation and review of data provided by BP, during the first six months of 2010 these properties produced 6,016 barrels of oil and 11 MMcf of gas per day of BP’s production, and had estimated net proved reserves of 20 MMboe at June 30, 2010 (59 percent liquids). The BP Properties in Egypt are complementary to the over 11 million gross acres in 21 separate concessions in the Western Desert we currently hold. The Merged Concession Agreement related to the development licenses runs through 2024, subject to a five year extension at the option of the operator.
     The acquisition is subject to a number of closing conditions, including regulatory approvals in the U.S., Canada and Egypt. On August 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Additional regulatory approvals are pending. Also, some of the BP Properties are subject to preferential rights to purchase interests held by third parties, and those rights may be exercised before or after we close the acquisition. The acquisition is subject to certain post-closing requirements relating to, among other things, resolution of title, environmental and legal issues and any exercise of preferential purchase rights after closing.
     Common and Depositary Share Offering In conjunction with the acquisition, Apache issued 26.45 million shares of common stock at a public offering price of $88.00 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering were approximately $2.3 billion. The Company also received proceeds, after underwriting discounts and before expenses, of $1.2 billion from the sale of 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00% Mandatory Convertible Preferred Stock, Series D, with an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). Proceeds to the Company from the common stock and depositary share offerings, after underwriting discounts and before expenses, totaled approximately $3.5 billion.
     The Company plans to fund the acquisition with the proceeds of these offerings and some combination of the following: cash on hand, our existing revolving credit and commercial paper facilities, a 364-day revolving credit facility, the issuance of term debt and the short term use of a bridge loan facility. The Company intends to increase its commercial paper program by $1 billion, the amount of the new 364-day revolving credit facility. We also secured a $5 billion bridge loan facility to backstop our financing requirements. The commitment under the bridge loan facility has been reduced by $3.5 billion, which is the amount of the net proceeds from the common stock and mandatory convertible preferred offerings discussed above. Depending on when the closing of the acquisition of the Permian Basin BP Properties occurs, we may fund a portion of the amount due for those properties by drawing under the bridge loan facility. Any such borrowing would be repaid from the Company’s next debt offering. Under the purchase and sale agreement, Apache advanced $5 billion of the purchase price to BP plc on July 30, 2010, ahead of the anticipated closings. This advance will be returned to Apache or applied to the purchase price at closing. BP plc provided a limited guarantee with respect to the BP Purchase Agreements, principally as to the return of the advance. The acquisition and related equity offerings are not expected to be accretive to earnings per share in the first several quarters and may be dilutive. They are, however, expected to be accretive to cash flow immediately and are expected to be accretive to per share production growth and neutral to earnings per share for the full year of 2011.
     Production following Closing of Recent Acquisitions and Mariner Merger Upon closing of the acquisition of the offshore Gulf of Mexico properties from Devon, the acquisition of BP Properties and following consummation of the Merger with Mariner, a larger percentage of Apache’s total production will be contributed from offshore Gulf of Mexico properties. Apache’s offshore Gulf of Mexico properties contributed 16 percent of our worldwide equivalent production in the second quarter of 2010. We expect Gulf of Mexico deepwater and shelf properties to contribute approximately 19 percent of our worldwide production following the completion of the Devon property acquisition, the BP property acquisition and the Mariner Merger. After completion of the BP property acquisitions, we expect production from Permian and Canada will rise to 12 and 15 percent of worldwide production, respectively.
Impact of Deepwater Horizon explosion and oil spill on Gulf of Mexico operations
     In April 2010, a deepwater Gulf of Mexico drilling rig, the Deepwater Horizon, operating in the Gulf of Mexico on Mississippi Canyon Block 252, sank after an apparent blowout and fire. As of the date of this filing it appears that the well has been contained as efforts to permanently cap the well proceed. Remediation of the environmental impacts of the spill is ongoing. Neither Apache nor Mariner owns an interest in the field.
     As a result of the incident and spill, the U.S. Department of the Interior (DOI) issued a series of reforms to the oversight and management of offshore exploration drilling activities on the federal Outer Continental Shelf (the OCS). On May 30, 2010, the Bureau of Ocean Energy Management, Regulatory and Enforcement (the BOEM, formerly the Minerals Management Service) of the DOI announced, as a result of the Deepwater Horizon incidents, a Moratorium Notice to Lessees and Operators (Moratorium NTL), which directed oil and gas lessees and operators to cease drilling new deepwater (depths greater than 500 feet) wells on the OCS, and put oil and gas lessees and operators on notice that, with certain exceptions, the BOEM would not consider drilling permits for deepwater wells and related activities for a period of six months. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the DOI has appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s

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request that the district court’s order be stayed while the appeal is pending. On July 12, 2010, the Secretary of the DOI directed the BOEM to issue a suspension until November 30, 2010 of drilling activities that use subsea blowout preventers or surface blowout preventers on floating facilities, rather than a moratorium based on water depths.
     In addition on June 8, 2010, the BOEM issued a Notice to Lessees, NTL-05, focusing on increased safety measures. This NTL specifically affects all drilling wells, workovers and anything with a blowout preventer. It requires:
    Third party review and certification of blowout preventers/shear rams;
    Professional engineer certification of well plan and cement procedures; and
    Chief Executive Officer certification that the operator is in compliance with and is conducting all operations in accordance with all operating regulations found at 30 CFR 250.
     On June 18, 2010, the BOEM issued a Notice to Lessees, NTL-06, focusing on operator’s plans for a blowout scenario and worst case discharge scenario. This NTL specifically affects all new drilling wells, and sidetracks that cross lease lines. It requires:
    Detailed response plans for a blowout event including relief well rig availability and timing to contract a rig, move it onsite and drill a relief well;
    Calculation of Worst Case Discharge (WCD) scenario including all models, calculations and assumptions used to calculate daily discharge rate; and
    Measures that operator would propose to enhance the ability to prevent or reduce the likelihood of a blowout.
     These regulatory changes effectively halted all permitting activity in the Gulf of Mexico; however, on July 16, 2010, the DOI issued a permit to Apache under NTL-05 to drill a natural gas well in shallow waters off the southeast Texas coast. This permit was the first issued since stricter safety and environmental measures were imposed. While we have seen additional approvals for permits under NTL-05, permits for wells falling under NTL-06 continue to be delayed. At the date of this filing, Apache has received only one permit under NTL-06, and as a result, has declared force majeure on a rig and subsequently released that rig for lack of permits. Apache continues to work with the DOI on other outstanding permit applications.
     The drilling suspension, lack of certainty and continuing delays in approval of drilling permits may also result in an exodus of both deepwater and shallow-water drilling rigs as they seek opportunities outside the Gulf of Mexico.
     The Gulf of Mexico offshore operations of Mariner and Apache have been impacted, and likely will be impacted in the future, by increased regulatory oversight, which may increase the cost of OCS wells and delay drilling and production therefrom. There may be future changes in laws and regulations, increases in insurance costs or decreases in insurance availability, as well as further delays in offshore exploration and drilling activities in the Gulf of Mexico. Once deepwater drilling activities are permitted to resume, projects may face additional delays because of increased time for permitting and rig availability.
Operating Highlights
United States
     Gulf of Mexico Shelf Acquisition On June 9, 2010, Apache completed a $1.05 billion acquisition of oil and gas assets in the Gulf of Mexico shelf from Devon Energy Corporation (Devon). The acquisition was effective as of January 1, 2010. The acquired assets include 477,000 net acres across 150 blocks and estimated proved reserves of 41 MMboe. Approximately half of the estimated net proved reserves were liquid hydrocarbons and seven major fields account for 90 percent of the estimated proved reserves. Virtually all of the production is located in fields in water depths less than 500 feet and Apache operates 75 percent of the production. The acquisition was funded primarily from existing cash balances.
     The Company believes that these well-maintained, high-quality assets fit well with Apache’s existing infrastructure and play to the strengths that come with our experience operating on the shelf, exploiting the current production base and capturing upside potential. Many of these properties are geologically complex fields that contain large structures with multiple pay intervals that we believe are under-exploited. The prospect inventory includes high-potential trend exploration opportunities in the Norphlet play and highly prospective exploratory acreage off the Texas coast.
     Mariner Energy, Inc. Merger Agreement On April 15, 2010, Apache and Mariner Energy, Inc., a Delaware corporation (Mariner), announced that we have entered into a definitive agreement, pursuant to which Apache will acquire Mariner in a stock and cash transaction. The Agreement and Plan of Merger dated April 14, 2010 (as

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amended by amendment No. 1 dated August 2, 2010, referred to as the Merger Agreement), by and among Apache, Mariner and ZMZ Acquisitions LLC, a Delaware limited liability company and wholly owned subsidiary of Apache (Merger Sub), contemplates a merger (the Merger) whereby Mariner will be merged with and into Merger Sub, with Merger Sub surviving the Merger as a wholly owned subsidiary of Apache.
     The total amount of cash and shares of Apache common stock that will be paid and issued, respectively, pursuant to the Merger Agreement is fixed, and Mariner stockholders will be entitled to receive (on an aggregate basis) 0.17043 of a share of Apache common stock, par value $0.625 per share, and $7.80 in cash for each share of Mariner common stock (the Mixed Consideration). In connection with the Merger, Apache expects to issue approximately 17.5 million shares of common stock (an increase of approximately five percent of Apache’s outstanding common shares) and pay cash of approximately $800 million to Mariner stockholders.
     Apache intends to fund the cash portion of the consideration with existing cash balances and commercial paper. Upon consummation of the Merger, Apache will assume Mariner’s debt, which was approximately $1.2 billion at the time of the Merger Agreement. Apache estimates it will ultimately incur approximately $130 million in costs related to the Merger.
     On May 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the HSR Act. Additional regulatory post-closing approvals are pending. Completion of the transaction is projected for the third quarter of 2010.
     The Merger Agreement also contains certain termination rights for both Apache and Mariner, including if the Merger is not completed by January 31, 2011. In the event of a termination of the Merger Agreement, under certain circumstances, Mariner may be required to pay Apache a termination fee of $67 million (less any Apache expenses previously reimbursed by Mariner). In connection with the settlement of two stockholder lawsuits, on August 2, 2010, Apache and Mariner amended the Merger Agreement to eliminate the termination fee for one of the events which would trigger the payment of the fee: in the event that Mariner terminates the Merger Agreement in order to enter into an unsolicited “superior proposal” with another party (refer to Note 9 – Commitments and Contingencies, of Item I of this Form 10-Q for further discussion). In addition, under certain circumstances, the Merger Agreement requires each of Apache and Mariner to reimburse the other’s expenses, up to $7.5 million, in the event the Merger Agreement is terminated. Any reimbursement of expenses by Mariner to Apache will reduce the amount of any termination fee paid by Mariner to Apache.
     Assuming the Merger is approved by Mariner stockholders and is cleared by regulatory authorities, the transaction will be accounted for as a business combination, with Mariner’s assets and liabilities reflected in Apache’s financial statements at fair value. The transaction is not expected to be accretive to earnings per share for the first several quarters and may be dilutive. It is, however, expected to be accretive to Apache’s per-share production growth and cash flow immediately, and is expected to be accretive to earnings per share for the full year of 2011.
Canada
     Kitimat LNG Terminal In the first quarter of 2010, Apache announced an agreement to acquire a 51-percent interest in Kitimat LNG Inc’s proposed liquefied natural gas (LNG) export terminal (Kitimat) in British Columbia. The Company also reserved 51 percent of throughput capacity in the terminal. Planned plant gross capacity will be approximately 700 MMcf/d, or five million metric tons of LNG per year. This project has the potential to access new markets in the Asia-Pacific region and enable Apache to monetize gas from its Canadian region, including its interest in the Horn River Basin. Kitimat is designed to be linked to the pipeline system servicing Western Canada’s natural gas producing regions proposed by Pacific Trail Pipelines. In association with the Company’s acquisition of interest in the Kitimat project, Apache also acquired a 25.5-percent interest in the proposed pipeline and 350 MMcf/d of net capacity rights. Preliminary gross construction cost of the Kitimat LNG export terminal, which will be refined upon completion of a front-end engineering and design (FEED) study, total C$3 billion and of the pipeline total C$1.1 billion. Apache projects that most of the costs for the LNG export terminal and pipeline will be incurred throughout the three and one-half year construction phase which is expected to begin in the second half of 2011.
     During the second quarter Apache received proposals from three contractors on the FEED study and expects to award the contract by the end of the third quarter of 2010. Memorandums of Understanding (MOUs) have been developed and discussions with LNG buyers have been ongoing to market the LNG. Also, negotiations for specific agreements required with First Nations and Canadian federal and provincial governments are underway with completion anticipated during the third quarter of 2010. A final investment decision is expected in 2011, with the first LNG shipments projected as early as the end of 2014.

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Egypt
     Egypt Gross Production 2X Goal On June 16, 2010, the Company announced that new production from its Faghur Basin field discoveries propelled its Egyptian gross-operated oil and gas production above 330,000 boe per day, surpassing the Company’s late-2005 goal of doubling output from Egypt’s Western Desert within five years. The completion of new Kalabsha processing and transportation facilities also helped enable Apache to achieve our goal. When the project was initiated, Apache’s gross-operated Egyptian production was approximately 163,000 boe per day.
     Apache invested $4.2 billion in exploration, development and facilities to achieve the “2X” production goal. During that period, the Company also:
    Discovered 57 new fields;
    Drilled 869 new wells;
    Acquired 17,300-square kilometers of three-dimensional (3D) seismic;
    Designed and constructed gathering facilities and two new gas processing trains for Qasr field gas production;
    Installed a major strategic gas pipeline compression project on Egypt’s northern gas pipeline;
    Built a third processing train at the Qarun Concession;
    Implemented 13 waterflood secondary oil recovery projects; and
    Completed the first phase of Kalabsha facilities in the Faghur Basin.
     Matruh Discovery On May 26, 2010, the Company announced that its second discovery of the year in Egypt’s Matruh Basin – the Samaa-1X – tested 44 MMcf of natural gas and 2,910 barrels of condensate per day from two zones. Eleven additional exploration wells and two appraisal wells are planned during the remainder of 2010. Apache has a 100 percent contractor interest in the Matruh Concession
     The Matruh Basin continues to be a successful focus area for Apache, with AEB and Safa reservoirs that have proven to be prolific oil and gas producers. The thickness of the sands and the stacked pay zones present multiple opportunities for further exploration.
     The Matruh Concession currently has gross production of 130 MMcf of gas and 18,000 barrels of oil per day from 16 wells. Since early 2009, gross production on the concession has grown from 60 MMcf of gas and 5,000 barrels of oil per day.
Australia
     Pyrenees and Van Gogh The second quarter of 2010 marked the first full quarter of oil production from the Pyrenees and Van Gogh developments located offshore Western Australia. The Pyrenees and Van Gogh developments, which contributed 22,347 b/d and 29,046 b/d during the second quarter, respectively, drove Australia oil production to 60,680 b/d.
     Wheatstone LNG Project In October 2009, Apache announced an agreement to become a foundation equity partner in Chevron’s Wheatstone LNG hub in Western Australia. Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG facilities with a 75 percent interest. Apache currently owns a 16.25 percent interest in the project and our partner in the Julimar and Brunello fields, Kuwait Foreign Petroleum Exploration Co., k.s.c. (KUFPEC) owns the remaining project interest. The Wheatstone project is targeting a final investment decision (FID) in 2011 and first sales from the facility are projected for 2015. Our net capital for the project is currently estimated to be $1.2 billion for upstream development of the Julimar and Brunello fields and $3.0 billion for the Wheatstone facilities. The investment in the multi-year project will be funded over several years.
     Apache is currently pursuing the sale of a small percentage of interests in its Julimar and Brunello field discoveries in conjunction with the sale of LNG to potential gas buyers, including those described below.
     On July 19, 2010, Apache announced that it, KUFPEC and KOGAS had signed Heads of Agreements (HoAs) for KOGAS to purchase LNG from and to buy an equity stake in the Wheatstone LNG project in Australia. Under the LNG purchase HoA, KOGAS plans to purchase 1.5 million tons per annum of LNG from Apache, KUFPEC and Chevron for up to 20 years. Approximately 25 percent of the LNG is expected to be purchased from Apache and KUFPEC, with the remainder from Chevron. Apache's share of the sales agreement is expected to be approximately 240,000 tons of LNG per year, or 32 MMcf per day of natural gas. Under the equity HoA and the related transaction with Chevron, KOGAS intends to acquire a five percent interest in the entire Wheatstone project, comprising a five percent interest in: Apache's and KUFPEC's Julimar and Brunello field interests; Chevron's Wheatstone field licenses; and the Wheatstone project facilities. Under the terms of KOGAS' participation, Apache's interest in the Wheatstone LNG facilities and Julimar and Brunello field discoveries, including the capital funding requirements, would be reduced to 15.4375 percent and 61.75 percent, respectively.

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Results of Operations
Oil and Gas Revenues
                                                                 
    For the Quarter Ended June 30,     For the Six Months Ended June 30,  
    2010     2009     2010     2009  
    $     %     $     %     $     %     $     %  
    Value     Contribution     Value     Contribution     Value     Contribution     Value     Contribution  
    ($ in millions)  
Total Oil and Gas Revenues:
                                                               
United States
  $ 962       32 %   $ 707       34 %   $ 1,954       35 %   $ 1,303       35 %
Canada
    240       8 %     215       10 %     493       9 %     425       12 %
 
                                               
North America
    1,202       40 %     922       44 %     2,447       44 %     1,728       47 %
 
                                               
Egypt
    806       28 %     655       32 %     1,547       27 %     1,075       29 %
Australia
    452       15 %     87       4 %     676       12 %     130       4 %
North Sea
    421       14 %     322       16 %     812       14 %     565       15 %
Argentina
    88       3 %     88       4 %     180       3 %     180       5 %
 
                                               
International
    1,767       60 %     1,152       56 %     3,215       56 %     1,950       53 %
 
                                               
Total (1)
  $ 2,969       100 %   $ 2,074       100 %   $ 5,662       100 %   $ 3,678       100 %
 
                                               
 
                                                               
Total Oil Revenues:
                                                               
United States
  $ 604       27 %   $ 459       31 %   $ 1,198       29 %   $ 792       32 %
Canada
    94       4 %     79       5 %     191       5 %     136       5 %
 
                                               
North America
    698       31 %     538       36 %     1,389       34 %     928       37 %
 
                                               
Egypt
    682       30 %     523       35 %     1,307       31 %     840       34 %
Australia
    411       19 %     60       4 %     594       14 %     83       3 %
North Sea
    417       18 %     319       22 %     804       19 %     560       22 %
Argentina
    50       2 %     51       3 %     101       2 %     103       4 %
 
                                               
International
    1,560       69 %     953       64 %     2,806       66 %     1,586       63 %
 
                                               
Total (2)
  $ 2,258       100 %   $ 1,491       100 %   $ 4,195       100 %   $ 2,514       100 %
 
                                               
 
                                                               
Total Gas Revenues:
                                                               
United States
  $ 314       48 %   $ 234       42 %   $ 680       50 %   $ 486       43 %
Canada
    139       21 %     131       23 %     289       21 %     281       25 %
 
                                               
North America
    453       69 %     365       65 %     969       71 %     767       68 %
 
                                               
Egypt
    124       19 %     132       23 %     240       17 %     235       22 %
Australia
    41       6 %     27       5 %     82       6 %     47       4 %
North Sea
    4       1 %     3       1 %     8       1 %     5        
Argentina
    31       5 %     33       6 %     62       5 %     68       6 %
 
                                               
International
    200       31 %     195       35 %     392       29 %     355       32 %
 
                                               
Total (3)
  $ 653       100 %   $ 560       100 %   $ 1,361       100 %   $ 1,122       100 %
 
                                               
 
                                                               
Natural Gas Liquids (NGL)
                                                               
Revenues:
                                                               
United States
  $ 44       76 %   $ 14       61 %   $ 76       72 %   $ 25       60 %
Canada
    7       12 %     5       22 %     13       12 %     8       19 %
 
                                               
North America
    51       88 %     19       83 %     89       84 %     33       79 %
 
                                               
Argentina
    7       12 %     4       17 %     17       16 %     9       21 %
 
                                               
Total
  $ 58       100 %   $ 23       100 %   $ 106       100 %   $ 42       100 %
 
                                               
 
(1)   Included in oil and gas production revenues were a gain of $52.5 million and $51.3 million for the 2010 second quarter and six-month period, respectively, and a gain of $51.6 million and $107.7 million for the 2009 second quarter and six-month period, respectively, from financial derivative hedging activities.
 
(2)   Included in oil revenues were a loss of $11.9 million and $26.3 million for the 2010 second quarter and six-month period, respectively, and a gain of $13.1 million and $51.6 million for the 2009 second quarter and six-month period, respectively, from financial derivative hedging activities.
 
(3)   Included in natural gas revenues were a gain of $64.4 million and $77.6 million for the 2010 second quarter and six-month period, respectively, and a gain of $38.5 million and $56.1 million for the 2009 second quarter and six-month period, respectively, from financial derivative hedging activities.

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Production
                                                 
    For the Quarter Ended June 30,   For the Six Months Ended June 30,
                    Increase                   Increase
    2010   2009   (Decrease)   2010   2009   (Decrease)
Oil Volume – b/d:
                                               
United States
    89,529       88,530       1 %     89,144       87,642       2 %
Canada
    14,561       15,833       (8 )%     14,447       16,090       (10 )%
 
                                               
North America
    104,090       104,363             103,591       103,732        
 
                                               
Egypt
    98,495       95,359       3 %     94,642       89,475       6 %
Australia
    60,680       10,478       479 %     43,978       9,164       380 %
North Sea
    58,141       59,688       (3 )%     57,995       60,089       (3 )%
Argentina
    9,874       11,948       (17 )%     9,897       12,192       (19 )%
 
                                               
International
    227,190       177,473       28 %     206,512       170,920       21 %
 
                                               
Total (1)
    331,280       281,836       18 %     310,103       274,652       13 %
 
                                               
 
                                               
Natural Gas Volume – Mcf/d:
                                               
United States
    674,886       662,834       2 %     673,361       637,894       6 %
Canada
    339,611       373,796       (9 )%     326,646       365,551       (11 )%
 
                                               
North America
    1,014,497       1,036,630       (2 )%     1,000,007       1,003,445        
 
                                               
Egypt
    388,367       376,737       3 %     375,249       347,443       8 %
Australia
    203,147       161,069       26 %     205,209       151,607       35 %
North Sea
    2,516       2,645       (5 )%     2,540       2,663       (5 )%
Argentina
    183,028       192,542       (5 )%     168,953       192,250       (12 )%
 
                                               
International
    777,058       732,993       6 %     751,951       693,963       8 %
 
                                               
Total (2)
    1,791,555       1,769,623       1 %     1,751,958       1,697,408       3 %
 
                                               
 
                                               
Natural Gas Liquids (NGL)
Volume – b/d:
                                               
United States
    11,878       5,483       117 %     9,374       5,198       80 %
Canada
    1,996       2,052       (3 )%     1,866       2,082       (10 )%
 
                                               
North America
    13,874       7,535       84 %     11,240       7,280       54 %
Argentina
    3,118       3,091       1 %     3,204       3,114       3 %
 
                                               
Total
    16,992       10,626       60 %     14,444       10,394       39 %
 
                                               
 
                                               
BOE per day(3)
                                               
United States
    213,889       204,485       5 %     210,746       199,156       6 %
Canada
    73,159       80,185       (9 )%     70,753       79,097       (11 )%
 
                                               
North America
    287,048       284,670       1 %     281,499       278,253       1 %
 
                                               
Egypt
    163,223       158,148       3 %     157,184       147,382       7 %
Australia
    94,538       37,323       153 %     78,179       34,431       127 %
North Sea
    58,560       60,129       (3 )%     58,418       60,533       (3 )%
Argentina
    43,497       47,130       (8 )%     41,260       47,348       (13 )%
 
                                               
International
    359,818       302,730       19 %     335,041       289,694       16 %
 
                                               
Total
    646,866       587,400       10 %     616,540       567,947       9 %
 
                                               
 
(1)   Approximately nine and 11 percent of worldwide oil production was subject to financial derivative hedges for the second quarter and six-month period of 2010, respectively, and eight percent for the 2009 second quarter and six-month periods.
 
(2)   Approximately 23 and 24 percent of worldwide natural gas production was subject to financial derivative hedges for the second quarter and six-month period of 2010, respectively, and eight percent for the 2009 second quarter and six-month periods.
 
(3)   The table shows reserves on a barrel of oil equivalent basis (boe) in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

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Pricing
                                                 
    For the Quarter Ended June 30,   For the Six Months Ended June 30,
                    Increase                   Increase
    2010   2009   (Decrease)   2010   2009   (Decrease)
Average Oil Price – Per barrel:
                                               
United States
  $ 74.20     $ 57.00       30 %   $ 74.26     $ 49.95       49 %
Canada
    70.87       55.17       28 %     73.10       46.49       57 %
North America
    73.73       56.72       30 %     74.10       49.41       50 %
Egypt
    76.08       60.30       26 %     76.27       51.90       47 %
Australia
    74.42       63.01       18 %     74.58       49.74       50 %
North Sea
    78.78       58.77       34 %     76.58       51.51       49 %
Argentina
    55.41       46.17       20 %     56.60       46.73       21 %
International
    75.43       58.99       28 %     75.05       51.28       46 %
Total (1)
    74.89       58.15       29 %     74.74       50.57       48 %
 
                                               
Average Natural Gas Price – Per Mcf:
                                               
United States
  $ 5.11     $ 3.88       32 %   $ 5.58     $ 4.21       33 %
Canada
    4.51       3.86       17 %     4.88       4.26       15 %
North America
    4.91       3.88       27 %     5.35       4.23       26 %
Egypt
    3.51       3.85       (9 )%     3.54       3.73       (5 )%
Australia
    2.22       1.82       22 %     2.22       1.71       30 %
North Sea
    17.15       12.24       40 %     17.73       9.82       81 %
Argentina
    1.88       1.89       (1 )%     2.01       1.94       4 %
International
    2.83       2.92       (3 )%     2.88       2.82       2 %
Total (2)
    4.01       3.48       15 %     4.29       3.65       18 %
 
                                               
Average NGL Price – Per barrel:
                                               
United States
  $ 40.48     $ 27.36       48 %   $ 44.63     $ 25.90       72 %
Canada
    35.76       24.23       48 %     37.97       22.40       70 %
North America
    39.80       26.50       50 %     43.52       24.90       75 %
Argentina
    25.68       15.91       61 %     30.23       16.51       83 %
Total
    37.21       23.42       59 %     40.58       22.39       81 %
 
(1)   Reflects a per barrel decrease of $.39 and $.47 from financial derivative hedging activities for the 2010 second quarter and six-month period, respectively, and an increase of $.51 and $1.04 from financial derivative hedging activities for the 2009 second quarter and six-month period, respectively.
 
(2)   Reflects a per Mcf increase of $.39 and $.24 from financial derivative hedging activities for the 2010 second quarter and six-month period, respectively, and an increase of $.24 and $.18 from financial derivative hedging activities for the 2009 second quarter and six-month period, respectively.
Second-Quarter 2010 compared to Second-Quarter 2009
     Crude Oil Revenues Second-quarter crude oil revenues of $2.3 billion were $767 million higher than the 2009 period as worldwide production surged 18 percent to 331,280 b/d and prices rose 29 percent. Crude oil accounted for 76 percent of our oil and gas production revenues during the quarter and 51 percent of our equivalent production, compared to 72 and 48 percent, respectively, for the same period last year. Higher production volumes contributed $337 million to the increase in second-quarter revenues, while higher realized prices added another $430 million.
     U.S. oil revenues were $145 million higher than the 2009 quarter; $138 million from higher price realizations and $7 million from increased production. Prices in the U.S. were 30 percent higher, while production increased marginally. The Gulf Coast region production was down two percent on natural decline. The Central region production increased 717 b/d on drilling activity and the Permian region increased production five percent on new drilling and acquisitions.
     Canada’s revenues increased $15 million, with higher prices contributing $23 million of additional revenues. The benefit from higher prices was partially offset by an eight percent drop in production, primarily from natural decline. Canada’s oil prices averaged $70.87 per barrel, up 28 percent from the 2009 comparative quarter.
     Egypt’s crude oil revenues rose $159 million compared to the prior-year quarter as oil price realizations increased 26 percent, boosting revenues by $137 million. Production growth added $22 million. Gross production increased 14 percent while net production was up only three percent, a function of higher prices and the mechanics of our production sharing contracts. Gross production growth was driven by our drilling and recompletion programs at the Matruh, East Bahariya Extension, South Umbarka and Shushan concessions.
     Australia’s oil revenues were $351 million higher than the prior-year quarter on a sharp increase in production at the Pyrenees and Van Gogh developments, which together contributed an additional 51,393 b/d, driving total Australia production to 60,680 b/d. The higher production added $340 million to revenue while higher price realizations, which were up 18 percent, added another $11 million.

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     North Sea crude oil revenues were up $98 million. This was due to a 34 percent increase in prices, raising revenues by $109 million, partially offset by a three percent drop in production, which decreased revenues by $11 million. Production was down primarily on natural decline.
     Argentina’s oil revenues totaled $50 million, down slightly from the year-ago period. Production decreased 17 percent on natural decline, lowering revenues by $11 million, mostly offset by 20 percent higher price realizations that contributed $10 million to revenues. Oil realizations averaged $55.41 per barrel, as export price limitations imposed on our Argentine production moderated price realizations as compared to our other operating regions.
     Natural Gas Revenues Second-quarter natural gas revenues of $653 million were $93 million higher than the comparable 2009 period, driven primarily by higher realized prices. Average realized prices for the quarter of $4.01 per Mcf, a 15 percent increase from the $3.48 seen in the second quarter of 2009, boosted revenues by $85 million. Worldwide production increased one percent to 1,792 MMcf/d, adding another $8 million.
     U.S. natural gas revenues were up $80 million, with a 32 percent rise in realized prices and two percent higher production increasing revenues by $74 million and $6 million, respectively. Natural gas prices averaged $5.11 per Mcf, up from $3.88 from the comparable year-ago period. Gulf Coast region gas production was up five percent with production restored from wells shut-in because of hurricanes, additional production resulting from new drilling and recompletion activity and properties acquired in the Devon acquisition more than offsetting natural decline. Central region production was up two percent from drilling and recompletion activity. A change in natural gas marketing strategy in the Permian region led to a 10 percent reduction in sales volumes. During the quarter we entered into new marketing contracts, and condensate-rich gas production which was previously sold prior to being processed is now being sold after liquids are removed. The result was an increase in the volumes of natural gas liquids (NGL) sold, and an associated decrease in the volumes of natural gas sold. Permian region’s NGL production for the period increased 5,128 b/d to 6,475 b/d, 381 percent higher than the year-ago period.
     Canada’s natural gas revenues increased $8 million as a 17 percent increase in price realizations was largely offset by a nine percent decrease in production. Gas price realizations rose $0.65 to $4.51 per Mcf, increasing revenues $22 million. Driven primarily by natural decline, gas production fell to 340 MMcf/d, reducing revenues by $14 million.
     Egypt’s natural gas revenues were down $8 million compared to the 2009 second quarter, with a $12 million reduction related to a nine percent price drop partially offset by $4 million of additional revenues attributed to production gains. Gross production was up 14 percent, while net production rose only three percent, a function of the mechanics of our production sharing contracts. The increase in gross production was primarily from drilling and recompletion activity on our Khalda and Matruh concessions.
     Australia’s natural gas revenues rose $14 million relative to the prior-year period, with a 26 percent increase in production adding $8 million in revenues and a 22 percent increase in prices contributing another $6 million. Production reached an average of 203 MMcf/d, up on higher customer takes from our Harriet and John Brookes fields.
     Argentina’s gas revenues fell $2 million on a five percent decline in production, related to natural decline. Production for the quarter was 183 MMcf/d. Natural gas realizations of $1.88 per Mcf were relatively flat from last year’s second quarter and resulted in a minimal downward impact on revenues.

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Operating Expenses
     The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses either on a boe basis, on an absolute dollar basis or both, depending on their relevance. Amounts included in this table and in the discussion that follows are rounded to millions and may differ slightly from those presented elsewhere in this document.
                                 
    For the Quarter Ended June 30,     For the Quarter Ended June 30,  
    2010     2009     2010     2009  
    (In millions)     (Per boe)  
Depreciation, depletion and amortization:
                               
Oil and gas property and equipment
                               
Recurring
  $ 676     $ 527     $ 11.49     $ 9.86  
Other assets
    53       46       .91       .87  
Asset retirement obligation accretion
    25       27       .42       .50  
Lease operating expenses
    446       405       7.58       7.58  
Gathering and transportation
    43       34       .73       .62  
Taxes other than income
    187       116       3.17       2.17  
General and administrative expenses
    92       91       1.56       1.70  
Financing costs, net
    56       61       .95       1.14  
 
                       
 
                               
Total
  $ 1,578     $ 1,307     $ 26.81     $ 24.44  
 
                       
     Depreciation, Depletion and Amortization (DD&A) The following table details the changes in recurring DD&A of oil and gas properties between the second quarters of 2010 and 2009:
         
    Recurring DD&A  
    (In millions)  
Second-quarter 2009 DD&A
  $ 527  
Volume change
    67  
Rate change
    82  
 
     
 
       
Second-quarter 2010 DD&A
  $ 676  
 
     
     Recurring full-cost DD&A expense of $676 million increased $149 million on an absolute dollar basis; $82 million higher on rate and $67 million from higher production. The Company’s full-cost DD&A rate increased $1.63 to $11.49 per boe as the costs to acquire, find and develop reserves continue to exceed our historical cost basis. The recent acquisition of assets on the Gulf of Mexico shelf from Devon, completed in June 2010, also impacted the current quarter full-cost depletion rate.
     Lease Operating Expenses (LOE) Second-quarter 2010 LOE increased $41 million, or 10 percent on an absolute dollar basis, as compared to the second quarter of 2009. On a per unit basis, LOE was unchanged. The following table identifies changes in Apache’s LOE rate between the second quarter of 2009 and 2010.
         
    Per boe  
Second-quarter 2009 LOE
  $ 7.58  
FX impact
    0.22  
Equipment rental – Australia
    0.22  
Workover costs
    0.13  
Labor and pumper costs
    0.12  
Other
    0.12  
Devon acquisition
    0.10  
Materials, surface and sub-surface
    0.08  
Non-recurring repair and maintenance
    0.06  
Power and fuel costs
    0.06  
U.S. hurricane repair costs
    (0.35 )
Increased production
    (0.76 )
 
     
 
       
Second-quarter 2010 LOE
  $ 7.58  
 
     

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     Gathering and Transportation Gathering and transportation costs totaled $43 million in the second quarter of 2010, up $9 million. On a per unit basis, gathering and transportation costs were up 18 percent as the impact from higher costs was partially offset by a decrease in rate related to higher production. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:
                 
    For the Quarter Ended  
    June 30,  
    2010     2009  
    (In millions)  
U.S.
  $ 11     $ 8  
Canada
    16       13  
North Sea
    6       6  
Egypt
    9       6  
Argentina
    1       1  
 
           
 
               
Total Gathering and Transportation
  $ 43     $ 34  
 
           
     The U.S. increased $3 million primarily from an increase in volumes transported under contracts where charges are paid directly to a third party. Canada’s transportation was up $3 million primarily from the impact of foreign exchange rates and higher gas transportation rates, partially offset by lower transported volumes. Egypt’s costs were up $3 million on an increase in tariff fees.
     Taxes other than Income Taxes other than income totaled $187 million, an increase of $71 million. On a per unit basis, taxes other than income increased 46 percent. Higher production decreased the rate by 15 percent, while higher costs increased the rate by 61 percent. A detail of these taxes follows:
                 
    For the Quarter Ended  
    June 30,  
    2010     2009  
    (In millions)  
U.K. PRT
  $ 130     $ 73  
Severance taxes
    28       18  
Ad valorem taxes
    17       13  
Canadian taxes
    3       4  
Other
    9       8  
 
           
 
               
Total Taxes other than Income
  $ 187     $ 116  
 
           
     U.K. Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $57 million higher than the 2009 period on an 85 percent increase in net profits, driven by 34 percent higher realized oil prices and 23 percent lower capital expenditures.
     Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The $10 million increase in severance taxes resulted from higher taxable revenues in the U.S. and Australia, consistent with the higher realized oil and natural gas prices.
     Ad valorem taxes are assessed on U.S. and Canadian property values. The $4 million increase resulted primarily from higher commodity prices which increased property values over 2009.
     General and Administrative Expenses General and administrative expenses (G&A) were $1 million higher on an absolute basis, but on a per unit basis were down $.14 to an average of $1.56 per boe. Lower employee separation costs and stock-based compensation costs were offset by higher administrative costs related to acquisitions, the Kitimat LNG project and various other corporate expenses.

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     Financing Costs, Net Financing costs incurred during the period noted are composed of the following:
                 
    For the Quarter Ended  
    June 30,  
    2010     2009  
    (In millions)  
Interest expense
  $ 75     $ 77  
Amortization of deferred loan costs
    1       1  
Capitalized interest
    (18 )     (15 )
Interest income
    (2 )     (2 )
 
           
Financing costs, net
  $ 56     $ 61  
 
           
     Net financing costs fell $5 million, or $.20 on a boe basis. The decrease in absolute dollars is primarily the result of a $2 million decrease in interest expense related to lower average outstanding debt balances and a $3 million increase in capitalized interest related to higher unproved property balances. The $.20 reduction on a unit basis was essentially split evenly between the lower net costs and the impact of higher production.
     Provision for Income Taxes During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year, after consideration of discrete items. No significant discrete tax events occurred during the second quarter of 2010 or 2009.
     The provision for income taxes increased $192 million to $534 million, 56 percent above prior year, as income before taxes increased on higher oil and gas production revenues. The effective income tax rate in the second quarter of 2010 was 38.3 percent compared to 43.5 percent in the second quarter of 2009. The 2010 rate was impacted by a $32 million non-cash benefit related to the strengthening U.S. dollar compared to $31 million of expense in 2009.
Year-to-Date 2010 compared to Year-to-Date 2009
     Crude Oil Revenues Year-to-date crude oil revenues of $4.2 billion were $1.7 billion higher than the 2009 period as worldwide production increased 13 percent to 310,103 b/d and prices rose 48 percent over the prior-year period. Crude oil accounted for 74 percent of our oil and gas production revenues during the period and 50 percent of our equivalent production, compared to 68 and 48 percent, respectively, for the same period last year. Higher realized prices added $1.2 billion to our six-month revenues, while higher production volumes contributed $480 million.
     U.S. oil revenues were $406 million higher than the comparable six-month period of 2009: $386 million from higher price realizations and $20 million from increased production. Prices in the U.S. jumped 49 percent, while production increased two percent. Central region production increased 18 percent on drilling activity and the Permian region increased production three percent on new drilling and acquisitions. Gulf Coast region production was flat as compared to the prior period.
     Canada’s revenues increased $55 million, with higher prices contributing $77 million and decreased production lowering revenues by $22 million. Canada’s oil prices averaged $73.10 per barrel, up 57 percent from the year-ago period. Production fell 10 percent, primarily from natural decline.
     Egypt’s crude oil revenues rose $467 million as oil price realizations increased 47 percent, boosting revenues $395 million. Production growth added $72 million, relative to the 2009 period. Gross production increased 16 percent while net production was up only six percent, a function of higher prices and the mechanics of our production sharing contracts. Gross production growth was driven by drilling and recompletion programs at the Matruh, East Bahariya Extension, South Umbarka and Northeast Abu Gharadig (NEAG) Extension concessions.
     Australia’s oil revenues were $511 million higher than the prior-year six-month period on a sharp increase in production at the Pyrenees and Van Gogh developments, which together contributed an additional 34,559 b/d, driving total Australia production to 43,978 b/d. The higher production added $470 million to revenue while higher price realizations, which were up 50 percent, adding another $41 million.
     North Sea crude oil revenues were up $244 million. This was due to a 49 percent increase in prices, raising revenues by $273 million, partially offset by a three percent drop in production, which decreased revenues by $29 million. Production was down on natural decline.

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     Argentina’s oil revenues totaled $101 million, down slightly from the year-ago period. Production decreased 19 percent on natural decline lowering revenues by $24 million, which was mostly offset by 21 percent higher price realizations that contributed $22 million of additional revenues. Oil realizations averaged $56.60 per barrel, as export price limitations imposed on our Argentine production moderate price realizations as compared to our other operating regions.
     Natural Gas Revenues Natural gas revenues for the six-month period of 2010 of $1.4 billion were $239 million higher than the comparable 2009 period, driven primarily by higher realized prices. Average realized prices for the period of $4.29 per Mcf, an 18 percent increase from the $3.65 seen in the 2009 period, boosted revenues by $197 million. Worldwide production increased three percent to 1,752 MMcf/d, adding another $42 million to revenues.
     U.S. natural gas revenues were up $194 million, with a 33 percent rise in realized prices and six percent higher production increasing revenues by $158 million and $36 million, respectively. Natural gas prices averaged $5.58 per Mcf, up from $4.21 in the comparable year-ago period. Gulf Coast region gas production increased 13 percent on new drilling and recompletions, as well as production from acquisitions. Central region production was down four percent on natural decline. Permian region gas production was up marginally.
     Canada’s natural gas revenues increased $8 million as a 15 percent increase in price realizations was largely offset by an 11 percent decrease in production. Gas price realizations rose $.62 to $4.88 per Mcf, increasing revenues $42 million. Driven primarily by natural decline, gas production fell to 327 MMcf/d, reducing revenues by $34 million.
     Egypt’s natural gas revenues were up $5 million compared to the 2009 period, with $17 million of additional revenues attributed to production gains being partially offset by a $12 million reduction related to a five percent price decline. Gross production was up 20 percent, while net production rose only eight percent, a function of the mechanics of our production sharing contracts. The increase in gross production was primarily from our Khalda and Matruh concessions.
     Australia’s natural gas revenues rose $35 million, with a 35 percent increase in production adding $21 million in revenues and a 30 percent increase in prices contributing another $14 million. Production reached an average of 205 MMcf/d in the period on higher customer takes from our Harriet and John Brookes fields.
     Argentina’s gas revenues fell $6 million, as 12 percent lower production reduced revenues by $8 million and four percent higher prices added back $2 million. Production for the current period was 169 MMcf/d, down primarily on natural decline. Natural gas realizations rose $.07 to $2.01 per Mcf.
Operating Expenses
     The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses either on a boe basis, on an absolute dollar basis or both, depending on their relevance. Amounts included in this table and in the discussion that follows are rounded to millions and may differ slightly from those presented elsewhere in this document.
                                 
    For the Six Months Ended June 30,     For the Six Months Ended June 30,  
    2010     2009     2010     2009  
    (In millions)     (Per boe)  
Depreciation, depletion and amortization:
                               
Oil and gas property and equipment
                               
Recurring
  $ 1,263     $ 1,063     $ 11.32     $ 10.34  
Additional
          2,818             27.41  
Other assets
    105       91       .94       .89  
Asset retirement obligation accretion
    49       53       .44       .5