APA 10-Q Quarterly Report June 30, 2011 | Alphaminr

APA 10-Q Quarter ended June 30, 2011

APACHE CORP
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10-Q 1 h82406e10vq.htm FORM 10-Q e10vq
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2011
OR
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to
Commission File Number 1-4300
APACHE CORPORATION
(exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
41-0747868
(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 Smaller reporting company o
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No þ
Number of shares of registrant’s common stock outstanding as of July 31, 2011            383,927,712


TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
ITEM 1 — FINANCIAL STATEMENTS
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4 — CONTROLS AND PROCEDURES
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
ITEM 1A. RISK FACTORS
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. [REMOVED AND RESERVED]
ITEM 5. OTHER INFORMATION
ITEM 6. EXHIBITS
SIGNATURES
EX-10.1
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,
2011 2010 2011 2010
(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues
$ 4,355 $ 2,969 $ 8,233 $ 5,662
Other
(17 ) 3 30 (17 )
4,338 2,972 8,263 5,645
OPERATING EXPENSES:
Depreciation, depletion and amortization
1,029 729 1,965 1,368
Asset retirement obligation accretion
38 25 75 49
Lease operating expenses
662 446 1,285 886
Gathering and transportation
73 43 149 83
Taxes other than income
255 187 419 364
General and administrative
103 84 215 171
Merger, acquisitions & transition
6 8 11 8
Financing costs, net
41 56 86 115
2,207 1,578 4,205 3,044
INCOME BEFORE INCOME TAXES
2,131 1,394 4,058 2,601
Current income tax provision
576 339 1,219 682
Deferred income tax provision
296 195 446 354
NET INCOME
1,259 860 2,393 1,565
Preferred stock dividends
19 38
INCOME ATTRIBUTABLE TO COMMON STOCK
$ 1,240 $ 860 $ 2,355 $ 1,565
NET INCOME PER COMMON SHARE:
Basic
$ 3.23 $ 2.55 $ 6.14 $ 4.64
Diluted
$ 3.17 $ 2.53 $ 6.03 $ 4.61
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic
384 338 383 337
Diluted
397 339 397 339
DIVIDENDS DECLARED PER COMMON SHARE
$ 0.15 $ 0.15 $ 0.30 $ 0.30
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
For the Six Months Ended
June 30,
2011 2010
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
$ 2,393 $ 1,565
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization
1,965 1,368
Asset retirement obligation accretion
75 49
Provision for deferred income taxes
446 354
Other
3 67
Changes in operating assets and liabilities:
Receivables
(355 ) (104 )
Inventories
(97 ) (7 )
Drilling advances
4 22
Deferred charges and other
(14 ) 1
Accounts payable
206 49
Accrued expenses
78 (292 )
Deferred credits and noncurrent liabilities
20 13
NET CASH PROVIDED BY OPERATING ACTIVITIES
4,724 3,085
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property
(3,170 ) (1,921 )
Additions to gas gathering, transmission and processing facilities
(269 ) (257 )
Acquisition of Devon properties
(1,017 )
Acquisitions, other
(78 ) (16 )
Proceeds from sale of oil and gas properties
192
Other, net
(52 ) (7 )
NET CASH USED IN INVESTING ACTIVITIES
(3,377 ) (3,218 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net
(289 ) (55 )
Dividends paid
(153 ) (101 )
Common stock activity
38 21
Treasury stock activity, net
4 3
Other
26 22
NET CASH USED IN FINANCING ACTIVITIES
(374 ) (110 )
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
973 (243 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
134 2,048
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$ 1,107 $ 1,805
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest
$ 72 $ 113
Income taxes paid, net of refunds
894 595
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
June 30, December
2011 31, 2010
(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 1,107 $ 134
Receivables, net of allowance
2,495 2,134
Inventories
633 564
Drilling advances
250 259
Prepaid assets and other
415 389
4,900 3,480
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties
61,028 57,904
Unproved properties and properties under development, not being amortized
5,252 5,048
Gathering, transmission and processing facilities
4,481 4,212
Other
637 582
71,398 67,746
Less: Accumulated depreciation, depletion and amortization
(31,560 ) (29,595 )
39,838 38,151
OTHER ASSETS:
Goodwill
1,032 1,032
Deferred charges and other
759 762
$ 46,529 $ 43,425
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable
$ 1,029 $ 779
Accrued operating expense
168 163
Accrued exploration and development
1,375 1,367
Accrued compensation and benefits
135 231
Current debt
448 46
Current asset retirement obligation
360 407
Derivative instruments
229 194
Accrued income taxes
266 2
Other
474 335
4,484 3,524
LONG-TERM DEBT
7,404 8,095
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes
4,698 4,249
Asset retirement obligation
2,535 2,465
Other
741 715
7,974 7,429
COMMITMENTS AND CONTINGENCIES (Note 7)
SHAREHOLDERS’ EQUITY:
Preferred stock, no par value, 10,000,000 shares authorized, 6% Cumulative Mandatory Convertible, Series D, $1,000 per share liquidation preference, 1,265,000 shares issued and outstanding
1,227 1,227
Common stock, $0.625 par, 860,000,000 shares authorized, 384,983,055 and 383,668,297 shares issued, respectively
241 240
Paid-in capital
8,969 8,864
Retained earnings
16,463 14,223
Treasury stock, at cost, 1,147,641 and 1,276,555 shares, respectively
(33 ) (36 )
Accumulated other comprehensive loss
(200 ) (141 )
26,667 24,377
$ 46,529 $ 43,425
The accompanying notes to consolidated financial statements
are an integral part of this statement.

3


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
(Unaudited)
Accumulated
Series D Other Total
Comprehensive Preferred Common Paid-In Retained Treasury Comprehensive Shareholders’
Income Stock Stock Capital Earnings Stock Income (Loss) Equity
(In millions)
BALANCE AT DECEMBER 31, 2009
$ $ 215 $ 4,634 $ 11,437 $ (217 ) $ (290 ) $ 15,779
Comprehensive income:
Net income
$ 1,565 1,565 1,565
Commodity hedges, net of income tax expense of $150
313 313 313
Comprehensive income
$ 1,878
Common stock dividends ($0.30 per share)
(101 ) (101 )
Common shares issued
1 12 13
Treasury shares issued, net
(1 ) 5 4
Compensation expense
102 102
Other
1 1
BALANCE AT JUNE 30, 2010
$ $ 216 $ 4,748 $ 12,901 $ (212 ) $ 23 $ 17,676
BALANCE AT DECEMBER 31, 2010
$ 1,227 $ 240 $ 8,864 $ 14,223 $ (36 ) $ (141 ) $ 24,377
Comprehensive income:
Net income
$ 2,393 2,393 2,393
Commodity hedges, net of income tax benefit of $14
(59 ) (59 ) (59 )
Comprehensive income
$ 2,334
Dividends:
Preferred
(38 ) (38 )
Common ($0.30 per share)
(115 ) (115 )
Common shares issued
1 19 20
Treasury shares issued, net
2 3 5
Compensation expense
84 84
Other
BALANCE AT JUNE 30, 2011
$ 1,227 $ 241 $ 8,969 $ 16,463 $ (33 ) $ (200 ) $ 26,667
The accompanying notes to consolidated financial statements
are an integral part of this statement.

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Table of Contents

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 Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010, 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, 2011, Apache’s significant accounting policies are consistent with those discussed in Note 1 of its consolidated financial statements contained in the Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010.
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 fair value of acquired assets and liabilities, 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.
New Pronouncements Issued But Not Yet Adopted
In May 2011 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, which amends FASB Accounting Standards Codification (ASC) Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.
In June 2011 the FASB issued ASU No. 2011-05, which amends ASC Topic 220, “Comprehensive Income.” This ASU requires companies to present items of net income, items of other comprehensive income (OCI) and total comprehensive income in either one continuous statement or two separate but consecutive statements. Companies will no longer be allowed to present OCI in the statement of stockholders’ equity, and reclassification adjustments between OCI and net income must be presented separately on the face of the financial statements. The guidance in ASU No. 2011-05 is effective for interim and annual periods beginning after December 15, 2011. The amendment provides only for a change in presentation of financial statements; therefore, adoption will have no impact on the Company’s financial position or results of operations.

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Table of Contents

2. ACQUISITIONS AND DIVESTITURES
2011 Activity
Kitimat LNG Project
In 2010 Apache Canada Ltd. (Apache Canada) and EOG Resources Canada, Inc. (EOG Canada), through their subsidiaries, purchased 51-percent and 49-percent interests, respectively, in a planned liquefied natural gas (LNG) export terminal (Kitimat LNG facility) and 25.5-percent and 24.5-percent interests, respectively, in Pacific Trail Pipelines Limited Partnership (PTP), a partnership that owns a related proposed pipeline. In February 2011, in order to align ownership and interests on the planned facility and pipeline development, Apache Canada and EOG Canada agreed to purchase Pacific Northern Gas Ltd.’s (PNG) remaining interest in PTP for $50 million. Following the close of the acquisition, Apache and EOG owned 51-percent and 49-percent interests, respectively, in PTP and secured full ownership in the proposed pipeline to transport natural gas from production areas to the Kitimat LNG facility. Under the terms of the agreement, PNG will operate and maintain the pipeline under a seven-year agreement with provisions for five-year renewals.
In March 2011, Apache Canada and EOG Canada announced that Encana Corporation agreed to purchase a 30-percent working interest ownership in both the Kitimat LNG facility and PTP. Under the new ownership agreement, Apache retained a 40-percent interest in both the facility and the related pipeline while EOG retained a 30-percent interest.
2010 Activity
During 2010 Apache completed the following material transactions:
Gulf of Mexico Shelf Acquisition
In June 2010 Apache completed an acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon Energy Corporation (Devon) for $1.05 billion, subject to normal post-closing adjustments. The acquisition was effective January 1, 2010, and was funded primarily from existing cash balances.
BP Acquisitions
In July 2010 Apache entered into three definitive purchase and sale agreements to acquire properties from subsidiaries of BP plc (collectively referred to as “BP”) for aggregate consideration of $7.0 billion. The effective date of the transactions was July 1, 2010. The acquisition of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of west Texas and New Mexico was completed on August 10, 2010, for an agreed-upon purchase price of $3.1 billion. Apache completed the acquisition of substantially all of BP’s western Canadian upstream natural gas assets on October 8, 2010, for $3.25 billion. On November 4, 2010, the Company completed the acquisition of BP’s interests in four development licenses and one exploration concession in the Western Desert of Egypt for $650 million. Preferential purchase rights for $658 million of the value of the Permian Basin properties were exercised, and accordingly, the aggregate purchase price for all three transactions was reduced to approximately $6.4 billion, subject to normal post-closing adjustments.
The acquisitions were funded by issuing a combination of common stock and mandatory convertible preferred shares, issuing new term debt and commercial paper, and using existing cash balances.
Mariner Energy, Inc. Merger
In November 2010 Apache acquired Mariner Energy, Inc. (Mariner), an independent exploration and production company, in a stock and cash transaction totaling $2.7 billion and assumed approximately $1.7 billion of Mariner’s debt. 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 region. The transaction was accounted for using the acquisition method of accounting, which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. Certain assets and liabilities may be adjusted as additional information is obtained, but no later than one year from the acquisition date.

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Table of Contents

Pro Forma Impact of Acquisitions (Unaudited)
The Devon acquisition was completed during the second quarter of 2010. The BP acquisitions and Mariner merger were completed subsequent to the second quarter of 2010. The following table presents pro forma information for Apache as if the acquisitions and merger occurred prior to January 1, 2010:
For the Quarter For the Six Months
Ended June 30, Ended June 30,
2010 2010
(In millions)
Revenues and Other
$ 3,534 $ 6,795
Net Income
$ 937 $ 1,730
Preferred Stock Dividends
19 38
Income Attributable to Common Stock
918 1,692
Net Income per Common Share — Basic
$ 2.41 $ 4.44
Net Income per Common Share — Diluted
$ 2.36 $ 4.36
Apache’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the acquisitions and merger and were factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company’s consolidated results of operations actually would have been had the acquisitions and merger been completed prior to January 1, 2010. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. Adjustments and assumptions made for this pro forma calculation are consistent with those used in the Company’s annual pro forma information as more fully described in Note 2 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Management believes it is prudent to manage the variability in cash flows by entering into derivative instruments 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. Derivatives entered into are typically designated as cash flow hedges.
Counterparty Risk
The use of derivative instruments 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 investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of June 30, 2011, Apache had derivative positions with 19 counterparties. 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 one of these counterparties not perform, Apache may not realize the benefit of some 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 has the right to demand the posting of collateral, demand a transfer or terminate the arrangement.

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Table of Contents

Derivative Instruments
As of June 30, 2011, 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 (in 000’s) (in 000’s) Floor Price (1) Ceiling Price (1)
Price (1)
2011
35,884 $ 5.96 4,600 $ 5.00 $ 8.85
2011
25,760 C$ 6.26 1,840 C$ 6.50 C$ 7.10
2012
41,554 $ 6.30 21,960 $ 5.54 $ 7.30
2012
43,920 C$ 6.61 7,320 C$ 6.50 C$ 7.27
2013
7,665 $ 6.83 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 gas contracts are entered into on a per gigajoule (GJ) basis and are settled against AECO Index. The Canadian natural gas prices represent a weighted average of AECO Index prices and are shown in Canadian dollars.
As of June 30, 2011, 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)
2011
2,641 $ 74.17 14,996 $ 69.18 $ 96.79
2012
3,786 72.26 9,142 69.30 98.11
2013
1,860 74.38 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. A portion of 2011 contracts are settled against Dated Brent.
Apache North Sea Ltd. has entered into a physical sales contract to deliver 20,000 barrels of oil per day in 2011, settled against Dated Brent with a floor price of $70 per barrel and an average ceiling price of $98.56 per barrel. This contract is not reflected in the above table because the associated sales are in the normal course of business and are recognized in oil and gas revenues on an accrual basis.
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
The Company accounts for derivative instruments and hedging activity in accordance with 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 and their locations on the consolidated balance sheet are as follows:
June 30, December 31,
2011 2010
(In millions)
Current Assets: Prepaid assets and other
$ 171 $ 167
Other Assets: Deferred charges and other
87 139
Total Assets
$ 258 $ 306
Current Liabilities: Derivative instruments
$ 229 $ 194
Noncurrent Liabilities: Other
125 124
Total Liabilities
$ 354 $ 318
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 9 — Fair Value Measurements of this Form 10-Q.

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Table of Contents

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:
For the Quarter For the Six Months
Ended
June 30,
Ended
June 30,
Gain (Loss) on Derivatives 2011 2010 2011 2010
Recognized In Income (In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)
Oil and Gas Production Revenues $ (53 ) $ 52 $ (47 ) $ 51
Gain (loss) on derivatives recognized in operations (ineffective portion and basis)
Revenues and Other: Other $ 4 $ $ 1 $
Derivative Activity in Accumulated Other Comprehensive Income (Loss)
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,
2011 2010
Before tax After tax Before tax After tax
(In millions)
Unrealized loss on derivatives at beginning of period
$ (54 ) $ (19 ) $ (267 ) $ (170 )
Realized amounts reclassified into earnings
47 36 (51 ) (33 )
Net change in derivative fair value
(119 ) (94 ) 514 346
Ineffectiveness and basis swaps reclassified into earnings
(1 ) (1 )
Unrealized gain (loss) on derivatives at end of period
$ (127 ) $ (78 ) $ 196 $ 143
Gains and losses on existing hedges will be realized in future earnings through mid-2014, in the same period as the related sales of natural gas and crude oil production occur. Included in accumulated other comprehensive loss as of June 30, 2011, is a net loss of approximately $77 million ($52 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.
4. ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the quarter ended June 30, 2011:
(In millions)
Asset retirement obligation at December 31, 2010
$ 2,872
Liabilities incurred
186
Liabilities settled
(238 )
Accretion expense
75
Asset retirement obligation at June 30, 2011
2,895
Less current portion
(360 )
Asset retirement obligation, long-term
$ 2,535

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5. DEBT AND FINANCING COSTS
The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt at June 30, 2011 and December 31, 2010:
June 30, 2011 December 31, 2010
Carrying Fair Carrying Fair
Amount Value Amount Value
(In millions)
Money market lines of credit
$ 48 $ 48 $ 46 $ 46
Commercial paper
620 620 913 913
Notes and debentures
7,184 7,818 7,182 7,870
Total Debt
$ 7,852 $ 8,486 $ 8,141 $ 8,829
The Company’s debt is recorded at the carrying amount on its consolidated balance sheet, net of unamortized discount. The carrying amount of the Company’s money market lines of credit and commercial paper approximates fair value because the interest rates are reflective of market rates. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
As of June 30, 2011, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2011 and $2.3 billion matures in May 2013. The facilities consist of a $1.0 billion 364-day facility, 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. As of June 30, 2011, available borrowing capacity under the Company’s credit facilities was $2.7 billion. The U.S. credit facilities are used to support Apache’s commercial paper program.
The Company is currently in negotiations to replace its $1.0 billion 364-day facility with a $1.0 billion five-year facility. This five-year facility will have terms similar to those of the Company’s other five-year facilities. It is anticipated that the facility will become effective in August 2011.
The Company has available a $2.95 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 2011 and 2013. As of June 30, 2011, the Company had $620 million in commercial paper outstanding, compared with $913 million outstanding as of December 31, 2010.
As of June 30, 2011, current debt includes $400 million 6.25-percent notes due within the next 12 months and $48 million borrowed under uncommitted overdraft lines in Argentina and Canada. As of December 31, 2010, current debt included $46 million drawn on uncommitted overdraft lines in the U.S. and Argentina.
Financing Costs
Financing costs incurred during the periods comprised the following:
For the Quarter Ended For the Six Months Ended
June 30, June 30,
2011 2010 2011 2010
(In millions)
Interest expense
$ 109 $ 75 $ 217 $ 151
Amortization of deferred loan costs
1 1 3 3
Capitalized interest
(63 ) (18 ) (124 ) (35 )
Interest income
(6 ) (2 ) (10 ) (4 )
Financing costs, net
$ 41 $ 56 $ 86 $ 115
6. 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 half of 2011 and 2010.

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In March 2011 the U.K. government proposed an increase in the corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent. The legislation received Royal Assent and was enacted on July 19, 2011. As a result of the enacted legislation, the Company will record a non-recurring tax charge estimated at $290 million in the third quarter of 2011. Of this amount, an estimated $230 million is related to periods prior to 2011, and approximately $60 million is related to operating results through the second quarter of 2011.
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.
7. 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 $11 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
As more fully described in Note 8 of the financial statements in our Amended Annual Report on Form 10-K/A for the 2010 fiscal year, in connection with the Pioneer acquisition 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 relating to various environmental and remediation claims. No material change in the status of these matters has occurred since the filing of our most recent Amended Annual Report on Form 10-K/A.
Louisiana Restoration
As more fully described in Note 8 of the financial statements in our Amended Annual Report on Form 10-K/A for the 2010 fiscal year, 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 for contamination and cleanup. No material change in the status of these matters has occurred since the filing of our most recent Amended Annual Report on Form 10-K/A.
Hurricane-Related Litigation
On May 27, 2011, a lawsuit captioned Comer et al. v. Murphy Oil USA, Inc. et al. , Case No. 1:11-cv-220 HS0-JMR, in the United States District Court for the Southern District of Mississippi, was filed in which certain named residents of Mississippi, as plaintiffs, allege that the oil, coal, and chemical industries are responsible for global warming, which they claim caused or increased the effect of Hurricane Katrina, allegedly resulting among other things in economic losses and increased insurance premiums. Plaintiffs seek class certification, damages for losses sustained, a declaration that state law tort claims are not preempted by federal law, and punitive and exemplary damages. Apache Corporation is one of numerous defendants. A similar action filed by Comer et al. was previously dismissed as explained in detail in Note 8 of the financial statements in our Amended Annual Report on Form 10-K/A for the 2010 fiscal year.

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Australia Gas Pipeline Force Majeure
As more fully described in Note 8 of the financial statements in our Amended Annual Report on Form 10-K/A for the 2010 fiscal year, Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas in Australia to customers under various long-term contracts. No material change in the status of these matters has occurred since the filing of our most recent Amended Annual Report on Form 10-K/A, except as follows:
Apache Northwest Pty Ltd and Apache Energy Limited were served with a lawsuit captioned Alcoa of Australia Limited vs. Apache Energy Limited, Apache Northwest Pty Ltd, Tap (Harriet) Pty Ltd, and Kufpec Australia Pty Ltd , Civ. 1481 of 2011, in the Supreme Court of Western Australia. The lawsuit concerns the pipeline explosion at Varanus Island in Western Australia on June 3, 2008, that interrupted deliveries of natural gas to Alcoa under two long-term contracts. Alcoa challenges the declaration of force majeure and the validity of the liquidated damages provisions in the contracts. Alcoa asserts claims based on breach of contract, statutory duties, and duty of care. Alcoa seeks approximately $158 million AUD in general damages or, alternatively, approximately $5.7 million AUD in liquidated damages. Apache Northwest and Apache Energy do not believe that Alcoa’s claims have merit and will vigorously pursue their defenses against such claims.
In reference to the pipeline license described in Note 8 of the financial statements in our Amended Annual Report on Form 10-K/A for the 2010 fiscal year, the application by Apache Northwest Pty Ltd, Kufpec Australia Pty Ltd, and Tap (Harriet) Pty Ltd for renewal and variation of the pipeline license covering the area of the Varanus Island facility was granted on April 19, 2011 by the Government of Western Australia, Department of Mines and Petroleum. The period of the license is 21 years commencing April 20, 2011.
Escheat Audits
The State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property), has notified numerous companies, including Apache Corporation, that the State intends to examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. The review will be conducted by Kelmar Associates on behalf of the State of Delaware. At least 30 other states have retained their own consultants and have sent similar notifications. The scope of each state’s audit varies. The State of Delaware advises, for example, that the scope of its examination will be for the period 1981 through the present. It is possible that one or more of the state audits could extend to all 50 states.
Burrup-Related Gas Supply Lawsuits
On May 19, 2011, a lawsuit captioned Oswal v. Apache Corporation , Cause No. 2011-30302, in the District Court of Harris County, Texas, was filed in which plaintiff Pankaj Oswal, in his personal capacity and as trustee for the Burrup Trust, asserts claims against the Company under the Australian Trade Practices Act. This lawsuit is one of a number of legal actions involving the Burrup Fertilisers Pty Ltd (Burrup Fertilisers) ammonia plant in Western Australia (the Burrup plant) founded by Oswal. Oswal’s shares, and those of his wife, together representing 65 percent of Burrup Holdings Limited (which owns Burrup Fertilisers), are being offered for sale by externally appointed administrators in Australia as a result of for alleged events of default on loans made to the Oswals by the Australia and New Zealand Banking Group Ltd (ANZ). In the Texas lawsuit, plaintiff Oswal alleges, among other things, that the Company induced him to make certain investments relating to the Burrup plant. Plaintiff Oswal seeks damages in the amount of $491 million USD. The Company believes that the claims are without merit and intends to vigorously defend against them. The Texas lawsuit relates to a pending action filed by Tap (Harriet) Pty Ltd against Burrup Fertilisers Pty Ltd et al. , Civ 2329 of 2009, in the Supreme Court of Western Australia, seeking a declaratory judgment regarding its contractual rights and obligations under a gas sales agreement between Burrup Fertilisers and the Harriet Joint Venture (comprised of a Company subsidiary and two joint venture partners, Tap (Harriet) Pty Ltd and Kufpec Australia Pty Ltd). The Company and the Company’s subsidiary, each of which has been added as a defendant by counterclaim, are diligently pursuing their claims and defenses.
Environmental Matters
As of June 30, 2011, the Company had an undiscounted reserve for environmental remediation of approximately $135 million. The Company is not aware of any environmental claims existing as of June 30, 2011, that 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.

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Apache Canada Ltd. has asserted a claim against BP Canada arising out of the acquisition of certain Canadian properties under the parties’ Partnership Interest and Share Purchase and Sale Agreement dated July 20, 2010. The dispute centers on Apache Canada Ltd.’s identification of Alleged Adverse Conditions, as that term is defined in the parties’ agreement, and more specifically the contention that liabilities associated with such conditions were retained by BP Canada as seller. Apache Canada Ltd. is diligently pursuing this claim.
On May 25, 2011, a panel of the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) published a report dated May 23, 2011, and titled “Vermilion Block, Production Platform A: An Investigation of the September 2, 2010 Incident in the Gulf of Mexico.” The report concerned the BOEMRE’s investigation of a fire on the Vermilion 380 A platform located in the Gulf of Mexico. At the time of the incident, Mariner Energy, Inc. (“MEI”) operated the platform. A small amount of hydrocarbons spilled from the platform into the surrounding water as a result of the incident, and 13 workers evacuated to safety by jumping into the water where they were later rescued. The BOEMRE concluded in its investigation that the fire was caused by MEI’s failure to adequately maintain or operate the platform’s heater-treater in a safe condition. The BOEMRE also identified other safety deficiencies on the platform. The BOEMRE has recommended that several Incidents of Non-Compliance be issued to MEI, which may provide the basis for the assessment of civil penalties against MEI. Effective November 10, 2010, MEI was acquired by Apache Corporation.
8. CAPITAL STOCK
Net Income per Common Share
A reconciliation of the components of basic and diluted net income per common share for the quarters and six-month periods ended June 30, 2011 and 2010 is presented in the table below.
For the Quarter Ended June 30,
2011 2010
Income Shares Per Share Income Shares Per Share
(In millions, except per share amounts)
Basic:
Income attributable to common stock
$ 1,240 384 $ 3.23 $ 860 338 $ 2.55
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock
19 12
Stock options and other
1 1
Diluted:
Income attributable to common stock, including assumed conversions
$ 1,259 397 $ 3.17 $ 860 339 $ 2.53
For the Six Months Ended June 30,
2011 2010
Income Shares Per Share Income Shares Per Share
(In millions, except per share amounts)
Basic:
Income attributable to common stock
$ 2,355 383 $ 6.14 $ 1,565 337 $ 4.64
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock
38 12
Stock options and other
2 2
Diluted:
Income attributable to common stock, including assumed conversions
$ 2,393 397 $ 6.03 $ 1,565 339 $ 4.61
The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 1.5 million and 3.3 million for the quarters ending June 30, 2011 and 2010, and 1.1 million and 2.9 million for the six months ended June 30, 2011 and 2010, respectively.

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Issuance of Common and Preferred Shares
In July 2010, in conjunction with Apache’s acquisition of properties from BP, the Company issued 26.45 million shares of common stock, as well as 25.3 million depositary shares, each representing a 1/20 th interest in a share of Apache’s 6.00% Mandatory Convertible Preferred Stock, Series D, or 1.265 million Preferred Shares. Each outstanding Preferred Share will, on August 1, 2013, automatically convert into a minimum of 9.164 or a maximum of 11.364 shares of Apache common stock depending on an average underlying price of the common stock immediately preceding the conversion.
In November 2010, in connection with the Mariner merger, Apache issued 17.3 million shares of common stock in exchange for Mariner common and restricted stock. For further discussion of the BP acquisitions and Mariner merger, please see Note 2 — Acquisitions and Divestitures of this Form 10-Q.
On May 5, 2011, Apache stockholders approved amendments to the Certificate of Incorporation increasing the number of common shares authorized for issuance from 430 million to 860 million and increasing the number of preferred shares authorized for issuance from five million to 10 million.
Common and Preferred Stock Dividends
For the quarters ending June 30, 2011 and 2010, Apache paid $58 million and $51 million, respectively, in dividends on its common stock. For the six-month periods ended June 30, 2011 and 2010, the Company paid $115 million and $101 million, respectively. In the three- and six-month periods ended June 30, 2011, Apache paid a total of $19 million and $38 million, respectively, in dividends on its Series D Preferred Stock issued in July 2010.
9. FAIR VALUE MEASUREMENTS
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 the 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 its derivative instruments. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The Company’s derivatives are not actively quoted in the open market but are valued utilizing commodity futures price strips for the underlying commodities, which are provided by a reputable third party. For further information regarding Apache’s derivative instruments and hedging activities, please see Note 3 — Derivative Instruments and Hedging Activities of this Form 10-Q.

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The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis for each hierarchy level:
Fair Value Measurements Using
Quoted
Price in
Significant Significant
Active Other Unobservable Total
Markets Inputs Inputs Fair Carrying
(Level 1) (Level 2) (Level 3) Value Netting (1) Amount
(In millions)
June 30, 2011
Assets:
Commodity Derivative Instruments
$ $ 369 $ $ 369 $ (111 ) $ 258
Liabilities:
Commodity Derivative Instruments
465 465 (111 ) 354
December 31, 2010
Assets:
Commodity Derivative Instruments
$ $ 454 $ $ 454 $ (148 ) $ 306
Liabilities:
Commodity Derivative Instruments
466 466 (148 ) 318
(1) The derivative fair values above are based on analysis of each contract on a gross basis, even where the legal right of offset exits, as required by ASC Topic 820. The carrying amounts of derivative assets and liabilities reported on the consolidated balance sheet are determined by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. See Note 3 — Derivative Instruments and Hedging Activities of this Form 10-Q for a discussion of amounts recorded on the consolidated balance sheet at June 30, 2011 and December 31, 2010.
10. COMPREHENSIVE INCOME
The following table presents the components of Apache’s comprehensive income for the quarter and six-month periods ended June 30, 2011 and 2010.
For the Quarter Ended For the Six Months Ended
June 30, June 30,
2011 2010 2011 2010
(In millions)
Net income
$ 1,259 $ 860 $ 2,393 $ 1,565
Other comprehensive income (loss):
Commodity hedges
362 102 (73 ) 463
Income tax related to commodity hedges
(117 ) (39 ) 14 (150 )
Total comprehensive income
$ 1,504 $ 923 $ 2,334 $ 1,878

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11. 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. At June 30, 2011, the Company had operations in the United States, Canada, Egypt, the United Kingdom North Sea, Australia and Argentina. Financial information for each country is presented below:
United Other
States Canada Egypt Australia North Sea Argentina International Total
(In millions)
For the Quarter Ended June 30, 2011
Oil and Gas Production Revenues
$ 1,560 $ 433 $ 1,201 $ 470 $ 572 $ 119 $ $ 4,355
Operating Income (Loss) (1)
$ 738 $ 104 $ 893 $ 311 $ 257 $ 21 $ (26 ) $ 2,298
Other Income (Expense):
Other
(17 )
General and administrative
(103 )
Merger, acquisitions & transition
(6 )
Financing costs, net
(41 )
Income Before Income Taxes
$ 2,131
For the Six Months Ended June 30, 2011
Oil and Gas Production Revenues
$ 2,937 $ 835 $ 2,401 $ 842 $ 1,002 $ 216 $ $ 8,233
Operating Income (Loss) (1)
$ 1,368 $ 182 $ 1,787 $ 536 $ 462 $ 31 $ (26 ) $ 4,340
Other Income (Expense):
Other
30
General and administrative
(215 )
Merger, acquisitions & transition
(11 )
Financing costs, net
(86 )
Income Before Income Taxes
$ 4,058
Total Assets
$ 22,142 $ 8,680 $ 6,677 $ 4,272 $ 2,999 $ 1,686 $ 73 $ 46,529
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
(84 )
Merger, acquisitions & transition
(8 )
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
(171 )
Merger, acquisitions & transition
(8 )
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
(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.

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12. SUPPLEMENTAL GUARANTOR INFORMATION
Apache Finance Canada Corporation (Apache Finance Canada) is a wholly-owned subsidiary of Apache and 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, 2011
All Other
Apache Subsidiaries
Apache Finance of Apache Reclassifications
Corporation Canada Corporation & Eliminations Consolidated
(In millions)
REVENUES AND OTHER:
Oil and gas production revenues
$ 1,127 $ $ 3,228 $ $ 4,355
Equity in net income (loss) of affiliates
972 (11 ) (20 ) (941 )
Other
4 (19 ) (1 ) (1 ) (17 )
2,103 (30 ) 3,207 (942 ) 4,338
OPERATING EXPENSES:
Depreciation, depletion and amortization.
315 714 1,029
Asset retirement obligation accretion
17 21 38
Lease operating expenses
213 449 662
Gathering and transportation
12 61 73
Taxes other than income
50 205 255
General and administrative
84 20 (1 ) 103
Merger, acquisitions & transition
5 1 6
Financing costs, net
34 14 (7 ) 41
730 14 1,464 (1 ) 2,207
INCOME (LOSS) BEFORE INCOME TAXES
1,373 (44 ) 1,743 (941 ) 2,131
Provision (benefit) for income taxes
114 (13 ) 771 872
NET INCOME (LOSS)
1,259 (31 ) 972 (941 ) 1,259
Preferred stock dividends
19 19
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
$ 1,240 $ (31 ) $ 972 $ (941 ) $ 1,240

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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 millions)
REVENUES AND OTHER:
Oil and gas production revenues
$ 861 $ $ 2,108 $ $ 2,969
Equity in net income (loss) of affiliates
731 39 (9 ) (761 )
Other
2 15 (13 ) (1 ) 3
1,594 54 2,086 (762 ) 2,972
OPERATING EXPENSES:
Depreciation, depletion and amortization
234 495 729
Asset retirement obligation accretion
13 12 25
Lease operating expenses
172 274 446
Gathering and transportation
10 33 43
Taxes other than income
32 155 187
General and administrative
64 21 (1 ) 84
Merger, acquisitions & transition
8 8
Financing costs, net
50 14 (8 ) 56
583 14 982 (1 ) 1,578
INCOME BEFORE INCOME TAXES
1,011 40 1,104 (761 ) 1,394
Provision for income taxes
151 10 373 534
INCOME ATTRIBUTABLE TO COMMON STOCK
$ 860 $ 30 $ 731 $ (761 ) $ 860

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2011
All Other
Apache Subsidiaries
Apache Finance of Apache Reclassifications
Corporation Canada Corporation & Eliminations Consolidated
(In millions)
REVENUES AND OTHER:
Oil and gas production revenues
$ 2,133 $ $ 6,100 $ $ 8,233
Equity in net income (loss) of affiliates
1,866 (25 ) (48 ) (1,793 )
Other
5 (39 ) 66 (2 ) 30
4,004 (64 ) 6,118 (1,795 ) 8,263
OPERATING EXPENSES:
Depreciation, depletion and amortization.
615 1,350 1,965
Asset retirement obligation accretion
34 41 75
Lease operating expenses
404 881 1,285
Gathering and transportation
24 125 149
Taxes other than income
91 328 419
General and administrative
173 44 (2 ) 215
Merger, acquisitions & transition
10 1 11
Financing costs, net
71 28 (13 ) 86
1,422 28 2,757 (2 ) 4,205
INCOME (LOSS) BEFORE INCOME TAXES
2,582 (92 ) 3,361 (1,793 ) 4,058
Provision (benefit) for income taxes
189 (19 ) 1,495 1,665
NET INCOME (LOSS)
2,393 (73 ) 1,866 (1,793 ) 2,393
Preferred stock dividends
38 38
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
$ 2,355 $ (73 ) $ 1,866 $ (1,793 ) $ 2,355

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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 millions)
REVENUES AND OTHER:
Oil and gas production revenues
$ 1,750 $ $ 3,912 $ $ 5,662
Equity in net income (loss) of affiliates
1,195 64 (15 ) (1,244 )
Other
3 29 (47 ) (2 ) (17 )
2,948 93 3,850 (1,246 ) 5,645
OPERATING EXPENSES:
Depreciation, depletion and amortization
448 920 1,368
Asset retirement obligation accretion
25 24 49
Lease operating expenses
337 549 886
Gathering and transportation
21 62 83
Taxes other than income
68 296 364
General and administrative
136 37 (2 ) 171
Merger, acquisitions & transition
8 8
Financing costs, net
102 28 (15 ) 115
1,145 28 1,873 (2 ) 3,044
INCOME BEFORE INCOME TAXES
1,803 65 1,977 (1,244 ) 2,601
Provision for income taxes
238 16 782 1,036
INCOME ATTRIBUTABLE TO COMMON STOCK
$ 1,565 $ 49 $ 1,195 $ (1,244 ) $ 1,565

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2011
All Other
Apache Subsidiaries
Apache Finance of Apache Reclassifications
Corporation Canada Corporation & Eliminations Consolidated
(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
$ 1,078 $ (29 ) $ 3,675 $ $ 4,724
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property
(864 ) (2,306 ) (3,170 )
Additions to gas gathering, transmission and processing facilities
(269 ) (269 )
Acquisitions, other
(78 ) (78 )
Proceeds from sales of oil and gas properties
6 186 192
Investment in subsidiaries, net
198 (198 )
Other
(34 ) (18 ) (52 )
NET CASH USED IN INVESTING ACTIVITIES
(694 ) (2,485 ) (198 ) (3,377 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net
(309 ) 20 (289 )
Intercompany borrowings
(1 ) (189 ) 190
Dividends paid
(153 ) (153 )
Common stock activity
38 30 (38 ) 8 38
Treasury stock activity, net
4 4
Other
38 (12 ) 26
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
(382 ) 29 (219 ) 198 (374 )
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
2 971 973
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
6 128 134
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$ 8 $ $ 1,099 $ $ 1,107

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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 millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
$ 1,184 $ (36 ) $ 1,937 $ $ 3,085
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property
(529 ) (1,408 ) (1,937 )
Additions to gas gathering, transmission and processing facilities
(257 ) (257 )
Acquisition of Devon properties
(1,017 ) (1,017 )
Investment in subsidiaries, net
(80 ) 80
Other
(45 ) 38 (7 )
NET CASH USED IN INVESTING ACTIVITIES
(1,671 ) (1,627 ) 80 (3,218 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net
2 3 18 (78 ) (55 )
Dividends paid
(101 ) (101 )
Common stock activity
21 33 (31 ) (2 ) 21
Treasury stock activity, net
3 3
Cost of debt and equity transactions
Other
22 22
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
(53 ) 36 (13 ) (80 ) (110 )
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(540 ) 297 (243 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
647 2 1,399 2,048
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$ 107 $ 2 $ 1,696 $ $ 1,805

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
June 30, 2011
All Other
Apache Subsidiaries
Apache Finance of Apache Reclassifications
Corporation Canada Corporation & Eliminations Consolidated
(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 8 $ $ 1,099 $ $ 1,107
Receivables, net of allowance
759 1,736 2,495
Inventories
58 575 633
Drilling advances
16 1 233 250
Prepaid assets and other
3,401 (2,986 ) 415
4,242 1 657 4,900
PROPERTY AND EQUIPMENT, NET
11,801 28,037 39,838
OTHER ASSETS:
Intercompany receivable, net
4,505 (2,973 ) (1,532 )
Equity in affiliates
18,451 1,309 97 (19,857 )
Goodwill, net
1,032 1,032
Deferred charges and other
175 1,003 581 (1,000 ) 759
$ 39,174 $ 2,313 $ 27,431 $ (22,389 ) $ 46,529
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable
$ 607 $ 1 $ 1,953 $ (1,532 ) $ 1,029
Accrued exploration and development
312 1,063 1,375
Current debt
400 48 448
Current asset retirement obligation
317 43 360
Derivative instruments
154 75 229
Other accrued expenses
368 4 671 1,043
2,158 5 3,853 (1,532 ) 4,484
LONG-TERM DEBT
6,756 647 1 7,404
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes
1,909 5 2,784 4,698
Asset retirement obligation
1,021 1,514 2,535
Other
663 250 828 (1,000 ) 741
3,593 255 5,126 (1,000 ) 7,974
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
26,667 1,406 18,451 (19,857 ) 26,667
$ 39,174 $ 2,313 $ 27,431 $ (22,389 ) $ 46,529

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2010
All Other
Subsidiaries
Apache Apache of Apache Reclassifications
Corporation Finance Canada Corporation & Eliminations Consolidated
(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
$ 6 $ $ 128 $ $ 134
Receivables, net of allowance
691 1,443 2,134
Inventories
55 509 564
Drilling advances
10 2 247 259
Prepaid assets and other
3,313 (2,924 ) 389
4,075 2 (597 ) 3,480
PROPERTY AND EQUIPMENT, NET
11,314 26,837 38,151
OTHER ASSETS:
Intercompany receivable, net
4,695 (3,149 ) (1,546 )
Equity in affiliates
16,649 1,275 98 (18,022 )
Goodwill, net
1,032 1,032
Deferred charges and other
178 1,003 581 (1,000 ) 762
$ 36,911 $ 2,280 $ 24,802 $ (20,568 ) $ 43,425
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable
$ 480 $ 2 $ 1,843 $ (1,546 ) $ 779
Accrued exploration and development
274 1,093 1,367
Current debt
16 30 46
Current asset retirement obligation
317 90 407
Derivative instruments
153 41 194
Other accrued expenses
400 3 328 731
1,640 5 3,425 (1,546 ) 3,524
LONG-TERM DEBT
7,447 647 1 8,095
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes
1,803 5 2,441 4,249
Asset retirement obligation
1,001 1,464 2,465
Other
643 250 822 (1,000 ) 715
3,447 255 4,727 (1,000 ) 7,429
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
24,377 1,373 16,649 (18,022 ) 24,377
$ 36,911 $ 2,280 $ 24,802 $ (20,568 ) $ 43,425

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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 operations in the United States, Canada, Egypt, the United Kingdom (U.K.) North Sea, Australia and Argentina.
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 Amended Annual Report on Form 10-K/A.
Financial Overview
A cornerstone of our business model is balancing our portfolio through a diversity of geologic risk, geographic risk, hydrocarbon mix (crude oil and natural gas) and reserve life in order to achieve consistent results and grow a profitable exploration and production company for the long-term benefit of our shareholders. This balanced approach and relentless focus on rate of return has underpinned our 2011 results. Record production and higher relative prices drove second-quarter 2011 earnings to $1.2 billion, or $3.17 per diluted common share, up 44 percent from $860 million, or $2.53 per share, in the comparable year-ago period. For the first half of 2011, earnings totaled $2.4 billion, or $6.03 per diluted share, compared to earnings of $1.6 billion, or $4.61 per share in 2010.
Our financial performance during 2011 highlights the importance of having a diverse portfolio of assets as well as maintaining a balanced product mix. Oil and liquids represent 49 percent of our total production, but provide 78 percent of our $4.4 billion second-quarter oil and gas revenues. This reflects the benefit of having a meaningful oil position in our balanced portfolio while North American natural gas prices continue to languish. Further benefiting our results is that nearly 60 percent of our crude oil sales come from international regions (outside of North America) where we receive prices indexed to Dated Brent. Dated Brent premiums have been higher during 2011 than they have historically been relative to West Texas Intermediate (WTI)-based prices. Similarly, both Heavy and Light Louisiana Sweet (HLS and LLS) crudes are trading at a higher than historical premium to WTI, positively impacting the majority of our production offshore in the Gulf of Mexico. Our geographic balance is also enhancing 2011 results with one-third of our natural gas production outside of North America, where prices are based on contracts averaging higher realized prices than previous years. Partially offsetting higher revenues is a rise in operating costs compared to prior periods. We continue to monitor cost trends very closely and make appropriate adjustments to drilling and development plans while actively pursuing cost efficiencies. As we continue to integrate our 2010 acquisitions, we believe further per-unit cost increases can be mitigated. In general, however, operating costs for wells producing crude oil and condensate are higher than operating costs for wells producing natural gas.
We remain committed to our objective of maintaining a conservative capital structure and are on target to keep 2011 exploration and development capital spending within operating cash flow estimates. Consistent with prior quarters, we routinely review capital budgets and region allocations through a disciplined process of assessing internally-generated drilling prospects and opportunities for tactical land acquisitions, occasionally entering new venture areas that could enhance our portfolio. We also remain financially positioned to take advantage of potential acquisition opportunities that may materialize. Specifically, we exited the quarter with $1.1 billion of cash, an increase of $1 billion from December 31, 2010, and a debt-to-capitalization ratio of 23 percent, down from 25 percent at year end. In addition, we have access to $2.7 billion of available committed borrowing capacity.
Key financial measures of our performance for the second quarter and first half of 2011 are summarized below:
Complemented with prior-year acquisition activity, average second-quarter 2011 production of 749 thousand barrels of oil equivalent per day (Mboe/d) set a new record for the Company and represents an increase of 16 percent from second-quarter 2010;
Net cash provided by operating activities (operating cash flows or cash flows) totaled $2.7 billion for the second quarter of 2011, up 42 percent from $1.9 billion in the prior-year period. Year-to-date operating cash flows for 2011 totaled $4.7 billion compared to $3.1 billion in 2010;
Second-quarter oil and gas production revenues increased 47 percent to $4.4 billion from the prior-year quarter, while first-half 2011 oil and gas production revenues increased 45 percent to $8.2 billion from the comparable prior year period;

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Pre-tax margin in the second quarter of 2011 was $31.29 per barrel of oil equivalent (boe), up 32 percent from the comparable 2010 period. Pre-tax margin year-to-date 2011 was $30.29 per boe, up 30 percent from the comparable 2010 period. Pre-tax margin is calculated as income before income taxes divided by barrels-equivalent production;
Oil and gas capital expenditures totaled $3.8 billion in the first half of 2011, consistent with the current $8.1 billion budgeted for the full year; and
Annualized after-tax return on average capital employed during the second quarter and first half of 2011 was 15 percent and 14 percent, respectively.
Please refer to Results of Operations in this Item 2 for a more detailed discussion of revenue and cost components.
Operating Highlights
Apache has a significant producing asset base as well as large undeveloped acreage positions which provide room for continued growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. We are also continuing to advance several longer-term, individually significant development projects. Our cash flows enable us to optimize both endeavors. Notable operating highlights for the second quarter of 2011 include:
United States
Apache continued to accumulate acreage in Alaska’s Cook Inlet and was the successful bidder on approximately 515,000 acres of onshore and offshore state leases during the second quarter. The Company has now accumulated approximately 800,000 gross acres in the Cook Inlet and has current plans to conduct a seismic survey for the area over the next 12 to 18 months.
Apache and its partners entered a unitization agreement to develop the Lucius deepwater discovery. Apache will participate in the unit with an 11.7-percent working interest in Keathley Canyon Blocks 874, 875, 918 and 919. Project sanction is expected later this year, with first production projected for 2014. Under terms of a separate agreement, gas produced from the nearby Hadrian South field will be processed at Lucius in exchange for a handling fee and reimbursement for any required facility upgrades.
On July 12, Apache agreed with Crosstex Energy, L.P. to jointly build an $85 million natural gas processing facility for our expanding Deadwood development in the Permian Basin of west Texas. The plant, in which Apache has a 50-percent interest, is anticipated to become fully operational in the second quarter of 2012 with capacity of 50 million cubic feet of natural gas per day (MMcf/d). This infrastructure will enable Apache to continue its active development program targeting multiple stacked formations, including the Wolfcamp, Cline, Strawn, Atoka and Fusselman. The company currently has 24 rigs operating in the Permian Basin, with 11 dedicated to the Deadwood play.
Canada
The Company progressed with the Kitimat liquefied natural gas (LNG) front-end engineering and design (FEED) study and continued its efforts to secure firm sales commitments, licenses and required permits necessary to make a final investment decision on the LNG project during the first quarter of 2012.
Egypt
On June 16, the Company announced five new field discoveries in the Faghur basin of Egypt’s Western Desert that tested in aggregate over 12,000 barrels of oil per day (b/d) and 19 MMcf/d. On August 4, Apache announced two additional discoveries that tested over 10,000 b/d and 7 MMcf/d. These wells are the most recent in a series of oil discoveries in the AEB, Safa and now Paleozoic reservoirs that support the multi-pay potential of this oil-prone basin. For 2011, Apache has drilled 11 exploration wells in the Faghur basin resulting in nine new field discoveries. The Company plans to drill an additional nine exploration wells in the area by year end.
Apache also announced the AG-96 development well in the Abu Gharadig Concession that tested nearly 3,500 b/d and 1 MMcf/d. This well was drilled on acreage acquired from BP and solidified plans to drill several additional wells in the area by year end.

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Australia
On June 1 Apache’s Halyard-1 gas discovery well commenced production into the Western Australian domestic market. The Halyard development, which utilizes existing pipelines and facilities, was completed ahead of schedule and sets the stage for development of our adjacent Spar field, which is expected to follow in late 2012 as additional capacity becomes available at Varanus Island.
In July Apache and its partners signed long-term agreements with Tokyo Electric Power Company (TEPCO) for the delivery of LNG from the Chevron-operated Wheatstone LNG hub in Western Australia. Under the agreements, Apache and its partners will deliver up to 3.1 million tons per annum (mtpa) of LNG to TEPCO for a period of up to 20 years. Through its 13-percent share in Wheatstone, Apache will supply approximately 0.45 mtpa to TEPCO from its natural gas produced at the Julimar and Brunello fields. A final investment decision is expected in the second half of 2011.
In the second quarter of 2011, the Company sanctioned plans to develop Apache’s Balnaves oil discovery through a new Floating Production Storage and Offloading (FPSO) vessel. The project is expected to deliver initial production of 30,000 b/d in 2014. Apache has a 65-percent working interest in the project.
Scheduled maintenance on the Van Gogh field’s FPSO vessel commenced in early June and was completed in early August.
North Sea
On July 6, 2011, Apache announced that the Charlie 4-3 and the Delta 3-5 wells commenced production at rates of 12,567 b/d and 8,781 b/d, respectively. These wells are the eighth and ninth development wells brought on production at the Forties field during 2011, where a total of 18 wells are expected to be drilled for the year. The success of the region’s drilling program is supported by a new 4-D time-lapse seismic survey.
Argentina
In May, Apache’s first horizontal well in the Anticlinal Campamento field in the Neuquén began producing at a rate over 10 MMcf/d. The well was a test of horizontal drilling and multi-stage hydraulic fracturing in the low-permeability Pre-Cuyo formation. Apache continues to evaluate the potential of tight and unconventional gas resources in the Pre-Cuyo, Los Molles and Vaca Muerta formations of the Neuquén basin, which is supported by higher gas prices realized under the Gas Plus program. In the second quarter, Apache’s Gas Plus production was 77 MMcf/d with an average price of $4.93 per thousand cubic feet of natural gas (Mcf).

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Results of Operations
Oil and Gas Revenues
For the Quarter Ended June 30, For the Six Months Ended June 30,
2011 2010 2011 2010
$ % $ % $ % $ %
Value Contribution Value Contribution Value Contribution Value Contribution
($ in millions)
Total Oil Revenues:
United States
$ 1,050 32% $ 604 27% $ 1,968 32% $ 1,198 29%
Canada
135 4% 94 4% 250 4% 191 5%
North America
1,185 36% 698 31% 2,218 36% 1,389 34%
Egypt
1,045 32% 682 30% 2,095 34% 1,307 31%
Australia
425 13% 411 19% 756 12% 594 14%
North Sea
567 17% 417 18% 993 16% 804 19%
Argentina
58 2% 50 2% 110 2% 101 2%
International
2,095 64% 1,560 69% 3,954 64% 2,806 66%
Total (1)
$ 3,280 100% $ 2,258 100% $ 6,172 100% $ 4,195 100%
Total Gas Revenues:
United States
$ 405 43% $ 314 48% $ 786 43% $ 680 50%
Canada
273 29% 139 21% 536 30% 289 21%
North America
678 72% 453 69% 1,322 73% 969 71%
Egypt
157 17% 124 19% 305 17% 240 17%
Australia
45 5% 41 6% 86 5% 82 6%
North Sea
5 0% 4 1% 9 0% 8 1%
Argentina
53 6% 31 5% 90 5% 62 5%
International
260 28% 200 31% 490 27% 392 29%
Total (2)
$ 938 100% $ 653 100% $ 1,812 100% $ 1,361 100%
Natural Gas Liquids (NGL)
Revenues:
United States
$ 105 77% $ 44 76% $ 183 73% $ 76 72%
Canada
25 18% 7 12% 49 20% 13 12%
North America
130 95% 51 88% 232 93% 89 84%
Egypt
1 0%
Argentina
7 5% 7 12% 16 7% 17 16%
International
7 5% 7 12% 17 7% 17 16%
Total
$ 137 100% $ 58 100% $ 249 100% $ 106 100%
Total Oil and Gas Revenues:
United States
$ 1,560 36% $ 962 32% $ 2,937 36% $ 1,954 35%
Canada
433 10% 240 8% 835 10% 493 9%
North America
1,993 46% 1,202 40% 3,772 46% 2,447 44%
Egypt
1,201 28% 806 28% 2,401 29% 1,547 27%
Australia
470 11% 452 15% 842 10% 676 12%
North Sea
572 13% 421 14% 1,002 12% 812 14%
Argentina
119 2% 88 3% 216 3% 180 3%
International
2,362 54% 1,767 60% 4,461 54% 3,215 56%
Total
$ 4,355 100% $ 2,969 100% $ 8,233 100% $ 5,662 100%
(1)
Financial derivative hedging activities and the North Sea fixed-price sales contract decreased oil revenues $148 million and $219 million for the 2011 second quarter and six-month period, respectively, and $12 million and $26 million for the 2010 second quarter and six-month period.
(2)
Financial derivative hedging activities increased natural gas revenues $61 million and $125 million for the 2011 second quarter and six-month period, respectively, and $65 million and $77 million for the 2010 second quarter and six-month period.

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Production
For the Quarter Ended June 30, For the Six Months Ended June 30,
Increase Increase
2011 2010 (Decrease) 2011 2010 (Decrease)
Oil Volume — b/d:
United States
117,257 89,529 31% 115,499 89,144 30%
Canada
14,408 14,561 (1)% 14,555 14,447 1%
North America
131,665 104,090 26% 130,054 103,591 26%
Egypt
99,634 98,495 1% 104,230 94,642 10%
Australia
40,573 60,680 (33)% 37,663 43,978 (14)%
North Sea
57,364 58,141 (1)% 52,195 57,995 (10)%
Argentina
9,656 9,874 (2)% 9,636 9,897 (3)%
International
207,227 227,190 (9)% 203,724 206,512 (1)%
Total (1)
338,892 331,280 2% 333,778 310,103 8%
Natural Gas Volume — Mcf/d:
United States
880,283 674,886 30% 869,276 673,361 29%
Canada
636,718 339,611 87% 639,707 326,646 96%
North America
1,517,001 1,014,497 50% 1,508,983 1,000,007 51%
Egypt
358,870 388,367 (8)% 365,157 375,249 (3)%
Australia
179,582 203,147 (12)% 181,243 205,209 (12)%
North Sea
2,367 2,516 (6)% 2,135 2,540 (16)%
Argentina
215,203 183,028 18% 201,722 168,953 19%
International
756,022 777,058 (3)% 750,257 751,951 0%
Total (2)
2,273,023 1,791,555 27% 2,259,240 1,751,958 29%
Natural Gas Liquids (NGL) Volume — b/d:
United States
21,803 11,878 84% 20,534 9,374 119%
Canada
5,998 1,996 201% 6,270 1,866 236%
North America
27,801 13,874 100% 26,804 11,240 138%
Egypt
(24 ) NM 101 NM
Argentina
3,014 3,118 (3)% 3,035 3,204 (5)%
International
2,990 3,118 (4)% 3,136 3,204 (2)%
Total
30,791 16,992 81% 29,940 14,444 107%
BOE per day (3)
United States
285,773 213,889 34% 280,913 210,746 33%
Canada
126,526 73,159 73% 127,443 70,753 80%
North America
412,299 287,048 44% 408,356 281,499 45%
Egypt
159,422 163,223 (2)% 165,190 157,184 5%
Australia
70,503 94,538 (25)% 67,870 78,179 (13)%
North Sea
57,758 58,560 (1)% 52,551 58,418 (10)%
Argentina
48,537 43,497 12% 46,291 41,260 12%
International
336,220 359,818 (7)% 331,902 335,041 (1)%
Total
748,519 646,866 16% 740,258 616,540 20%
(1)
Approximately 29 and 30 percent of worldwide oil production was subject to financial derivative hedges for the second quarter and six-month period of 2011, respectively, and nine and 11 percent for the comparative 2010 second quarter and six-month periods.
(2)
Approximately 16 percent of worldwide natural gas production was subject to financial derivative hedges for the second quarter and six-month period of 2011, and 23 and 24 percent for the comparative 2010 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
2011 2010 (Decrease) 2011 2010 (Decrease)
Average Oil Price — Per barrel:
United States
$ 98.41 $ 74.20 33% $ 94.15 $ 74.26 27%
Canada
102.42 70.87 45% 94.78 73.10 30%
North America
98.85 73.73 34% 94.22 74.10 27%
Egypt
115.26 76.08 51% 111.05 76.27 46%
Australia
115.18 74.42 55% 110.92 74.58 49%
North Sea
108.44 78.78 38% 105.06 76.58 37%
Argentina
65.58 55.41 18% 62.99 56.60 11%
International
111.04 75.43 47% 107.22 75.05 43%
Total (1)
106.31 74.89 42% 102.15 74.74 37%
Average Natural Gas Price — Per Mcf:
United States
$ 5.05 $ 5.11 (1)% $ 4.99 $ 5.58 (11)%
Canada
4.71 4.51 4% 4.63 4.88 (5)%
North America
4.91 4.91 0% 4.84 5.35 (10)%
Egypt
4.79 3.51 36% 4.61 3.54 30%
Australia
2.74 2.22 23% 2.62 2.22 18%
North Sea
26.41 17.15 54% 23.72 17.73 34%
Argentina
2.74 1.88 46% 2.48 2.01 23%
International
3.79 2.83 34% 3.61 2.88 25%
Total (2)
4.54 4.01 13% 4.43 4.29 3%
Average NGL Price — Per barrel:
United States
$ 52.91 $ 40.48 31% $ 49.22 $ 44.63 10%
Canada
46.63 35.76 30% 43.25 37.97 14%
North America
51.56 39.80 30% 47.82 43.52 10%
Egypt
43.53 NM 65.73 NM
Argentina
27.64 25.68 8% 29.08 30.23 (4)%
International
27.51 25.68 7% 30.26 30.23 0%
Total
49.22 37.21 32% 45.98 40.58 13%
(1)
Reflects a per barrel decrease of $4.80 and $3.63 from derivative activities and the North Sea fixed-price sales contract for the 2011 second quarter and six-month period, respectively, and a decrease of $.39 and $.47 from derivative activities for the comparative 2010 second quarter and six-month period.
(2)
Reflects a per Mcf increase of $.30 and $.31 from derivative activities for the 2011 second quarter and six-month period, respectively, and an increase of $.39 and $.24 from derivative activities for the comparative 2010 second quarter and six-month period.
Second-Quarter 2011 compared to Second-Quarter 2010
Crude Oil Revenues Crude oil revenues for the second quarter of 2011 totaled $3.3 billion, over $1 billion higher than the comparative 2010 quarter, primarily the result of a 42-percent increase in average realized prices. Crude oil accounted for 75 percent of oil and gas production revenues and 45 percent of worldwide production in the second quarter of 2011. Higher realized prices added $948 million to the increase in second-quarter 2011 revenues compared to the prior-year quarter, while higher production volumes contributed an additional $74 million.
Crude oil prices realized in the second quarter of 2011 averaged $106.31 per barrel, compared with $74.89 in the comparative prior-year quarter. Our international regions’ crude oil realizations averaged $111.04, an increase of 47 percent compared with second-quarter 2010 realizations of $75.43. Our Egypt, Australia and North Sea regions, which comprise approximately 58 percent of our worldwide oil production, continue to benefit from wide Dated Brent premiums to U.S. WTI-based prices, with second-quarter 2011 oil realizations averaging $113.27 compared with second-quarter 2010 realizations of $76.34.
Worldwide production increased 8 thousand barrels of oil per day (Mb/d) from the second quarter of 2010 to 339 Mb/d in the second quarter of 2011, primarily a result of a 31-percent increase in U.S. production. The 28 Mb/d increase in U.S. oil production is primarily a result of 2010 acquisition activity. The Permian region was up 14 Mb/d on properties added from the BP acquisition and the Mariner merger and on increased drilling activity. The Gulf of Mexico (GOM) onshore and offshore regions added 10 Mb/d, reflecting properties acquired in the Devon acquisition and the Mariner merger; however, natural decline negatively impacted results, as new drilling continues to be impacted by the slow pace of permitting in the GOM. Egypt’s gross oil production increased 19 percent from volumes acquired in the BP acquisition and additional capacity provided by the Kalabsha oil processing facility beginning in the second half of 2010. Egypt’s net production, however, remained relatively flat as higher oil prices impacted our allocated volumes. Australia production decreased 20 Mb/d as a result of repairs to the Van Gogh FPSO vessel and natural decline. Production decreased .8 Mb/d in the North Sea on natural decline, planned maintenance and downtime related to a shut-in intra-field pipeline. An existing pipeline was converted to oil service for temporary use until the permanent replacement line is completed in the third quarter of 2011.

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Natural Gas Revenues Gas revenues for the second quarter of 2011 totaled $939 million, up 44 percent from the second quarter of 2010. A 27-percent increase in average production added $199 million to natural gas revenues as compared to the prior-year quarter, while a 13-percent rise in average realized prices contributed an additional $86 million. Natural gas accounted for 22 percent of our oil and gas production revenues and 51 percent of our equivalent production. All of our international regions, which comprise approximately one-third of total gas production, benefited from higher realized prices.
Worldwide production grew 481 MMcf/d between the periods on production increases in Canada, the U.S., and Argentina. Daily production in Canada increased 87 percent, up 297 MMcf/d on additional volumes from properties acquired from BP and an active drilling and completion program in the Horn River basin. U.S. daily production increased 205 MMcf/d, primarily as a result of acquisition activity in 2010. Permian region production rose 88 MMcf/d on incremental volumes from properties added from the BP acquisition and the Mariner merger and on increased drilling activity. The GOM onshore and offshore regions added 101 MMcf/d from properties acquired in the Devon acquisition and the Mariner merger, offset by natural decline, as new drilling continues to be impacted by the slow pace of permitting in the GOM. Argentina’s production was up 32 MMcf/d from recompletions and new drilling, primarily associated with the country’s Gas Plus program. Egypt’s gross production was up 76 MMcf/d on a successful drilling program and additional gas throughput from the Obaiyed Gas Plant, as well as production from properties added in the BP acquisition. Net production was down eight percent, as higher oil prices impacted our allocated volumes. Australia’s daily gas production fell 24 MMcf/d as customer maintenance activities resulted in lower takes under existing contractual arrangements.
Year-to-Date 2011 compared to Year-to-Date 2010
Crude Oil Revenues Crude oil revenues for the first half of 2011 totaled $6.2 billion, nearly $2 billion higher than the comparative 2010 period, the result of a 37-percent increase in average realized prices and an eight-percent increase in worldwide production. Crude oil accounted for 75 percent of oil and gas production revenues and 45 percent of worldwide production, compared with 74 percent and 50 percent, respectively, in the 2010 period. Higher realized prices added $1.5 billion to the increase in revenues compared to the prior-year period, while higher production volumes contributed an additional $438 million.
Crude oil prices realized in the first six months of 2011 averaged $102.15 per barrel, compared with $74.74 in the comparative prior-year period. Our international regions’ crude oil realizations averaged $107.22, an increase of 43 percent compared with 2010-period realizations of $75.05. Our Egypt, Australia and North Sea regions, which comprise approximately 58 percent of our worldwide oil production, continue to benefit from wide Dated Brent premiums to U.S. WTI-based prices, with oil realizations averaging $109.41 compared with realizations of $75.98 in the 2010 period.
Worldwide production increased 24 Mb/d from the year-to-date 2010 to 334 Mb/d in the first half of 2011, driven by increased production in the U.S. and Egypt. The 26 Mb/d increase in U.S. oil production is primarily a result of 2010 acquisition activity. The Permian region was up 13 Mb/d on properties added from the BP acquisition and the Mariner merger, offset by natural decline and weather-related shut-ins. The GOM onshore and offshore regions added 10 Mb/d reflecting properties acquired in the Devon acquisition and the Mariner merger; however, natural decline negatively impacted results, as new drilling has been impacted by the slow pace of permitting in the GOM. Egypt’s gross oil production increased 21 percent, while net production was up 10 percent, as higher oil prices impacted our allocated volumes. The production increase was a result of additional capacity provided by the Kalabsha oil processing facility, production from properties added in the BP acquisition and an active drilling program. Australia saw production decrease 6 Mb/d as a result of tropical cyclones and repairs to the Van Gogh FPSO vessel. Production decreased 6 Mb/d in the North Sea on natural decline, planned maintenance and downtime related to a shut-in intra-field pipeline. An existing pipeline was converted to oil service for temporary use until the permanent replacement line is completed in the third quarter of 2011.
Natural Gas Revenues Gas revenues for the first six months of 2011 totaled $1.8 billion, up 33 percent from the comparative 2010 period. A 29-percent increase in average production added $407 million to natural gas revenues, while a three-percent increase in average realized prices contributed an additional $44 million. Natural gas accounted for 22 percent of our oil and gas production revenues and 51 percent of our equivalent production, compared to 24 and 47 percent, respectively, for the 2010 period. All of our international regions, which comprise approximately one-third of total gas production, benefited from higher realized prices.

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Worldwide production grew 507 MMcf/d between the periods on production increases in Canada, the U.S., and Argentina. Daily production in Canada almost doubled, rising 313 MMcf/d on additional volumes from properties acquired from BP and an active drilling and completion program in the Horn River basin. U.S. daily production increased 196 MMcf/d, primarily as a result of acquisition activity in 2010. Permian region production rose 73 MMcf/d on incremental volumes from properties added from the BP acquisition and the Mariner merger and on increased drilling activity. Frigid weather during the first quarter tempered production gains. The GOM onshore and offshore regions added 102 MMcf/d from properties acquired in the Devon acquisition and the Mariner merger, offset by natural decline, as new drilling has been impacted by the slow pace of permitting in the GOM. Argentina’s production was up 33 MMcf/d from new drilling and recompletions. Australia’s daily gas production fell 24 MMcf/d on downtime from tropical cyclones and customer maintenance activities resulting in lower takes under existing contractual arrangements. Egypt’s gross production was up nine percent on a successful drilling program, additional gas throughput from the Obaiyed Gas Plant and production from properties added in the BP acquisition. Net production was down three percent, as higher prices impacted our allocated volumes.
Operating Expenses
The table below presents a comparison of our expenses on an absolute dollar basis and a boe basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on their relevance.
For the Quarter Ended June 30, For the Six Months Ended June 30,
2011 2010 2011 2010 2011 2010 2011 2010
(In millions) (Per boe) (In millions) (Per boe)
Depreciation, depletion and amortization:
Oil and gas property
$ 960 $ 676 $ 14.10 $ 11.49 $ 1,830 $ 1,263 $ 13.65 $ 11.32
Other assets
69 53 1.00 0.91 135 105 1.01 0.94
Asset retirement obligation accretion
38 25 0.57 0.42 75 49 0.56 0.44
Lease operating costs
662 446 9.72 7.58 1,285 886 9.59 7.94
Gathering and transportation costs
73 43 1.06 0.73 149 83 1.12 0.75
Taxes other than income
255 187 3.74 3.17 419 364 3.12 3.26
General and administrative expense
103 84 1.52 1.42 215 171 1.61 1.53
Merger, acquisitions & transition
6 8 0.08 0.14 11 8 0.09 0.07
Financing costs, net
41 56 0.60 0.95 86 115 0.64 1.03
Total
$ 2,207 $ 1,578 $ 32.39 $ 26.81 $ 4,205 $ 3,044 $ 31.39 $ 27.28
Second-Quarter 2011 compared to Second-Quarter 2010
Depreciation, Depletion and Amortization (DD&A) The following table details the changes in DD&A of oil and gas properties between the second quarters of 2011 and 2010:
Oil and Gas
Property DD&A
(In millions)
Second-quarter 2010 DD&A
$ 676
Volume change
90
Rate change
168
Other
26
Second-quarter 2011 DD&A
$ 960
Oil and gas property DD&A expense of $960 million increased $284 million on an absolute dollar basis: $168 million on rate, $90 million from higher volumes and $26 million associated with new venture seismic activity in countries where Apache has no established presence. The Company’s oil and gas property DD&A rate increased $2.61 to $14.10 per boe, reflecting acquisition and drilling costs that exceed our historical basis.

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Lease Operating Expenses (LOE) Second-quarter 2011 LOE increased $216 million, or 48 percent on an absolute dollar basis, as compared to the second quarter of 2010. On a per unit basis, LOE increased 28 percent to $9.72 per boe. The following table identifies changes in Apache’s LOE rate between the second quarters of 2010 and 2011.
Per boe
Second-quarter 2010 LOE
$ 7.58
Acquisitions, net of associated production
(0.21 )
Workover costs
0.47
Labor and overhead costs
0.43
FX impact
0.33
Transportation
0.21
Repairs and maintenance
0.16
Non-operated costs
0.16
Power and fuel costs
0.11
Other
0.14
Decreased production, excluding acquisitions
0.34
Second-quarter 2011 LOE
$ 9.72
Gathering and Transportation Gathering and transportation costs totaled $73 million in the second quarter of 2011, up $30 million from the second quarter of 2010. On a per-unit basis, gathering and transportation costs of $1.06 were up 45 percent. 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,
2011 2010
(In millions)
Canada
$ 41 $ 16
U.S.
15 11
Egypt
8 9
North Sea
7 6
Argentina
2 1
Total Gathering and Transportation
$ 73 $ 43
The $25 million increase in Canada resulted from a combination of an increase in gas volumes of 87 percent, higher average rates and foreign exchange impacts. Average per-unit costs were directly influenced by Apache’s increased production in Canada’s Horn River basin and properties acquired during 2010, where the associated gathering, processing and transportation contracts had higher average rates than Apache’s legacy properties. The $4 million increase in the U.S. is directly related to increased volumes.
Taxes other than Income Taxes other than income totaled $255 million for the second quarter of 2011, an increase of $68 million from the prior-year period. The following table presents a comparison of these expenses:
For the Quarter Ended
June 30,
2011 2010
(In millions)
U.K. PRT
$ 155 $ 130
Severance taxes
57 28
Ad valorem taxes
27 17
Canadian taxes
7 3
Other
9 9
Total Taxes other than Income
$ 255 $ 187
The North Sea Petroleum Revenue Tax (PRT) is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties field in the U.K. North Sea. U.K. PRT was $25 million higher than the 2010 period based on a 22-percent increase in net receipts, primarily driven by higher revenues. Prior-year property acquisitions and higher realized oil and gas prices resulted in an increase of severance and ad valorem tax expense of $29 million and $10 million, respectively. Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. Ad valorem taxes are assessed on U.S and Canadian property values and sales.

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General and Administrative Expenses General and administrative expenses (G&A) were $19 million higher than the prior-year quarter on an absolute basis, driven by increases in insurance costs, stock-based and other incentive compensation, and various other corporate expenses resulting from the 2010 acquisitions. Per-unit G&A increased $.10 to an average of $1.52, with the impact of higher production partially offsetting the impact of higher costs.
Financing Costs, Net Financing costs incurred during the period comprised the following:
For the Quarter Ended
June 30,
2011 2010
(In millions)
Interest expense
$ 109 $ 75
Amortization of deferred loan costs
1 1
Capitalized interest
(63 ) (18 )
Interest income
(6 ) (2 )
Financing costs, net
$ 41 $ 56
Net financing costs were down $15 million in second-quarter 2011 compared to second-quarter 2010. The decrease is primarily related to a $45 million increase in capitalized interest, the result of additional unproved balances from the BP acquisitions and Mariner merger. This decrease is partially offset by a $34 million increase in interest expense associated with $2.5 billion of debt issued in the second half of 2010.
Provision for 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 material discrete tax events that occurred during the second quarter of 2011.
The 2011 second-quarter provision for income taxes increased $338 million to $872 million on a 53-percent increase in income before income taxes. The effective income tax rate for the second-quarter 2011 was 41 percent, up from an effective rate of 38 percent in the second-quarter 2010.
In March 2011 the U.K. government proposed an increase in the corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent. The legislation received Royal Assent and was enacted on July 19, 2011. As a result of the enacted legislation, the Company will record a non-recurring tax charge estimated at $290 million in the third quarter of 2011. Of this amount, an estimated $230 million is related to periods prior to 2011 and approximately $60 million is related to operating results through the second quarter of 2011.
Year-to-Date 2011 compared to Year-to-Date 2010
DD&A The following table details the changes in DD&A of oil and gas properties between the six-month periods of 2011 and 2010:
Oil and Gas
Property DD&A
(In millions)
2010 DD&A
$ 1,263
Volume change
216
Rate change
325
Other
26
2011 DD&A
$ 1,830
Oil and gas property DD&A expense of $1.8 billion increased $567 million on an absolute dollar basis: $325 million on rate, $216 million from higher volumes and $26 million associated with new venture seismic activity in countries where Apache has no established presence. The Company’s oil and gas property DD&A rate increased $2.33 to $13.65 per boe, reflecting acquisition and drilling costs that exceed our historical basis.

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LOE LOE for the first six months of 2011 increased $399 million, or 45 percent on an absolute dollar basis, as compared to the same period of 2010. On a per unit basis, LOE increased 21 percent to $9.59 per boe. The following table identifies changes in Apache’s LOE rate between the six-month periods ended June 30, 2010 and 2011.
Per boe
2010 LOE
$ 7.94
Acquisitions, net of associated production
(0.23 )
FX impact
0.32
Workover costs
0.30
Repairs and maintenance
0.29
Labor and overhead costs
0.28
Chemicals, power and fuel costs
0.20
Transportation
0.17
Other
0.32
2011 LOE
$ 9.59
Gathering and Transportation Gathering and transportation costs totaled $149 million in the first six months of 2011, up $66 million from the prior-year period. On a per-unit basis, gathering and transportation costs of $1.12 were up 49 percent from the prior-year six-month period. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:
For the Six Months Ended
June 30,
2011 2010
(In millions)
Canada
$ 86 $ 32
U.S
29 22
Egypt
18 15
North Sea
12 12
Argentina
4 2
Total Gathering and Transportation
$ 149 $ 83
The $54 million increase in Canada resulted from a combination of an increase in gas volumes of 96 percent, higher average rates and foreign exchange impacts. Average per-unit costs were directly influenced by Apache’s increased production in Canada’s Horn River basin and properties acquired during 2010, where the associated gathering, processing and transportation contracts had higher average rates than Apache’s legacy properties. The $7 million increase in the U.S. is directly related to increased volumes, while Egypt’s costs were up $3 million on a higher number of oil sales cargoes and higher vessel freight costs.
Taxes other than Income Taxes other than income totaled $419 million, an increase of $55 million. The following table presents a comparison of these expenses:
For the Six Months Ended
June 30,
2011 2010
(In millions)
U.K. PRT
$ 237 $ 253
Severance taxes
104 60
Ad valorem taxes
54 35
Canadian taxes
9 1
Other
15 15
Total Taxes other than Income
$ 419 $ 364
U.K. PRT was $16 million lower than the 2010 period based on a five-percent decrease in net receipts, primarily driven by capital expenditures that were more than double prior-year levels. Prior-year property acquisitions and higher realized oil and gas prices resulted in an increase of severance and ad valorem tax expense of $44 million and $19 million, respectively, when compared to the prior-year period. Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. Ad valorem taxes are assessed on U.S and Canadian property values and sales.

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G&A G&A were $44 million higher on an absolute basis, driven by increases in insurance costs, incentive compensation, and various other corporate expenses resulting from the 2010 acquisitions. Per-unit G&A increased $.08 to an average of $1.61, with the impact of higher production partially offsetting the impact of higher costs.
Financing Costs, Net Financing costs incurred during the periods comprised the following:
For the Six Months Ended
June 30,
2011 2010
(In millions)
Interest expense
$ 217 $ 151
Amortization of deferred loan costs
3 3
Capitalized interest
(124 ) (35 )
Interest income
(10 ) (4 )
Financing costs, net
$ 86 $ 115
Net financing costs were down $29 million for the first six months of 2011 compared to the same 2010 period. The decrease is primarily related to an $88 million increase in capitalized interest, the result of additional unproved balances from the BP acquisitions and Mariner merger. This decrease is partially offset by a $65 million increase in interest expense associated with $2.5 billion of debt issued in the second half of 2010.
Provision for 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 material discrete tax events that occurred during the first six months of 2011.
The 2011 first-half provision for income taxes increased $629 million to $1.7 billion on a 56-percent increase in income before income taxes. The effective income tax rate for the first six months of 2011 was 41 percent, consistent with an effective rate of 40 percent in the first six months of 2010.
In March 2011 the U.K. government proposed an increase in the corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent. The legislation received Royal Assent and was enacted on July 19, 2011. As a result of the enacted legislation, the Company will record a non-recurring tax charge estimated at $290 million in the third quarter of 2011. Of this amount, an estimated $230 million is related to periods prior to 2011 and approximately $60 million is related to operating results through the second quarter of 2011.

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Non-GAAP Measures
The Company makes reference to some measures in discussion of its financial and operating highlights that are not required by or presented in accordance with GAAP. Management uses these measures in assessing operating results and believes the presentation of these measures provides information useful in assessing the Company’s financial condition and results of operations. These non-GAAP measures should not be considered as alternatives to GAAP measures and may be calculated differently from, and therefore may not be comparable to, similarly-titled measures used at other companies.
Adjusted Earnings
To assess the Company’s operating trends and performance, management uses Adjusted Earnings, which is net income excluding certain items that management believes affect the comparability of operating results. Management believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings for items that may obscure underlying fundamentals and trends. The reconciling items below are the types of items management excludes and believes are frequently excluded by analysts when evaluating the operating trends and comparability of the Company’s results.
For the Quarter For the Six Months
Ended June 30, Ended June 30,
2011 2010 2011 2010
(In millions, except per share data)
Income Attributable to Common Stock (GAAP)
$ 1,240 $ 860 $ 2,355 $ 1,565
Adjustments:
Foreign currency fluctuation impact on deferred tax expense
19 (31 ) 31 (25 )
Merger, acquisitions & transition, net of tax
3 5 7 5
Adjusted Earnings (Non-GAAP)
$ 1,262 $ 834 $ 2,393 $ 1,545
Net Income per Common Share — Diluted (GAAP)
$ 3.17 $ 2.53 $ 6.03 $ 4.61
Adjustments:
Foreign currency fluctuation impact on deferred tax expense
.04 (.09 ) .07 (.07 )
Merger, acquisitions & transition, net of tax
.01 .02 .02 .02
Adjusted Earnings Per Share — Diluted (Non-GAAP)
$ 3.22 $ 2.46 $ 6.12 $ 4.56
Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. Apache’s cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash flows, and potentially our liquidity if spending does not trend downward as well. Sales volumes and costs also impact cash flows, but these historically have not been as volatile or as impactive as commodity prices in the short-term.
Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Our business, as with other extractive industries, is a depleting one in which each unit produced must be replaced or the Company and its reserves, a critical source of future liquidity, will shrink. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities and our ability to acquire additional reserves at reasonable costs.
We may also elect to utilize available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets for all other liquidity and capital resource needs. We believe the liquidity and capital resource alternatives available to Apache, combined with operating cash flows, will be adequate to fund our short-term and long-term operations, including our capital spending program, repayment of debt maturities and any amount that may ultimately be paid in connection with contingencies.
Apache’s primary uses of cash are for exploration, development and acquisition of oil and gas properties, costs necessary to maintain ongoing operations, repayment of principal and interest on outstanding debt and payment of dividends. We fund our exploration and development activities primarily through operating cash flows and budget capital expenditures based on projected cash flows.

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See Part II, Item 1A, “Risk Factors” of this Form 10-Q and Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors Related to Our Business and Operations,” in our Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the periods presented.
For the Six Months Ended
June 30,
2011 2010
(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities
$ 4,724 $ 3,085
Sale of oil and gas properties
192
Common stock activity and treasury stock activity
42 24
Other
26 22
4,984 3,131
Uses of Cash and Cash Equivalents:
Capital expenditures (1)
$ 3,439 $ 2,178
Oil and gas acquisitions
78 1,033
Net commercial paper and bank loan repayments
289 55
Dividends
153 101
Other
52 7
4,011 3,374
Increase (decrease) in cash and cash equivalents
$ 973 $ (243 )
(1) The table presents capital expenditures on a cash basis; therefore, the amounts differ from those discussed elsewhere in this document, which include accruals.
Net Cash Provided by Operating Activities Cash flows are our primary source of capital and liquidity and are impacted, both in the short-term and the long-term, by volatile oil and natural gas prices. The factors in determining operating cash flow are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation (ARO) accretion and deferred income tax expense, which affect earnings but do not affect cash flows.
Net cash provided by operating activities for the first six months of 2011 totaled $4.7 billion, up $1.6 billion from the first six months of 2010. The increase reflects the impact of higher oil and gas revenues (up $2.6 billion), with higher commodity prices contributing $1.6 billion, and a 20-percent increase in daily equivalent production adding another $1.0 billion. Also positively impacting operating cash flows was the change in working capital during the first six months of 2011.
For a detailed discussion of commodity prices, production, costs and expenses, refer to the “Results of Operations” of this Item 2. For additional detail of changes in operating assets and liabilities, see the statement of consolidated cash flows in Item 1, Financial Statements of this Form 10-Q.
Sale of Oil and Gas Properties In June 2011 Apache completed the sale of certain properties in Canada and the U.S. for $192 million. While we intend to divest additional non-strategic assets, given strong oil prices and higher than expected cash flows, we will sell less than originally planned at year-end 2010.

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Capital Expenditures We fund exploration and development (E&D) activities primarily through operating cash flows and budget capital expenditures based on projected cash flows. The Company remains determined to not outspend operating cash flows, and we review our capital budget accordingly on a quarterly basis. In response to higher realized commodity prices, in the second quarter of 2011, we reassessed our capital expenditure budget for 2011 and raised our plan from $7.5 billion to $8.1 billion.
For the Six Months Ended
June 30,
2011 2010
(In millions)
E&D Costs:
United States
$ 1,288 $ 618
Canada
434 365
North America
1,722 983
Egypt
477 305
Australia
318 295
North Sea
421 230
Argentina
158 94
Chile
1 14
Other International
26
International
1,401 938
Worldwide E&D Costs
3,123 1,921
Gathering Transmission and Processing Facilities (GTP):
Canada
84 72
Egypt
54 90
Australia
119 90
Argentina
4 1
Total GTP Costs
261 253
Asset Retirement Costs
161 82
Capitalized Interest
123 35
Capital Expenditures, excluding acquisitions
3,668 2,291
Acquisitions — Oil and Gas Properties
95 1,033
Asset Retirement Costs — Acquired
25 233
Total Capital Expenditures
$ 3,788 $ 3,557
Worldwide E&D expenditures for the first six months of 2011 totaled $3.1 billion, or 63 percent above the first six months of 2010. E&D spending in North America, which was up 75 percent, totaled 55 percent of worldwide E&D spending. U.S. E&D expenditures more than doubled on increased activity in the Permian region, where we continue to aggressively pursue opportunities on our Mariner-acquired Deadwood acreage. Current period activity also includes expenditures on Mariner-acquired deepwater properties for ongoing field development activities at Mandy, Wideberth and Lucius. Our Central region’s active horizontal drilling program in the Granite Wash and Cherokee plays also contributed to our increase in expenditures. E&D spending in Canada increased 19 percent to $434 million on an active drilling program in several plays including the Horn River basin and several liquids-rich gas opportunities.
E&D expenditures outside of North America increased 49 percent over first six-month 2010 levels to $1.4 billion. E&D spending in the North Sea was up $191 million over the comparable period on the Forties field drilling program and the construction of the Forties Alpha satellite platform. Egypt expenditures were up $172 million, or 56 percent, on continued drilling activity across all major basins. Argentina was $64 million higher on additional drilling and development activity.
We invested $261 million in GTP in the first six months of 2011 compared to $253 million in the first six months of 2010. GTP expenditures in Australia consisted of construction activity at the Devil Creek and Macedon gas plants. Australia has also incurred costs related to the FEED study and long-lead time acquisitions for the Wheatstone LNG project. Activity in Canada was centered in the Horn River basin, with expenditures for gathering systems and a gas processing plant. GTP expenditures in Egypt primarily comprised final stages of construction on the Kalabsha oil processing facility.
Dividends For the six-month periods ended June 30, 2011 and 2010, the Company paid $115 million and $101 million, respectively, in dividends on its common stock. The Company also made dividend payments of $38 million on its Series D Preferred Stock in the first six months of 2011.

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Liquidity
The following table presents a summary of our key financial indicators at the dates presented:
June 30, December 31,
2011 2010
(In millions of dollars, except as indicated)
Cash and cash equivalents
$ 1,107 $ 134
Total debt
7,852 8,141
Shareholders’ equity
26,667 24,377
Available committed borrowing capacity
2,680 2,387
Floating-rate debt/total debt
9% 12%
Percent of total debt-to-capitalization
23% 25%
Cash and Cash Equivalents We had $1.1 billion in cash and cash equivalents as of June 30, 2011, compared to $134 million at December 31, 2010. Approximately $1 billion of the cash was held by foreign subsidiaries, with the remaining balance held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly-liquid investment grade securities with maturities of three months or less at the time of purchase.
Debt As of June 30, 2011, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $7.9 billion. Current debt includes $400 million 6.25-percent notes due within the next 12 months and $48 million borrowed under uncommitted overdraft lines in Argentina and Canada.
Available committed borrowing capacity As of June 30, 2011, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2011 and $2.3 billion matures in May 2013. These consist of a $1.0 billion 364-day facility, 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. There was $2.7 billion of available borrowing capacity under the unsecured credit facilities at June 30, 2011.
The Company is currently in negotiations to replace its $1.0 billion 364-day facility with a $1.0 billion five-year facility. This five-year facility will have terms similar to those of the Company’s other five-year facilities. It is anticipated that the facility will become effective in August 2011.
The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100-percent backstop.
The Company was in compliance with the terms of all credit facilities as of June 30, 2011.
Percent of total debt to capitalization The Company’s June 30, 2011 debt-to-capitalization ratio was 23 percent, down from 25 percent at December 31, 2010.

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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather and climate. Our average crude oil realizations have increased dramatically since the first six months of 2010, rising 37 percent to $102.15 per barrel in the first six months of 2011 from $74.74 per barrel in the first six months of 2010. Our average natural gas price realizations have also risen slightly, increasing three percent to $4.43 per Mcf in the first six months of 2011 from $4.29 per Mcf in the first six months of 2010.
We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. For the second quarter and first six months of 2011, our natural gas production was subject to financial derivative hedges of approximately 16 percent in both periods, and our crude oil production was subject to financial derivative hedges of approximately 29 and 30 percent, respectively.
Apache may use futures contracts, swaps and options to hedge commodity price risk. Realized gains or losses from the Company’s price-risk management activities are recognized in oil and gas production revenues when the associated production occurs. Apache does not hold or issue derivative instruments for trading purposes.
On June 30, 2011, the Company had open natural gas derivative hedges in an asset position with a fair value of $367 million. A 10-percent increase in natural gas prices would reduce the fair value by approximately $76 million, while a 10-percent decrease in prices would increase the fair value by approximately $76 million. The Company also had open oil derivatives in a liability position with a fair value of $463 million. A 10-percent increase in oil prices would increase the liability by approximately $276 million, while a 10-percent decrease in prices would decrease the liability by approximately $228 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2011. See Note 3 — Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.
Interest Rate Risk
The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 91 percent of the Company’s debt. At June 30, 2011, total debt included $669 million of floating-rate debt. As a result, Apache’s annual interest costs in 2011 will fluctuate based on short-term interest rates on approximately nine percent of our total debt outstanding at June 30, 2011. The impact on cash flow of a 10-percent change in the floating interest rate based on debt balances at June 30, 2011, would be approximately $179,000 per quarter.
Foreign Currency Risk
The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts, and the majority of our gas production is sold under fixed-price Australian dollar contracts. Approximately half of our costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil and gas prices and costs, such as equipment rentals and services, are generally denominated in Canadian dollars but heavily influenced by U.S. markets. Our North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars, but are converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, Egyptian pounds and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other,” or, as is the case when we remeasure our foreign tax liabilities, as a component of the Company’s provision for income taxes on the statement of consolidated operations in Item 1 of this Form 10-Q. A 10-percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, Egyptian pound and Argentine peso as of June 30, 2011, would result in a cumulative foreign currency net loss or gain, respectively, of approximately $117 million.

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Forward-Looking Statements and Risk
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2010, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
the market prices of oil, natural gas, NGLs and other products or services;
our commodity hedging arrangements;
the integration of Mariner and the BP properties;
increased scrutiny from regulatory agencies due to the BP acquisitions;
the supply and demand for oil, natural gas, NGLs and other products or services;
production and reserve levels;
drilling risks;
economic and competitive conditions;
the availability of capital resources;
capital expenditure and other contractual obligations;
the significant transaction and acquisition costs related to the Mariner merger and BP property acquisitions;
currency exchange rates;
weather conditions;
inflation rates;
the availability of goods and services;
legislative or regulatory changes;
the impact on our operations due to the change in government in Egypt;
terrorism;
occurrence of property acquisitions or divestitures;
the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and
other factors disclosed under Items 1 and 2 — Business and Properties — Estimated Proved Reserves and Future Net Cash Flows, Item 1A — Risk Factors, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A — Quantitative and Qualitative Disclosures About Market Risk and elsewhere in our most recently filed Amended Form 10-K/A, other risks and uncertainties in our second-quarter 2011 earnings release, and other filings that we make with the SEC.

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All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.
ITEM 4 — CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
G. Steven Farris, the Company’s Chairman and Chief Executive Officer, in his capacity as principal executive officer, and Thomas P. Chambers, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2011, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.
Changes in Internal Control over Financial Reporting
There was no change in our internal controls over financial reporting during the period covered by this Quarterly Report on Form 10-Q that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART II — OTHER INFORMATION
ITEM 1.   LEGAL PROCEEDINGS
Please refer to both Part I, Item 3 of the Company’s Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010 (filed with the SEC on April 7, 2011) and Part I, Item 1 of this Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2011 for a description of material legal proceedings.
ITEM 1A. RISK FACTORS
During the quarter ending June 30, 2011, there were no material changes from the risk factors as previously disclosed in the Company’s Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010.
ITEM 2.   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None
ITEM 3.   DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4.   [REMOVED AND RESERVED]
ITEM 5.   OTHER INFORMATION
None

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ITEM 6. EXHIBITS
*10.1
Apache Corporation Outside Directors’ Retirement Plan, as amended and restated July 21, 2011.
*31.1
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
**101.INS
XBRL Instance Document.
**101.SCH
XBRL Taxonomy Schema Document.
**101.CAL
XBRL Calculation Linkbase Document.
**101.LAB
XBRL Label Linkbase Document.
**101.PRE
XBRL Presentation Linkbase Document.
**101.DEF
XBRL Definition Linkbase Document.
*
Filed herewith
**
Furnished herewith

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
APACHE CORPORATION
Dated: August 8, 2011 /s/ Thomas P. Chambers
Thomas P. Chambers
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Dated: August 8, 2011 /s/ Rebecca A. Hoyt
Rebecca A. Hoyt
Vice President, Chief Accounting Officer and Controller
(Principal Accounting Officer)

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