10-Q

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

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.

1

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.

2

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

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.

4

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.

5

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.

6

   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.

7

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.

8

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

9

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.

10

     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.

12

     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.

13

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.

14

     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

15

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.

16

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.

17

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

19

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

20

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

21

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

22

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

23

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

24

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

25

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;

26

• 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.

27

   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).

28

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.

29

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.

30

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.

32

     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.

33

     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.

34

     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.

35

     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.

36

     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.

42

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.

43

     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

45

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)

EX-10.1

Exhibit 10.1

APACHE CORPORATION
OUTSIDE DIRECTORS’ RETIREMENT PLAN
(As Amended and Restated July 21, 2011)

APACHE CORPORATION (the “Company”) established the Apache Corporation Outside Directors’ Retirement Plan (the “Plan”), effective as of December 15, 1992, to provide non-employee Directors of the Company (“Outside Directors”) with certain retirement and death payments. The purpose of the Plan is to advance the interests of the Company, its subsidiaries, and its stockholders by continuing to attract and retain outstanding individuals as Outside Directors and to stimulate the efforts of such individuals by giving suitable recognition to services which will contribute materially to the success of the Company.

It is the Company’s express intention that this Plan comply with the requirements of Code §409A, and the Plan shall be interpreted in that light.

ARTICLE I
Eligibility, Participation and Contributions

1.1 Eligibility and Participation.

     Each Outside Director begins to participate in the Plan as of the date his or her Service begins.

1.2 Contributions.

     All amounts payable under the Plan shall be paid from the general assets of the Company. Nothing contained in the Plan shall be deemed to create any fiduciary relationship between the Company and the participating Outside Director (“Participant”). The rights of a Participant under the Plan are no greater than the rights of an unsecured general creditor of the Company.

ARTICLE II
Retirement Payments

2.1 Definitions.

     The term “Separation from Service” has the same meaning as the term “separation from service” in Code §409A(a)(2)(A)(i). A Separation from Service is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A, including the special rules for a member of a board of directors found in Treasury Regulation §1.409A-1(h)(5) and §1.409A-1(c)(2)(ii). In general, a Separation from Service will occur when a Participant ceases to be a member of the Company’s Board of Directors.

1

     The term “Specified Employee” has the same meaning as the term “specified employee” in Code §409A(a)(2)(B)(i), and is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A.

2.2 Retirement Payments.

     (a) Eligibility for Benefits. A Participant who Retires with four or more Quarters of Service is entitled to receive benefits under the Plan.

     (b) Amount of Benefits. The amount of benefits under the Plan is equal to the value of a series of quarterly payments, with each payment equal in amount to one-fourth of the Participant’s Annual Director’s Retainer, and with the number of quarterly payments equal to the number of the Participant’s Quarters of Service. As a consequence, each Participant will generally receive an annual benefit of 100% of his or her Annual Director’s Retainer.

     (c) “Annual Director’s Retainer” means the aggregate annual amount of an Outside Director’s board retainer fee payable pursuant to section 1 of the Company’s Non-Employee Directors’ Compensation Plan (or comparable section of any successor plan), whether or not all or a portion of such amount is deferred or delayed. Such amount will be determined as of the earlier of the date a Participant ceases to be an Outside Director or the date the Participant dies.

     (d) “Quarter of Service” means the aggregate total full months of Service as an Outside Director divided by three and rounded up to the next whole number, up to a maximum of 40 Quarters of Service.

     (e) “Retirement, Retired or Retires” means a Participant’s ceasing to hold office as an Outside Director, for any reason other than death.

     (f) “Service” means the aggregate total, not to exceed 120, of (i) the number of full months beginning on or after July 1, 1992 (whether or not consecutive) that a Participant held office as an Outside Director, whether or not a Participant at the time, and (ii) ¹/2 the number of full months prior to July 1, 1992 (whether or not consecutive) that a Participant held office as an Outside Director; provided, however, that a Participant who, as of December 15, 1992, has held office as an Outside Director for an aggregate total of 15 years shall automatically be credited with 120 full months of Service.

     (g) Episodic Participation. If a Participant has a Separation from Service and then becomes an Outside Director again, (i) the Participant’s benefits from his or her initial episode of participation shall be paid according to the terms of the Plan on the date of his or her Separation from Service and shall not be affected by any subsequent Service, and (ii) the Participant’s benefits from his or her later episodes of participation shall be calculated by ignoring his or her Service from earlier episodes of participation. In calculating the amount of benefits for the most recent episode of participation, the

2

maximum Quarters of Service is 40, reduced by the number of Quarters of Service for which he or she earned benefits under this Plan from earlier episodes of participation.

2.3 Retirement Payments Following a Change of Control.

     In the event of a “change of control” of the Company, as defined in the Company’s Income Continuance Plan (as amended or the corresponding provisions of any successor plan), each then current Outside Director shall be eligible for the benefits described in section 2.2 even if the Outside Director has less than four Quarters of Service. If the change of control is a transaction described in §409A(a)(2)(A)(v) of the Internal Revenue Code of 1986, as amended (“Code”), each Participant shall be paid a single lump-sum payment on the date of the change of control, or as soon as practicable thereafter, equal to the net present value of the benefit to which the Participant is entitled, calculated in the manner described in section 2.5, as of the date of the change of control; however, if the Participant was a Specified Employee whose Separation from Service occurred less than six months before the change of control, he or she shall be paid a single lump-sum payment six months after the Separation from Service, or as soon as practicable thereafter, equal to the net present value of the benefit to which the Participant is entitled, calculated in the manner described in section 2.5, as of the date six months after the Separation from Service. If the change of control is not a transaction described in Code §409A(a)(2)(A)(v), each Participant shall be paid at the time(s) specified in section 2.4 or 2.5, whichever is applicable.

2.4 Quarterly Payments.

     A Participant may elect to be paid quarterly installments that are paid on the last day of each calendar quarter (or as near to that date as administratively practicable). See section 2.5 for the deadline for the Participant’s payout election. The first quarterly payment shall be made as of the last day of the calendar quarter after the date of the Participant’s Separates from Service, unless the Participant is a Specified Employee, in which case the first two quarterly payments shall be delayed until, and paid with, the third regularly scheduled quarterly payment.

2.5 Lump-Sum Payments.

     A Participant shall receive a single lump-sum payment unless the Participant elects quarterly installments. Participants on December 31, 2008 have already made their payout election. A new Participant’s payout election must be made within 30 days after the individual becomes an Outside Director. Once the deadline for making a payout election has passed, the payout election is irrevocable.

     The lump sum shall be paid as soon as administratively practicable after the Participant’s Separation from Service, unless the Participant is a Specified Employee, in which case the lump sum shall be paid as soon as administratively practicable after six months after the Participant’s Separation from Service. The amount of the lump sum

3

shall be calculated by the Committee as of the date of the Participant’s Separation from Service. The amount of the lump sum shall be equal to the net present value of the quarterly payments to which the Participant would otherwise be entitled, determined using an annual interest rate equal to the rate on ten-year treasury bonds/notes as reported in The Wall Street Journal published on or most recently prior to the date of the Participant’s Separation from Service.

2.6 Retirement before 2011.

     A Participant whose Separation from Service occurred between December 31, 2004 and January 1, 2009, shall receive his or her benefit in accordance with the terms of the Plan in effect at the time of the Separation from Service. A Participant who Retired before January 1, 2005, shall receive his or her benefit in accordance with the terms of the Plan in effect at the time of the Retirement. A Participant whose Separation from Service occurred between January 1, 2009 and July 21, 2011, shall receive his or her benefit in accordance with the terms of the Plan in effect at the time of the Retirement.

ARTICLE III
Death Payments

3.1 Death Benefits.

     (a) Eligibility for Death Benefits. If a Participant dies before receiving all of his or her benefits under Article II, the Participant’s Beneficiary, as determined in section 3.2, shall receive the remaining benefits. If a Participant elected quarterly payments, the Participant’s Beneficiary shall be paid a lump sum equal to the net present value of any remaining payments, calculated as of the date of the Participant’s death, and calculated in the manner specified in section 2.5. If a Participant is scheduled to receive a single lump-sum payment, but dies before doing so, the Participant’s Beneficiary shall be paid the lump sum.

     (b) Timing. Payment to the Beneficiary shall be made as soon as administratively practicable four months after the Participant’s death, which provides the Beneficiary with an opportunity to disclaim, except that no payment shall be made until the Company has been furnished with proof of death and such other information as it may reasonably require.

     (c) Beneficiary in Pay Status. The Beneficiary of a Participant who died on or before December 31, 2008 shall receive his or her death benefits in accordance with the terms of the Plan in effect on the date of the Participant’s death.

4

3.2 Beneficiaries.

     (a) “Beneficiary” means the recipient of the Participant’s death benefits under section 3.1.

     (b) Designation. Each Participant shall designate one or more persons, trusts, or other entities as his or her Beneficiary. In the absence of an effective Beneficiary designation as to part or all of a Participant’s death benefits, the Participant’s surviving Spouse, if any, shall be the Participant’s Beneficiary, and in the absence of a surviving Spouse, the Participant’s estate shall be the Beneficiary. Unless the Participant’s Beneficiary designation form specifies otherwise, if a Beneficiary dies after the Participant but before being paid by the Plan, the Plan shall pay the Beneficiary’s estate.

     (c) Changing Beneficiaries. A Beneficiary designation may be changed by the Participant at any time and without the consent of any previously designated Beneficiary. However, if the Participant is married, the Participant’s Spouse shall be the Participant’s Beneficiary unless the Spouse has consented to the designation of a different Beneficiary. To be effective, the Spouse’s consent must have been made before January 1, 2005 or, if made on or after January 1, 2005, the Spouse’s consent must be in writing, witnessed by a notary public, and filed with the Company. If the Participant has designated his or her Spouse as a primary or contingent Beneficiary, and the Participant and Spouse later divorce (or their marriage is annulled), then the former Spouse will be treated as having pre-deceased the Participant for purposes of interpreting a Beneficiary designation form completed prior to the divorce or annulment; this provision will apply only if the Company is notified of the divorce or annulment before payment to the former Spouse is made.

     (d) “Spouse” shall mean the individual to whom a Participant is lawfully married according to the laws of the state of the Participant’s domicile.

     (e) Disclaimers. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his or her interest in the Plan, provided that the disclaimer satisfies the requirements of Code §2518(b) and applicable state law. The legal guardian of a minor or legally incompetent person may disclaim for such person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed shall be distributed as if the disclaimant had predeceased the individual whose death caused the disclaimant to become a Beneficiary.

5

ARTICLE IV
Administration, Amendment and Termination

4.1 The Management Development and Compensation Committee.

     The Plan shall be administered by the Management Development and Compensation Committee (the “Committee”) of the Company’s Board of Directors. All administrative duties, including but not limited to, the power to interpret the Plan and to decide any dispute, shall be carried out by the Committee, which shall have full discretion and authority hereunder. All claims under the Plan shall be filed with the Company and shall be decided by the Committee. The decisions made by the Committee shall be final and binding on all persons having or claiming to have rights under the Plan.

4.2 Termination or Amendment of Plan.

     The Plan may be terminated or amended at any time through action of the Company’s Board of Directors. No termination or amendment, however, shall reduce the payments (a) to a Participant or Beneficiary where a Participant has already died or reached Retirement, (b) to which a Participant is or may become entitled, based on such Participant’s Service and Annual Director’s Retainer as determined on the effective date of such termination or amendment, or (c) to which a Participant is or may become entitled pursuant to section 2.3 as a result of a change of control. The termination of the Plan shall not affect the timing of any benefit payments; payments after the Plan has terminated will be made at the time(s) specified in Articles II and III.

ARTICLE V
Miscellaneous

5.1 Inalienability of Payments.

     No Participant shall have the right to assign, transfer, hypothecate, encumber or anticipate his or her interest in any payments under the Plan, nor shall the payments under the Plan be subject to any legal process to levy upon or attach such payments for any claim against the Participant, Spouse, or Beneficiary.

5.2 Notices.

     Any notice, form, or election required or permitted to be given under the Plan shall be in writing and shall be given by first class mail, by Federal Express, UPS, or other carrier, by fax or other electronic means, or by personal delivery to the appropriate party, addressed:

     (a) If to the Company, to Apache Corporation at its principal place of business at 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400 (Attention:

6

Corporate Secretary) or at such other address as may have been furnished in writing by the Company to a Participant; or

     (b) If to a Participant or Spouse, at the address the Participant has furnished to the Company in writing.

     (c) If to a Beneficiary, at the address the Participant has furnished to the Company in writing for such Beneficiary, unless the Beneficiary has furnished his or her own address to the Company.

Any such notice to a Participant, Spouse, or Beneficiary shall be deemed to have been given as of the third day after deposit in the United States Postal Service, postage prepaid, properly addressed as set forth above, in the case of a mailed notice, or as of the date delivered in the case of any other method of delivery.

5.3 Disposition of Unclaimed Payments.

     Any communication, statement or notice addressed to a Participant at his or her last post office address, as provided to the Company under section 5.2, will be binding on the Participant, Spouse, or Beneficiary for all purposes of the Plan. If the Company cannot ascertain the whereabouts of any person to whom a payment is due under the Plan within three years from the date such payment is due, such payment shall be cancelled on the records of the Plan and the amount thereof forfeited to the Company.

5.4 Administrative Delays.

     The Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments from the Plan when there is a change of recordkeeper, and a delay may be imposed on payments to any recipient until they have provided the information needed for tax withholding and tax reporting, as well as any other information reasonably requested by the Committee.

5.5 409A Noncompliance.

     To the extent that the Company takes any action that causes a violation of Code §409A or fails to take reasonable actions required to comply with Code §409A, the Company shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1) that is sufficient to put the individual in the same after-tax position he or she would have been in had there been no violation of Code §409A. The Company shall not pay a gross-up if the cause of the violation of Code §409A is the recipient’s failure to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the Committee — with the result that the delay in payment violates Code §409A). Any gross-up will be made as soon as administratively convenient after the Committee determines the gross-up is owed, and no later than the

7

end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation.

5.6 Gender.

     Any term herein used in the singular shall also include the plural, and the masculine gender shall also include the feminine gender, and vice versa.

5.7 Statutory References.

     Any reference to a specific section of the Code shall be deemed to refer to that section or to the appropriate successor section.

5.8 Governing Law.

     The Plan shall be governed by the laws of the State of Texas, ignoring any conflicts-of-law provisions.

Dated: July 21, 2011

ATTEST:		APACHE CORPORATION
By:	/s/ Cheri L. Peper	By:	/s/ Margery M. Harris
	Cheri L. Peper		Margery M. Harris
	Corporate Secretary		Senior Vice President, Human Resources

8

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, G. Steven Farris, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Apache Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ G. Steven Farris  

G. Steven Farris 

Chairman and Chief Executive Officer
(principal executive officer) 

Date: August 8, 2011

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Thomas P. Chambers, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Apache Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Thomas P. Chambers  

Thomas P. Chambers 

Executive Vice President and Chief Financial Officer (principal financial officer) 

Date: August 8, 2011

EX-32.1

EXHIBIT 32.1

APACHE CORPORATION

Certification of Principal Executive Officer
and Principal Financial Officer

     I, G. Steven Farris, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of Apache Corporation for the quarterly period ending June 30, 2011, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ G. Steven Farris
By : G. Steven Farris
Title:	Chairman and Chief Executive Officer (principal executive officer)

Date: August 8, 2011

     I, Thomas P. Chambers, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the quarterly report on Form 10-Q of Apache Corporation for the quarterly period ending June 30, 2011, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ Thomas P. Chambers
By : Thomas P. Chambers
Title:	Executive Vice President and Chief Financial Officer (principal financial officer)

Date: August 8, 2011

XML



Supplemental Guarantor Information (Details Textuals) (USD $) In Millions	Jun. 30, 2011
Notes Due 2029 [Member]
Supplemental Guarantor Information (Textuals) [Abstract]
Publicly traded notes	$ 300
Notes Due 2015 [Member]
Supplemental Guarantor Information (Textuals) [Abstract]
Publicly traded notes	$ 350

XML



Statement of Consolidated Cash Flows (Unaudited) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
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

XML



Consolidated Balance Sheet (Unaudited) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
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
Total current assets	4,900	3,480
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
Total property and equipment, gross	71,398	67,746
Less: Accumulated depreciation, depletion and amortization	(31,560)	(29,595)
Total property and equipment, net	39,838	38,151
OTHER ASSETS:
Goodwill	1,032	1,032
Deferred charges and other	759	762
Total Assets	46,529	43,425
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
Total current liabilities	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
Total deferred credits other noncurrent liabilities	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)
Total shareholders' equity	26,667	24,377
Total liabilities and shareholders' equity	$ 46,529	$ 43,425

XML



Asset Retirement Obligation (Tables)

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

	(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

XML



Document and Entity Information (USD $)	6 Months Ended
	Jun. 30, 2011	Jul. 31, 2011	Jun. 30, 2010
Document and Entity Information [Abstract]
Entity Registrant Name	APACHE CORP
Entity Central Index Key	0000006769
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 28,439,311,280
Entity Common Stock, Shares Outstanding		383,927,712

XML



Supplemental Guarantor Information (Details 1) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$ 4,724	$ 3,085
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(3,170)	(1,937)
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 PROVIDED BY (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
Apache Corporation [Member]
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	1,078	1,184
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(864)	(529)
Acquisition of Devon properties		(1,017)
Proceeds from sale of oil and gas properties	6
Investment in subsidiaries, net	198	(80)
Other, net	(34)	(45)
NET CASH USED IN INVESTING ACTIVITIES	(694)	(1,671)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net	(309)	2
Dividends paid	(153)	(101)
Common stock activity	38	21
Treasury stock activity, net	4	3
Other	38	22
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(382)	(53)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2	(540)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	6	647
CASH AND CASH EQUIVALENTS AT END OF PERIOD	8	107
Apache Finance Canada [Member]
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(29)	(36)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		3
Intercompany borrowings	(1)
Common stock activity	30	33
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	29	36
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		0
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	0	2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	0	2
All Other Subsidiaries of Apache Corporation [Member]
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	3,675	1,937
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(2,306)	(1,408)
Additions to gas gathering, transmission and processing facilities	(269)	(257)
Acquisitions, other	(78)
Proceeds from sale of oil and gas properties	186
Other, net	(18)	38
NET CASH USED IN INVESTING ACTIVITIES	(2,485)	(1,627)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net	20	18
Intercompany borrowings	(189)
Common stock activity	(38)	(31)
Other	(12)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(219)	(13)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	971	297
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	128	1,399
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,099	1,696
Reclassifications and Eliminations [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries, net	(198)	80
NET CASH USED IN INVESTING ACTIVITIES	(198)	80
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(78)
Intercompany borrowings	190
Common stock activity	8	(2)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	198	(80)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	0	0
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0	$ 0

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value Measurements [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

     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.

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Supplemental Guarantor Information (Details) (USD $) In Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2011	Jun. 30, 2010
REVENUES AND OTHER:
Oil and gas production revenues	$ 4,355	$ 2,969		$ 8,233	$ 5,662
Other	(17)	3		30	(17)
Total revenues and other	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
Total operating expenses	2,207	1,578		4,205	3,044
INCOME BEFORE INCOME TAXES	2,131	1,394		4,058	2,601
Provision (benefit) for income taxes	872	534		1,665	1,036
NET INCOME	1,259	860	1,565	2,393	1,565
Preferred stock dividends	19			38
INCOME ATTRIBUTABLE TO COMMON STOCK	1,240	860		2,355	1,565
Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues	1,127	861		2,133	1,750
Equity in net income (loss) of affiliates	972	731		1,866	1,195
Other	4	2		5	3
Total revenues and other	2,103	1,594		4,004	2,948
OPERATING EXPENSES:
Depreciation, depletion and amortization	315	234		615	448
Asset retirement obligation accretion	17	13		34	25
Lease operating expenses	213	172		404	337
Gathering and transportation	12	10		24	21
Taxes other than income	50	32		91	68
General and administrative	84	64		173	136
Merger, acquisitions & transition	5	8		10	8
Financing costs, net	34	50		71	102
Total operating expenses	730	583		1,422	1,145
INCOME BEFORE INCOME TAXES	1,373	1,011		2,582	1,803
Provision (benefit) for income taxes	114	151		189	238
NET INCOME	1,259			2,393
Preferred stock dividends	19			38
INCOME ATTRIBUTABLE TO COMMON STOCK	1,240	860		2,355	1,565
Apache Finance Canada [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates	(11)	39		(25)	64
Other	(19)	15		(39)	29
Total revenues and other	(30)	54		(64)	93
OPERATING EXPENSES:
Financing costs, net	14	14		28	28
Total operating expenses	14	14		28	28
INCOME BEFORE INCOME TAXES	(44)	40		(92)	65
Provision (benefit) for income taxes	(13)	10		(19)	16
NET INCOME	(31)			(73)
INCOME ATTRIBUTABLE TO COMMON STOCK	(31)	30		(73)	49
All Other Subsidiaries of Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues	3,228	2,108		6,100	3,912
Equity in net income (loss) of affiliates	(20)	(9)		(48)	(15)
Other	(1)	(13)		66	(47)
Total revenues and other	3,207	2,086		6,118	3,850
OPERATING EXPENSES:
Depreciation, depletion and amortization	714	495		1,350	920
Asset retirement obligation accretion	21	12		41	24
Lease operating expenses	449	274		881	549
Gathering and transportation	61	33		125	62
Taxes other than income	205	155		328	296
General and administrative	20	21		44	37
Merger, acquisitions & transition	1			1
Financing costs, net	(7)	(8)		(13)	(15)
Total operating expenses	1,464	982		2,757	1,873
INCOME BEFORE INCOME TAXES	1,743	1,104		3,361	1,977
Provision (benefit) for income taxes	771	373		1,495	782
NET INCOME	972			1,866
INCOME ATTRIBUTABLE TO COMMON STOCK	972	731		1,866	1,195
Reclassifications and Eliminations [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates	(941)	(761)		(1,793)	(1,244)
Other	(1)	(1)		(2)	(2)
Total revenues and other	(942)	(762)		(1,795)	(1,246)
OPERATING EXPENSES:
General and administrative	(1)	(1)		(2)	(2)
Total operating expenses	(1)	(1)		(2)	(2)
INCOME BEFORE INCOME TAXES	(941)	(761)		(1,793)	(1,244)
NET INCOME	(941)			(1,793)
INCOME ATTRIBUTABLE TO COMMON STOCK	$ (941)	$ (761)		$ (1,793)	$ (1,244)

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Debt and Financing Costs

6 Months Ended

Jun. 30, 2011

Debt and Financing Costs [Abstract]

DEBT AND FINANCING COSTS

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

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Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2011

Capital Stock [Abstract]

Components of Apache's 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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Capital Stock (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	Nov. 30, 2010	Jul. 31, 2010	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Capital Stock (Textuals) [Abstract]
Options and restricted stock, anti-dilutive			1,500,000	3,300,000	1,100,000	2,900,000
Depository shares in separate underwriting		25,300,000
Depositary shares each representing		1/20th interest
Mandatory convertibles preferred stock, Series D		6.00%			6.00%		6.00%
Preferred stock, shares outstanding		1,265,000	1,265,000		1,265,000		1,265,000
Conversion of preferred stock to equity shares ratio, minimum					9.164
Conversion of preferred stock to equity shares ratio, maximum					11.364
Common stock issued	17,300,000
Common stock, shares authorized			860,000,000	430,000,000	860,000,000	430,000,000	860,000,000
Preferred stock, shares authorized			10,000,000	5,000,000	10,000,000	5,000,000	10,000,000
Common stock dividends			$ 58	$ 51	$ 115	$ 101
Dividend paid, Series D preferred stock				$ 19	$ 38	$ 38

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Debt and Financing Costs (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Carrying amounts and estimated fair values of the Company's debt
Carrying Amount, Money market lines of credit	$ 48		$ 48		$ 46
Carrying Amount, Commercial paper	620		620		913
Carrying Amount	7,852		7,852		8,141
Fair Value	8,486		8,486		8,829
Financing Costs, Net
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
Money Market Lines Of Credit [Member]
Carrying amounts and estimated fair values of the Company's debt
Fair Value	48		48		46
Commercial Paper [Member]
Carrying amounts and estimated fair values of the Company's debt
Fair Value	620		620		913
Notes And Debentures [Member]
Carrying amounts and estimated fair values of the Company's debt
Carrying Amount	7,184		7,184		7,182
Fair Value	$ 7,818		$ 7,818		$ 7,870

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Capital Stock (Tables)

6 Months Ended

Jun. 30, 2011

Capital Stock [Abstract]

Net Income (Loss) 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

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Comprehensive Income

6 Months Ended

Jun. 30, 2011

Capital Stock [Abstract]

COMPREHENSIVE INCOME

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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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2011

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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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Derivative Instruments and Hedging Activities (Details 3) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)
Unrealized gain (loss) on derivatives at beginning of period, before tax	$ (54)	$ (267)
Realized amounts reclassified into earnings	47	(51)
Net change in derivative fair value, before tax	(119)	514
Ineffectiveness and basis swaps reclassified into earnings, before tax	(1)
Unrealized gain (loss) on derivatives at end of period, before tax	(127)	196
Unrealized gain (loss) on derivatives at beginning of period, after tax	(19)	(170)
Realized amounts reclassified into earnings, after tax	36	(33)
Net change in derivative fair value, after tax	(94)	346
Ineffectiveness and basis swaps reclassified into earnings, after tax	(1)
Unrealized gain (loss) on derivatives at end of period, after tax	$ (78)	$ 143

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

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.

   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.

     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.

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Supplemental Guarantor Information

6 Months Ended

Jun. 30, 2011

Supplemental Guarantor Information [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

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.

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

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

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

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

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

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

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

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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Capital Stock

6 Months Ended

Jun. 30, 2011

Capital Stock [Abstract]

CAPITAL STOCK

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.

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.

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Derivative Instruments and Hedging Activities (Details)	Jun. 30, 2011 USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2011 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2011 [Member] Collars [Member] USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2012 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2012 [Member] Collars [Member] USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2013 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2013 [Member] Collars [Member] USD ($)	Jun. 30, 2011 Open Crude Oil Derivative Positions [Member] 2014 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2011 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2011 [Member] Fixed-Price Swaps [Member] CAD	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2011 [Member] Collars [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2011 [Member] Collars [Member] CAD	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2012 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2012 [Member] Fixed-Price Swaps [Member] CAD	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2012 [Member] Collars [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2012 [Member] Collars [Member] CAD	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2013 [Member] Fixed-Price Swaps [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2013 [Member] Collars [Member] USD ($)	Jun. 30, 2011 Open Natural Gas Derivative Positions [Member] 2014 [Member] Fixed-Price Swaps [Member] USD ($)
Commodity Derivative Instruments [Abstract]
Mbbls		2,641,000	14,996,000	3,786,000	9,142,000	1,860,000	2,416,000	76,000	35,884,000	35,884,000	4,600,000	4,600,000	41,544,000	41,544,000	21,960,000	21,960,000	7,665,000	6,825,000	755,000
GJ									25,760,000	25,760,000	1,840,000	1,840,000	43,920,000	43,920,000	7,320,000	7,320,000
Weighted Average Fixed Price		$ 74.17		$ 72.26		$ 74.38		$ 74.50	$ 5.96	6.26			$ 6.3	6.61			$ 6.83		$ 7.23
Weighted Average Floor Price			69.18		69.30		78.02				5.00	6.50			5.54	6.50		5.35
Weighted Average Ceiling price	$ 98.56		$ 96.79		$ 98.11		$ 103.06				$ 8.85	7.10			$ 7.30	7.27		$ 6.67

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes [Abstract]

INCOME TAXES

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.

     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.

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Statement of Consolidated Shareholders' Equity (Unaudited) (USD $) In Millions	Total	Comprehensive Income	Series D Preferred Stock	Common Stock	Paid-In Capital	Retained Earnings	Treasury Stock	Accumulated Other Comprehensive Income (Loss)
Beginning Balance at Dec. 31, 2009	$ 15,779		$ 0	$ 215	$ 4,634	$ 11,437	$ (217)	$ (290)
Comprehensive income:
Net income	1,565	1,565				1,565
Commodity hedges, net of income tax expense of $150 and $14 for 2010 and 2011, respectively	313	313						313
Comprehensive income	1,878	1,878
Dividends:
Preferred	(38)
Common stock dividends ($0.30 per share)	(101)					(101)
Common shares issued	13			1	12
Treasury shares issued, net	4				(1)		5
Compensation expense	102				102
Other	1				1
Ending Balance at Jun. 30, 2010	17,676		0	216	4,748	12,901	(212)	23
Beginning Balance at Dec. 31, 2010	24,377		1,227	240	8,864	14,223	(36)	(141)
Comprehensive income:
Net income	2,393	2,393				2,393
Commodity hedges, net of income tax expense of $150 and $14 for 2010 and 2011, respectively	(59)	(59)						(59)
Comprehensive income	2,334	2,334
Dividends:
Preferred	(38)					(38)
Common stock dividends ($0.30 per share)	(115)					(115)
Common shares issued	20			1	19
Treasury shares issued, net	5				2		3
Compensation expense	84				84
Ending Balance at Jun. 30, 2011	$ 26,667		$ 1,227	$ 241	$ 8,969	$ 16,463	$ (33)	$ (200)

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2011

Acquisitions and Divestitures [Abstract]

ACQUISITIONS AND DIVESTITURES

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.

   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.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended		12 Months Ended
	Sep. 30, 2011	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010	Jul. 19, 2011
Income Taxes (Textuals) [Abstract]
Significant discrete tax events		0	0
Company's administrative appeals tax years		2004 through 2007
Calendar period for audit		2008 tax year
Corporate income tax rate				50.00%	62.00%
Deferred tax liabilities	$ 290	$ 60		$ 230

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Acquisitions and Divestitures (Details Textuals) (USD $)														3 Months Ended
	Mar. 31, 2011	Aug. 10, 2010	Jul. 31, 2010	Nov. 30, 2010 Mariner Energy Inc [Member]	Jun. 30, 2010 Gulf of Mexico, Devon [Member]	Dec. 31, 2010 Kitimat LNG [Member] Apache Canada [Member]	Dec. 31, 2010 Kitimat LNG [Member] EOG Canada [Member]	Mar. 31, 2011 Kitimat LNG [Member] Encana [Member]	Feb. 28, 2011 Pacific Trails Pipeline [Member] Apache Canada [Member]	Dec. 31, 2010 Pacific Trails Pipeline [Member] Apache Canada [Member]	Feb. 28, 2011 Pacific Trails Pipeline [Member] EOG Canada [Member]	Dec. 31, 2010 Pacific Trails Pipeline [Member] EOG Canada [Member]	Aug. 10, 2010 BP's Oil And Gas Operations [Member]	Jun. 30, 2011 PNG [Member]	Mar. 31, 2011 PTP and Kitimat LNG [Member] Apache Canada [Member]	Mar. 31, 2011 PTP and Kitimat LNG [Member] EOG Canada [Member]	Jul. 31, 2010 Bp Acquisitions [Member]	Oct. 08, 2010 Western Canada Sedimentary Basin [Member]	Nov. 04, 2010 Western Desert, Egypt [Member]
Acquisitions and Divestitures (Textuals) [Abstract]
Percentage of acquisition						51.00%	49.00%	30.00%	51.00%	25.50%	49.00%	24.50%			40.00%	30.00%
Total consideration transferred				$ 2,700,000,000											$ 50,000,000
Percentage of retained interest in acquisition	40.00%
Period of provision of renewals														5 years
Period of pipeline agreement														7 years
Purchase price of acquisition			6,400,000,000		1,050,000,000								3,100,000,000				7,000,000,000	3,250,000,000	650,000,000
Preferential purchase right		658,000,000
Liabilities assumed				$ 1,700,000,000

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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.

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.

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.

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Capital Stock (Details) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Basic:
Income attributable to common stock	$ 1,240	$ 860	$ 2,355	$ 1,565
Income attributable to common stock, shares	384	338	383	337
Income attributable to common stock, per share	$ 3.23	$ 2.55	$ 6.14	$ 4.64
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	12		12
Mandatory Convertible Preferred Stock, Income	19		38
Stock options and other	1	1	2	2
Diluted:
Income attributable to common stock, including assumed conversions, Amount	$ 1,259	$ 860	$ 2,393	$ 1,565
Income attributable to common stock, including assumed conversions, Shares	397	339	397	339
Income attributable to common stock, including assumed conversions, per share	$ 3.17	$ 2.53	$ 6.03	$ 4.61

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Business Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Business Segment Information [Abstract]

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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Derivative Instruments and Hedging Activities (Details 1) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
Derivative asset fair value net	$ 258	$ 306
Derivative liability fair value net	354	318
Prepaid Assets and Other [Member]
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
Derivative asset fair value net	171	167
Deferred Charges and Other [Member]
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
Derivative asset fair value net	87	139
Derivative Instruments [Member]
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
Derivative liability fair value net	229	194
Other Liabilities [Member]
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
Derivative liability fair value net	$ 125	$ 124

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011
Commitments and Contingencies (Textuals) [Abstract]
Accrued liability for legal contingencies	$ 11
Maximum expected contractual liquidated damages under long term contracts	5.7
Validity of pipeline license	21 years
Percentage of combined ownership held by the plaintiff in the company	65.00%
Undiscounted reserve for environmental remediation	135
Workers evacuated by safety	13
Alcoa [Member]
Loss Contingencies [Line Items]
Maximum expected contractual general damages under long term contracts	158
Oswal [Member]
Loss Contingencies [Line Items]
Maximum expected contractual general damages under long term contracts	$ 491

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Acquisitions And Divestitures (Details) (USD $) In Millions, except Per Share data	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011
Proforma information for the Company as if the acquisition of properties
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

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Business Segment Information

6 Months Ended

Jun. 30, 2011

Business Segment Information [Abstract]

BUSINESS SEGMENT INFORMATION

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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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

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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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2011

Acquisitions and Divestitures [Abstract]

Proforma information for the Company as if the acquisition of properties

     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

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Debt and Financing Costs (Details Textuals) (USD $)	1 Months Ended		6 Months Ended
	May 31, 2013	Aug. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
Short-term Debt [Line Items]
Period For Borrowing Funds			270 days
Line of Credit Facility [Line Items]
Borrowed on uncommitted overdraft lines			$ 48,000,000	$ 46,000,000
Line of Credit Facility, Remaining Borrowing Capacity			2,700,000,000
Line of credit facility, expiration date			P5Y
Debt and Financing Costs (Textuals) [Abstract]
Maturing date of credit facilities	May 31, 2013	Aug. 31, 2011
Carrying Amount, Commercial paper			620,000,000	913,000,000
Period For Borrowing Funds			270 days
Short-term debt, terms			6.25 percent notes due within the next 12 months
Commercial Paper Program Maximum Amount [Member]
Short-term Debt [Line Items]
Commercial paper program			2,950,000,000
Notes Payable, Other Payables [Member]
Short-term Debt [Line Items]
Short term debt borrowings			400,000,000
Unsecured Committed Bank Credit Facilities [Member]
Line of Credit Facility [Line Items]
Unsecured credit facility available to Company	2,300,000,000	1,000,000,000	3,300,000,000
Revolving bank facility			1,500,000,000
Unsecured Committed Bank Credit Facilities in U.S. [Member]
Line of Credit Facility [Line Items]
Revolving bank facility			450,000,000
Unsecured Committed Bank Credit Facilities in Australia [Member]
Line of Credit Facility [Line Items]
Revolving bank facility			200,000,000
Unsecured Committed Bank Credit Facilities in Canada [Member]
Line of Credit Facility [Line Items]
Revolving bank facility			$ 150,000,000
364 Day Facility [Member]
Line of Credit Facility [Line Items]
Period of Revolving bank facility			364 days

XML



Supplemental Guarantor Information (Tables)

6 Months Ended

Jun. 30, 2011

Supplemental Guarantor Information [Abstract]

Supplemental Condensed Consolidating Statement of Operations

						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

					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

						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

					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

Supplemental Condensed Consolidating Statement of Cash Flows

							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

							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

Supplemental Condensed Consolidating Balance Sheet

					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

					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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Consolidated Balance Sheet (Parenthetical) (Unaudited) (USD $)	1 Months Ended	6 Months Ended	12 Months Ended
	Jul. 31, 2010	Jun. 30, 2011	Dec. 31, 2010
SHAREHOLDERS' EQUITY:
Preferred stock, par value		$ 0	$ 0
Preferred stock, shares authorized		10,000,000	10,000,000
Cumulative preferred stock interest rate	6.00%	6.00%	6.00%
Preferred stock, liquidation preference per share		$ 1,000	$ 1,000
Preferred stock, shares issued		1,265,000	1,265,000
Preferred stock, shares outstanding	1,265,000	1,265,000	1,265,000
Common stock, par value		$ 0.625	$ 0.625
Common stock, shares authorized		860,000,000	860,000,000
Common stock, shares issued	26,450,000	384,983,055	383,668,297
Treasury stock, shares		1,147,641	1,276,555

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities [Abstract]

Open Crude Oil and Natural Gas 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.

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

Commodity Derivative Activity Recorded in Statement of Consolidated Operations

     The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:

		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		$	—

Commodity 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

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Fair Value Measurements (Details) (Recurring [Member], USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity Derivative Instruments, Assets	$ 369	$ 454
Commodity Derivative Instruments, Liabilities	465	466
Quoted Price in Active Markets (Level 1) [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity Derivative Instruments, Assets	0	0
Commodity Derivative Instruments, Liabilities	0	0
Significant Other Inputs (Level 2) [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity Derivative Instruments, Assets	369	454
Commodity Derivative Instruments, Liabilities	465	466
Significant Unobservable Inputs (Level 3) [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity Derivative Instruments, Assets	0	0
Commodity Derivative Instruments, Liabilities	0	0
Netting [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity Derivative Instruments, Assets	(111)	(148)
Commodity Derivative Instruments, Liabilities	(111)	(148)
Carrying Amount [Member]
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Commodity Derivative Instruments, Assets	258	306
Commodity Derivative Instruments, Liabilities	$ 354	$ 318

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Debt and Financing Costs (Tables)

6 Months Ended

Jun. 30, 2011

Debt and Financing Costs [Abstract]

Carrying amounts and estimated fair values of the Company's debt

     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

Financing Costs, Net

     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

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Statement of Consolidated Shareholders' Equity (Parenthetical) (Unaudited) (USD $) In Millions, except Per Share data	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Comprehensive income:
Income tax benefit to commodity hedges	$ 14	$ 150
Dividends:
Common stock, dividends, per share	$ 0.30	$ 0.30
Comprehensive Income
Comprehensive income:
Income tax benefit to commodity hedges	14	150
Retained Earnings
Dividends:
Common stock, dividends, per share	$ 0.30	$ 0.30
Accumulated Other Comprehensive Income (Loss)
Comprehensive income:
Income tax benefit to commodity hedges	$ 14	$ 150

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

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.

     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.

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Derivative Instruments and Hedging Activities (Details 2) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Oil and Gas Production Revenues [Member]
Commodity Derivative Activity Recorded in Statement of Consolidated Operations
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)	$ (53)	$ 52	$ (47)	$ 51
Revenues [Member]
Commodity Derivative Activity Recorded in Statement of Consolidated Operations
Gain (loss) derivatives recognized in operations (ineffective portion and basis swaps)	$ 4		$ 1

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2011

Summary of Significant Accounting Policies [Abstract]

Use of Estimates

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.

Derivative Instruments and Hedging Activities

     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.

Fair Value Measurements

     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.

Comprehensive Income

     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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Statement of Consolidated Operations (Unaudited) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
REVENUES AND OTHER:
Oil and gas production revenues	$ 4,355	$ 2,969	$ 8,233	$ 5,662
Other	(17)	3	30	(17)
Total revenues and other	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
Total operating expenses	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

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Derivative Instruments and Hedging Activities (Details Textuals) (USD $)	6 Months Ended
	Jun. 30, 2011
Derivative Instruments and Hedging Activities (Textuals)
Number of counterparties	19
Number of barrels to be delivered as per contract	20,000
Floor price of oil, Dated Brent	70
Average ceiling price	$ 98.56
Realization of gains and losses on hedges in future earnings	mid 2014
Net loss included in accumulated other comprehensive income (loss), before tax applied to next twelve months	77,000,000
Net loss included in accumulated other comprehensive income (loss), after tax applied to next twelve months	$ 52,000,000

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Supplemental Guarantor Information (Details 2) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2009
CURRENT ASSETS:
Cash and cash equivalents	$ 1,107	$ 134	$ 1,805	$ 2,048
Receivables, net of allowance	2,495	2,134
Inventories	633	564
Drilling advances	250	259
Prepaid assets and other	415	389
Total current assets	4,900	3,480
PROPERTY AND EQUIPMENT, NET	39,838	38,151
OTHER ASSETS:
Intercompany receivable, net	0	0
Equity in affiliates	0	0
Goodwill, net	1,032	1,032
Deferred charges and other	759	762
Total Assets	46,529	43,425	30,432
CURRENT LIABILITIES:
Accounts payable	1,029	779
Accrued exploration and development	1,375	1,367
Current debt	448	46
Current asset retirement obligation	360	407
Derivative instruments	229	194
Other accrued expenses	1,043	731
Total current liabilities	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
Total deferred credits other noncurrent liabilities	7,974	7,429
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY	26,667	24,377	17,676	15,779
Total liabilities and shareholders' equity	46,529	43,425
Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	8	6	107	647
Receivables, net of allowance	759	691
Inventories	58	55
Drilling advances	16	10
Prepaid assets and other	3,401	3,313
Total current assets	4,242	4,075
PROPERTY AND EQUIPMENT, NET	11,801	11,314
OTHER ASSETS:
Intercompany receivable, net	4,505	4,695
Equity in affiliates	18,451	16,649
Goodwill, net	0	0
Deferred charges and other	175	178
Total Assets	39,174	36,911
CURRENT LIABILITIES:
Accounts payable	607	480
Accrued exploration and development	312	274
Current debt	400	16
Current asset retirement obligation	317	317
Derivative instruments	154	153
Other accrued expenses	368	400
Total current liabilities	2,158	1,640
LONG-TERM DEBT	6,756	7,447
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	1,909	1,803
Asset retirement obligation	1,021	1,001
Other	663	643
Total deferred credits other noncurrent liabilities	3,593	3,447
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY	26,667	24,377
Total liabilities and shareholders' equity	39,174	36,911
Apache Finance Canada [Member]
CURRENT ASSETS:
Cash and cash equivalents	0	0	2	2
Receivables, net of allowance	0	0
Inventories	0	0
Drilling advances	1	2
Prepaid assets and other	0	0
Total current assets	1	2
PROPERTY AND EQUIPMENT, NET	0	0
OTHER ASSETS:
Intercompany receivable, net	0	0
Equity in affiliates	1,309	1,275
Goodwill, net	0	0
Deferred charges and other	1,003	1,003
Total Assets	2,313	2,280
CURRENT LIABILITIES:
Accounts payable	1	2
Accrued exploration and development	0	0
Current debt	0	0
Current asset retirement obligation	0	0
Derivative instruments	0	0
Other accrued expenses	4	3
Total current liabilities	5	5
LONG-TERM DEBT	647	647
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	5	5
Asset retirement obligation	0	0
Other	250	250
Total deferred credits other noncurrent liabilities	255	255
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY	1,406	1,373
Total liabilities and shareholders' equity	2,313	2,280
All Other Subsidiaries of Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	1,099	128	1,696	1,399
Receivables, net of allowance	1,736	1,443
Inventories	575	509
Drilling advances	233	247
Prepaid assets and other	(2,986)	(2,924)
Total current assets	657	(597)
PROPERTY AND EQUIPMENT, NET	28,037	26,837
OTHER ASSETS:
Intercompany receivable, net	(2,973)	(3,149)
Equity in affiliates	97	98
Goodwill, net	1,032	1,032
Deferred charges and other	581	581
Total Assets	27,431	24,802
CURRENT LIABILITIES:
Accounts payable	1,953	1,843
Accrued exploration and development	1,063	1,093
Current debt	48	30
Current asset retirement obligation	43	90
Derivative instruments	75	41
Other accrued expenses	671	328
Total current liabilities	3,853	3,425
LONG-TERM DEBT	1	1
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	2,784	2,441
Asset retirement obligation	1,514	1,464
Other	828	822
Total deferred credits other noncurrent liabilities	5,126	4,727
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY	18,451	16,649
Total liabilities and shareholders' equity	27,431	24,802
Reclassifications and Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables, net of allowance	0	0
Inventories	0	0
Drilling advances	0	0
Prepaid assets and other	0	0
Total current assets	0	0
PROPERTY AND EQUIPMENT, NET	0	0
OTHER ASSETS:
Intercompany receivable, net	(1,532)	(1,546)
Equity in affiliates	(19,857)	(18,022)
Goodwill, net	0	0
Deferred charges and other	(1,000)	(1,000)
Total Assets	(22,389)	(20,568)
CURRENT LIABILITIES:
Accounts payable	(1,532)	(1,546)
Accrued exploration and development	0	0
Current debt	0	0
Current asset retirement obligation	0	0
Derivative instruments	0	0
Other accrued expenses	0	0
Total current liabilities	(1,532)	(1,546)
LONG-TERM DEBT	0	0
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	0	0
Asset retirement obligation	0	0
Other	(1,000)	(1,000)
Total deferred credits other noncurrent liabilities	(1,000)	(1,000)
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY	(19,857)	(18,022)
Total liabilities and shareholders' equity	$ (22,389)	$ (20,568)

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Comprehensive Income (Details) (USD $) In Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2011	Jun. 30, 2010
Components of Apache's comprehensive income
Net income	$ 1,259	$ 860	$ 1,565	$ 2,393	$ 1,565
Other Comprehensive Income:
Commodity hedges	362	102		(73)	463
Income tax related to commodity hedges	(117)	(39)		14	(150)
Comprehensive income	$ 1,504	$ 923		$ 2,334	$ 1,878

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Business Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Business Segment Information
Oil and gas production revenues	$ 4,355	$ 2,969	$ 8,233	$ 5,662
Operating Income	2,298	1,539	4,340	2,912
Other Income (Expense):
Other	(17)	3	30	(17)
General and administrative	(103)	(84)	(215)	(171)
Merger, acquisitions & transition	(6)	(8)	(11)	(8)
Financing costs, net	(41)	(56)	(86)	(115)
INCOME BEFORE INCOME TAXES	2,131	1,394	4,058	2,601
Total assets	46,529	30,432	46,529	30,432	43,425
Business Segment Information (Textuals) [Abstract]
Number of countries, in which the company has production	6		6
United States [Member]
Business Segment Information
Oil and gas production revenues	1,560	962	2,937	1,954
Operating Income	738	452	1,368	963
Other Income (Expense):
Total assets	22,142	12,473	22,142	12,473
Canada [Member]
Business Segment Information
Oil and gas production revenues	433	240	835	493
Operating Income	104	71	182	166
Other Income (Expense):
Total assets	8,680	4,243	8,680	4,243
Egypt [Member]
Business Segment Information
Oil and gas production revenues	1,201	806	2,401	1,547
Operating Income	893	548	1,787	1,041
Other Income (Expense):
Total assets	6,677	5,910	6,677	5,910
Australia [Member]
Business Segment Information
Oil and gas production revenues	470	452	842	676
Operating Income	311	285	536	386
Other Income (Expense):
Total assets	4,272	3,737	4,272	3,737
U K North Sea [Member]
Business Segment Information
Oil and gas production revenues	572	421	1,002	812
Operating Income	257	165	462	313
Other Income (Expense):
Total assets	2,999	2,526	2,999	2,526
Argentina [Member]
Business Segment Information
Oil and gas production revenues	119	88	216	180
Operating Income	21	18	31	43
Other Income (Expense):
Total assets	1,686	1,488	1,686	1,488
Other International [Member]
Business Segment Information
Operating Income			(26)
Other Income (Expense):
Total assets	$ 73	$ 55	$ 73	$ 55

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Asset Retirement Obligation (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Asset Retirement Obligation
Asset retirement obligation at beginning of year			$ 2,872
Liabilities incurred			186
Liabilities settled			(238)
Accretion expense	38	25	75	49
Asset retirement obligation at end of the period	2,895		2,895
Less current portion	(360)		(360)		(407)
Asset retirement obligation - long-term	$ 2,535		$ 2,535		$ 2,465