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 September 30, 2009

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to

Commission File Number: 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	41-0747868
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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, 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 September 30, 2009             336,174,361

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
	ITEM 1 — FINANCIAL STATEMENTS
	ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	ITEM 5. OTHER INFORMATION
	ITEM 6. EXHIBITS
SIGNATURES
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)

	For the Quarter					For the Nine Months
	Ended September 30,					Ended September 30,
	2009		2008			2009			2008
	(In thousands, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,325,705	$	3,368,882		$	6,003,663		$	10,450,949
Other		6,726		(3,998	)		55,971			1,867
		2,332,431		3,364,884			6,059,634			10,452,816
OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		625,898		600,887			1,779,874			1,849,044
Additional		—		—			2,818,161			—
Asset retirement obligation accretion		26,053		24,970			79,274			77,146
Lease operating expenses		445,535		488,166			1,248,297			1,389,542
Gathering and transportation		36,232		42,375			103,050			123,118
Taxes other than income		183,931		304,280			387,211			845,406
General and administrative		82,492		57,561			258,443			218,856
Financing costs, net		61,684		33,291			181,426			116,594
		1,461,825		1,551,530			6,855,736			4,619,706
INCOME (LOSS) BEFORE INCOME TAXES		870,606		1,813,354			(796,102	)		5,833,110
Current income tax provision		262,430		305,735			483,171			1,495,641
Deferred income tax provision (benefit)		166,160		316,794			(409,069	)		679,902
NET INCOME (LOSS)		442,016		1,190,825			(870,204	)		3,657,567
Preferred stock dividends		1,420		1,420			4,260			4,260
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	440,596	$	1,189,405		$	(874,464	)	$	3,653,307
NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	1.31	$	3.55		$	(2.61	)	$	10.93
Diluted	$	1.30	$	3.52		$	(2.61	)	$	10.84

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 Nine Months Ended
	September 30,
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(870,204	)	$	3,657,567
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		4,598,035			1,849,044
Asset retirement obligation accretion		79,274			77,146
Provision for (benefit from) deferred income taxes		(409,069	)		679,902
Unrealized loss on derivatives		—			35,586
Other		140,527			(11,231	)
Changes in operating assets and liabilities:
Receivables		(228,095	)		251,920
Inventories		11,897			(7,729	)
Advances and other		(49,569	)		27,891
Deferred charges and other		868			(200,038	)
Accounts payable		(183,884	)		71,188
Accrued expenses		(351,153	)		(367,553	)
Deferred credits and noncurrent liabilities		(59,156	)		(35,125	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		2,679,471			6,028,568
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(2,838,537	)		(4,062,975	)
Additions to gas gathering, transmission and processing facilities		(203,783	)		(420,850	)
Acquisition of Marathon properties		(181,133	)		—
Short-term investments		791,999			—
Restricted cash		13,880			(13,844	)
Proceeds from sale of oil and gas properties		—			306,701
Other, net		(98,096	)		(42,509	)
NET CASH USED IN INVESTING ACTIVITIES		(2,515,670	)		(4,233,477	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		230,176			(169,042	)
Payments on fixed-rate notes		(100,000	)		(353	)
Dividends paid		(155,125	)		(187,735	)
Common stock activity		19,028			31,207
Treasury stock activity, net		5,344			4,171
Cost of debt and equity transactions		(618	)		(1,224	)
Other		13,308			46,666
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		12,113			(276,310	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		175,914			1,518,781
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,181,450			125,823
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,357,364		$	1,644,604
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	199,570		$	137,106
Income taxes paid, net of refunds		461,024			1,512,864

The accompanying notes to consolidated financial statements
are an integral part of this statement.

2

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)

	September 30,			December 31,
	2009			2008
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,357,364		$	1,181,450
Short-term investments		—			791,999
Receivables, net of allowance		1,590,913			1,356,979
Inventories		539,442			498,567
Drilling advances		138,889			93,377
Derivative instruments		29,166			154,280
Prepaid taxes		292,332			303,414
Prepaid assets and other		71,596			70,908
		4,019,702			4,450,974
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		43,516,994			40,639,281
Unproved properties and properties under development, not being amortized		1,370,951			1,300,347
Gas gathering, transmission and processing facilities		3,087,572			2,883,789
Other		481,619			452,989
		48,457,136			45,276,406
Less: Accumulated depreciation, depletion and amortization		(25,911,605	)		(21,317,889	)
		22,545,531			23,958,517
OTHER ASSETS:
Restricted cash		—			13,880
Goodwill, net		189,252			189,252
Deferred charges and other		471,011			573,862
	$	27,225,496		$	29,186,485

The accompanying notes to consolidated financial statements
are an integral part of this statement.

3

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)

	September 30,			December 31,
	2009			2008
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	391,900		$	548,945
Accrued operating expense		114,409			168,531
Accrued exploration and development		662,387			964,859
Accrued compensation and benefits		122,216			111,907
Accrued interest		75,153			91,456
Accrued income taxes		50,311			48,028
Current debt		39,669			112,598
Asset retirement obligation		267,269			339,155
Derivative instruments		63,842			—
Other		199,793			134,956
		1,986,949			2,520,435
LONG-TERM DEBT		5,010,030			4,808,975
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,643,522			3,166,657
Asset retirement obligation		1,623,347			1,555,529
Other		606,326			626,168
		4,873,195			5,348,354
COMMITMENTS AND CONTINGENCIES (Note 7)
SHAREHOLDERS’ EQUITY:
Preferred stock, no par value, 5,000,000 shares authorized — Series B, 5.68% Cumulative, $100 million aggregate liquidation value, 100,000 shares issued and outstanding		98,387			98,387
Common stock, $0.625 par, 430,000,000 shares authorized, 343,907,219 and 342,754,114 shares issued, respectively		214,942			214,221
Paid-in capital		4,563,848			4,472,826
Retained earnings		10,904,323			11,929,827
Treasury stock, at cost, 7,732,858 and 8,044,050 shares, respectively		(219,472	)		(228,304	)
Accumulated other comprehensive income (loss)		(206,706	)		21,764
		15,355,322			16,508,721
	$	27,225,496		$	29,186,485

The accompanying notes to consolidated financial statements
are an integral part of this statement.

4

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
(Unaudited)

																	Accumulated
				Series B													Other			Total
	Comprehensive			Preferred		Common		Paid-In			Retained			Treasury			Comprehensive			Shareholders’
	Income (Loss)			Stock		Stock		Capital			Earnings			Stock			Income (Loss)			Equity
	(In thousands)
BALANCE AT DECEMBER 31, 2007				$	98,387	$	213,326	$	4,367,149		$	11,457,592		$	(238,264	)	$	(520,211	)	$	15,377,979
Comprehensive income:
Net income	$	3,657,567			—		—		—			3,657,567			—			—			3,657,567
Commodity hedges, net of income tax benefit of $89,376		(172,989	)		—		—		—			—			—			(172,989	)		(172,989	)
Comprehensive income	$	3,484,578
Dividends:
Preferred					—		—		—			(4,260	)		—			—			(4,260	)
Common ($.55 per share)					—		—		—			(183,735	)		—			—			(183,735	)
Common shares issued					—		885		36,109			—			—			—			36,994
Treasury shares issued, net					—		—		247			—			9,283			—			9,530
Compensation expense					—		—		65,645			—			—			—			65,645
FIN 48					—		—		(23,770	)		—			—			—			(23,770	)
Other					—		—		131			14			—			—			145
BALANCE AT SEPTEMBER 30, 2008				$	98,387	$	214,211	$	4,445,511		$	14,927,178		$	(228,981	)	$	(693,200	)	$	18,763,106
BALANCE AT DECEMBER 31, 2008				$	98,387	$	214,221	$	4,472,826		$	11,929,827		$	(228,304	)	$	21,764		$	16,508,721
Comprehensive loss:
Net loss	$	(870,204	)		—		—		—			(870,204	)		—			—			(870,204	)
Commodity hedges, net of income tax benefit of $124,671		(228,470	)		—		—		—			—			—			(228,470	)		(228,470	)
Comprehensive loss	$	(1,098,674	)
Dividends:
Preferred					—		—		—			(4,260	)		—			—			(4,260	)
Common ($.45 per share)					—		—		—			(151,040	)		—			—			(151,040	)
Common shares issued					—		721		3,778			—			—			—			4,499
Treasury shares issued, net					—		—		(5,706	)		—			8,832			—			3,126
Compensation expense					—		—		95,731			—			—			—			95,731
Other					—		—		(2,781	)		—			—			—			(2,781	)
BALANCE AT SEPTEMBER 30, 2009				$	98,387	$	214,942	$	4,563,848		$	10,904,323		$	(219,472	)	$	(206,706	)	$	15,355,322

The accompanying notes to consolidated financial statements
are an integral part of this statement.

5

APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

     These financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with the Annual Report on Form 10-K for the fiscal year ended December 31, 2008, 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 September 30, 2009, Apache’s significant accounting policies are consistent with those discussed in Note 1 of its consolidated financial statements contained in the Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Use of Estimates

     The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and related present value estimates of future net cash flow therefrom, asset retirement obligations and income taxes. Actual results could differ from those estimates.

Recently Adopted Accounting Pronouncements

     In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 141 (Revised), “Business Combinations” (SFAS No. 141 (R)), which was amended by FASB Staff Position (FSP) FAS No. 141 (R)-1 in April 2009. This guidance has been primarily codified into the FASB Accounting Standards Codification (ASC, also known collectively as the Codification) Topic 805, “Business Combinations.” The guidance broadens the definition of a business combination to include all transactions or other events in which control of one or more businesses is obtained. Further, the standard establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interests in the acquiree and the goodwill acquired. The statement requires the acquiring entity in a business combination to recognize the fair value of all the assets acquired and liabilities assumed in the transaction. It also modifies disclosure requirements. Apache adopted this statement effective January 1, 2009. However, since the Company did not close any material business combinations during the nine months ended September 30, 2009, the adoption had a negligible impact on the Company’s consolidated financial statements.

     Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” which was primarily codified into ASC Topic 810, “Consolidations.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” This guidance establishes accounting and reporting standards for the noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, sometimes called a minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Additionally, the amounts of consolidated net income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the income statement. Apache adopted this statement as of January 1, 2009. There were no noncontrolling interests at the adoption date. Adoption did not impact the Company’s financial position or results of operations.

6

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which was primarily codified into ASC Topic 815, “Derivatives and Hedging.” This guidance amends and expands the disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and requires qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value of derivative instruments and related gains and losses, and disclosures about credit risk-related contingent features in derivative agreements. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Apache adopted this standard as of January 1, 2009. The statement provides only for enhanced disclosures. Therefore, adoption of this standard had no impact on the Company’s financial position or results of operations.

     In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which was primarily codified into ASC Topic 260, “Earnings Per Share.” This guidance addresses whether instruments granted in share-based payment transactions should be considered participating securities for the purposes of applying the two-class method of calculating earnings per share (EPS) pursuant to FASB Statement No. 128, “Earnings Per Share,” also codified into ASC Topic 260. This guidance concludes that unvested share-based payment awards that contain rights to receive nonforfeitable dividends or dividend equivalents are participating securities prior to vesting and, therefore, should be included in the earnings allocations in computing basic EPS under the two-class method. Apache adopted this standard effective January 1, 2009. The number of unvested shares subject to the two-class method had a negligible impact on Apache’s earnings per share.

     In April 2009, the FASB issued FSP FAS No. 107-1 and APB Opinion No. 28-1, “Interim Disclosures About Fair Value of Financial Instruments,” which was primarily codified into ASC Topic 825, “Financial Instruments.” This guidance requires quarterly fair value disclosures for financial instruments that are not reflected on the Company’s Consolidated Balance Sheet at fair value in interim financial statements effective for interim periods ending after June 15, 2009. Apache adopted the new standard for the quarter ended June 30, 2009. Adoption had no impact on the Company’s financial position or results of operations. See Note 9 — Fair Value Measurements of this Form 10-Q for interim disclosures required by this statement.

     In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which was primarily codified into ASC Topic 855, “Subsequent Events.” This guidance establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, this statement sets forth:

• The period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements;

• The circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and

• The disclosures that an entity should make about events or transactions that occurred after the balance sheet date.

     This standard is effective for interim or annual periods ending after June 15, 2009, and is to be applied prospectively. Apache adopted this statement as of June 30, 2009. For evaluation of subsequent events, see Note 8 — Subsequent Events of this Form 10-Q.

     In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles,” which has been primarily codified into ASC Topic 105, “Generally Accepted Accounting Standards.” This guidance establishes the FASB Accounting Standards Codification, which officially commenced July 1, 2009, to become the single source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants. All other accounting literature excluded from the Codification is considered nonauthoritative. The subsequent issuances of new standards will be in the form of Accounting Standards Updates that will be included in the Codification. Generally, the Codification does not change U.S. GAAP. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Apache has adopted this standard for the quarter ending September 30, 2009. The standard has had a minimal effect on the Company’s financial statement disclosures, as all references to authoritative accounting literature are referenced in accordance with the Codification.

7

New Pronouncements Issued But Not Yet Adopted

     In December 2008, the FASB issued FSP FAS No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which was primarily codified into ASC Topic 715, “Compensation — Retirement Benefits.” This guidance requires additional disclosures about plan assets of a defined benefit pension or other postretirement plan, including investment strategies, major categories of plan assets, concentrations of risk within plan assets, inputs and valuation techniques used to measure the fair value of plan assets and the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period. This standard is effective for fiscal years ending after December 15, 2009, with earlier application permitted. The statement provides only for enhanced disclosures and does not require additional interim disclosures. Adoption will have no impact on the Company’s financial position or results of operations.

     In January 2009, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K and bringing full-cost accounting rules into alignment with the revised disclosure requirements. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. In September 2009, the FASB issued Proposed Accounting Standards Update (ASU), “Extractive Industries—Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures” (Exposure Draft No. 1730-100), to align the guidance in U.S. GAAP with the changes the SEC made in December 2008. The final rules are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. The public comment period for the Proposed ASU ended October 15, 2009; however, no final guidance has been issued by the FASB. The Company is continuing to evaluate the impact of this release.

2. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies for Using Derivative Instruments

     The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Management believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. Derivative instruments typically entered into are swaps and options and are generally designated as cash flow hedges.

Counterparty Risk

     The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Apache’s commodity derivative instruments are with a diversified group of counterparties, primarily financial institutions. To reduce the concentration of exposure to any individual counterparty, Apache had positions with 17 counterparties as of September 30, 2009. All of these counterparties are rated A- or higher by Standard & Poor’s and A3 or higher by Moody’s. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments under 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, as defined in the applicable agreement, in its credit ratings, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement.

8

Commodity Derivative Instruments

     As of September 30, 2009, Apache had the following open crude oil derivative positions:

			Weighted		Weighted
Production			Average		Average
Period	Mbbls		Floor Price (1)		Ceiling Price (1)
2009		3,036	$	63.24	$	78.13
2010 (2)		12,049		65.44		77.54
2011		9,122		67.45		79.09
2012		5,846		68.84		78.91
2013		1,451		72.01		72.01
2014		76		74.50		74.50

(1)	Crude oil prices represent a weighted average of all fixed-price swap contracts and collars.
(2)	Subsequent to September 30, 2009, Apache entered into crude oil hedges totaling 730 thousands of barrels (Mbbls). After consideration of these hedges, the weighted average floor and ceiling prices for our 2010 production period positions are $65.70 and $78.58 per barrel, respectively.

     As of September 30, 2009, Apache had the following open natural gas derivative positions:

			Weighted		Weighted
Production	MMBtu (1)		Average		Average
Period	(in 000’s)		Floor Price (1)		Ceiling Price (1)
2009		22,036	$	5.63	$	7.34
2010 (2)		128,071		5.59		5.62
2011		35,985		6.61		6.67
2012		42,927		6.72		6.98
2013		1,825		7.05		7.05
2014		755		7.23		7.23

(1)

Natural gas prices and volumes represent a weighted average of all fixed-price swap contracts and collars for U.S. and Canadian dollar-denominated contracts entered into on a per million British thermal units (MMBtu) basis and on a per gigajoule (GJ) basis, respectively. Canadian gas contracts are converted to U.S. dollars utilizing a period-end exchange rate and are converted to an MMBtu equivalent for purposes of this table. Natural gas contracts are settled primarily against NYMEX Henry Hub, various Inside FERC indices and the AECO Index.

(2)

Subsequent to September 30, 2009, Apache entered into natural gas hedges totaling 21,900 MMBtu (in 000’s). After consideration of these hedges, the weighted average floor and ceiling prices for our 2010 production period positions are $5.62 and $5.82 per MMBtu, respectively.

     As of September 30, 2009, Apache had the following open natural gas financial basis swap contracts:

			Weighted
			Average
Production	MMBtu		Price
Period	(in 000’s)		Differential (1)
2009		2,760	$	(0.52	)
2010		41,975		(0.54	)

(1) Natural gas financial basis swap contracts represent a weighted average differential between prices at Inside FERC PEPL and NYMEX Henry Hub prices.

9

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 are as follows:

	September 30,		December 31,
	2009		2008
	(In millions)
Current Assets: Derivative instruments	$	29	$	154
Other Assets: Deferred charges and other		23		65
Total Assets	$	52	$	219
Current Liabilities: Derivative instruments	$	63	$	—
Noncurrent Liabilities: Other		130		7
Total Liabilities	$	193	$	7

     Note 9 — Fair Value Measurements of this Form 10-Q discusses 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.

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 Nine
		Ended					Months Ended
	Gain (Loss) on Derivatives	September 30,					September 30,
	Recognized in Operations	2009		2008			2009		2008
		(In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)	Oil and Gas Production Revenues	$	48	$	(202	)	$	154	$	(515	)
Gain (loss) on derivatives recognized in operations (ineffective portion and basis)	Revenues and Other: Other	$	2	$	(39	)	$	—	$	(34	)

Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)

     As of September 30, 2009, substantially all of the Company’s derivative instruments were designated as cash flow hedges in accordance with ASC Topic 815. A reconciliation of the components of accumulated other comprehensive income (loss) in the Statement of Consolidated Shareholders’ Equity related to Apache’s cash flow hedges is presented in the table below:

	Before tax			After tax
	(In millions)
Unrealized gain on derivatives as of December 31, 2008	$	212		$	138
Realized amounts reclassified into earnings		(154	)		(105	)
Net change in derivative fair value		(199	)		(124	)
Ineffectiveness and basis swaps reclassified into earnings		—			—
Unrealized loss on derivatives as of September 30, 2009	$	(141	)	$	(91	)

     Based on market prices as of September 30, 2009, the Company’s net unrealized earnings in accumulated other comprehensive income (loss) for commodity derivatives designated as cash flow hedges totaled a loss of $141 million ($91 million after tax). Gains and losses on hedges are realized in future earnings through mid-2014, in the same period as the related sales of natural gas and crude oil production applicable to specific hedges. Included in accumulated other comprehensive income (loss) as of September 30, 2009 is a net loss of approximately $33 million ($21 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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3. DEBT

     As of September 30, 2009, the Company had unsecured committed revolving syndicated bank credit facilities totaling $2.3 billion. The facilities consist of a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. There are no outstanding borrowings or commercial paper at quarter-end, and the full $2.3 billion of unsecured credit facilities is available to the Company.

     The Company has available a $1.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2013.

     One of the Company’s Australian subsidiaries has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The facility provides for total commitments of $350 million, with availability determined by a borrowing-base formula. The borrowing base was set at $350 million and will be redetermined after the fields commence production and certain tests have been met, and semi-annually thereafter. The outstanding balance under the facility as of September 30, 2009 and December 31, 2008, respectively, was $335 million and $100 million. As of September 30, 2009, available borrowing capacity was $15 million. Under the terms of the agreement, the facility amount begins reducing on June 30, 2010 and semi-annually thereafter until maturity on March 31, 2014. The outstanding amount under this facility must not exceed $300 million on June 30, 2010. Accordingly, $35 million of the current balance will be repaid by June 30, 2010 and has been classified as current debt at September 30, 2009.

     At September 30, 2009 and December 31, 2008, there was $4.7 million and $12.6 million, respectively, borrowed on uncommitted overdraft lines.

     On March 15, 2009, $100 million of Apache Finance Pty Ltd (Apache Finance Australia) 7.0% notes matured and were repaid using existing cash balances.

Financing Costs, Net

     Financing costs incurred during the periods noted are composed of the following:

	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(In thousands)
Interest expense	$	76,860		$	66,055		$	233,137		$	201,690
Amortization of deferred loan costs		1,400			818			4,173			2,498
Capitalized interest		(14,345	)		(24,032	)		(45,325	)		(68,419	)
Interest income		(2,231	)		(9,550	)		(10,559	)		(19,175	)
Financing costs, net	$	61,684		$	33,291		$	181,426		$	116,594

4. 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. The year-to-date tax provision includes the tax impact of the non-cash write-down of proved oil and gas properties recorded as a discrete item in the first quarter of 2009.

     Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.

     The Company is in Administrative Appeals with the United States Internal Revenue Service (IRS) regarding the 2004 and 2005 tax years and under IRS audit for the 2006 and 2007 tax years. 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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5. CAPITAL STOCK

Net Income (Loss) per Common Share

     A reconciliation of the components of basic and diluted net income (loss) per common share is presented in the table below:

	For the Quarter Ended September 30,
	2009						2008
	Income		Shares		Per Share		Income		Shares		Per Share
	(In thousands, except per share amounts)
Basic:
Income attributable to common stock	$	440,596		336,159	$	1.31	$	1,189,405		334,825	$	3.55
Effect of Dilutive Securities:
Stock options and other		—		1,713				—		3,069
Diluted:
Income attributable to common stock, including assumed conversions	$	440,596		337,872	$	1.30	$	1,189,405		337,894	$	3.52

	For the Nine Months Ended September 30,
	2009								2008
	Loss			Shares		Per Share			Income		Shares		Per Share
	(In thousands, except per share amounts)
Basic:
Income (Loss) attributable to common stock	$	(874,464	)		335,637	$	(2.61	)	$	3,653,307		334,145	$	10.93
Effect of Dilutive Securities:
Stock options and other		—			—					—		3,006
Diluted:
Income (Loss) attributable to common stock, including assumed conversions	$	(874,464	)		335,637	$	(2.61	)	$	3,653,307		337,151	$	10.84

     The diluted earnings per share calculation excludes options and restricted stock that were anti-dilutive totaling 2.4 million and 4.0 million for the three- and nine-month periods ending September 30, 2009, respectively, and 358,000 for the three- and nine-month periods ending September 30, 2008. As more fully described in Note 1 — Summary of Significant Accounting Policies of this Form 10-Q, the Company adopted the provisions of ASC Topic 260, “Earnings Per Share.” The adoption of ASC Topic 260 had a negligible impact on Apache’s earnings per share.

Common and Preferred Stock Dividends

     For each of the quarters ending September 30, 2009 and 2008, Apache paid $50 million in dividends on its common stock. For the nine-month periods ended September 30, 2009 and 2008, the Company paid $151 million and $183 million, respectively. The higher common stock dividends for the first nine months of 2008 were attributable to a special cash dividend of 10 cents per common share paid on March 18, 2008. In addition, for each of the three- and nine-month periods ended September 30, 2009 and 2008, Apache paid a total of $1.4 million and $4.3 million, respectively, in dividends on its Series B Preferred Stock.

Stock-Based Compensation

     Share Appreciation Plans The Company utilizes share appreciation plans from time to time to provide incentives for substantially all full-time employees to increase Apache’s share price within a stated measurement period. To achieve the payout, the Company’s stock price must close at or above a stated threshold for 10 out of any 30 consecutive trading days before the end of the stated period. Since 2005, two separate share appreciation plans have been approved. A summary of these plans follows:

• On May 7, 2008, the Stock Option Plan Committee of the Company’s Board of Directors, pursuant to the Company’s 2007 Omnibus Equity Compensation Plan, approved the 2008 Share Appreciation Program, with a target to increase Apache’s share price to $216 by the end of 2012 and an interim goal of $162 to be achieved by the end of 2010. Any awards under the program would be payable in five equal annual installments. As of September 30, 2009, neither share price threshold had been met.

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• On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan, with a target to increase Apache’s share price to $108 by the end of 2008 and an interim goal of $81 to be achieved by the end of 2007. Awards under the plan are payable in four equal annual installments to eligible employees remaining with the Company. Apache’s share price exceeded the interim $81 threshold for the 10-day requirement as of June 14, 2007, and the first and second installments were awarded in July 2007 and 2008. The third installment was awarded in June 2009. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008, and the first and second installments were awarded in March of 2008 and 2009.

6. ASSET RETIREMENT OBLIGATION

     The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine months ended September 30, 2009:

	(In thousands)
Asset retirement obligation at December 31, 2008	$	1,894,684
Liabilities incurred		180,133
Liabilities settled		(304,806	)
Accretion expense		79,274
Revisions in estimated liabilities		41,331
Asset retirement obligation at September 30, 2009		1,890,616
Less current portion		267,269
Asset retirement obligation, long-term	$	1,623,347

     The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. To determine the current present value of this obligation, some key assumptions the Company must estimate include the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

     Liabilities settled primarily relate to individual properties plugged and abandoned during the period. Most of the activity was in the Gulf of Mexico, a portion of which relates to the continued abandonment activity on platforms toppled in 2005 during Hurricanes Katrina and Rita and in 2008 during Hurricane Ike.

7. COMMITMENTS AND CONTINGENCIES

     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 $18 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 affect on the Company’s financial position or results of operations.

Legal Matters

     Grynberg As more fully described in Note 9 of the financial statements in our Annual Report on Form 10-K for our 2008 fiscal year, in 1997, Jack J. Grynberg began filing lawsuits against other natural gas producers, gatherers and pipelines claiming that the defendants have underpaid royalty to the federal government and Indian tribes by mismeasurement of the volume and heating content of natural gas and are responsible for acts of others who mis-measured natural gas. The claims filed against Apache in 2005 were dismissed, though Mr. Grynberg appealed the dismissal. On March 17, 2009, the United States Court of Appeals for the Tenth Circuit affirmed the dismissal, and on May 4, 2009, the Tenth Circuit denied Mr. Grynberg’s petition for rehearing. On October 5, 2009, the United States Supreme Court denied Mr. Grynberg’s petition for a writ of certiorari. This matter is concluded.

13

     Argentine Environmental Claims As more fully described in Note 9 of the financial statements in our Annual Report on Form 10-K for our 2008 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 Annual Report on Form 10-K.

     Louisiana Restoration As more fully described in Note 9 of the financial statements in our Annual Report on Form 10-K for our 2008 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 Annual Report on Form 10-K.

     Hurricane Related Litigation In a case styled Ned Comer, et al vs. Murphy Oil USA, Inc., et al, Case No: 1:05-cv-00436; U.S.D.C., United States District Court, Southern District of Mississippi, Mississippi property owners allege that hurricanes’ meteorological effects increased in frequency and intensity due to global warming, and there will be continued future damage from increasing intensity of storms and sea level rises. They claim this was caused by the various defendants (oil and gas companies, electric and coal companies, and chemical manufacturers). Plaintiffs claim defendants’ emissions of “greenhouse gases” cause global warming, which they blame as the cause of their damages. They also claim that the oil company defendants artificially inflated and manipulated the prices of gasoline, diesel fuel, jet fuel, natural gas, and other end-use petrochemicals, and covered it up by misrepresentations. They further allege a conspiracy to disseminate misinformation and cover up the relationship between the defendants and global warming. Plaintiffs seek, among other damages, actual, consequential, and punitive or exemplary damages. The District Court dismissed the case on August 30, 2007. The plaintiffs appealed the dismissal. Prior to the dismissal, the plaintiffs filed a motion to amend the lawsuit to add additional defendants, including Apache. On October 16, 2009, the United States Court of Appeals for the Fifth Circuit reversed the judgment of the District Court and remanded the case to the District Court. The Fifth Circuit held that plaintiffs have pleaded sufficient facts to demonstrate standing for their public and private nuisance, trespass, and negligence claims, and that those claims are justifiable and do not present a political question. However, the Fifth Circuit declined to find standing for the unjust enrichment, civil conspiracy, and fraudulent misrepresentation claims, and therefore dismissed those claims.

     Australia Gas Pipeline Force Majeure As more fully described in Note 9 of the financial statements in our Annual Report on Form 10-K for our 2008 fiscal year, Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas in Australia to customers under various long-term contracts. On May 27, 2009, the Department of Mines and Petroleum of Western Australia filed a prosecution notice in the Magistrates Court of Western Australia, charging Apache Northwest Pty Ltd and its co-licensees with failure to maintain a pipeline in good condition and repair under the Petroleum Pipelines Act 1969, Section 38(b). The maximum fine associated with the alleged offense is AU$50,000. The Company subsidiary does not believe that the charge has merit and plans to vigorously pursue its defenses. No material change in the status of these matters has occurred since the filing of our most recent Annual Report on Form 10-K.

Environmental Matters

     As of September 30, 2009, the Company had an undiscounted reserve for environmental remediation of approximately $29 million. The Company is not aware of any environmental claims existing as of September 30, 2009 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.

14

8. SUBSEQUENT EVENTS

     Subsequent events have been evaluated for recognition and disclosure through November 6, 2009, the date these financial statements were filed with the SEC.

     On October 22, 2009, Apache and Kuwait Foreign Petroleum Exploration Co. (KUFPEC) signed an exclusive agreement to supply gas from the Julimar and Brunello discoveries and become foundation equity partners in Chevron’s Wheatstone liquefied natural gas (LNG) hub in Western Australia, opening up new markets for gas reserves from two of Apache’s largest discoveries. Apache holds a 65-percent interest in the discoveries. Apache’s projected net sales would approximate 190 MMcf/d and 5,100 b/d with a projected 15-year production plateau when the multi-year project is fully operational.

     Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG facilities with a 75-percent project interest. Apache and KUFPEC will own the remaining 25-percent project interest. Wheatstone’s first phase will consist of an offshore processing platform and pipeline to shore, along with two LNG processing trains with a combined capacity of approximately 8.6 million tons per year. Our net capital for the project is currently estimated to be $1.2 billion for upstream development of the Julimar and Brunello fields and $3.0 billion in the Wheatstone facilities. The investment will be funded as the multi-year project is developed.

9. FAIR VALUE MEASUREMENTS

     ASC 820-10-35 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

     Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

     Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to 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 estimates the fair values of derivative instruments using published commodity futures price strips for the underlying commodities as of the date of the estimate. The fair values of the Company’s derivative instruments are not actively quoted in the open market and are valued using forward commodity price curves provided by a reputable third-party. These valuations are Level 2 inputs. See Note 2 — Derivative Instruments and Hedging Activities of this Form 10-Q for further information.

     The following table presents the Company’s material assets and liabilities measured at fair value on a recurring basis for each hierarchy level:

	September 30, 2009
	Fair Value Measurements Using
	Quoted Price		Significant		Significant
	in Active		Other		Unobservable
	Markets		Inputs		Inputs		Total Fair					Carrying
	(Level 1)		(Level 2)		(Level 3)		Value		Netting (1)			Amount
	(In millions)
Assets:
Commodity Derivative Instruments	$	—	$	81	$	—	$	81	$	(29	)	$	52
Liabilities:
Commodity Derivative Instruments		—		222		—		222		(29	)		193

⁽¹⁾ The derivative fair values above are based on analysis of each contract as required by ASC Topic 820. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 2 — Derivative Instruments and Hedging Activities of this Form 10-Q for a discussion of net amounts recorded on the Consolidated Balance Sheet at September 30, 2009.

15

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

     Certain assets and liabilities are reported at fair value on a nonrecurring basis in Apache’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

     Asset Retirement Obligations Incurred in Current Period Apache estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. AROs incurred in the current period were Level 3 fair value measurements. Note 6 — Asset Retirement Obligation of this Form 10-Q provides a summary of changes in the ARO liability.

     Debt The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. In accordance with ASC 825-10-50, certain disclosures about the fair value of debt are required for interim reporting. The fair value of Apache’s fixed-rate debt is based upon estimates provided by an independent investment banking firm, which is a Level 2 fair value measurement. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The following table presents the carrying amounts and estimated fair values of the Company’s debt at September 30, 2009 and December 31, 2008:

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In millions)
Total Debt, Net of Unamortized Discount	$	5,050	$	5,718	$	4,922	$	5,092

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10. BUSINESS SEGMENT INFORMATION

     Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. The Company has production in six countries: the United States (Gulf Coast and Central regions), Canada, Egypt, offshore Australia, offshore the United Kingdom (U.K.) in the North Sea and Argentina. Apache also has exploration interests on the Chilean side of the island of Tierra del Fuego. Financial information by country is presented below:

	United										U.K.				Other
	States			Canada			Egypt		Australia		North Sea		Argentina		International		Total
	(In thousands)
For the Quarter Ended September 30, 2009
Oil and Gas Production Revenues	$	801,841		$	213,840		$	697,207	$	115,868	$	411,148	$	85,801	$	—	$	2,325,705
Operating Income (1)	$	295,292		$	52,223		$	476,828	$	15,160	$	151,300	$	17,253	$	—	$	1,008,056
Other Income (Expense):
Other																		6,726
General and administrative																		(82,492	)
Financing costs, net																		(61,684	)
Income Before Income Taxes																	$	870,606
For the Nine Months Ended September 30, 2009
Oil and Gas Production Revenues	$	2,104,781		$	639,234		$	1,772,498	$	245,429	$	976,101	$	265,620	$	—	$	6,003,663
Operating Income (Loss) (1)	$	(561,283	)	$	(1,442,810	)	$	1,140,765	$	15,051	$	379,102	$	56,971	$	—	$	(412,204	)
Other Income (Expense):
Other																		55,971
General and administrative																		(258,443	)
Financing costs, net																		(181,426	)
Loss Before Income Taxes																	$	(796,102	)
Total Assets	$	10,547,529		$	4,549,469		$	5,273,039	$	3,147,525	$	2,269,512	$	1,406,548	$	31,874	$	27,225,496
For the Quarter Ended September 30, 2008
Oil and Gas Production Revenues	$	1,311,052		$	462,470		$	778,124	$	76,817	$	642,563	$	97,856	$	—	$	3,368,882
Operating Income(1)	$	734,907		$	245,126		$	606,142	$	20,297	$	286,704	$	15,028	$	—	$	1,908,204
Other Expense
Other																		(3,998	)
General and administrative																		(57,561	)
Financing costs, net																		(33,291	)
Income Before Income Taxes																	$	1,813,354
For the Nine Months Ended September 30, 2008
Oil and Gas Production Revenues	$	4,345,687		$	1,384,790		$	2,328,440	$	328,415	$	1,787,367	$	276,250	$	—	$	10,450,949
Operating Income(1)	$	2,587,714		$	721,435		$	1,870,362	$	134,398	$	806,239	$	46,545	$	—	$	6,166,693
Other Income (Expense)
Other																		1,867
General and administrative																		(218,856	)
Financing costs, net																		(116,594	)
Income Before Income Taxes																	$	5,833,110
Total Assets	$	13,689,943		$	7,824,649		$	4,481,858	$	2,443,667	$	2,736,426	$	1,792,951	$	22,938	$	32,992,432

⁽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. The U.S. and Canada operating losses for the nine-month period of 2009 include additional depletion of $1.2 billion and $1.6 billion, respectively, to write-down the carrying value of oil and gas properties.

17

11. SUPPLEMENTAL GUARANTOR INFORMATION

     Apache Finance Canada Corporation (Apache Finance Canada) is a subsidiary of Apache and has approximately $650 million of publicly traded notes outstanding 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 Pty Ltd. (Apache Finance Australia), a subsidiary of Apache, had $100 million of publicly traded securities, which matured on March 15, 2009. The notes were repaid using existing cash balances.

     Each of these companies has been fully consolidated in Apache’s consolidated financial statements. As such, these condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto, of which this note is an integral part.

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 30, 2009

					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	728,072	$	—	$	1,597,633		$	—		$	2,325,705
Equity in net income (loss) of affiliates		315,186		8,480		(8,100	)		(315,566	)		—
Other		1,240		14,824		(8,302	)		(1,036	)		6,726
		1,044,498		23,304		1,581,231			(316,602	)		2,332,431
OPERATING EXPENSES:
Depreciation, depletion and amortization		228,120		—		397,778			—			625,898
Asset retirement obligation accretion		15,607		—		10,446			—			26,053
Lease operating expenses		193,952		—		251,583			—			445,535
Gathering and transportation costs		8,526		—		27,706			—			36,232
Taxes other than income		27,408		—		156,523			—			183,931
General and administrative		64,001		—		19,527			(1,036	)		82,492
Financing costs, net		58,295		14,110		(10,721	)		—			61,684
		595,909		14,110		852,842			(1,036	)		1,461,825
INCOME BEFORE INCOME TAXES		448,589		9,194		728,389			(315,566	)		870,606
Provision for income taxes		6,573		8,814		413,203			—			428,590
NET INCOME		442,016		380		315,186			(315,566	)		442,016
Preferred stock dividends		1,420		—		—			—			1,420
INCOME ATTRIBUTABLE TO COMMON STOCK	$	440,596	$	380	$	315,186		$	(315,566	)	$	440,596

19

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 30, 2008

											All Other
							Apache		Apache		Subsidiaries
	Apache			Apache			Finance		Finance		of Apache			Reclassifications
	Corporation			North America			Australia		Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,290,323		$	—		$	—	$	—	$	2,086,279		$	(7,720	)	$	3,368,882
Equity in net income (loss) of affiliates		842,215			36,760			27,015		124,596		(3,705	)		(1,026,881	)		—
Other		(51,534	)		(24,263	)		24,263		14,701		33,757			(922	)		(3,998	)
		2,081,004			12,497			51,278		139,297		2,116,331			(1,035,523	)		3,364,884
OPERATING EXPENSES:
Depreciation, depletion and amortization		257,091			—			—		—		343,796			—			600,887
Asset retirement obligation accretion		16,174			—			—		—		8,796			—			24,970
Lease operating expenses		229,018			—			—		—		259,148			—			488,166
Gathering and transportation costs		11,928			—			—		—		38,167			(7,720	)		42,375
Taxes other than income		57,863			—			—		—		246,417			—			304,280
General and administrative		43,661			—			—		—		14,822			(922	)		57,561
Financing costs, net		32,780			(2,777	)		4,523		14,152		(15,387	)		—			33,291
		648,515			(2,777	)		4,523		14,152		895,759			(8,642	)		1,551,530
INCOME (LOSS) BEFORE INCOME TAXES		1,432,489			15,274			46,755		125,145		1,220,572			(1,026,881	)		1,813,354
Provision (benefit) for income taxes		241,664			(7,628	)		9,995		141		378,357			—			622,529
NET INCOME		1,190,825			22,902			36,760		125,004		842,215			(1,026,881	)		1,190,825
Preferred stock dividends		1,420			—			—		—		—			—			1,420
INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,189,405		$	22,902		$	36,760	$	125,004	$	842,215		$	(1,026,881	)	$	1,189,405

20

\

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2009

							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,913,223		$	—		$	4,090,440		$	—		$	6,003,663
Equity in net income (loss) of affiliates		(323,601	)		(526,463	)		133,123			716,941			—
Other		1,632			44,138			13,272			(3,071	)		55,971
		1,591,254			(482,325	)		4,236,835			713,870			6,059,634
OPERATING EXPENSES:
Depreciation, depletion and amortization		1,871,151			—			2,726,884			—			4,598,035
Asset retirement obligation accretion		48,082			—			31,192			—			79,274
Lease operating expenses		540,759			—			707,538			—			1,248,297
Gathering and transportation costs		24,222			—			78,828			—			103,050
Taxes other than income		69,696			—			317,515			—			387,211
General and administrative		210,178			—			51,336			(3,071	)		258,443
Financing costs, net		169,706			42,338			(30,618	)		—			181,426
		2,933,794			42,338			3,882,675			(3,071	)		6,855,736
INCOME (LOSS) BEFORE INCOME TAXES		(1,342,540	)		(524,663	)		354,160			716,941			(796,102	)
Provision (benefit) for income taxes		(472,336	)		(131,323	)		677,761			—			74,102
NET LOSS		(870,204	)		(393,340	)		(323,601	)		716,941			(870,204	)
Preferred stock dividends		4,260			—			—			—			4,260
LOSS ATTRIBUTABLE TO COMMON STOCK	$	(874,464	)	$	(393,340	)	$	(323,601	)	$	716,941		$	(874,464	)

21

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2008

											All Other
							Apache		Apache		Subsidiaries
	Apache			Apache			Finance		Finance		of Apache			Reclassifications
	Corporation			North America			Australia		Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,267,293		$	—		$	—	$	—	$	6,230,045		$	(46,389	)	$	10,450,949
Equity in net income (loss) of affiliates		2,267,847			51,205			51,760		307,270		(4,893	)		(2,673,189	)		—
Other		(41,679	)		(16,880	)		16,804		44,024		2,365			(2,767	)		1,867
		6,493,461			34,325			68,564		351,294		6,227,517			(2,722,345	)		10,452,816
OPERATING EXPENSES:
Depreciation, depletion and amortization		845,486			—			—		—		1,003,558			—			1,849,044
Asset retirement obligation accretion		50,882			—			—		—		26,264			—			77,146
Lease operating expenses		644,344			—			—		—		745,198			—			1,389,542
Gathering and transportation costs		32,904			—			—		—		136,603			(46,389	)		123,118
Taxes other than income		173,689			—			—		—		671,717			—			845,406
General and administrative		176,373			—			—		—		45,250			(2,767	)		218,856
Financing costs, net		102,882			(8,272	)		13,518		42,378		(33,912	)		—			116,594
		2,026,560			(8,272	)		13,518		42,378		2,594,678			(49,156	)		4,619,706
INCOME (LOSS) BEFORE INCOME TAXES		4,466,901			42,597			55,046		308,916		3,632,839			(2,673,189	)		5,833,110
Provision (benefit) for income taxes		809,334			(3,056	)		3,841		432		1,364,992			—			2,175,543
NET INCOME		3,657,567			45,653			51,205		308,484		2,267,847			(2,673,189	)		3,657,567
Preferred stock dividends		4,260			—			—		—		—			—			4,260
INCOME ATTRIBUTABLE TO COMMON STOCK	$	3,653,307		$	45,653		$	51,205	$	308,484	$	2,267,847		$	(2,673,189	)	$	3,653,307

22

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2009

							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	983,028		$	(22,377	)	$	1,718,820		$	—		$	2,679,471
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(859,789	)		—			(1,978,748	)		—			(2,838,537	)
Additions to gas gathering, transmission and processing facilities		—			—			(203,783	)		—			(203,783	)
Acquisition of Marathon properties		(181,133	)		—			—			—			(181,133	)
Short-term investments		791,999			—			—			—			791,999
Restricted cash for acquisition settlement		13,880			—			—			—			13,880
Proceeds from sale of oil & gas properties		—			—			—			—			—
Investment in subsidiaries, net		(308,246	)		—			—			308,246			—
Other, net		(30,770	)		—			(67,326	)		—			(98,096	)
NET CASH USED IN INVESTING ACTIVITIES		(574,059	)		—			(2,249,857	)		308,246			(2,515,670	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt borrowings		996			60			531,533			(302,413	)		230,176
Payments on debt		—			—			(100,000	)		—			(100,000	)
Dividends paid		(155,125	)		—			—			—			(155,125	)
Common stock activity		19,028			20,606			(14,773	)		(5,833	)		19,028
Treasury stock activity, net		5,344			—			—			—			5,344
Cost of debt and equity transactions		(618	)		—			—			—			(618	)
Other		2,672			—			10,636			—			13,308
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(127,703	)		20,666			427,396			(308,246	)		12,113
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		281,266			(1,711	)		(103,641	)		—			175,914
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		142,026			1,714			1,037,710			—			1,181,450
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	423,292		$	3		$	934,069		$	—		$	1,357,364

23

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2008

													All Other
							Apache			Apache			Subsidiaries
	Apache			Apache			Finance			Finance			of Apache			Reclassifications
	Corporation			North America			Australia			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,548,120		$	(12,424	)	$	(11,967	)	$	(26,375	)	$	3,531,214		$	—		$	6,028,568
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,663,706	)		—			—			—			(2,399,269	)		—			(4,062,975	)
Additions to gas gathering, transmission and processing facilities		—			—			—			—			(420,850	)		—			(420,850	)
Restricted cash		(13,844	)		—			—			—			—			—			(13,844	)
Proceeds from sale of oil & gas properties		206,748			—			—			—			99,953			—			306,701
Investment in subsidiaries, net		(230,924	)		(12,975	)		—			—			—			243,899			—
Other, net		(34,814	)		—			—			—			(7,695	)		—			(42,509	)
NET CASH USED IN INVESTING ACTIVITIES		(1,736,540	)		(12,975	)		—			—			(2,727,861	)		243,899			(4,233,477	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and money market borrowings, net		(138,511	)		—			65			56			(30,652	)		—			(169,042	)
Payments on fixed-rate debt		—			—			—			—			(353	)		—			(353	)
Dividends paid		(187,735	)		4,940			(1,073	)		(2,130	)		143,313			(145,050	)		(187,735	)
Common stock activity		31,207			—			—			—			—			—			31,207
Treasury stock activity, net		4,171			19,975			12,975			26,699			39,200			(98,849	)		4,171
Cost of debt and equity transactions		(1,224	)		—			—			—			—			—			(1,224	)
Other		44,115			—			—			—			2,551			—			46,666
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(247,977	)		24,915			11,967			24,625			154,059			(243,899	)		(276,310	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		563,603			(484	)		—			(1,750	)		957,412			—			1,518,781
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		3,626			484			1			1,751			119,961			—			125,823
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	567,229		$	—		$	1		$	1		$	1,077,373		$	—		$	1,644,604

24

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of September 30, 2009

					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache		Reclassifications
	Corporation		Canada		Corporation		& Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	423,291	$	3	$	934,070	$	—		$	1,357,364
Receivables, net of allowance		526,047		—		1,064,866		—			1,590,913
Short-term investments		—		—		—		—			—
Inventories		61,879		—		477,563		—			539,442
Drilling advances and other		251,908		1,095		249,814		—			502,817
Derivative instruments		11,534		—		17,632		—			29,166
		1,274,659		1,098		2,743,945		—			4,019,702
PROPERTY AND EQUIPMENT, NET		9,243,054		—		13,302,477		—			22,545,531
OTHER ASSETS:
Intercompany receivable, net		1,488,184		—		246,773		(1,734,957	)		—
Restricted cash		—		—		—		—			—
Goodwill, net		—		—		189,252		—			189,252
Equity in affiliates		10,929,246		1,075,503		42,021		(12,046,770	)		—
Deferred charges and other		161,380		1,003,113		306,518		(1,000,000	)		471,011
	$	23,096,523	$	2,079,714	$	16,830,986	$	(14,781,727	)	$	27,225,496
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term debt	$	—	$	—	$	39,669	$	—		$	39,669
Accounts payable		259,367		247,866		1,619,624		(1,734,957	)		391,900
Accrued exploration and development		145,893		—		516,494		—			662,387
Other accrued expenses		533,198		62,905		296,890		—			892,993
		938,458		310,771		2,472,677		(1,734,957	)		1,986,949
LONG-TERM DEBT		4,062,000		647,131		300,899		—			5,010,030
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,193,920		4,288		1,445,314		—			2,643,522
Asset retirement obligation		903,313		—		720,034		—			1,623,347
Derivative instruments		—		—		—		—			—
Other		643,510		—		962,816		(1,000,000	)		606,326
		2,740,743		4,288		3,128,164		(1,000,000	)		4,873,195
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		15,355,322		1,117,524		10,929,246		(12,046,770	)		15,355,322
	$	23,096,523	$	2,079,714	$	16,830,986	$	(14,781,727	)	$	27,225,496

25

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2008

											All Other
						Apache					Subsidiaries
	Apache		Apache			Finance			Apache		of Apache			Reclassifications
	Corporation		North America			Australia			Finance Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	142,026	$	—		$	2		$	1,714	$	1,037,708		$	—		$	1,181,450
Short-term investments		791,899		—			—			—		100			—			791,999
Receivables, net of allowance		514,174		—			—			1,095		841,710			—			1,356,979
Inventories		59,106		—			—			—		439,461			—			498,567
Drilling advances and other		319,648		—			—			1,786		146,265			—			467,699
Derivative instruments		137,308		—			—			—		16,972			—			154,280
		1,964,161		—			2			4,595		2,482,216			—			4,450,974
PROPERTY AND EQUIPMENT, NET		9,970,619		—			—			—		13,987,898			—			23,958,517
OTHER ASSETS:
Intercompany receivable, net		1,185,771		—			—			—		—			(1,185,771	)		—
Restricted cash		13,880		—			—			—		—			—			13,880
Goodwill, net		—		—			—			—		189,252			—			189,252
Equity in affiliates		12,919,395		510,620			714,092			1,556,673		(157,276	)		(15,543,504	)		—
Deferred charges and other		212,635		—			—			1,003,353		357,874			(1,000,000	)		573,862
	$	26,266,461	$	510,620		$	714,094		$	2,564,621	$	16,859,964		$	(17,729,275	)	$	29,186,485
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term debt	$	—	$	—		$	99,977		$	—	$	12,621		$	—		$	112,598
Accounts payable		2,038,266		—			—			—		(1,489,321	)		—			548,945
Accrued exploration and development		279,746		—			—			—		685,113			—			964,859
Other accrued expenses		575,451		(10,097	)		165,432			290,587		1,058,431			(1,185,771	)		894,033
		2,893,463		(10,097	)		265,409			290,587		266,844			(1,185,771	)		2,520,435
LONG-TERM DEBT		4,061,005		—			—			647,071		100,899			—			4,808,975
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,599,539		—			(31,292	)		3,548		1,594,862			—			3,166,657
Asset retirement obligation		844,126		—			—			—		711,403			—			1,555,529
Derivative instruments		—		30,643			(30,643	)		—		7,713			—			7,713
Other		359,607		—			—			—		1,258,848			(1,000,000	)		618,455
		2,803,272		30,643			(61,935	)		3,548		3,572,826			(1,000,000	)		5,348,354
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		16,508,721		490,074			510,620			1,623,415		12,919,395			(15,543,504	)		16,508,721
	$	26,266,461	$	510,620		$	714,094		$	2,564,621	$	16,859,964		$	(17,729,275	)	$	29,186,485

26

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. We have exploration and production interests in the United States, Canada, Egypt, offshore Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea) and Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego.

     This discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with our consolidated financial statements and accompanying notes included under Part I, Item 1, of this Quarterly Report on Form 10-Q, as well as our consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our most recent Annual Report on Form 10-K.

OPERATING HIGHLIGHTS

     Apache produced a record 607,118 barrels of oil equivalent (boe) per day in the third quarter of 2009, up three percent from the second quarter of 2009 and 19 percent from the third quarter of 2008. Year-to-date 2009 production increased eight percent over the comparable 2008 period. Our diverse asset base contains a balance of near-term investment opportunities and a pipeline of longer-term, individually significant impactive projects. This platform, coupled with production restoration from the 2008 hurricanes and fire at Varanus Island, enabled us to deliver production growth for the year (despite curtailed capital spending, which was 37 percent below the first nine months of 2008) and is the foundation for solid long-term growth.

     Operational highlights for the third quarter of 2009 and growth drivers for 2010 and beyond are as follows:

Third-quarter 2009 operational highlights

• Our Egypt Region achieved a new quarterly record for gross production of 290,452 boe per day, up six percent from the second quarter of 2009 and 27 percent from the third quarter of 2008. The increase was driven by higher gas output primarily from Apache’s Qasr field through two new processing trains at the Salam Gas Plant and additional oil production from several discoveries in the Faghur Basin in the Khalda Offset Concession.

• In Australia, net gas production averaged a record 225 million cubic feet of gas per day (MMcf/d) following completion of repairs at the Varanus Island gas processing facility in the second quarter of 2009. While the facility was undergoing repairs for damage caused by a June 2008 explosion, gross compression capacity was expanded to 460 terajoules per day (TJ/d). As a result, average net gas production for the third quarter of 2009 was approximately 15 percent higher than pre-incident levels.

• At the Forties Field in the North Sea, we set a record for monthly production since acquiring the property in 2003. Net production for July 2009 averaged 71,472 boe per day and contributed to the second-highest quarterly production posted since Apache took over operations. Third-quarter 2009 oil output increased 13 percent from the second quarter of 2009 and 11 percent from the third quarter of 2008, on strong drilling results and increased field efficiency.

• We had our first full quarter of production from our deepwater Geauxpher Field discovery in the Gulf of Mexico. The field produced 98 MMcf/d gross, adding 39MMcf/d net to Apache during the third quarter of 2009.

• Continued restorations from the 2008 hurricanes returned nearly 900 barrels of oil per day (b/d) (net) and 26 MMcf/d (net) to production during the third quarter.

27

Growth drivers for 2010 and beyond

•	In Australia, our Van Gogh field is projected to add 20,000 b/d net to Apache when it is fully operational. The Ningaloo Vision floating production, storage and offloading vessel (FPSO) is scheduled to arrive at the Van Gogh field in the Exmouth Basin in December 2009, with first production projected for early 2010.
	Pyrenees, a second oil project in the Exmouth Basin, is scheduled to begin producing late in the first quarter of 2010. Production is projected to build to a peak of 20,000 b/d net to Apache in 2010.
•	In Canada, at Apache’s Horn River Basin shale development in northeast British Columbia, Apache and its joint venture partner are scheduled to bring an additional 27 horizontal wells (gross) on production by the end of the first half of the 2010.
•	We recently announced the results of our first operated horizontal Granite Wash well drilled in our Central Region. The Hostetter #1-23H in Washita County, Oklahoma is producing 17 MMcf/d and 800 b/d after approximately six weeks of production. Apache owns a 72-percent working interest in the well. The Granite Wash has long been a core stacked play for our Central Region, where we have drilled hundreds of vertical wells over the past decade. As a result, we now control over 200,000 gross acres in the play, most held by production. Horizontal multi-fracture technology has vastly improved the potential recoveries. The wells generally have a high associated liquid yield and produce higher rates of return than wells in gas-only resource plays during periods of low gas prices. We expect to utilize four horizontal rigs throughout 2010 to drill at least 20 new horizontal wells. We have hundreds of additional potential locations across this play, adding opportunities beyond 2010.
•	In Egypt, production from the Phiops area in the Faghur basin is presently facilities constrained to 6,500 b/d. Expansion to 8,000 b/d is planned by year-end 2009, and expansion to 20,000 b/d is targeted for the second half of 2010.
•	On October 22, 2009, Apache and Kuwait Foreign Petroleum Exploration Co. (KUFPEC) signed an exclusive agreement to supply gas from the Julimar and Brunello discoveries and become foundation equity partners in Chevron’s Wheatstone liquefied natural gas (LNG) hub in Western Australia, opening up new markets for gas reserves from two of Apache’s largest discoveries. Apache holds a 65-percent interest in the discoveries. Apache’s projected net sales would approximate 190 MMcf/d and 5,100 b/d with a projected 15-year production plateau when the multi-year project is fully operational.
	Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG facilities with a 75-percent project interest. Apache and KUFPEC will own the remaining 25-percent project interest. Wheatstone’s first phase will consist of an offshore processing platform and pipeline to shore, along with two LNG processing trains and associated off-take facilities with a combined capacity of approximately 8.6 million tons per year. Our net capital for the project is currently estimated to be $1.2 billion for upstream development of the Julimar and Brunello fields and $3.0 billion in the Wheatstone facilities. The investment will be funded as the multi-year project is developed.
•	In September 2009, we broke ground at our Devil Creek Domestic Gas Hub in Western Australia. Natural gas from our Reindeer field will be delivered to the mainland via pipeline. First production is currently scheduled for the third quarter of 2011 and is projected to add 60 MMcf/d (gross) at realized prices substantially higher than we currently realize in Australia. We operate and own a 55-percent interest in the Reindeer field.
•	In Argentina, Apache was given approval to supply up to 50 MMcf/d from two fields in Argentina’s Neuquén and Rio Negro provinces at a price of $5 per MMBtu. Delivery under the program — the first approved by the Secretary of Energy under the government’s Gas Plus program — is scheduled to commence in January 2011, although the customer, a power plant operator, has indicated it may begin taking gas in mid-2010. Apache has submitted five additional development projects for approval under the Gas Plus program, which is designed to bring new supplies to market. In the third quarter of 2009, Argentina’s realized gas prices averaged $1.89 per thousand cubic feet of gas (Mcf).

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COMMODITY PRICES

     Third-quarter 2009 earnings and net cash provided by operating activities (operating cash flows or cash flows) benefited from strengthening oil prices: average prices for the quarter were the highest realized since the third quarter of 2008. While liquids accounted for 49 percent of our oil and gas production during the third quarter of 2009, they generated 75 percent of our oil and gas revenues, a reflection of the benefit of our balanced commodity production portfolio. However, commodity prices remain lower than a year ago, which resulted in cash flows lower than 2008 record levels. North American gas prices remained relatively weak in the third quarter of 2009, and, in the face of increasing North American gas supplies, we believe they will likely remain depressed in the near-term.

     In order to manage the variability in cash flows on an additional portion of our 2010 gas and crude oil production, we increased our commodity hedge position during the third quarter of 2009. As of the date of this filing, we had hedged an average of just over 410,000 million British thermal units (MMBtu) per day of our projected 2010 North American natural gas production, utilizing a combination of swaps and collars. Approximately 90 percent of the hedged volume was swapped at an average price of just over $5.60 per MMBtu. The balance was hedged using collars with average floor and ceiling prices of approximately $5.65 and $7.55 per MMBtu, respectively. For perspective, these 2010 hedges represent approximately 21 percent of our 2009 third-quarter worldwide daily gas volumes and approximately 36 percent of our 2009 third-quarter North American daily gas production. For comparative purposes, our average realized North American gas prices were $3.86 and $4.10 per Mcf for the third quarter and the first nine months of 2009, respectively.

     On the oil side, we have currently hedged an average of just over 35,000 b/d for 2010, primarily utilizing collars with average floor and ceiling prices of approximately $65.70 and $78.58 per barrel, respectively. For perspective, these 2010 hedges represent approximately 12 percent of our third-quarter 2009 worldwide daily oil production. For comparative purposes, our average realized oil prices were $64.89 and $55.52 per barrel for the third quarter and the first nine months of 2009, respectively. See Note 2 — Derivative Instruments and Hedging Activities in Part I, Item 1 of this Form 10-Q for additional information regarding our derivative contracts.

FINANCIAL POSITION

     We believe our strong balance sheet will continue to provide us with the financial flexibility to take advantage of exceptional investment opportunities that may materialize. We exited the third quarter of 2009 with approximately $1.4 billion in cash, up $586 million from the second quarter of 2009. This compares to approximately $2 billion of cash and short-term investments at December 31, 2008. We have $2.3 billion of available committed borrowing capacity and a debt-to-capitalization ratio of 25 percent. In addition, we have the ability to access debt and equity capital markets, options supported by our investment-grade credit ratings. Apache’s current debt ratings are A-, A3, and A- from Standard & Poor’s, Moody’s Investor Service and Fitch Ratings, respectively.

EARNINGS AND CASH FLOW

     Our third-quarter 2009 earnings of $441 million ($1.30 per diluted common share), as compared to third-quarter 2008 earnings of $1.2 billion ($3.52 per share), were negatively impacted by significantly lower crude oil and natural gas price realizations. Oil and gas revenues for the third quarter of 2009 were 31 percent, or $1 billion, lower than the third quarter of 2008, driven by a 36 percent drop in average crude oil realizations and a 53 percent drop in natural gas realizations. Equivalent daily production increased 19 percent from the third quarter of 2008, with gains in five of our six producing countries. Total operating expenses were six percent lower than the third quarter of 2008 on an absolute dollar basis, and 21 percent lower on a per unit basis. Service costs have trended downward since the third quarter of 2008; however, we continue to monitor service costs very closely and actively pursue further cost reductions. We make adjustments to drilling and development schedules as warranted.

     Our nine-month period earnings in 2009, relative to 2008, were also negatively impacted by lower crude oil and natural gas price realizations and by a $1.98 billion non-cash after-tax write-down of the carrying value of our U.S. and Canadian proved oil and gas properties in the first quarter of 2009. This write-down contributed to a loss of $2.61 per share for the 2009 nine-month period compared to earnings of $10.84 per share in the 2008 period. Operating cash flows for the 2009 nine-month period totaled $2.7 billion, compared to $6 billion in the comparable 2008 period.

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RESULTS OF OPERATIONS

Revenues

Changes in Oil and Gas Production Revenues — Quarter

	Crude Oil			Natural Gas			NGL’s			Total
				(In thousands)
Revenues for the quarter ended September 30, 2007	$	1,627,467		$	819,351		$	51,776		$	2,498,594
Volume increase (decrease)		(115,470	)		(167,640	)		(12,974	)		(296,084	)
Price increase		870,081			458,763			19,770			1,348,614
Impact of hedges (decrease)		(128,808	)		(53,434	)		—			(182,242	)
Increase in 2008	$	625,803		$	237,689		$	6,796		$	870,288
Revenues for the quarter ended September 30, 2008	$	2,253,270		$	1,057,040		$	58,572		$	3,368,882
Contribution to total third-quarter 2008 revenues		67	%		31	%		2	%		100	%
Volume increase		257,060			96,027			4,927			358,014
Price decrease		(977,432	)		(627,690	)		(32,559	)		(1,637,681	)
Impact of hedges increase		171,567			64,923			—			236,490
Decrease in 2009	$	(548,805	)	$	(466,740	)	$	(27,632	)	$	(1,043,177	)
Revenues for the quarter ended September 30, 2009	$	1,704,465		$	590,300		$	30,940		$	2,325,705
Contribution to total third-quarter 2009 revenues		73	%		26	%		1	%		100	%

Changes in Oil and Gas Production Revenues — Nine Months

	Crude Oil			Natural Gas			NGL’s			Total
				(In thousands)
Revenues for the nine months ended September 30, 2007	$	4,261,017		$	2,568,847		$	135,828		$	6,965,692
Volume increase (decrease)		315,047			(294,882	)		(15,940	)		4,225
Price increase		2,845,712			1,087,197			60,825			3,993,734
Impact of hedges (decrease)		(441,882	)		(70,820	)		—			(512,702	)
Increase in 2008	$	2,718,877		$	721,495		$	44,885		$	3,485,257
Revenues for the nine months ended September 30, 2008	$	6,979,894		$	3,290,342		$	180,713		$	10,450,949
Contribution to total year-to-date 2008 revenues		67	%		31	%		2	%		100	%
Volume increase (decrease)		353,417			102,895			(3,327	)		452,985
Price decrease		(3,641,227	)		(1,812,566	)		(104,330	)		(5,558,123	)
Impact of hedges increase		526,409			131,443			—			657,852
Decrease in 2009	$	(2,761,401	)	$	(1,578,228	)	$	(107,657	)	$	(4,447,286	)
Revenues for the nine months ended September 30, 2009	$	4,218,493		$	1,712,114		$	73,056		$	6,003,663
Contribution to total 2009 year-to-date revenues		70	%		29	%		1	%		100	%

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Production and Pricing

	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
					Increase							Increase
	2009		2008		(Decrease)			2009		2008		(Decrease)
Oil Volume — b/d:
United States		88,213		80,284		10	%		87,835		93,622		(6	)%
Canada		14,595		16,655		(12	)%		15,586		17,247		(10	)%
North America		102,808		96,939		6	%		103,421		110,869		(7	)%
Egypt		93,550		64,803		44	%		90,848		64,082		42	%
Australia		10,849		7,083		53	%		9,732		8,286		17	%
North Sea		67,288		60,856		11	%		62,515		58,740		6	%
Argentina		11,026		12,729		(13	)%		11,799		12,342		(4	)%
International		182,713		145,471		26	%		174,894		143,450		22	%
Total (1)		285,521		242,410		18	%		278,315		254,319		9	%
Average Oil price — Per barrel:
United States	$	64.57	$	93.69		(31	)%	$	54.89	$	91.48		(40	)%
Canada		63.79		111.81		(43	)%		51.95		108.10		(52	)%
North America		64.46		96.80		(33	)%		54.45		94.07		(42	)%
Egypt		65.64		105.60		(38	)%		56.67		110.01		(48	)%
Australia		73.70		99.66		(26	)%		58.74		111.86		(47	)%
North Sea		65.76		113.56		(42	)%		56.68		110.08		(49	)%
Argentina		48.53		50.95		(5	)%		47.29		48.76		(3	)%
International		65.13		103.86		(37	)%		56.15		104.88		(46	)%
Total (2)		64.89		101.04		(36	)%		55.52		100.17		(45	)%
Natural Gas Volume — Mcf/d:
United States		699,062		635,891		10	%		658,507		712,529		(8	)%
Canada		371,516		349,000		6	%		367,562		355,834		3	%
North America		1,070,578		984,891		9	%		1,026,069		1,068,363		(4	)%
Egypt		372,312		287,231		30	%		355,824		254,786		40	%
Australia		225,349		54,726		312	%		176,457		124,888		41	%
North Sea		2,983		2,697		11	%		2,771		2,604		6	%
Argentina		183,504		217,091		(15	)%		189,303		193,257		(2	)%
International		784,148		561,745		40	%		724,355		575,535		26	%
Total (3)		1,854,726		1,546,636		20	%		1,750,424		1,643,898		6	%
Average Natural Gas price — Per Mcf:
United States	$	3.99	$	9.96		(60	)%	$	4.13	$	9.64		(57	)%
Canada		3.61		8.70		(59	)%		4.04		8.63		(53	)%
North America		3.86		9.51		(59	)%		4.10		9.30		(56	)%
Egypt		3.86		5.62		(31	)%		3.78		5.68		(33	)%
Australia		2.04		2.36		(14	)%		1.85		2.18		(15	)%
North Sea		14.89		27.17		(45	)%		11.66		21.88		(47	)%
Argentina		1.89		1.41		34	%		1.92		1.53		25	%
International		2.92		3.78		(23	)%		2.85		3.60		(21	)%
Total (4)		3.46		7.43		(53	)%		3.58		7.30		(51	)%
Natural Gas Liquids (NGL)
Volume — Barrels per day:
United States		7,019		5,450		29	%		5,812		6,636		(12	)%
Canada		2,166		2,034		6	%		2,110		2,046		3	%
North America		9,185		7,484		23	%		7,922		8,682		(9	)%
Argentina		3,291		3,005		10	%		3,174		2,877		10	%
Total		12,476		10,489		19	%		11,096		11,559		(4	)%
Average NGL Price — Per barrel:
United States	$	33.20	$	72.82		(54	)%	$	28.87	$	64.49		(55	)%
Canada		24.22		63.77		(62	)%		23.03		58.62		(61	)%
North America		31.08		70.36		(56	)%		27.32		63.11		(57	)%
Argentina		15.44		36.63		(58	)%		16.13		38.81		(58	)%
Total		26.96		60.70		(56	)%		24.12		57.06		(58	)%

(1)	Approximately 12 percent and nine percent of oil production was subject to financial derivative hedges for the 2009 third quarter and nine-month period, respectively; 20 percent and 19 percent for the 2008 third quarter and nine-month period, respectively.
(2)	Reflects a per barrel increase of $.13 and $.72 from financial derivative hedging activities for the 2009 third quarter and nine-month period, respectively, and a decrease of $7.54 and $6.77 from financial derivative hedging activities for the 2008 third quarter and nine-month period, respectively.
(3)	Approximately eight percent of natural gas production was subject to financial derivative hedges for the 2009 third quarter and nine-month period, respectively; 22 percent and 20 percent for the 2008 third quarter and nine-month period, respectively.
(4)	Reflects a per Mcf increase of $.27 and $.21 from financial derivative hedging activities for the 2009 third quarter and nine-month period, respectively, and a decrease of $.13 and $.06 from financial derivative hedging activities for the 2008 third quarter and nine-month period, respectively.

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Third-Quarter 2009 compared to Third-Quarter 2008

     Crude Oil Revenues Crude oil accounted for 47 percent of our equivalent production and 73 percent of our oil and gas production revenues during the third quarter of 2009, compared to 47 and 67 percent, respectively, for the same period last year. Third-quarter 2009 crude oil revenues of $1.7 billion were $549 million lower than the 2008 period. The impact of a 36 percent decrease in average realized price more than offset additional revenues provided by increased production.

     Worldwide production increased 18 percent; with growth in four of our six producing countries. Egypt’s gross oil production increased 26 percent on successful new wells and recompletions at our East Bahariya Extension, South Umbarka, West Kalabsha and Matruh concessions. Egypt’s net production to Apache increased 44 percent with the additional benefit of an increased allocation of gross production for cost recovery, a function of lower prices and the mechanics of our production-sharing contracts. In the U.S., production increased 10 percent, driven by a 23 percent increase in our Gulf Coast Region where production continued to be restored following the 2008 hurricanes. The North Sea’s production was the second highest quarterly average since we purchased the property in 2003. Production increased 11 percent from the third quarter of 2008 on strong drilling results and increased field efficiency. Australia production was up 53 percent primarily on production restored following completion of repairs at Varanus Island, but also because of additional liquids following an increase in throughput from expansion of plant capacity as discussed in gas below. Production declined 13 percent in Argentina and 12 percent in Canada, where capital spending was significantly reduced in the first nine months of the year and natural decline more than offset production from new wells.

     Natural Gas Revenues Gas accounted for 51 percent of our equivalent production and 26 percent of our oil and gas production revenues during the third quarter of 2009, compared to 50 and 31 percent, respectively, for the same period last year. Third-quarter 2009 natural gas revenues of $590 million declined $467 million from the third quarter of 2008 on a 53 percent decrease in realized natural gas prices, which more than offset higher production.

     Worldwide production increased 20 percent to a record 1,855 MMcf/d, with increases in four of our five major gas producing countries. Australia’s production increased over 300% when compared to the 2008 period, primarily on production restored following completion of repairs to the Varanus Island facility. While the facility was undergoing repairs the gross compression capacity was expanded, allowing for higher customer takes. As a result, average net gas production for the third-quarter was approximately 15 percent higher than pre-incident levels. Egypt’s gross gas production increased 28 percent, driven by successful drilling and recompletion activities at our Matruh concession and higher gas output from two new processing trains at the Salem Gas Plant. Egypt’s net production increased 30 percent with the additional benefit of an increased allocation of cost recovery volumes, a function of lower prices and the mechanics of our production-sharing contracts. U.S. production increased 10 percent, driven by a 23 percent increase in our Gulf Coast Region with contributions from both restored volumes following shut-ins related to the 2008 hurricanes and a full quarter of production from our Geauxpher field discovery. Canada’s gas production increased from drilling and recompletion activities and a lower effective royalty rate. Argentina production decreased 15 percent primarily on natural decline and an increase in gas re-injections.

Year-to-Date 2009 compared to Year-to-Date 2008

     Crude Oil Revenues Crude oil accounted for 48 percent of our equivalent production and 70 percent of our oil and gas production revenues for the nine-month period of 2009, compared to 47 and 67 percent, respectively, for the same period last year. Crude oil revenues for the nine-month period of 2009 totaled $4.2 billion and were $2.8 billion lower than the 2008 period. The impact of a 45 percent decrease in average realized price more than offset additional revenues provided by increased production.

     Worldwide production was up nine percent, driven by increases in Egypt, Australia and the North Sea. Egypt’s gross oil production increased 24 percent on successful new wells and recompletions at our East Bahariya Extension, South Umbarka, West Kalabsha and Matruh concessions. Egypt’s net production to Apache increased 42 percent with the additional benefit of an increased allocation of gross production for cost recovery, a function of lower prices and the mechanics of our production-sharing contracts. Australia production was up 17 percent primarily on production restored following completion of repairs at Varanus Island. Production in the North Sea was up six percent on successful drilling and recompletion programs. Production was down in Canada, the U.S. and Argentina (10 percent, six percent and four percent, respectively), as natural decline more than offset the impact of drilling and recompletion activities. In those three countries, capital spending during the first nine months of 2009 was less than half of the amount invested during the same period of 2008.

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     Natural Gas Revenues Gas accounted for 51 percent of our equivalent production and 29 percent of our oil and gas production revenues for the nine-month period of 2009, compared to 51 and 31 percent, respectively, for the same period last year. Natural gas revenues for the nine-month period of 2009 totaled $1.7 billion and were $1.6 billion lower than the 2008 period, reflecting a 51 percent decline in realized natural gas prices, which more than offset higher production.

     Worldwide production increased six percent. Australia production was up 41 percent, mostly on production restored following completion of repairs to the Varanus Island facility. Egypt’s gross gas production increased 24 percent, driven by successful drilling and recompletion activities at our Matruh concession and higher gas output from two new processing trains at the Salem Gas Plant. Egypt’s net production to Apache increased 40 percent with the additional benefit of an increased allocation of cost recovery volumes, a function of lower prices and the mechanics of our production-sharing contracts. Canada saw production gains from our drilling and recompletion program and a lower effective royalty rate. Production was down eight percent in the U.S. as a result of properties shut-in for repairs to third-party pipelines and 2008 hurricanes in the Gulf of Mexico. The benefits of the acquired Marathon properties and our drilling and recompletion activities offset natural decline. Argentina decreased two percent on natural decline.

Operating Expenses

     The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses either on a boe basis, on an absolute dollar basis or both, depending on their relevance. Amounts included in this table and in the discussion below are rounded to millions and may differ slightly from those presented in elsewhere in this document.

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2009		2008		2009		2008		2009		2008		2009		2008
	(In millions)				(Per boe)				(In millions)				(Per boe)
Depreciation, depletion and amortization (DD&A):
Oil and gas property
Recurring	$	576	$	560	$	10.31	$	11.93	$	1,638	$	1,734	$	10.33	$	11.72
Additional		—		—		—		—		2,818		—		17.76		—
Other assets		50		41		.90		.86		142		115		.89		.78
Total DD&A		626		601		11.21		12.79		4,598		1,849		28.98		12.50
Asset retirement obligation accretion		26		25		.47		.53		79		77		.50		.52
Lease operating costs		446		488		7.98		10.39		1,248		1,390		7.87		9.39
Gathering and transportation costs		36		43		.65		.90		103		123		.65		.83
Taxes other than income		184		304		3.29		6.48		387		846		2.44		5.72
General and administrative expense		82		58		1.48		1.22		259		219		1.63		1.48
Financing costs, net		62		33		1.10		.71		182		116		1.14		.79
Total	$	1,462	$	1,552	$	26.18	$	33.02	$	6,856	$	4,620	$	43.21	$	31.23

Third-Quarter 2009 compared to Third-Quarter 2008

     Depreciation, Depletion and Amortization (DD&A) The following table details the changes in recurring DD&A of oil and gas properties between the third quarters of 2008 and 2009:

	Recurring DD&A
	(In millions)
2008 DD&A	$	560
Volume change		95
Rate change		(79	)
2009 DD&A	$	576

     Recurring full-cost DD&A expense of $576 million increased $16 million on an absolute dollar basis. A 19 percent increase in equivalent production added $95 million and was mostly offset by a decrease in rate per boe produced. The rate decreased $1.62, to $10.31 per boe produced. The decrease in rate is the result of a $5.33 billion non-cash write-down of the carrying value of our December 31, 2008, proved oil and gas property balances in the U.S., U.K. North Sea, Canada and Argentina and a $2.82 billion non-cash write-down of the carrying value of our March 31, 2009, proved oil and gas property balances in the U.S. and Canada.

33

     Under the full-cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices and using costs in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. Write-downs required by these rules do not impact cash flow from operating activities.

     Lease Operating Expenses (LOE) Our 2009 third-quarter LOE decreased nine percent on an absolute dollar basis compared to the third quarter of 2008. On a per unit basis, LOE was down 23 percent, or $2.41 per boe, when compared to the same period in 2008: nine percent on lower cost and 14 percent on higher production. The rate was impacted by the items below:

Higher production	$	(1.50	)
Power and fuel		(.50	)
Workover costs		(.38	)
Foreign exchange rate impact		(.33	)
Varanus Island repair costs		(.12	)
Other		(.13	)
Hurricane repairs		.30
Stock based compensation, primarily SARs		.25
Change	$	(2.41	)

     Gathering and Transportation Gathering and transportation costs totaled $36 million in the third quarter of 2009, down $7 million from the third quarter of 2008. On a per unit basis, gathering and transportation costs were down 28 percent: 14 percent on lower costs and 14 percent on higher total production. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:

	For the Quarter Ended
	September 30,
	2009		2008
	(In millions)
U.S	$	9	$	12
Canada		14		16
North Sea		7		8
Egypt		5		6
Argentina		1		1
Total Gathering and Transportation	$	36	$	43

     The decreases in the U.S. and Canada were driven by lower volumes transported under third-party contracts and rate decreases. Canada also benefited from the impact of foreign exchange rates.

     Taxes other than Income Taxes other than income totaled $184 million in the third quarter of 2009, a decrease of $120 million from the third quarter of 2008. On a per unit basis, taxes other than income decreased 49 percent: 39 percent on lower costs and 10 percent on higher production. A detail of these taxes follows:

	For the Quarter Ended
	September 30,
	2009		2008
	(In millions)
U.K. PRT	$	133	$	228
Severance taxes		26		48
Ad valorem taxes		13		16
Canadian taxes		5		4
Other		7		8
Total Taxes other than Income	$	184	$	304

34

     North Sea Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $95 million less than the 2008 period on a 36 percent decrease in net profits, driven by lower realized oil prices.

     Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The decrease in severance taxes resulted from lower taxable revenues in the U.S. and Australia, consistent with the lower realized oil and natural gas prices.

     Ad valorem taxes are based on U.S. and Canadian assessed property values. The $3 million decrease resulted from a decline in taxable valuations associated with lower oil and natural gas prices.

     General and Administrative Expenses General and administrative expenses (G&A) increased $24 million compared to the third quarter of 2008. Stock-based compensation expense, which includes the mark-to-market of stock appreciation rights (SARs), added $20 million. SARs expense was up as a result of a 27 percent increase in Apache’s stock price during the third quarter of 2009 compared to a 25 percent decrease in the comparative 2008 period. Insurance costs drove the remainder of the increase. On a per unit basis, G&A increased $.26 per boe, with production gains partially offsetting the impact of higher reported expense.

     Financing Costs, Net Financing costs incurred during the periods noted are composed of the following:

	For the Quarter Ended
	September 30,
	2009			2008
	(In millions)
Interest expense	$	77		$	66
Amortization of deferred loan costs		1			1
Capitalized interest		(14	)		(24	)
Interest income		(2	)		(10	)
Financing costs, net	$	62		$	33

     Net financing costs rose $29 million in the third quarter of 2009, up $.39 per boe from the third quarter of 2008. The increase in absolute dollars is the result of an $11 million increase in interest expense related to higher average outstanding debt balances, a $10 million reduction in capitalized interest related to lower unproved property balances and completion of several long-term construction projects, and an $8 million decrease in interest income on a lower average cash balance.

     Provision for Income Taxes During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year, after consideration of discrete items.

     The provision for income taxes decreased $194 million to $429 million in the third quarter of 2009, 31 percent below the prior year, as income before taxes fell on lower oil and gas production revenues. The effective income tax rate in the third quarter of 2009 was 49.2 percent compared to 34.3 percent in the third quarter of 2008. The third-quarter 2009 rate was impacted by a $92 million non-cash charge related to the effect of the weakening U.S. dollar, while third-quarter 2008 included a $114 million benefit, as the U.S. dollar was strengthening during that period.

Year-to-Date 2009 compared to Year-to-Date 2008

     Depreciation, Depletion and Amortization (DD&A) The following table details the changes in recurring DD&A of oil and gas properties between the nine-month periods of 2008 and 2009:

	Recurring DD&A
	(In millions)
2008 DD&A	$	1,734
Volume change		68
Rate change		(164	)
2009 DD&A	$	1,638

     Recurring full-cost DD&A expense of $1.64 billion in the first nine months of 2009 was $96 million less than the comparable 2008 period: $68 million from 7 percent higher equivalent production offset by $164 million on a lower rate per boe produced. The Company’s full-cost DD&A rate decreased $1.39 to $10.33 per boe. The decrease in rate reflects the impact of a $5.33 billion non-cash write-down of the carrying value of our December 31, 2008, proved property balances in the U.S., U.K. North Sea, Canada and Argentina and a $2.82 billion non-cash write-down of the carrying value of our March 31, 2009, proved oil and gas property balances in the U.S. and Canada.

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     Under the full-cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices and using costs in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. Write-downs required by these rules do not impact cash flow from operating activities.

     Lease Operating Expenses (LOE) In the first nine months of 2009, LOE decreased 10 percent on an absolute dollar basis compared to the first nine months of 2008. On a per unit basis, LOE was down 16 percent, or $1.52 per boe, when compared to the same period of 2008: 10 percent on lower costs and six percent on higher production. The rate was impacted by the items below:

Higher production	$	(.57	)
Foreign exchange rate impact		(.55	)
Workover activity and costs		(.44	)
Power and fuel		(.31	)
Other		(.06	)
Hurricane repairs		.30
Stock based compensation, primarily SARs		.07
Varanus Island repairs and recommissioning		.04
Change	$	(1.52	)

     Gathering and Transportation Gathering and transportation costs totaled $103 million in the first nine months of 2009, down $20 million from the first nine months of 2008. On a per unit basis, gathering and transportation costs were down 22 percent: 16 percent on lower costs and six percent on higher total production. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:

	For the Nine Months Ended
	September 30,
	2009		2008
	(In millions)
U.S	$	25	$	33
Canada		38		49
North Sea		20		23
Egypt		17		15
Argentina		3		3
Total Gathering and Transportation	$	103	$	123

     The decrease in the U.S. resulted from both lower volumes transported under third-party contracts and rate decreases. Canada’s transportation was down primarily from the impact of foreign exchange rates and lower transported volumes. North Sea costs were down on foreign exchange rates.

     Taxes other than Income Taxes other than income totaled $387 million in the first nine months of 2009, a decrease of $459 million from the first nine months of 2008. On a per unit basis, taxes other than income decreased 57 percent: 54 percent on lower costs and three percent on higher total production. A detail of these taxes follows:

	For the Nine Months Ended
	September 30,
	2009		2008
	(In millions)
U.K. PRT	$	256	$	613
Severance taxes		61		141
Ad valorem taxes		34		55
Canadian taxes		13		13
Other		23		24
Total Taxes other than Income	$	387	$	846

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     North Sea PRT is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $357 million less than the 2008 period on a 45 percent decrease in net profits driven by lower realized oil prices.

     Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The decrease in severance taxes resulted from lower taxable revenues in the U.S., consistent with lower realized oil and natural gas prices.

     Ad valorem taxes are based on U.S. and Canadian assessed property values. The $21 million decrease resulted from a decline in taxable valuations associated with lower in oil and natural gas prices.

     General and Administrative Expenses General and administrative expenses (G&A) were $40 million higher in the first nine months of 2009, a result of $41 million of nonrecurring charges related to the retirement of our founder and former chairman and staff reduction separation costs. Stock-based compensation expense, which includes the mark-to-market of our SARs, increased $16 million on higher stock appreciation relative to the first nine months of 2008. Net reductions in other corporate expenses decreased G&A expense by $17 million.

     Financing Costs, Net Financing costs incurred during the periods noted are composed of the following:

	For the Nine Months Ended
	September 30,
	2009			2008
	(In millions)
Interest expense	$	233		$	201
Amortization of deferred loan costs		4			2
Capitalized interest		(45	)		(68	)
Interest income		(10	)		(19	)
Financing costs, net	$	182		$	116

     Net financing costs rose $66 million, or $.35 per boe, in the first nine months of 2009 compared to the first nine months of 2008. The increase in absolute dollars is primarily the result of a $32 million increase in interest expense related to higher average outstanding debt balances, a $23 million reduction in capitalized interest related to lower unproved property balances and completion of several long-term construction projects, and a $9 million decrease in interest income on a lower average cash balance.

     Provision for Income Taxes During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year, after consideration of discrete items. The Company’s non-cash write-down of the carrying value of its proved oil and gas properties was deemed a discrete event, and therefore, the tax effects of the write-down were recorded in the first quarter of 2009.

     The provision for income taxes for the first nine months of 2009 was $74 million compared to $2.2 billion in the 2008 period. The calculation of the 2009 effective income tax rate is not meaningful because of the magnitude of the non-cash write-down of the carrying value of our proved oil and gas properties previously discussed. Absent the write-down, the 2009 effective rate would have been 45 percent compared to 37 percent in 2008. The 2009 rate was impacted by a $116 million non-cash charge related to the weakening U.S. dollar compared to a $125 million benefit in 2008.

CAPITAL RESOURCES AND LIQUIDITY

     Operating cash flows are our primary source of liquidity. Our 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 costs do not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactive as commodity prices in the short-term.

     Our 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 barrel produced must be replaced or the Company and our 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 or our ability to acquire additional reserves at reasonable costs.

37

     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. Apache’s ability to access the debt and equity capital markets is supported by its investment-grade credit ratings.

     We believe the liquidity and capital resource alternatives available to Apache, combined with internally-generated 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.

     Our primary uses of cash are 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 net cash flows and budget our capital expenditures based on projected cash flows.

     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 Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

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 Nine Months Ended
	September 30,
	2009		2008
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	2,679	$	6,029
Sale of short-term investments		792		—
Sales of property and equipment		—		307
Net commercial paper and bank loan borrowings		230		—
Restricted cash		14		—
Common stock issuances		19		31
Other		18		50
		3,752		6,417
Uses of Cash and Cash Equivalents:
Capital expenditures(1)	$	3,043	$	4,484
Acquisitions		181		—
Payments on fixed-rate notes		100		—
Dividends		155		188
Restricted cash		—		14
Net commercial paper and bank loan repayments		—		169
Other		97		43
		3,576		4,898
Increase (decrease) in cash and cash equivalents	$	176	$	1,519

⁽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 is impacted, both in the short-term and the long-term, by highly volatile oil and natural gas prices.

     Our average natural gas price realizations have been on a downward trend since peaking in July 2008, rebounding slightly in June and July 2009 before reaching a multi-year low of $3.24 per Mcf in September 2009. Our crude oil realizations initially followed a similar trend, bottoming at a monthly average of $36.45 per barrel in December 2008, before increasing to an average of $70.06 in August 2009, then falling slightly to an average of $64.04 in September 2009. Average realized prices for natural gas and crude oil in the first nine months of 2009 were $3.58 per Mcf and $55.52 per barrel, respectively, substantially below the respective $7.30 per Mcf and $100.17 per barrel realized in the first nine months of 2008.

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     In order manage the variability in cash flows on an additional portion of our 2010 gas and crude oil production, we increased our commodity hedge position during the third quarter of 2009. As of the date of this filing, we had hedged an average of just over 410,000 MMBtu per day of our projected 2010 North American natural gas production. Nearly all of the volumes were hedged using fixed-price swaps at an average price of just over $5.60 per MMBtu. In addition, we currently have an average of just over 35,000 b/d of oil production hedged for 2010. Crude oil production was primarily hedged using collars that had average floor and ceiling prices of approximately $65.70 and $78.58 per barrel, respectively. For perspective, the 2010 hedges represent 21 percent of our daily worldwide third-quarter 2009 natural gas volumes, 12 percent of our daily worldwide oil volumes for the same quarter and 36 percent of third-quarter 2009 North America natural gas volumes. See Note 2 — Derivative Instruments and Hedging Activities in Part I, Item 1 of this Form 10-Q for additional information regarding our derivative contracts. See “Commodity Risk” in Part I, Item 3 of this Form 10-Q for quantitative and qualitative information regarding our use of derivatives to manage commodity price risk.

     The factors affecting operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, ARO accretion and deferred income tax expense.

     For the first nine months of 2009, operating cash flows totaled $2.7 billion, down $3.3 billion from the comparable 2008 period. The primary driver of the reduction was a $4.4 billion decrease in oil and gas revenues, with the impact of lower commodity prices more than offsetting an eight percent increase in equivalent daily production. Also negatively impacting operating cash flows was a net decrease in operating assets and liabilities. These items were partially offset by the positive impact of a decline in cash-based expenses (expenses excluding non-cash expenses described above) and lower current taxes.

     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 the changes in operating assets and liabilities and the non-cash expenses which do not impact net cash provided by operating activities, see the Statement of Consolidated Cash Flows in Part I, Item 1, “Financial Statements” of this Form 10-Q.

     Short-term Investments We occasionally invest in highly-liquid, short-term investments until funds are needed to further supplement our operating cash flows. At December 31, 2008, we had $792 million invested in U.S. Treasury securities with original maturities greater than three months but less than one year. These securities matured on April 2, 2009. At September 30, 2009, we held no short-term investments.

     Net commercial paper and bank loan borrowings One of the Company’s Australian subsidiaries has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The outstanding balance under the facility has increased $235 million during the year, from $100 million at December 31, 2008 to $335 million at September 30, 2009. For a more detailed discussion of this facility and information regarding our available committed borrowing capacity, refer to “Liquidity” of this Form 10-Q.

Capital Expenditures

     As we have experienced over the last 12 months, commodity prices remain volatile. Future prices cannot be accurately predicted. For these reasons, we have historically based our capital expenditure budget on projected cash flows, modifying initial annual budgets in the event of significant changes in commodity prices or costs. Given the recent commodity price levels, our expenditures for the third quarter and first nine months of 2009 were substantially lower than 2008 levels.

     We entered the year with a 2009 capital budget that was approximately half of 2008 spending in an effort to keep expenditures in line with our projected cash flows. As a result of strengthening oil prices and declining drilling costs, we increased our 2009 capital budget, and spending is now projected to be approximately $4.1 billion. We will continue to review and revise our capital budgets throughout the year based on changing industry conditions and results-to-date.

39

     Capital expenditures totaled $3.2 billion for the first nine months of 2009, $1.9 billion lower than the first nine months of 2008. The following table presents a summary of the Company’s capital expenditures for the nine months ended September 30, 2009 and 2008:

	For the Nine Months Ended
	September 30,
	2009		2008
	(In millions)
Exploration and Development Costs:
United States	$	748	$	1,606
Canada		313		526
North America		1,061		2,132
Egypt		535		624
Australia		421		662
North Sea		293		369
Argentina		109		235
Chile		4		11
International		1,362		1.901
Worldwide Exploration and Development Costs		2,423		4,033
Gathering Transmission and Processing Facilities:
Canada		69		16
Egypt		110		374
Australia		23		13
Argentina		2		3
Total Gathering Transmission and Processing Facility Cost		204		406
Asset Retirement Costs		216		350
Capitalized Interest		45		69
Capital Expenditures, excluding Acquisitions		2,888		4,858
Acquisitions — Oil and Gas Properties		264		156
Total Capital Expenditures	$	3,152	$	5,014

     Worldwide exploration and development (E&D) expenditures were down 40 percent in the first nine months of 2009 compared to the first nine months of 2008, with decreases in all countries. The most significant decrease in spending occurred in North America, where E&D investments declined 50 percent. Decreased drilling activity in the Western Desert drove Egypt’s E&D spending $89 million lower than the prior-year period. However, Egypt’s percentage of worldwide E&D spending rose to 22 percent, up from 15 percent, as this decline was less pronounced than in other regions. Australia’s E&D expenditures decreased 36 percent on lower drilling activity and lower investments in platforms and production facilities. North Sea E&D expenditures were $76 million lower upon completion of several platform upgrade projects in 2008.

     Payments on fixed-rate notes The $100 million Apache Finance Pty Ltd (Apache Finance Australia) 7.0% notes matured on March 15, 2009. The notes were repaid using existing cash balances.

     Dividends Common stock dividends paid during the first nine months of 2009 totaled $151 million, compared with $183 million paid in the first nine months of 2008. The 2008 period included a special cash dividend of 10 cents per common share paid on March 18, 2008. During the first nine months of each of 2009 and 2008, Apache paid $4.3 million in dividends on its Series B Preferred Stock issued in August 1998.

40

Liquidity

     The following table presents a summary of our key financial indicators for the periods presented:

	September 30,			December 31,
	2009			2008
	(In millions of dollars, except as indicated)
Cash	$	1,357		$	1,181
Short-term investments		—			792
Restricted cash		—			14
Cash and short-term investments		1,357			1,987
Total debt		5,050			4,922
Shareholders’ equity		15,355	(2)		16,509	(1)
Available committed borrowing capacity		2,315			2,550
Floating-rate debt/total debt		7	%		2	%
Percent of total debt-to-capitalization		25	% (2)		23	% (1)

(1)	Our year-end shareholders’ equity balance and debt-to-capitalization ratio were impacted by a $3.6 billion (after-tax) non-cash write-down in the carrying value of oil and gas properties on December 31, 2008.
(2)	Our September 30, 2009, shareholders’ equity balance and debt-to-capitalization ratio were impacted by a $3.6 billion (after-tax) non-cash write-down in the carrying value of oil and gas properties on December 31, 2008, and a $1.98 billion (after-tax) non-cash write-down in the carrying value of oil and gas properties on March 31, 2009.

     Cash and Cash Equivalents We had $1.4 billion in cash and cash equivalents at September 30, 2009, compared to $1.2 billion at December 31, 2008. At September 30, 2009, $920 million of cash was held by foreign subsidiaries and $437 million was 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. We intend to use cash from our international subsidiaries to fund international projects.

     Short-term Investments We occasionally invest in highly-liquid, short-term investments. At September 30, 2009, we held no short-term investments.

     Debt At September 30, 2009, outstanding debt, which consisted of notes, debentures, uncommitted bank lines and project financing, totaled $5.05 billion. Current debt of $40 million includes $35 million borrowed under our subsidiary’s project financing facility for our Van Gogh and Pyrenees oil developments and $4.7 million borrowed under uncommitted overdraft lines.

     Available committed borrowing capacity We ended the third quarter of 2009 with $2.3 billion of available committed borrowing capacity, as discussed below.

     As of September 30, 2009, the Company had unsecured committed revolving syndicated bank credit facilities totaling $2.3 billion. The facilities consist of a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. Since there are no outstanding borrowings or commercial paper at quarter-end, the full $2.3 billion of unsecured credit facilities are available to the Company.

     The Company has available a $1.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. 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.

     One of the Company’s Australian subsidiaries has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The facility provides for total commitments of $350 million, with availability determined by a borrowing base formula. The borrowing base was set at $350 million and will be redetermined after the fields commence production and certain tests have been met, and semi-annually thereafter. The outstanding balance under the facility as of September 30, 2009 and December 31, 2008, respectively, was $335 million and $100 million. As of September 30, 2009, available borrowing capacity was $15 million. Under the terms of the agreement, the facility amount begins reducing on June 30, 2010 and semi-annually thereafter until the maturity on March 31, 2014. The outstanding amount under this facility must not exceed $300 million on June 30, 2010. Accordingly, $35 million of the current balance will be repaid by June 30, 2010 and has been classified as current debt at September 30, 2009.

     The Company was in compliance with the terms of all credit facilities as of September 30, 2009.

     Credit Ratings As of September 30, 2009, the Company’s debt ratings are A-, A3, and A- from Standard & Poor’s, Moody’s Investor Service and Fitch Ratings, respectively. We cannot predict, nor can we assure, that we will not receive a ratings downgrade from our current ratings in the future.

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ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

     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 third quarter and first nine months of 2009, approximately eight percent of our natural gas production was subject to financial derivative hedges. In the third quarter of 2009, we entered into additional hedges on our 2010 projected North American gas production. For perspective, these 2010 hedges represent approximately 21 percent of our 2009 third-quarter worldwide daily gas volumes and approximately 36 percent of our 2009 third-quarter North American daily gas production.

     For the third quarter and first nine months of 2009, approximately 12 and nine percent, respectively, of our crude oil production was subject to financial derivative hedges. In the third quarter of 2009, we entered into additional crude oil hedges on our 2010 projected production. For perspective, these 2010 hedges represent approximately 12 percent of our third-quarter 2009 worldwide daily oil production.

     Apache may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. 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 generally hold or issue derivative instruments for trading purposes.

     On September 30, 2009, the Company had open natural gas derivative hedges in a liability position with a fair value of $15 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $105 million, while a 10 percent decrease in prices would increase the fair value by approximately $106 million. The Company also had open oil derivatives in a liability position with a fair value of $126 million. A 10 percent increase in oil prices would increase the liability by approximately $185 million, while a 10 percent decrease in prices would move the derivatives to an asset position of $53 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2009. See Part I, Item 1, Note 2 - - Derivative Instruments and Hedging Activities of this Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

     On September 30, 2009, the Company’s debt with fixed interest rates represented approximately 93 percent of total debt. As a result, the interest expense on approximately seven percent of Apache’s debt will fluctuate based on short-term interest rates. A 10 percent change in floating interest rates on September 30, 2009 floating debt balances would change annual interest expense by approximately $112,000.

Foreign Currency Risk

     The Company’s cash flows relating to certain international operations are 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, the majority of oil and gas production is sold under Canadian dollar contracts. The majority of our costs incurred are paid in Canadian dollars. 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 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 income tax provision (benefit) on the Statement of Consolidated Operations in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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, 2008, 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,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “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 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;

• currency exchange rates;

• weather conditions;

• inflation rates;

• the availability of goods and services;

• legislative or regulatory changes;

• 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 Annual Report on Form 10-K.

     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.

43

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 Roger B. Plank, the Company’s President, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2009, 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 Commission’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.

44

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please refer to both Part I, Item 3 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 (filed with the SEC on March 1, 2009) and Part I, Item 1 of each of our Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31, 2009, June 30, 2009 and September 30, 2009 for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

During the quarter ending September 30, 2009, there were no material changes from the risk factors as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, other than the following:

Proposed federal climate change regulation could increase our operating and capital costs.

The American Clean Energy and Security Act of 2009 (ACES), also known as the Waxman-Markey Bill, was approved by the U.S. House of Representatives on June 26, 2009. The ACES, if passed by the U.S. Senate, would establish a variant of a “cap-and-trade” plan for greenhouse gases (GHG) in order to address climate change. A “cap-and-trade” plan would require businesses that emit more GHG than permitted to acquire emission allowances from other businesses that emit GHG at levels lower than the limits specified and then surrender these allowances as a credit against such emissions. As a result of such a plan, we could be required to implement costly compliance technology and procedures in the U.S.

Although it is not possible at this time to predict the final outcome of the ACES, any new federal restrictions on GHG emissions, including a cap-and-trade-plan, that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on our business or demand for the crude oil and natural gas we produce in the U.S.

The proposed U.S. federal budget for fiscal year 2010 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 26, 2009, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2010. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; levy of an excise tax on Gulf of Mexico oil and gas production; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the

geological and geophysical amortization period for independent producers. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Proposed federal regulation regarding hydraulic fracturing could increase our operating and capital costs.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. We routinely use fracturing techniques in the U.S. and other regions to expand the available space for natural gas to migrate toward the well-bore. It is typically done at substantial depths in very tight formations.

Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.

45

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS

*3.1	—	Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
*3.2	—	Bylaws of Registrant, as amended August 6, 2009 (incorporated by reference to Exhibit 3.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended June 30, 2009, SEC File No. 001-4300).
**12.1	—	Statement of computation of ratio of earnings to fixed charges and combined fixed charges and preferred stock dividends.
**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 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	—	The following materials from the Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) Statement of Consolidated Operations, (ii) Consolidated Balance Sheet, (iii) Statement of Consolidated Cash Flows, (iv) Statement of Consolidated Shareholders’ Equity, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.

*	Incorporated by reference.
**	Filed herewith.
***	Furnished herewith.

46

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: November 6, 2009	/s/ ROGER B. PLANK Roger B. Plank
	President
	(Principal Financial Officer)
Dated: November 6, 2009	/s/ REBECCA A. HOYT Rebecca A. Hoyt
	Vice President and Controller
	(Principal Accounting Officer)

EX-12.1

EXHIBIT 12.1

APACHE CORPORATION
STATEMENT OF COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES AND
COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
(In Thousands)

	Nine Months Ended
	September 30,
	2009			2008		2008		2007		2006		2005		2004
EARNINGS (LOSS)
Pretax income (loss) from continuing operations	$	(796,102	)	$	5,833,110	$	932,392	$	4,672,612	$	4,009,595	$	4,206,254	$	2,663,083
Add: Fixed charges excluding capitalized interest		209,093			153,032		214,288		258,221		178,399		138,399		134,797
Adjusted Earnings (Loss)	$	(587,009	)	$	5,986,142	$	1,146,680	$	4,930,833	$	4,187,994	$	4,344,653	$	2,797,880
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Interest expense including capitalized interest (1)	$	233,137		$	201,690	$	280,457	$	308,235	$	217,454	$	175,419	$	168,090
Amortization of debt expense		4,173			2,498		3,689		3,310		2,048		3,748		2,471
Interest component of lease rental expenditures (2)		17,108			17,263		24,306		22,424		20,198		16,220		14,984
Fixed charges		254,418			221,451		308,452		333,969		239,700		195,387		185,545
Preferred stock dividend requirements (3)		3,897			6,794		7,438		9,437		8,922		9,105		9,058
Combined Fixed Charges and Preferred Stock Dividends (1)	$	258,315		$	228,245	$	315,890	$	343,406	$	248,622	$	204,492	$	194,603
Ratio of Earnings to Fixed Charges		—			27.03		3.72		14.76		17.47		22.24		15.08
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		—			26.23		3.63		14.36		16.84		21.25		14.38

(1)	Interest expense related to the provisions for uncertainty in income taxes under ASC Topic 740, “Income Taxes” is not included in the computation of ratios of earnings to fixed charges and combined fixed charges and preferred stock dividends.
(2)	Represents the portion of rental expense assumed to be attributable to interest factors of related rental obligations determined at interest rates appropriate for the period during which the rental obligations were incurred. Approximately 32 to 34 percent applies to rental payments for all periods presented.
(3)	The Company does not receive a tax benefit for its preferred stock dividends. This amount represents the pre-tax earnings that would be required to cover its preferred stock dividends.

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: November 6, 2009

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Roger B. Plank, 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/ Roger B. Plank Roger B. Plank

President

(principal financial officer)

Date: November 6, 2009

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 September 30, 2009, 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: November 6, 2009

     I, Roger B. Plank, 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 September 30, 2009, 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/ Roger B. Plank By:         Roger B. Plank

Title:      President (principal financial officer)

Date: November 6, 2009