Edgar Filing: APACHE CORP

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2009


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

For the transition period from to

Commission File Number: 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		41-0747868 (I.R.S. Employer Identification Number)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)

Registrant’s telephone number, including area code: (713) 296-6000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ


Number of shares of registrant’s common stock outstanding as of June 30, 2009		335,747,077

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-3.2
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 Six Months
	Ended June 30,					Ended June 30,
	2009		2008			2009			2008
	(In thousands, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,074,344	$	3,904,118		$	3,677,958		$	7,082,067
Other		19,034		(3,927	)		49,245			5,865


		2,093,378		3,900,191			3,727,203			7,087,932


OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		573,359		627,668			1,153,976			1,248,157
Additional		—		—			2,818,161			—
Asset retirement obligation accretion		26,483		25,679			53,221			52,176
Lease operating expenses		405,273		446,738			802,762			901,376
Gathering and transportation		33,479		39,767			66,818			80,743
Taxes other than income		115,941		298,548			203,280			541,126
General and administrative		90,905		78,872			175,951			161,295
Financing costs, net		61,155		39,050			119,742			83,303


		1,306,595		1,556,322			5,393,911			3,068,176


INCOME (LOSS) BEFORE INCOME TAXES		786,783		2,343,869			(1,666,708	)		4,019,756
Current income tax provision		218,247		702,106			220,741			1,189,906
Deferred income tax provision (benefit)		123,816		196,534			(575,229	)		363,108


NET INCOME (LOSS)		444,720		1,445,229			(1,312,220	)		2,466,742
Preferred stock dividends		1,420		1,420			2,840			2,840


INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	443,300	$	1,443,809		$	(1,315,060	)	$	2,463,902


NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	1.32	$	4.32		$	(3.92	)	$	7.38

Diluted	$	1.31	$	4.28		$	(3.92	)	$	7.32

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

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)


	For the Six Months Ended June 30,
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(1,312,220	)	$	2,466,742
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		3,972,137			1,248,157
Asset retirement obligation accretion		53,221			52,176
Provision for (benefit from) deferred income taxes		(575,229	)		363,108
Other		104,734			34,250
Changes in operating assets and liabilities:
Receivables		(173,502	)		(332,836	)
Inventories		(4,049	)		(1,720	)
Advances and other		(89,751	)		(92,352	)
Deferred charges and other		5,871			(133,128	)
Accounts payable		(176,572	)		246,449
Accrued expenses		(376,981	)		(84,237	)
Deferred credits and noncurrent liabilities		(60,930	)		(28,696	)


NET CASH PROVIDED BY OPERATING ACTIVITIES		1,366,729			3,737,913


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(2,117,415	)		(2,543,077	)
Additions to gas gathering, transmission and processing facilities		(164,723	)		(245,627	)
Acquisition of Marathon properties		(181,133	)		–
Short-term investments		791,999			–
Restricted cash		13,880			(94,357	)
Proceeds from sale of oil and gas properties		127			299,937
Other, net		(85,526	)		(25,438	)


NET CASH USED IN INVESTING ACTIVITIES		(1,742,791	)		(2,608,562	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		147,666			(182,351	)
Payments on fixed-rate notes		(100,000	)		(353	)
Dividends paid		(103,331	)		(136,145	)
Common stock activity		9,971			28,526
Treasury stock activity, net		2,669			3,416
Cost of debt and equity transactions		(403	)		(964	)
Other		9,597			41,139


NET CASH USED IN FINANCING ACTIVITIES		(33,831	)		(246,732	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(409,893	)		882,619

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,181,450			125,823


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	771,557		$	1,008,442


SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	122,120		$	90,316
Income taxes paid, net of refunds		188,251			1,093,752

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

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)


	June 30,			December 31,
	2009			2008
	(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	771,557		$	1,181,450
Short-term investments		—			791,999
Receivables, net of allowance		1,536,649			1,356,979
Inventories		571,612			498,567
Drilling advances		176,791			93,377
Derivative instruments		67,915			154,280
Prepaid taxes		308,516			303,414
Prepaid assets and other		52,045			70,908


		3,485,085			4,450,974


PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		42,752,798			40,639,281
Unproved properties and properties under development, not being amortized		1,310,031			1,300,347
Gas gathering, transmission and processing facilities		3,048,513			2,883,789
Other		467,221			452,989


		47,578,563			45,276,406
Less: Accumulated depreciation, depletion and amortization		(25,288,255	)		(21,317,889	)


		22,290,308			23,958,517

OTHER ASSETS:
Restricted cash		—			13,880
Goodwill, net		189,252			189,252
Deferred charges and other		437,282			573,862


	$	26,401,927		$	29,186,485

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

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)


	June 30,			December 31,
	2009			2008
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	389,347		$	548,945
Accrued operating expense		94,804			168,531
Accrued exploration and development		687,959			964,859
Accrued compensation and benefits		92,428			111,907
Accrued interest		89,749			91,456
Accrued income taxes		78,089			48,028
Current debt		12,656			112,598
Asset retirement obligation		267,929			339,155
Other		95,394			134,956


		1,808,355			2,520,435


LONG-TERM DEBT		4,954,667			4,808,975


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,502,554			3,166,657
Asset retirement obligation		1,585,116			1,555,529
Other		592,540			626,168


		4,680,210			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, 343,613,544 and 342,754,114 shares issued, respectively		214,758			214,221
Paid-in capital		4,527,358			4,472,826
Retained earnings		10,514,200			11,929,827
Treasury stock, at cost, 7,866,467 and 8,044,050 shares, respectively		(223,264	)		(228,304	)
Accumulated other comprehensive income (loss)		(172,744	)		21,764


		14,958,695			16,508,721


	$	26,401,927		$	29,186,485

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

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	$	2,466,742			—		—		—			2,466,742			—			—			2,466,742
Commodity hedges, net of income tax benefit of $667,072		(1,256,329	)		—		—		—			—			—			(1,256,329	)		(1,256,329	)

Comprehensive income	$	1,210,413

Dividends:
Preferred					—		—		—			(2,840	)		—			—			(2,840	)
Common ($.40 per share)					—		—		—			(133,435	)		—			—			(133,435	)
Common shares issued					—		764		34,858			—			—			—			35,622
Treasury shares issued, net					—		—		(270	)		—			8,590			—			8,320
Compensation expense					—		—		37,453			—			—			—			37,453
FIN 48					—		—		(19,142	)		—			—			—			(19,142	)
Other					—		—		85			14			—			—			99


BALANCE AT JUNE 30, 2008				$	98,387	$	214,090	$	4,420,133		$	13,788,073		$	(229,674	)	$	(1,776,540	)	$	16,514,469


BALANCE AT DECEMBER 31, 2008				$	98,387	$	214,221	$	4,472,826		$	11,929,827		$	(228,304	)	$	21,764		$	16,508,721
Comprehensive loss:
Net loss	$	(1,312,220	)		—		—		—			(1,312,220	)		—			—			(1,312,220	)
Commodity hedges, net of income tax benefit of $108,393		(194,508	)		—		—		—			—			—			(194,508	)		(194,508	)

Comprehensive loss	$	(1,506,728	)

Dividends:
Preferred					—		—		—			(2,840	)		—			—			(2,840	)
Common ($.30 per share)					—		—		—			(100,567	)		—			—			(100,567	)
Common shares issued					—		537		(3,886	)		—			—			—			(3,349	)
Treasury shares issued, net					—		—		(4,840	)		—			5,040			—			200
Compensation expense					—		—		63,356			—			—			—			63,356
Other					—		—		(98	)		—			—			—			(98	)


BALANCE AT JUNE 30, 2009				$	98,387	$	214,758	$	4,527,358		$	10,514,200		$	(223,264	)	$	(172,744	)	$	14,958,695

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

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

0. GENERAL ACCOUNTING DESCRIPTION

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 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 June 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 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 flows there from, asset retirement obligations, income taxes, valuation of derivative instruments and contingency obligations including legal and environmental risks and exposures. 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. The statement 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 statement 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. Primarily, 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 SFAS No. 141 (R) and FSP FAS No. 141 (R)-1 effective January 1, 2009. However, since the Company did not close any material business combinations during the six months ended June 30, 2009, the adoption had a minimal impact on the Company’s consolidated financial statements.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” SFAS No. 160 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 SFAS No. 160 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.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” SFAS No. 161 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 amounts of derivative instruments and related gains and losses, and disclosures about credit risk-related contingent features in derivative agreements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Apache adopted SFAS No. 161 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.” FSP EITF Issue No. 03-6-1 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.” This FSP 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 FSP EITF Issue No. 03-6-1 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 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 FSP SFAS 107-1 and APB 28-1.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which 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, SFAS No. 165 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; and

•

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.

SFAS No. 165 is effective for interim or annual periods ending after June 15, 2009, and is to be applied prospectively. Apache adopted SFAS No. 165 as of June 30, 2009. For evaluation of subsequent events, see Note 8 – Subsequent Events of this Form 10-Q.

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.” This FSP 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. FSP FAS No. 132(R)-1 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 Securities and Exchange Commission (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. 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 Company is continuing to evaluate the impact of this release.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles.” SFAS No. 168 establishes the FASB Accounting Standards Codification^TM (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 GAAP for SEC registrants. All other accounting literature excluded from the Codification will be 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 is not expected to change U.S. GAAP. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. Apache will adopt SFAS No. 168 for the quarter ending September 30, 2009. The Company is currently evaluating the effect of the standard on its financial statement disclosures, as all future references to authoritative accounting literature will be referenced in accordance with the Codification.

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 by the Company and designated as cash flow hedges are swaps and options.

Fair Value of Derivatives

All of the Company’s derivative instruments are reflected as either assets or liabilities at fair value in the Consolidated Balance Sheet. 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.

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 13 counterparties as of June 30, 2009. Apache enters into derivative transactions with counterparties 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 and/or may incur a loss.

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.

Commodity Derivative Instruments

Approximately eight percent of the Company’s worldwide oil and natural gas production was subject to financial derivative hedges for the second quarter and six-month period of 2009. As of June 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		6,072	$	63.24	$	78.13
2010		8,399		63.98		74.96
2011		8,027		67.78		77.91
2012		4,748		69.73		75.44
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.

As of June 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		30,513	$	5.99	$	8.35
2010		22,299		5.62		5.82
2011		28,685		6.12		6.18
2012		37,437		6.26		6.39
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 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.

Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet

The Company accounts for derivative instruments and hedging activity in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and all derivative instruments are reflected as either assets or liabilities at fair value in the Consolidated Balance Sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The fair market value of the Company’s derivative assets and liabilities are as follows:


	June 30,		December 31,
	2009		2008
	(In millions)
Current Assets: Derivative instruments	$	68	$	154
Other Assets: Deferred charges and other		7		65

Total Assets		75		219

Current Liabilities: Other		37		—
Noncurrent Liabilities: Other		131		7

Total Liabilities	$	168	$	7

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 Ended					For the Six Months Ended
	Gain (Loss) on Derivatives	June 30,					June 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	$	50	$	(220	)	$	106		$	(313	)
Gain (loss) on derivatives recognized in operations (ineffective portion and basis)	Revenues and Other: Other	$	1	$	5		$	(2	)	$	5

Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of June 30, 2009, substantially all of the Company’s derivative instruments were designated as cash flow hedges in accordance with SFAS No. 133. 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 at December 31, 2008	$	212		$	138
Realized amounts reclassified into earnings		(106	)		(72	)
Net change in derivative fair value		(199	)		(124	)
Ineffectiveness and basis swaps reclassified into earnings		2			1


Unrealized loss on derivatives at June 30, 2009	$	(91	)	$	(57	)

Based on market prices as of June 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 $91 million ($57 million after tax). Gains and losses on hedges are realized in future earnings through mid-2014, contemporaneously with the related sales of natural gas and crude oil production applicable to specific hedges. Included in accumulated other comprehensive income (loss) at June 30, 2009 is a net gain of approximately $34 million ($26 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.

3. DEBT

As of June 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 are available to the Company.

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

One of the Company’s Australian subsidiaries has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments, offshore Western Australia. The facility provides for total commitments of $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 June 30, 2009 and December 31, 2008, respectively, was $245 million and $100 million.

At June 30, 2009 and December 31, 2008, there was $12.2 million and $12.6 million, respectively, borrowed on uncommitted overdraft lines in Argentina.

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 Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(In thousands)
Interest expense	$	77,363		$	66,328		$	156,277		$	135,635
Amortization of deferred loan costs		1,365			829			2,773			1,680
Capitalized interest		(14,972	)		(22,810	)		(30,981	)		(44,387	)
Interest income		(2,601	)		(5,297	)		(8,327	)		(9,625	)

Financing costs, net	$	61,155		$	39,050		$	119,742		$	83,303

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. No significant discrete tax events occurred during the second quarter of 2009. 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 tax 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.

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 June 30,
	2009								2008
	Income			Shares		Per Share			Income		Shares		Per Share
				(In thousands, except per share amounts)
Basic:
Income attributable to common stock	$	443,300			335,637	$	1.32		$	1,443,809		334,208	$	4.32


Effect of Dilutive Securities:
Stock options and other		—			1,728					—		3,468


Diluted:
Income attributable to common stock, including assumed conversions	$	443,300			337,365	$	1.31		$	1,443,809		337,676	$	4.28


	For the Six Months Ended June 30,
	2009								2008
	Loss			Shares		Per Share			Income		Shares		Per Share
				(In thousands, except per share amounts)
Basic:
Income (Loss) attributable to common stock	$	(1,315,060	)		335,372	$	(3.92	)	$	2,463,902		333,801	$	7.38


Effect of Dilutive Securities:
Stock options and other		—			—					—		3,001


Diluted:
Income (Loss) attributable to common stock, including assumed conversions	$	(1,315,060	)		335,372	$	(3.92	)	$	2,463,902		336,802	$	7.32

The diluted earnings per share calculation excludes options and restricted stock that were anti-dilutive totaling 4.1 million and 3.9 million for the quarter and six months ending June 30, 2009, respectively, and 380,000 for the quarter and six months ending June 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 FSP EITF Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” effective January 1, 2009. The adoption of FSP EITF Issue No. 03-6-1 had a negligible impact on Apache’s earnings per share.

Common and Preferred Stock Dividends

For each quarter ending June 30, 2009 and 2008, Apache paid $50 million in dividends on its common stock. For the six-month periods ended June 30, 2009 and 2008, the Company paid $100 million and $133 million, respectively. The higher common stock dividends for the first six months of 2008 were attributable to a special cash dividend of 10 cents per common share paid March 18, 2008. In addition, for each of the three- and six-month periods ended June 30, 2009 and 2008, Apache paid a total of $1.4 million and $2.8 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 plan would be payable in five equal annual installments. As of June 30, 2009, neither share price threshold had been met.

•

On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan, with a target to increase Apache’s share price to $108 by the end of 2008 and an interim goal of $81 to be achieved by the end of 2007. Awards under the plan 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 six months ended June 30, 2009:


	(In thousands)
Asset retirement obligation at December 31, 2008	$	1,894,684
Liabilities incurred		93,706
Liabilities settled		(188,566	)
Accretion expense		53,221


Asset retirement obligation at June 30, 2009		1,853,045

Less current portion		267,929

Asset retirement obligation, long-term	$	1,585,116

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 $19 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. No other material changes in this matter have occurred since the filing of our most recent Annual Report on Form 10-K.

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.

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 AUD$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 June 30, 2009, the Company had an undiscounted reserve for environmental remediation of approximately $28 million. The Company is not aware of any environmental claims existing as of June 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.

8. SUBSEQUENT EVENTS

Subsequent events have been evaluated for recognition and disclosure through August 7, 2009, the date these financial statements were filed with the SEC. No significant subsequent events have been identified.

9. FAIR VALUE MEASUREMENTS

SFAS No. 157, “Fair Value Measurements,” 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 third-party, which are Level 2 inputs (see Note 2 – Derivative Instruments and Hedging Activities of this Form 10-Q).

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


	June 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	$	—	$	88	$	—	$	88	$	(13	)	$	75

Liabilities:
Commodity Derivative Instruments		—		181		—		181		(13	)		168


⁽¹⁾		The derivative fair values above are based on analysis of each contract as required by SFAS No. 157. 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 June 30, 2009.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Asset Retirement Obligations Incurred in Current Period Apache estimates the fair value of asset retirement obligations (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. Asset retirement obligations 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 FSP FAS No. 107-1 and APB Opinion No. 28-1, 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 June 30, 2009 and December 31, 2008:


	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
			(In millions)

Total Debt, Net of Unamortized Discount	$	4,967	$	5,505	$	4,922	$	5,092

10. BUSINESS SEGMENT INFORMATION

Apache 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. We also have exploration interest 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 June 30, 2009

Oil and Gas Production Revenues	$	707,081		$	215,476		$	655,063	$	86,726		$	322,181	$	87,817	$	—	$	2,074,344


Operating Income ⁽¹⁾	$	242,962		$	62,934		$	441,175	$	12,482		$	140,149	$	20,107	$	—	$	919,809


Other Income (Expense):
Other																			19,034
General and administrative																			(90,905	)
Financing costs, net																			(61,155	)

Income Before Income Taxes																		$	786,783


For the Six Months Ended June 30, 2009

Oil and Gas Production Revenues	$	1,302,939		$	425,394		$	1,075,291	$	129,561		$	564,954	$	179,819	$	—	$	3,677,958


Operating Income (Loss) ⁽¹⁾	$	(856,576	)	$	(1,495,033	)	$	663,935	$	(107	)	$	227,804	$	39,717	$	—	$	(1,420,260	)


Other Income (Expense):
Other																			49,245
General and administrative																			(175,951	)
Financing costs, net																			(119,742	)

Loss Before Income Taxes																		$	(1,666,708	)


Total Assets	$	10,438,404		$	4,435,413		$	5,102,967	$	3,004,809		$	2,024,529	$	1,395,704	$	101	$	26,401,927


For the Quarter Ended June 30, 2008
Oil and Gas Production Revenues	$	1,665,167		$	516,058		$	878,418	$	127,499		$	628,428	$	88,548	$	—	$	3,904,118


Operating Income ⁽¹⁾	$	1,069,688		$	295,585		$	731,592	$	69,182		$	287,706	$	11,965	$	—	$	2,465,718


Other Income (Expense):
Other																			(3,927	)
General and administrative																			(78,872	)
Financing costs, net																			(39,050	)

Income Before Income Taxes																		$	2,343,869


For the Six Months Ended June 30, 2008

Oil and Gas Production Revenues	$	3,034,635		$	922,320		$	1,550,316	$	251,598		$	1,144,804	$	178,394	$	—	$	7,082,067


Operating Income ⁽¹⁾	$	1,852,807		$	476,309		$	1,264,220	$	114,101		$	519,535	$	31,517	$	—	$	4,258,489


Other Income (Expense):
Other																			5,865
General and administrative																			(161,295	)
Financing costs, net																			(83,303	)

Income Before Income Taxes																		$	4,019,756


Total Assets	$	13,191,709		$	7,542,245		$	4,258,260	$	2,308,963		$	2,816,537	$	1,745,382	$	14,063	$	31,877,159


⁽¹⁾		Operating Income (Loss) consists of oil and gas production revenues less depreciation, depletion and amortization, asset retirement obligation accretion, lease operating expenses, gathering and transportation costs, and taxes other than income. The U.S. and Canada operating losses for the six- month period of 2009 include additional depletion of $1.2 billion and $1.6 billion, respectively, to write-down the carrying value of oil and gas properties.

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.

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


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
							(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	640,421		$	—		$	1,433,923		$	—		$	2,074,344
Equity in net income of affiliates		306,956			7,393			3,911			(318,260	)		—
Other		(1,184	)		14,630			6,625			(1,037	)		19,034

		946,193			22,023			1,444,459			(319,297	)		2,093,378


OPERATING EXPENSES:
Depreciation, depletion and amortization		201,542			—			371,817			—			573,359
Asset retirement obligation accretion		16,166			—			10,317			—			26,483
Lease operating expenses		173,639			—			231,634			—			405,273
Gathering and transportation costs		7,217			—			26,262			—			33,479
Taxes other than income		20,861			—			95,080			—			115,941
General and administrative		73,286			—			18,656			(1,037	)		90,905
Financing costs, net		57,959			14,115			(10,919	)		—			61,155

		550,670			14,115			742,847			(1,037	)		1,306,595


INCOME BEFORE INCOME TAXES		395,523			7,908			701,612			(318,260	)		786,783
Provision (benefit) for income taxes		(49,197	)		(3,396	)		394,656			—			342,063


NET INCOME		444,720			11,304			306,956			(318,260	)		444,720
Preferred stock dividends		1,420			—			—			—			1,420

INCOME ATTRIBUTABLE TO COMMON STOCK	$	443,300		$	11,304		$	306,956		$	(318,260	)	$	443,300

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended June 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	$	1,623,565	$	—	$	—		$	—	$	2,301,447		$	(20,894	)	$	3,904,118
Equity in net income (loss) of affiliates		782,543		6,742		14,166			92,918		(55,375	)		(840,994	)		—
Other		9,889		—		(7,459	)		14,657		(20,091	)		(923	)		(3,927	)

		2,415,997		6,742		6,707			107,575		2,225,981			(862,811	)		3,900,191


OPERATING EXPENSES:
Depreciation, depletion and amortization		299,879		—		—			—		327,789			—			627,668
Asset retirement obligation accretion		16,931		—		—			—		8,748			—			25,679
Lease operating expenses		202,001		—		—			—		244,737			—			446,738
Gathering and transportation costs		10,849		—		—			—		49,812			(20,894	)		39,767
Taxes other than income		61,617		—		—			—		236,931			—			298,548
General and administrative		65,829		—		—			—		13,966			(923	)		78,872
Financing costs, net		32,629		—		4,498			14,113		(12,190	)		—			39,050

		689,735		—		4,498			14,113		869,793			(21,817	)		1,556,322


INCOME BEFORE INCOME TAXES		1,726,262		6,742		2,209			93,462		1,356,188			(840,994	)		2,343,869
Provision (benefit) for income taxes		281,033		—		(4,533	)		48,495		573,645			—			898,640


NET INCOME		1,445,229		6,742		6,742			44,967		782,543			(840,994	)		1,445,229
Preferred stock dividends		1,420		—		—			—		—			—			1,420

INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,443,809	$	6,742	$	6,742		$	44,967	$	782,543		$	(840,994	)	$	1,443,809

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


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,185,151		$	—		$	2,492,807		$	—		$	3,677,958
Equity in net income (loss) of affiliates		(638,787	)		(534,943	)		141,223			1,032,507			—
Other		392			29,314			21,574			(2,035	)		49,245

		546,756			(505,629	)		2,655,604			1,030,472			3,727,203


OPERATING EXPENSES:
Depreciation, depletion and amortization		1,643,031			—			2,329,106			—			3,972,137
Asset retirement obligation accretion		32,475			—			20,746			—			53,221
Lease operating expenses		346,807			—			455,955			—			802,762
Gathering and transportation costs		15,696			—			51,122			—			66,818
Taxes other than income		42,288			—			160,992			—			203,280
General and administrative		146,177			—			31,809			(2,035	)		175,951
Financing costs, net		111,411			28,228			(19,897	)		—			119,742

		2,337,885			28,228			3,029,833			(2,035	)		5,393,911


LOSS BEFORE INCOME TAXES		(1,791,129	)		(533,857	)		(374,229	)		1,032,507			(1,666,708	)
Provision (benefit) for income taxes		(478,909	)		(140,137	)		264,558			—			(354,488	)


NET LOSS		(1,312,220	)		(393,720	)		(638,787	)		1,032,507			(1,312,220	)
Preferred stock dividends		2,840			—			—			—			2,840

LOSS ATTRIBUTABLE TO COMMON STOCK	$	(1,315,060	)	$	(393,720	)	$	(638,787	)	$	1,032,507		$	(1,315,060	)

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 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	$	2,976,970	$	—	$	—		$	—	$	4,143,766		$	(38,669	)	$	7,082,067
Equity in net income (loss) of affiliates		1,425,632		14,792		25,092			182,511		(57,866	)		(1,590,161	)		—
Other		9,855		—		(7,459	)		29,314		(24,000	)		(1,845	)		5,865

		4,412,457		14,792		17,633			211,825		4,061,900			(1,630,675	)		7,087,932


OPERATING EXPENSES:
Depreciation, depletion and amortization		588,395		—		—			—		659,762			—			1,248,157
Asset retirement obligation accretion		34,708		—		—			—		17,468			—			52,176
Lease operating expenses		415,326		—		—			—		486,050			—			901,376
Gathering and transportation costs		20,976		—		—			—		98,436			(38,669	)		80,743
Taxes other than income		115,826		—		—			—		425,300			—			541,126
General and administrative		132,712		—		—			—		30,428			(1,845	)		161,295
Financing costs, net		70,102		—		8,995			28,226		(24,020	)		—			83,303

		1,378,045		—		8,995			28,226		1,693,424			(40,514	)		3,068,176


INCOME BEFORE INCOME TAXES		3,034,412		14,792		8,638			183,599		2,368,476			(1,590,161	)		4,019,756
Provision (benefit) for income taxes		567,670		—		(6,154	)		48,654		942,844			—			1,553,014


NET INCOME		2,466,742		14,792		14,792			134,945		1,425,632			(1,590,161	)		2,466,742
Preferred stock dividends		2,840		—		—			—		—			—			2,840

INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,463,902	$	14,792	$	14,792		$	134,945	$	1,425,632		$	(1,590,161	)	$	2,463,902

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


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	659,679		$	(22,357	)	$	729,407		$	—		$	1,366,729


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(666,421	)		—			(1,450,994	)		—			(2,117,415	)
Additions to gas gathering, transmission and processing facilities		—			—			(164,723	)		—			(164,723	)
Acquisition of Marathon properties		(181,133	)		—			—			—			(181,333	)
Short-term investments		791,999			—			—			—			791,999
Restricted cash for acquisition settlement		13,880			—			—			—			13,880
Proceeds from sale of oil & gas properties		144			—			(17	)		—			127
Investment in subsidiaries, net		(300,472	)		—			—			300,472			—
Other, net		(26,903	)		—			(58,623	)		—			(85,526	)

NET CASH USED IN INVESTING ACTIVITIES		(368,906	)		—			(1,674,357	)		300,472			(1,742,791	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Debt borrowings		652			40			448,985			(302,011	)		147,666
Payments on debt		—			—			(100,000	)		—			(100,000	)
Dividends paid		(103,331	)		—			—			—			(103,331	)
Common stock activity		9,971			20,606			(22,145	)		1,539			9,971
Treasury stock activity, net		2,669			—			—			—			2,669
Cost of debt and equity transactions		(403	)		—			—			—			(403	)
Other		9,597			—			—			—			9,597

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(80,845	)		20,646			326,840			(300,472	)		(33,831	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		209,928			(1,711	)		(618,110	)		—			(409,893	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		142,026			1,714			1,037,710			—			1,181,450


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	351,954		$	3		$	419,600		$	—		$	771,557

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 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	$	1,168,611		$	—		$	(3,194	)	$	(22,652	)	$	2,595,148		$	—		$	3,737,913


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(765,114	)		—			—			—			(1,777,963	)		—			(2,543,077	)
Additions to gas gathering, transmission and processing facilities		—			—			—			—			(245,627	)		—			(245,627	)
Restricted cash		(94,357	)		—			—			—			—			—			(94,357	)
Proceeds from sale of oil & gas properties		198,842			—			—			—			101,095			—			299,937
Investment in subsidiaries, net		(175,241	)		(5,974	)		—			—			(23,974	)		205,189			—
Other, net		(11,242	)		—			—			—			(14,196	)		—			(25,438	)

NET CASH USED IN INVESTING ACTIVITIES		(847,112	)		(5,974	)		—			—			(1,960,665	)		205,189			(2,608,562	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and money market borrowings, net		(140,670	)		—			(2,781	)		(2,091	)		90,189			(126,998	)		(182,351	)
Payments on fixed-rate debt		—			—			—			—			(353	)		—			(353	)
Dividends paid		(136,145	)		—			—			—			—			—			(136,145	)
Common stock activity		28,526			5,974			5,974			22,993			43,250			(78,191	)		28,526
Treasury stock activity, net		3,416			—			—			—			—			—			3,416
Cost of debt and equity transactions		(964	)		—			—			—			—			—			(964	)
Other		41,139			—			—			—			—			—			41,139

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(204,698	)		5,974			3,193			20,902			133,086			(205,189	)		(246,732	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		116,801			—			(1	)		(1,750	)		767,569			—			882,619

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		3,626			—			1			1,751			120,445			—			125,823


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	120,427		$	—		$	—		$	1		$	888,014		$	—		$	1,008,442

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of June 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	$	351,954	$	3	$	419,600	$	—		$	771,557
Receivables, net of allowance		517,886		—		1,018,763		—			1,536,649
Inventories		63,714		—		507,898		—			571,612
Drilling advances and other		299,406		1,576		236,370		—			537,352
Derivative instruments		30,379		—		37,536		—			67,915

		1,263,339		1,579		2,220,167		—			3,485,085


PROPERTY AND EQUIPMENT, NET		9,161,874		—		13,128,434		—			22,290,308


OTHER ASSETS:
Intercompany receivable, net		1,487,782		—		254,595		(1,742,377	)		—
Restricted cash		—		—		—		—			—
Goodwill, net		—		—		189,252		—			189,252
Equity in affiliates		10,594,021		1,072,461		57,202		(11,723,684	)		—
Deferred charges and other		156,228		1,003,195		270,159		(1,000,000	)		429,582
Derivative instruments		6,740		—		690		—			7,430
Long-term investments		—		—		270		—			270

	$	22,669,984	$	2,077,235	$	16,120,769	$	(14,466,061	)	$	26,401,927

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Short-term debt	$	—	$	—	$	12,656	$	—		$	12,656
Accounts payable		250,868		250,009		1,630,847		(1,742,377	)		389,347
Accrued exploration and development		165,692		—		522,267		—			687,959
Other accrued expenses		507,960		46,633		163,800		—			718,393

		924,520		296,642		2,329,570		(1,742,377	)		1,808,355

LONG-TERM DEBT		4,061,657		647,111		245,899		—			4,954,667


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,220,617		3,819		1,278,118		—			2,502,554
Advances from gas purchasers		—		—		—		—			—
Asset retirement obligation		873,118		—		711,998		—			1,585,116
Derivative instruments		100,386		—		30,565		—			130,951
Other		530,991		—		930,598		(1,000,000	)		461,589

		2,725,112		3,819		2,951,279		(1,000,000	)		4,680,210


COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY		14,958,695		1,129,663		10,594,021		(11,723,684	)		14,958,695

	$	22,669,984	$	2,077,235	$	16,120,769	$	(14,466,061	)	$	26,401,927

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		456,956		—			—			1,786		163,237			—			621,979

		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
Other accrued expenses		855,197		(10,097	)		165,432			290,587		1,743,544			(1,185,771	)		1,858,892

		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

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, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our most recent Annual Report on Form 10-K.

OVERVIEW

Apache’s performance during the quarter reflects the benefts of our geological and geographical diversity as well as our balanced product mix. Initial development from projects in the Gulf of Mexico and the Western Desert of Egypt contributed to record second-quarter 2009 production, which increased six percent from the second quarter of 2008 and seven percent from the first quarter of 2009. Both increases reflect production growth in four of the six countries in which we operate.

Our balanced product mix served us well during the year, as the benefit from the rebound in oil prices more than offset continuing deterioration of North American natural gas prices. Oil production contributed 48 percent of Apache’s worldwide second-quarter production, but 72 percent of oil and gas revenues. Prices for both oil and gas were substantially below year-earlier quarter and six-month levels, which were at historically high levels.

We continue to make progress reducing per unit operating costs. Lease operating costs are down nine percent from the second quarter and 11 percent from the first half of 2008. Absent nonrecurring costs related to staff reductions and the retirement of our founder and former chairman, our general and administrative costs for the first six months of 2009 would have been $23 million lower than the first half of 2008. Apache employees united in cost-reduction efforts and, in addition to other cost-cutting initiatives, company-wide salary increases were deferred for a six-month period, and the four members of the Office of the Chief Executive reduced their salaries by 10 percent. We continue to push for even greater efficiencies.

We remain steadfast to the business principles that have guided Apache’s progress since our inception. We set the objective of continuing to live within our means and are on target to keep 2009 exploration and development capital spending within cash flow. We also remain strategically positioned to take advantage of potential acquisition opportunities that may materialize. We ended the quarter with $772 million in cash, $2.4 billion of available committed borrowing capacity, a debt-to-capitalization ratio of 25 percent and single-A credit ratings. In the current economic and political climate, it is imperative that we keep a long-term perspective and continue to demand operational excellence.

EARNINGS AND CASH FLOW

Our second-quarter earnings of $1.31 per diluted common share were negatively impacted by significantly lower crude oil and natural gas price realizations relative to the second quarter of 2008, which saw record earnings of $4.28 per share. Our six-month period earnings in 2009, relative to 2008, were also negatively impacted by lower crude oil and natural gas price realizations and our $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 $3.92 per share for the 2009 six-month period compared to earnings of $7.32 per share in the year-ago period. Cash provided by operating activities for the 2009 six-month period totaled $1.4 billion compared to $3.7 billion in the comparable prior-year period. For additional discussion on prices, refer to “Pricing Trends” under this Item 2. We believe weak commodity prices are likely to be a challenge for the remainder of 2009.

Second-quarter 2009 oil and gas revenues were 47 percent, or $1.8 billion, lower than the second quarter of 2008, driven by a 47 percent drop in average crude oil realizations and a 57 percent drop in natural gas realizations. On a unit basis, daily production was six percent above the year-ago period, with gains in Egypt, Australia and the North Sea offsetting the continuing impact of the 2008 U.S. hurricanes. Total operating expenses were 16 percent lower than the second quarter of 2008. Reductions in service costs continue to lag behind the sharp decline in commodity prices and are not presently at levels we believe are in line with today’s lower commodity prices. We continue to monitor service cost trends very closely and make appropriate adjustments to drilling and development schedules while actively pursuing further cost reductions.

OPERATING HIGHLIGHTS

Egypt

Exploration Activity

	•		On July 30, 2009, we announced that the Falcon 1-X wildcat in the Matruh Concession, drilled in May 2009, tested 4,400 barrels of oil per day (b/d) from the Alam El Buieb (AEB-3D) formation. The well will be initially completed in the AEB-3D oil zone, and first production from the well should commence in the third quarter of 2009. The well also encountered hydrocarbon pay zones in the AEB-6 and Jurassic Safa formation that will not be produced until additional processing and transportation capacity is developed. The Jurassic Safa tested at a rate of 11 million cubic feet of natural gas per day (MMcf/d) and 415 b/d. The AEB-6 tested at 35 MMcf/d and 1,953 b/d. An appraisal well is planned before year-end.

	•		On July 30, 2009, we also announced that the Hydra-5X appraisal well in the Shushan Concession tested 21 MMcf/d and 3,744 barrels of condensate per day from the Jurassic Upper Safa formation. This well follows Apache’s Hydra-1X discovery drilled in 2008. The field will be developed upon completion of a gas sales agreement with the Egyptian General Petroleum Corporation.

	•		On April 30, 2009, Apache announced discovery of the Phiops field, the largest of five fields discovered since 2006 by Apache through its joint venture partner, Khalda Petroleum Company, in the Faghur Basin of the Western Desert. The Phiops-1X well in the South Umbarka Concession was completed earlier this year as an oil producer and test-flowed 2,278 b/d and 5 MMcf/d from the Safa formation. The Phiops field was subsequently appraised by the Phiops-5 well discussed below.

	•		On April 30, we also announced that the WKAL-A-1X well, located five miles west of Phiops-1X in the West Kalabsha Concession, tested at 770 b/d and 4 MMcf/d from the Jurassic Zahra formation and 2,906 b/d and 16 MMcf/d from the Cretaceous AEB-3 formation. Apache plans to apply for a development lease on this discovery.

	•		On April 30, we also announced the NTRK-C-1X well, our first new field discovery in the North Tarek Concession along the Mediterranean coast, tested at a rate of 3,489 b/d and 5 MMcf/d. Additional drilling is planned for this new concession.

Development and Appraisal Activity

	•		On June 9, 2009, we announced that the Phiops-5 appraisal well in the Faghur Basin in Egypt’s Western Desert test-flowed 8,279 b/d and 0.4 MMcf/d. A new pipeline from Phiops to the Khepri-Sethos facilities is expected to be completed during the third quarter of 2009. The new pipeline and additional storage capacity at Kalabsha and Khepri-Sethos are estimated to increase gross production capacity in the Kalabsha area from 4,000 b/d to 20,000 b/d in early 2010. We plan to continue an exploration, appraisal and development program in the second half of 2009 to capitalize on these successes, including the acquisition of 740 square kilometers of three-dimensional seismic data in the area.

	•		During the second quarter, we completed performance tests at the new Salam Gas Plant Trains 3 and 4, and the Northern Pipeline Compression project is now fully operational. These two new trains add 200 MMcf/d and 10,000 b/d of gross processing capacity and are currently operating at design capacity throughput.

•

Amendments to extend our Siwa, Sallum, and West Ghazalat exploration concessions for an additional three years (to July 27, 2013) were approved by the Egyptian Parliament in June 2009. These concessions encompass 3.8 million gross acres, which Apache operates with a 50-percent contractor interest. Apache’s first well in West Ghazalat should spud in October 2009.

Australia

Varanus Island

•

Early in the third quarter, Apache subsidiaries completed final repairs to the Varanus Island gas processing and transportation hub offshore Western Australia, which sustained damage from a gas pipeline explosion in June 2008. The subsidiaries are also installing a compressor at Varanus Island to expand gross compression capacity to 460 terajoules per day (TJ/d). Installation is expected to be completed during the third quarter of this year.

Exploration Activity

•

We drilled two new wells in the Julimar-Brunello complex during the second quarter. We are presently evaluating all options to commercialize this large gas resource, and the process is expected to be completed by year-end.

Development Activity

•

At our Van Gogh oil project, the Van Gogh-6H development well and Van Gogh-12 water injector were completed. Repairs of the floating production, storage and offloading (FPSO) vessel, a result of April’s control room fire, are well underway, and we estimate first production at Van Gogh around year-end. The fire delayed first production, initially scheduled for the second quarter of this year. The FPSO is owned and operated by a third party and will be leased by Apache when it is delivered to the Van Gogh field.

North Sea

Development Activity

	•		Apache completed four successful oil development wells during the quarter, bringing the 2009 total to seven. Of note is the Forties Charlie 6-3 well, which encountered 34 meters of pay and was brought on production in mid-June at 10,500 b/d, the highest initial rate in the field since 1994. Apache owns a 97.14-percent interest in the Forties field.

	•		The Forties Field is currently producing at sustained rates in excess of 70,000 gross b/d. We are in the process of drilling one development well and completing an additional successful oil development well, which is scheduled to be on production in August 2009.

U.S. Central Region

Development Activity

	•		Region rig activity was deliberately slowed in the first two quarters of 2009 in an effort to better align service costs with the current lower oil and gas price environment. With the reduced activity levels, the region concentrated on building their inventory of drillable prospects and proceeded with lower cost projects, such as water-flood expansions to target oil.

	•		We also began a rigorous evaluation of our emerging horizontal tight-gas play in the Anadarko Basin. We are presently drilling our first operated horizontal granite wash well following recent industry successes. Apache has identified a number of horizontal oil and gas plays on our acreage and will be testing these over the remainder of 2009 and into 2010.

	•		We believe we can drill and complete a well today for roughly two-thirds of 2008 costs as service costs continue to fall. With costs down and over 60 percent of the region’s annual budget unspent at the end of the second quarter, we plan to accelerate our drilling and workover programs in the second half of 2009.

Acquisitions

•

On June 3, 2009, we completed the acquisition of nine Permian Basin oil and gas fields from Marathon Oil Corporation. Apache has indentified numerous attractive oil drilling targets, especially in southeastern New Mexico, where we recently sanctioned a 10-well program for the second half of 2009.

U.S. Gulf Coast Region

Development Activity

	•		Our much anticipated, 40-percent owned, Geauxpher (Garden Banks 462) development came on line May 15, 2009. Through July 31, 2009, the two-well field had already produced 7.5 billion cubic feet (Bcf) and was continuing to flow at 105 MMcf/d.

	•		We also made considerable progress restoring Gulf Coast region production previously shut-in because of hurricane damage. The region restored an average of 5,100 barrels of oil equivalent per day (boe/d) in the second quarter. The last 8,800 boe/d is projected to be restored in the third quarter of 2009. The timing of the remaining restoration in many instances is beyond our control since we are awaiting repairs to third-party pipelines and facilities.

	•		On April 20, 2009, Apache reported that its Ewing Banks 998 #1 discovery test-flowed 4,254 b/d and 5.4 MMcf/d. The well will be connected to existing facilities, with first production projected for the first quarter of 2010. Apache owns a 50-percent interest in the property.

	•		The Gulf Coast Region continues to see further reductions in rig rates. For example, jack-up rig activity has fallen to fewer than 20 rigs, down from the more traditional 100-rig level. As a result, quotes are now below 2008 rates. We are also seeing significant cost reductions for support vessels.

Canada

Development Activity

	•		Continued weak gas prices and a high-cost environment slowed our development drilling activity in Canada. Although we drilled 118 development wells during the first half of 2009, very little activity occurred after the winter drilling campaign concluded in the first quarter. We plan to drill another 53 wells in the second half of the year, predominately for oil targets. The province of Alberta implemented a royalty incentive limiting royalties to five percent for the first year if the well is completed before April 1, 2011, as well as a $200-per-meter drilled royalty credit. We continue to evaluate our substantial prospect inventory with these incentives in mind but will generally need more cost relief and/or higher gas prices to increase activity substantially.

	•		Activity at our Horn River (Ootla) shale play remained high during the quarter. We currently have six horizontal Muskwa wells from the 2008 drilling program producing an aggregate gross 14 MMcf/d after more than a year, on average. Also, the first three wells from the Encana-operated 2009 program are on production and together produced a gross 26 MMcf/d after three weeks, on average. A fourth well is expected to be on production in early August 2009. Encana will finish drilling another 11 wells while Apache completes its 16-well program on the 70-K pad by the end of the third quarter of 2009. Completion operations for these wells will commence late this year, and we anticipate first production by the end of the first quarter of 2010. We are quite pleased with the improved efficiencies that we have been able to achieve, as drilling times have improved to as little as 16 days from our original estimation of 30 days.

			In the second quarter, the partners commissioned a new dehydration and compressor facility and a new 42-mile, 24-inch sales line, with capacity of over 700 MMcf/d, that will allow us to flow gas to a third-party’s interconnect point.

			Given soft gas prices, the partners will need to continue to look for ways to reduce costs. We believe combining our results to date with our acreage position will enable us to drill up to 3,000 gross wells in the Ootla shale play over the next several decades.

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 June 30, 2007	$	1,473,621		$	922,736		$	47,674		$	2,444,031

Volume increase (decrease)		89,708			(119,798	)		(5,056	)		(35,146	)
Price increase		1,243,800			444,557			18,948			1,707,305
Impact of hedges decrease		(200,225	)		(11,847	)		–			(212,072	)

Increase in 2008	$	1,133,283		$	312,912		$	13,892		$	1,460,087

Revenues for the quarter ended June 30, 2008	$	2,606,904		$	1,235,648		$	61,566		$	3,904,118


Contribution to total year-to-date 2008 revenues		67	%		31	%		2	%		100	%

Volume increase (decrease)		118,948			31,342			(2,936	)		147,354
Price decrease		(1,453,720	)		(760,451	)		(35,981	)		(2,250,152	)
Impact of hedges increase		219,264			53,760			–			273,024

Decrease in 2009	$	(1,115,508	)	$	(675,349	)	$	(38,917	)	$	(1,829,774	)

Revenues for the quarter ended June 30, 2009	$	1,491,396		$	560,299		$	22,649		$	2,074,344

Contribution to total year-to-date 2009 revenues		72	%		27	%		1	%		100	%


Changes in Oil and Gas Production Revenues – Six Months
	Crude Oil			Natural Gas			NGL’s			Total
				(In thousands)
Revenues for the six months ended June 30, 2007	$	2,633,550		$	1,749,497		$	84,051		$	4,467,098

Volume increase (decrease)		416,323			(129,932	)		(3,637	)		282,754
Price increase		1,989,824			631,233			41,727			2,662,784
Impact of hedges decrease		(313,073	)		(17,496	)		–			(330,569	)

Increase in 2008	$	2,093,074		$	483,805		$	38,090		$	2,614,969

Revenues for the six months ended June 30, 2008	$	4,726,624		$	2,233,302		$	122,141		$	7,082,067


Contribution to total year-to-date 2008 revenues		67	%		31	%		2	%		100	%
Volume increase (decrease)		125,669			2,387			(7,180	)		120,876
Price decrease		(2,693,106	)		(1,180,396	)		(72,845	)		(3,946,347	)
Impact of hedges increase		354,842			66,520			–			421,362

Decrease in 2009	$	(2,212,595	)	$	(1,111,489	)	$	(80,025	)	$	(3,404,109	)

Revenues for the six months ended June 30, 2009	$	2,514,029		$	1,121,813		$	42,116		$	3,677,958

Contribution to total 2009 year-to-date revenues		68	%		31	%		1	%		100	%

Production and Pricing


	For the Quarter Ended June 30,							For the Six Months Ended June 30,
					Increase							Increase
	2009		2008		(Decrease)			2009		2008		(Decrease)
Oil Volume – b/d:
United States		88,530		100,049		(12	)%		87,642		100,364		(13	)%
Canada		15,833		17,746		(11	)%		16,090		17,547		(8	)%

North America		104,363		117,795		(11	)%		103,732		117,911		(12	)%

Egypt		95,359		64,886		47	%		89,475		63,718		40	%
Australia		10,478		8,367		25	%		9,164		8,894		3	%
North Sea		59,688		56,570		6	%		60,089		57,670		4	%
Argentina		11,948		12,067		(1	)%		12,192		12,146		—

International		177,473		141,890		25	%		170,920		142,428		20	%


Total ⁽¹⁾		281,836		259,685		9	%		274,652		260,339		6	%


Average Oil price – Per barrel:
United States	$	57.00	$	97.64		(42	)%	$	49.95	$	90.59		(45	)%
Canada		55.17		119.16		(54	)%		46.49		106.33		(56	)%
North America		56.72		100.88		(44	)%		49.41		92.93		(47	)%
Egypt		60.30		126.20		(52	)%		51.90		112.28		(54	)%
Australia		63.01		133.79		(53	)%		49.74		116.78		(57	)%
North Sea		58.77		121.10		(51	)%		51.51		108.23		(52	)%
Argentina		46.17		50.12		(8	)%		46.73		47.61		(2	)%
International		58.99		118.14		(50	)%		51.28		105.41		(51	)%
Total ⁽²⁾		58.15		110.32		(47	)%		50.57		99.76		(49	)%

Natural Gas Volume – Mcf/d:
United States		662,834		758,524		(13	)%		637,894		751,269		(15	)%
Canada		373,796		357,828		4	%		365,551		359,289		2	%

North America		1,036,630		1,116,352		(7	)%		1,003,445		1,110,558		(10	)%

Egypt		376,737		233,793		61	%		347,443		238,385		46	%
Australia		161,069		129,531		24	%		151,607		160,355		(5	)%
North Sea		2,645		2,507		6	%		2,663		2,556		4	%
Argentina		192,542		197,284		(2	)%		192,250		181,209		6	%

International		732,993		563,115		30	%		693,963		582,505		19	%


Total ⁽³⁾		1,769,623		1,679,467		5	%		1,697,408		1,693,063		—


Average Natural Gas price – Per Mcf:
United States	$	3.88	$	10.62		(63	)%	$	4.21	$	9.50		(56	)%
Canada		3.86		9.63		(60	)%		4.26		8.59		(50	)%
North America		3.88		10.30		(62	)%		4.23		9.21		(54	)%
Egypt		3.85		6.26		(39	)%		3.73		5.72		(35	)%
Australia		1.82		2.17		(16	)%		1.71		2.14		(20	)%
North Sea		12.24		21.90		(44	)%		9.82		19.05		(48	)%
Argentina		1.89		1.39		36	%		1.94		1.60		21	%
International		2.92		3.69		(21	)%		2.82		3.51		(20	)%
Total ⁽⁴⁾		3.48		8.09		(57	)%		3.65		7.25		(50	)%

Natural Gas Liquids (NGL)
Volume – Barrels per day:
United States		5,483		7,231		(24	)%		5,198		7,236		(28	)%
Canada		2,052		1,868		10	%		2,082		2,052		1	%

North America		7,535		9,099		(17	)%		7,280		9,288		(22	)%
Argentina		3,091		2,905		6	%		3,114		2,812		11	%

Total		10,626		12,004		(11	)%		10,394		12,100		(14	)%


Average NGL Price – Per barrel:
United States	$	27.36	$	65.27		(58	)%	$	25.90	$	61.32		(58	)%
Canada		24.23		59.26		(59	)%		22.40		56.05		(60	)%
North America		26.50		64.04		(59	)%		24.90		60.15		(59	)%
Argentina		15.91		32.31		(51	)%		16.51		39.98		(59	)%
Total		23.42		56.36		(58	)%		22.39		55.46		(60	)%


⁽¹⁾		Approximately eight percent of oil production was subject to financial derivative hedges for the second quarter and six-month period of 2009; 18 percent for the 2008 second quarter and six-month period.

⁽²⁾		Reflects a per barrel increase of $.51 and $1.04 from financial derivative hedging activities for the 2009 second quarter and six-month period, respectively, and a decrease of $8.72 and $6.40 from financial derivative hedging activities for the 2008 second quarter and six-month period, respectively.

⁽³⁾		Approximately eight percent of natural gas production was subject to financial derivative hedges for the second quarter and six-month period of 2009; 20 percent and 19 percent for the 2008 second quarter and six-month period, respectively.

⁽⁴⁾		Reflects a per Mcf increase of $.24 and $.18 from financial derivative hedging activities for the 2009 second quarter and six-month period, respectively, and a decrease of $.10 and $.03 from financial derivative hedging activities for the 2008 second quarter and six-month period, respectively.

Second-Quarter 2009 compared to Second-Quarter 2008

Crude Oil Revenues Second-quarter crude oil revenues of $1.5 billion were $1.1 billion lower than the 2008 period, with gains driven by a nine percent increase in oil production more than offset by a 47 percent decrease in average realized price. Crude oil accounted for 72 percent of our oil and gas production revenues during the quarter and 48 percent of our equivalent production, compared to 68 and 47 percent, respectively, for the same period last year. While production increased in three of our six producing countries, production in North America declined from natural decline on lower levels of capital investments. North American exploration and development capital was 43 percent less than 2008.

U.S. oil revenues were $430 million less than the 2008 quarter: $370 million from lower price and $60 million from lower production. Prices in the U.S. decreased 42 percent from the year-ago period, while production declined 12 percent. Our Gulf Coast region production was down 15 percent; nine percent on natural decline and six percent from production shut-in as a result of the hurricanes in the second half of 2008. Our Central region production decreased six percent from natural decline.

Canada’s revenues decreased $113 million, with $103 million of the decline attributed to lower price realizations. Canada’s oil prices averaged $55.17 per barrel, down from $119.16 in the 2008 comparative quarter. Production declined 11 percent, primarily from natural decline.

Egypt’s crude oil revenues were $222 million less than the prior-year quarter, despite a significant increase in production. Oil price realizations were well below year-ago levels, falling 52 percent, reducing revenues by $389 million. Production growth added $167 million, relative to the 2008 period. Net production increased 47 percent while gross production was up only 27 percent. Our drilling and recompletion programs at the Khalda, Khalda Extension, East Bahariya, South Umbarka, Matruh and West Kalabsha concessions drove the gross production growth. The additional gains in net production were related to an increased allocation of gross production for cost recovery relative to the prior period, a function of lower prices and the mechanics of our production sharing contracts.

Australia’s oil revenues dropped $42 million, with the impact of lower prices offsetting a 25 percent increase in production. Oil price realizations were 53 percent lower than the 2008 quarter reducing revenues by $54 million. Production increased on restored volumes at Varanus Island, less third-party downtime, and a successful workover and recompletion program at our Stag platform. The additional production added $12 million in revenues. Repairs to the Varanus Island facility, which was damaged in a 2008 gas pipeline explosion, and installation of a compressor to expand gross compression capacity to 460 TJ/d will be completed in the third quarter and enable the facility to produce above pre-incident levels.

North Sea crude oil revenues fell $304 million on a 51 percent decline in prices, reducing revenues by $321 million. The impact of lower prices was partially offset by a six percent increase in production. Production was up on a comparative basis because of our drilling program, particularly at our Alpha platform, a successful workover program and less downtime. On June 22, 2009, we announced that our Forties Charlie 6-3 well commenced production at a gross rate of 10,500 b/d, boosting our second-quarter exit-rate to more than 70,000 gross b/d.

Argentina’s oil revenues fell $4.8 million, as the combination of lower production and lower pricing impacted the current year’s quarter. Oil realizations declined eight percent, reducing revenues by $4.3 million. Export price limitations imposed on our Argentine production limited the volatility on price realizations that we experienced in other areas. Production declined one percent as natural decline offset the impact of new wells and a successful workover program.

Natural Gas Revenues Second-quarter natural gas revenues of $560 million declined $675 million on a 57 percent decrease in realized natural gas prices. Worldwide production increased five percent to 1,770 MMcf/d. Production increased in four of our six producing countries.

U.S. natural gas revenues decreased $499 million, with a 63 percent drop realized prices and a 13 percent decrease in production reducing revenues by $465 million and $34 million, respectively. Natural gas prices averaged $3.88 per Mcf, down $6.74 per Mcf from the comparable year-ago period. Central region production was down one percent from natural decline. Gulf Coast region production was 20 percent lower, split between natural decline and production shut-in because of the 2008 hurricanes. Gulf Coast region gas production was impacted by the lower levels of capital investment as discussed under “Crude Oil Revenues” above. The wells still shut-in are awaiting repairs to third-party pipelines, the timing of which is beyond our control.

Canada’s natural gas revenues fell $182 million on a 60 percent decrease in realized natural gas prices. Gas price realizations fell $5.77 to $3.86 per Mcf, lowering revenues $188 million. Natural gas production increased four percent on improved net realizations resulting from a lower effective royalty rate, new wells and recompletion activity. Increased production added $6 million in revenues.

Egypt’s natural gas revenues were essentially flat compared to the 2008 second quarter, with $50 million of additional revenues attributed to production gains offsetting the $51 million reduction related to a 39 percent price decline. Net production was up 61 percent, while gross production rose only 33 percent. The increase in gross production followed the completion of two new Salam Base gas trains and the Northern Pipeline compression project, which increased transportation and processing capacity. The additional net production was primarily related to an increased allocation of gross production for cost recovery relative to the prior period, a function of lower prices and the mechanics of our production sharing contracts.

Australia’s natural gas revenues were flat to the prior-year period, with the impact of a 24 percent increase in production offsetting a 16 percent decrease in price. Prices were down mostly on foreign currency fluctuations. Production was up primarily because of repairs to the Varanus Island facility, which was damaged in a 2008 gas pipeline explosion. These repairs and installation of a compressor to expand gross compression capacity to 460 TJ/d will be completed in the third quarter and enable the facility to produce above pre-incident levels.

Argentina’s gas revenues increased $8 million as higher prices offset the impact of slightly lower production. Natural gas realizations averaged $1.89, up $.50 per Mcf from last year’s second quarter as we delivered more of our gas into higher-priced contracts. The increase in price added $9 million in revenues. Production declined two percent because of sales pipeline constraints.

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

Crude Oil Revenues Crude oil revenues for the six-month period of 2009 totaled $2.5 billion and were $2.2 billion lower than the 2008 period because of a 49 percent decrease in average realized price. Crude oil for the six-month period accounted for 68 percent of our oil and gas revenues and 48 percent of our equivalent production, compared to 67 and 47 percent, respectively, for the same period last year. Production increased five percent, to 274,652 b/d, as a 20 percent increase in production from our international regions more than offset a 12 percent decline in our North America production. Production declines in North America stem from our reduction in exploration and development capital, which was 43 percent below year-ago levels. Worldwide, our exploration and development capital investments for the first half of the year decreased 33 percent from the same period in 2008.

U.S. oil revenues declined $862 million on a 45 percent decrease in realized crude oil prices and a 13 percent decrease in production. The impact from price and production was $742 million and $120 million, respectively. Gulf Coast region production was down 18 percent, two-thirds of which was driven by natural decline which offset drilling and recompletion activities. The remainder was associated with production that has not yet been restored after the hurricanes in the second half of 2008. Production from our Central region decreased four percent from natural decline and lower drilling activities.

Canada’s revenues decreased $204 million, $191 million of which was related to lower price realizations. Canada’s oil prices averaged $46.49 per barrel, down from $106.33 in the comparative period. Production declined eight percent, with the impact of natural decline, increases in provincial royalties and property divestitures more than offsetting a reduction in drilling activities.

Egypt’s oil revenues fell $462 million compared to last year’s six-month period, despite an increase in production. Oil realizations fell 54 percent reducing revenues by $700 million. Net production was 40 percent higher, while gross production increased only 24 percent. The increase in gross production came from new wells and successful recompletions, notably from our East Bahariya Extension, South Umbarka and Matruh concessions. Additional gains in net production resulted from a higher allocation of gross production for cost recovery relative to the prior period, a function of lower prices and the mechanics of our production sharing contracts.

Australia’s oil revenues were $107 million lower than the comparable period despite a three percent increase in production. Prices, which were 57 percent lower than the prior year, reduced revenues by $109 million. Production rose on less weather-related and third-party downtime, as well as restored production volumes from Varanus Island.

North Sea crude oil revenues fell $576 million from year-ago levels, with a 52 percent drop in realized prices reducing revenues by $595 million. Production rose 2,419 b/d driven by our drilling program, a successful workover program and less downtime.

Argentina’s oil revenues were down $2 million on lower prices. Oil realizations fell two percent to $46.73 per barrel. Export price limitations imposed on our Argentine production limited the volatility on realized prices that we experienced in other jurisdictions. Production rose marginally from last year’s levels as new wells brought online offset production lost from natural decline.

Natural Gas Revenues Natural gas revenues for the six-month period of 2009 totaled $1.1 billion, half of the comparable 2008 revenues. The decline reflects a 50 percent decrease in realized natural gas prices. Production was flat period-over-period as a 10 percent decline in North America production was offset by increased gas production internationally.

U.S. natural gas revenues decreased $813 million on a 56 percent decline in realized prices and a 15 percent decrease in production. Natural gas prices averaged $4.21 per Mcf, down $5.29 per Mcf from the comparable year-ago period, decreasing revenues by $723 million. In our Central region, production was held flat, with drilling activities and strategic acquisitions offsetting natural decline. In the Gulf Coast region, production was 25 percent lower, split between natural decline and production shut-in from the 2008 hurricanes. The wells still shut-in are awaiting repairs to damaged third-party pipelines, the timing of which is beyond our control.

Canada’s natural gas revenues fell $280 million on a 50 percent decrease in realized natural gas prices. Gas price realizations fell $4.33 to $4.26 per Mcf. Natural gas production increased two percent on improved net realizations resulting from a lower effective royalty rate, in addition to new wells and recompletion activity, relative to the prior-year period.

Egypt’s natural gas revenues fell $13 million. Increased net production did not fully offset the impact of a 35 percent decrease in realized price, which lowered revenues $86 million. Production gains increased revenues $73 million. Net production was up 46 percent, while gross production rose only 22 percent. The increase in gross production followed the completion of two new Salam Base gas trains and the Northern Pipeline compression project, which increased transportation and processing capacity. The additional net production was primarily related to an increased allocation of gross production for cost recovery relative to the prior period, a function of lower prices and the mechanics of our production sharing contracts.

Australia reported a $16 million dollar decrease in natural gas revenues compared to last year’s six-month period. Lower realized prices and production reduced revenues $13 million and $3 million, respectively. Realized prices fell 20 percent, mostly on foreign currency fluctuations. Production was five percent lower on the impact of a June 2008 pipeline explosion and fire at the Varanus Island facility, which shut-in production from our John Brooke’s field and Harriet Joint Venture. Repairs to the Varanus Island facility and installation of a compressor to expand gross compression capacity to 460 TJ/d will be completed in the third quarter and enable the facility to produce above pre-incident levels.

Argentina’s natural gas revenues rose $15 million on increases in both prices and production. Production increased six percent from new wells and recompletions in the Neuquén basin, which more than offset the impact of natural decline and increased re-injections at Tierra del Fuego. Prices averaged $1.94 per Mcf, 21 percent higher than the prior-year period on a more favorable sales mix achieved by delivering more of our gas into higher-priced contracts.

Costs

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.


	For the Quarter Ended June 30,								For the Six Months Ended June 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	$	527	$	591	$	9.86	$	11.77	$	1,063	$	1,174	$	10.34	$	11.63
Additional		–		–		–		–		2,818		–		27.41		–
Other assets		46		37		.87		.74		91		74		.89		.73

Total DD&A		573		628		10.73		12.51		3,972		1,248		38.64		12.36
Asset retirement obligation accretion		27		25		.50		.51		53		52		.52		.52
Lease operating costs		405		447		7.58		8.90		803		902		7.81		8.93
Gathering and transportation costs		34		40		.62		.79		67		81		.65		.80
Taxes other than income		116		298		2.17		5.95		203		541		1.98		5.36
General and administrative expense		91		79		1.70		1.57		176		161		1.71		1.60
Financing costs, net		61		39		1.14		.78		120		83		1.16		.83

Total	$	1,307	$	1,556	$	24.44	$	31.01	$	5,394	$	3,068	$	52.47	$	30.40

Second-Quarter 2009 compared to Second-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 second quarters of 2009 and 2008:


	Recurring DD&A
	(In millions)
2008 DD&A	$	591
Volume change		11
Rate change		(75	)


2009 DD&A	$	527

Recurring full-cost DD&A expense of $527 million decreased $64 million on an absolute dollar basis: $75 million lower on rate offset by an increase of $11 million from higher production. The Company’s full-cost DD&A rate decreased $1.91 to $9.86 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 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.

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.

Lease Operating Expenses (LOE) Our 2009 second-quarter LOE decreased nine percent on an absolute dollar basis. On a per unit basis, LOE was down 15 percent when compared to the same period in 2008: nine percent on lower cost and six percent on higher production.

Our LOE rate, which decreased $1.32 per boe, was impacted by the items below:

	•		A stronger U.S. dollar relative to the prior-year quarter resulted in a $.56 reduction.

	•		Reduced workover costs in all regions, particularly on Permian Basin oil properties, resulted in a reduction of $.53.

	•		Higher production reduced the rate by $.49.

	•		A reduction in power usage and declining rates per kilowatt hour in the U.S. Central Region and Canada, lowered the rate by $.28.

	•		Hurricane repair costs in the U.S. added $.33 to the rate.

	•		The prior period includes a non-recurring LOE credit related to a reduction in our accrual for an insurance contingency assessed by Oil Insurance Limited (OIL) should Apache withdraw from the insurance pool. This credit in the second quarter of 2008 accounted for $.21 of the increase in rate.

Gathering and Transportation Gathering and transportation costs totaled $34 million in the second quarter of 2009, down $6 million. On a per unit basis, gathering and transportation costs were down 21 percent: 15 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 Quarter Ended
	June 30,
	2009		2008
	(In millions)
U.S.	$	8	$	11
Canada		13		16
North Sea		6		7
Egypt		6		5
Argentina		1		1


Total Gathering and Transportation	$	34	$	40

The decrease in Canada resulted primarily from the impact of foreign exchange rates, lower oil production and decreased gas transportation rates. The decrease in the U.S. resulted primarily from lower volumes transported under contracts where costs are paid directly to a third party.

Taxes other than Income Taxes other than income totaled $116 million, a decrease of $182 million. On a per unit basis, taxes other than income decreased 64 percent: 58 percent on lower costs and six percent on higher total production. A detail of these taxes follows:


	For the Quarter Ended
	June 30,
	2009		2008
	(In millions)
U.K. PRT	$	73	$	220
Severance taxes		18		47
Ad valorem taxes		13		17
Canadian taxes		4		4
Other		8		10


Total Taxes other than Income	$	116	$	298

North Sea Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $147 million less than the 2008 period on a 49 percent decrease in net profits, driven by 50 percent 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 assessed on U.S. and Canadian assessed property values. The $4 million decrease resulted from lower taxable valuations associated with decreases in oil and natural gas prices.

General and Administrative Expenses General and administrative expenses (G&A) were $12 million higher, up $.13 to an average of $1.70 per boe. Non-recurring employee separation costs incurred in the second quarter of 2009 added $.28 to the rate relative to 2008. Higher stock-based compensation expense, which includes stock appreciation rights (SARs) expense, added $.03 to the second-quarter 2009 rate as compared to 2008. These costs were partially offset by the impact of production gains (-$.11 per boe) and various other miscellaneous corporate expense reductions (-$.07 per boe).

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


	For the Quarter Ended
	June 30,
	2009			2008
	(In thousands)
Interest expense	$	77,363		$	66,328
Amortization of deferred loan costs		1,365			829
Capitalized interest		(14,972	)		(22,810	)
Interest income		(2,601	)		(5,297	)

Financing costs, net	$	61,155		$	39,050

Net financing costs rose $22 million, or $.37 per boe. The increase in absolute dollars is the result of an $11 million increase in interest expense related to higher average outstanding debt balances, $8 million reduction in capitalized interest related to lower unproved property balances and completion of long-term construction projects, and a $3 million decrease in interest income. Higher production mitigated the impact of higher absolute costs on the rate per boe.

The provision for income taxes decreased $557 million to $342 million, 62 percent below prior year, as income before taxes fell on lower oil and gas production revenues. The effective income tax rate in the second quarter of 2009 was 43.5 percent compared to 38.3 percent in the second quarter of 2008. The 2009 rate was higher on a $31 million non-cash deferred tax expense related to the effect of the weakening U.S. dollar on re-measurement of our foreign deferred tax liabilities. The foreign exchange impact on second-quarter 2008 income taxes was minimal.

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 six-month periods of 2009 and 2008:


	Recurring DD&A
	(In millions)
2008 DD&A	$	1,174
Volume change		(24	)
Rate change		(87	)


2009 DD&A	$	1,063

Recurring full-cost DD&A expense of $1.06 billion decreased $111 million on an absolute dollar basis: $87 million lower on rate and $24 million from production mix, despite an increase in total production. A higher percentage of production was contributed from regions with lower DD&A rates. The Company’s full-cost DD&A rate decreased $1.29 to $10.34 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.

Lease Operating Expenses (LOE) Our first six months of 2009 LOE decreased 11 percent on an absolute dollar basis. On a per unit basis, LOE was down 13 percent; 11 percent on lower costs and two percent on higher production.

Our LOE rate, which decreased $1.12 per boe, was impacted by the items below:

	•		A stronger U.S. dollar relative to the first six months of 2008 resulted in a $.64 reduction.

	•		Reduced workover costs in all regions, particularly on Permian Basin oil properties, resulted in a reduction of $.47.

	•		Higher production reduced the rate by $.38.

	•		Lower labor and service costs reduced the rate by $.21.

	•		A reduction in power usage and declining rates per kilowatt hour in the U.S. Central Region and Canada lowered the rate by $.16.

	•		Repair costs and shut-in production related to the 2008 Gulf of Mexico hurricanes added $.55 to the rate.

	•		General cost increases in various other categories increased the rate by $.19.

Gathering and Transportation Gathering and transportation costs totaled $67 million in the first six months of 2009, down $14 million. On a per unit basis, gathering and transportation costs were down 19 percent: 17 percent on lower costs and two 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 Six Months Ended
	June 30,
	2009		2008
	(In millions)
U.S.	$	16	$	21
Canada		24		34
North Sea		13		15
Egypt		12		9
Argentina		2		2


Total Gathering and Transportation	$	67	$	81

The decrease in the U.S resulted primarily from a decrease in volumes transported under contracts where charges are paid directly to a third party. 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. Egypt costs were up $3 million on an increase in exported cargoes.

Taxes other than Income Taxes other than income totaled $203 million, a decrease of $338 million. On a per unit basis, taxes other than income decreased 63 percent: 61 percent on lower costs and two percent on higher total production. A detail of these taxes follows:


	For the Six Months Ended
	June 30,
	2009		2008
	(In millions)
U.K. PRT	$	123	$	385
Severance taxes		35		93
Ad valorem taxes		21		39
Canadian taxes		8		8
Other		16		16


Total Taxes other than Income	$	203	$	541

North Sea PRT is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $262 million less than the 2008 period on a 51 percent decrease in net profits driven by a 52 percent decrease in 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 the lower realized oil and natural gas prices.

Ad valorem taxes are assessed on U.S. and Canadian assessed property values. The $18 million decrease resulted from lower taxable valuations associated with decreases in oil and natural gas prices.

General and Administrative Expenses General and administrative expenses (G&A) were $15 million higher, up $.11 to an average of $1.71 per boe. Expenses recognized pursuant to the retirement of our founder and former chairman and separation costs related to staff reductions added $.37 to the 2009 rate. These non-recurring costs were partially offset by lower incentive compensation (-$.14), stock-based compensation, which includes SARs expense (-$.03), lower fringe benefit cost (-$.06) and the impact of higher production (-$.03). SARs expense was down as a result of a four percent decline in Apache’s stock price during the first six months of 2009 compared to a 46 percent increase in the comparative 2008 period.

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


	For the Six Months Ended
	June 30,
	2009			2008
	(In thousands)
Interest expense	$	156,277		$	135,635
Amortization of deferred loan costs		2,773			1,680
Capitalized interest		(30,981	)		(44,387	)
Interest income		(8,327	)		(9,625	)

Financing costs, net	$	119,742		$	83,303

Net financing costs rose $36 million, or $.34 per boe. The increase in absolute dollars is primarily the result of a $21 million increase in interest expense related to higher average outstanding debt balances and a $13 million reduction in capitalized interest related to lower unproved property balances and completion of long-term construction projects. Higher production mitigated the impact of higher absolute costs on the rate per boe.

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. No significant discrete tax events occurred during the second quarter of 2009.

The provision for income taxes for the first six months of 2009 was a benefit of $354 million compared to an expense of $1.55 billion in the 2008 period. The benefit was associated with the non-cash write-down of the carrying value of our proved oil and gas properties previously discussed. The effective income tax rate, impacted by the magnitude of the tax benefit related to the write-down, was 21.3 percent compared to 38.6 percent in 2008. We recorded a $26 million increase to tax expense in 2009 related to foreign currency fluctuations, compared to a $13 million benefit in 2008.

CAPITAL RESOURCES AND LIQUIDITY

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.

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 continuously required 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 having capital resources available, the success of our exploration and development activities and on acquiring additional reserves.

We fund our exploration and development activities primarily through net cash provided by operating activities (“operating cash flows” or “cash flows”) and budget our capital expenditures based on projected cash flows. Our long-term operating cash flows are dependent on commodity prices, reserve replacement and the level of costs required for ongoing operations. Our operating cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices (see “Commodity Price” below). Sales volumes and costs have also impacted cash flows in the short-term, but have not been as volatile as commodity prices.

While cash flows are our primary source of liquidity, 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.

The ongoing disruption in the credit markets has had a significant adverse impact on a number of financial institutions. We regularly review the credit worthiness of the banks and financial institutions with which we do business. Thus far, our financial position and sources of liquidity have not been materially impacted. However, further deterioration in the credit markets could adversely affect the availability of external sources of short-term and long-term capital funding.

See Part II, Other Information, Item 1A, “Risk Factors” of this Form 10-Q and Part 1, Item 1 and 2, Business and Properties, “Risk Factors Related to Our Business and Operations,” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Commodity Prices

Crude oil trades in a global market; consequently, prices for all types and grades of crude oil have historically moved in the same general direction. Natural gas has a limited global transportation system and, therefore, is currently subject to local supply and demand conditions. Approximately 60 percent of our natural gas is sold in the North American market, which tracks New York Mercantile Exchange (NYMEX) prices, while our remaining international gas is not subject to fluctuating daily gas spot markets.

Our average natural gas price realizations have been on a downward trend since peaking in July 2008, reaching a multi-year low of $3.38 per Mcf in April 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 $68.76 in June 2009. Second-quarter 2009 average realized prices were substantially lower than 2008 second-quarter prices. Average realized prices for natural gas and crude oil in the first six months of 2009 were $3.65 per Mcf and $50.57 per barrel, respectively, substantially below the $7.25 per Mcf and $99.76 per barrel realized in the year-earlier period.

Following is a table of published monthly average NYMEX prices in the first half of 2009 and 2008:


	2009
	June		May		April		March		February		January
Crude Oil (per bbl)	$	69.72	$	59.51	$	50.48	$	48.25	$	39.47	$	41.99

Natural Gas (per Mcf)	$	3.53	$	3.29	$	3.97	$	4.13	$	4.49	$	5.96


	2008
	June		May		April		March		February		January
Crude Oil (per bbl)	$	134.65	$	125.67	$	112.62	$	105.15	$	94.92	$	92.96

Natural Gas (per Mcf)	$	11.86	$	11.01	$	9.52	$	9.11	$	8.03	$	7.08

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. Given the recent commodity price levels, our expenditures for the second quarter and first six months of 2009 were substantially lower than 2008 levels. We continue to monitor prices and will adjust our capital budgets accordingly. Any price deterioration will negatively impact our future oil and gas production revenues, earnings, cash flows and liquidity.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the periods presented.


	For the Six Months Ended
	June 30,
	2009			2008
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	1,367		$	3,738
Sale of short-term investments		792			—
Sales of property and equipment		—			300
Net commercial paper and bank loan borrowings		148			—
Restricted cash		14			—
Common stock issuances		10			29
Other		12			45

		2,343			4,112

Uses of Cash and Cash Equivalents:
Capital expenditures⁽¹⁾	$	2,464		$	2,789
Payments on fixed-rate notes		100			—
Dividends		103			136
Restricted cash		—			94
Net commercial paper and bank loan repayments		—			183
Other		86			27

		2,753			3,229


Increase (decrease) in cash and cash equivalents	$	(410	)	$	883


⁽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 Net cash provided by operating activities is our primary source of capital and liquidity. 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.

Operating cash flows totaled $1.4 billion for the first six months of the year, down $2.4 billion from the comparable 2008 period. The primary driver of the reduction was a $3.4 billion decrease in oil and gas revenues, with the impact of lower commodity prices (oil and gas realizations declined 49 percent and 50 percent, respectively) more than offsetting a two percent increase in equivalent production. Also negatively impacting operating cash flows was a $449 million net decrease in working capital. These items were partially offset by the positive impact of a $399 million decline in cash based expenses (expenses excluding non-cash expenses described above) and lower current taxes, which decreased $969 million.

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 Item 1, Financial Statements of this Form 10-Q.

Short-term Investments We occasionally invest in highly-liquid, short-term investments in order to maximize our income on available cash balances. As needed, we may reduce such short-term investment balances 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 June 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. During the year, the amount outstanding under that facility increased $145 million, to $245 million.

Capital Expenditures As a result of the global economic slowdown and decline in oil and gas prices, we substantially reduced our 2009 capital budget to approximately half of 2008 spending in an effort to keep expenditures in line with our cash flows. Capital spending for the first half of the year is in line with our Plan. As is our custom, we will review and revise our capital expenditure estimates throughout the year based on changing industry conditions and results-to-date.

Capital expenditures totaled $2.3 billion for the first six months of 2009, $944 million lower than the first half of 2008. The following table presents a summary of the Company’s capital expenditures for the six months ended June 30, 2009 and 2008:


	For the Six Months
	Ended
	June 30,
	2009		2008
	(In millions)
Exploration and Development Costs:
United States	$	569	$	1,005
Canada		210		353

North America		779		1,358

Egypt		389		413
Australia		285		453
North Sea		216		255
Argentina		82		146
Chile		4		4

International		976		1,271

Worldwide Exploration and Development Costs		1,755		2,629

Gathering Transmission and Processing Facilities:
Canada		56		10
Egypt		95		218
Australia		13		5
Argentina		1		3

Total Gathering Transmission and Processing Facility Cost		165		236


Asset Retirement Costs		88		172

Capitalized Interest		31		44


Capital Expenditures, excluding acquisitions		2,039		3,081


Acquisitions – Oil and Gas Properties		249		151


Total Capital Expenditures	$	2,288	$	3,232

Worldwide exploration and development (E&D) expenditures were down 33 percent from the same period last year, with decreases in all six countries in which we have exploration and production interests. The most significant decrease in spending occurred in North America, where E&D investments declined 43 percent on lower activity. Decreased drilling activity in the Western Desert drove Egypt’s E&D spending $24 million lower than the prior-year period. However, Egypt’s percentage of worldwide E&D spending rose to 22 percent, up from 16 percent, as this decline was less pronounced than in other regions. Australia’s E&D expenditures decreased nearly 37 percent on lower drilling activity and reduced investments in platforms and production facilities. North Sea E&D expenditures were $39 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 of $100 million paid during the first six months of 2009 were $33 million less than in 2008. The 2008 common stock dividends included a special cash dividend of 10 cents per common share paid on March 18, 2008. During the first six months of 2009 and 2008, Apache paid $2.8 million in dividends on its Series B Preferred Stock issued in August 1998.

Liquidity

The following table presents a summary of our key financial indicators at June 30, 2009 and December 31, 2008:


	June 30,			December 31,
	2009			2008
	(In millions of dollars, except as indicated)
Cash	$	772		$	1,181
Short-term investments		—			792
Restricted cash		—			14
Total debt		4,967			4,922
Shareholders’ equity		14,959	⁽²⁾		16,509	⁽¹⁾
Available committed borrowing capacity		2,405			2,550
Floating-rate debt/total debt		5	%		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 June 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 $772 million in cash and cash equivalents at June 30, 2009, compared to $1.2 billion at December 31, 2008. At June 30, 2009, $415 million of cash was held by foreign subsidiaries and $357 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 in order to maximize our income on available cash balances. At June 30, 2009, we held no short-term investments.

Debt At June 30, 2009, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $4.97 billion. Current debt includes $12 million borrowed under uncommitted overdraft lines in Argentina.

Available committed borrowing capacity We ended the quarter with $2.4 billion of available committed borrowing capacity, as discussed below.

As of June 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. As of June 30, 2009, there was $245 million outstanding under the facility, allowing for additional available borrowing capacity of $105 million.

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

Percent of total debt to capitalization The Company’s June 30, 2009, debt-to-capitalization ratio was 25 percent, up from 23 percent at December 31, 2008.

Credit Rating As of June 30, 2009, we have maintained our single-A credit ratings. We cannot predict, nor can we assure, that we will not receive a ratings downgrade in the future.

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 first six months of 2009, approximately eight percent of our natural gas and crude oil production was subject to financial derivative hedges.

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 June 30, 2009, the Company had open natural gas derivative hedges in an asset position with a fair value of $60 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $33 million, while a 10 percent decrease in prices would increase the fair value by approximately $36 million. The Company also had open oil derivatives in a liability position with a fair value of $153 million. A 10 percent increase in oil prices would increase the liability by approximately $170 million, while a 10 percent decrease in prices would move the derivatives to an asset position of $11 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2009. See Note 2 – Derivative Instruments and Hedging Activities in Item 1 of this Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 95 percent of the Company’s debt. At June 30, 2009, total debt included $257 million of floating-rate debt. As a result, Apache’s annual interest costs in 2009 will fluctuate based on short-term interest rates on what is approximately five percent of our total debt outstanding at June 30, 2009. The impact on cash flow of a 10 percent change in the floating interest rate from that at June 30, 2009, would be approximately $144,000 per quarter.

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 Item 1 of this quarterly report.

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 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.

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 June 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.

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 and June 30, 2009, for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

			During the quarter ending June 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:

			*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 greenhouse gases than permitted to acquire emission allowances from other businesses that emit greenhouse gases 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.

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

			The Company’s annual meeting of stockholders was held in Houston, Texas, at 10:00 a.m. local time, on Thursday, May 7, 2009. Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934.

			Out of a total of 335,174,637 shares of the Company’s common stock outstanding and entitled to vote, 290,759,619 shares were present at the meeting in person or by proxy, representing 86.75 percent of the shares entitled to vote. Matters voted upon at the meeting were as follows:

We received stockholder votes for the election of four directors of Apache, each to serve until Apache’s annual meeting in 2012, or until their successors are duly elected. We counted and tabulated all votes and determined the results of the votes as follows:


Nominee	For		Against		Abstain
Frederick M. Bohen		263,940,934		26,394,545		424,140
George D. Lawrence		264,008,005		26,334,486		417,128
Rodman D. Patton		282,665,960		7,762,956		330,703
Charles J. Pitman		275,517,526		14,918,628		323,465

The name of each director whose term of office as a director continued after the meeting is listed below:


	G. Steven Farris		Randolph M. Ferlic
	Eugene C. Fiedorek		A. D. Frazier, Jr.
	Patricia Albjerg Graham		John A. Kocur
	F. H. Merelli

ITEM 5. OTHER INFORMATION

On August 6, 2009, the Board of Directors of Apache Corporation (“Apache”) amended Sections 4 and 5 of Article IV and Section 4 of Article XI of Apache’s bylaws, in compliance with applicable law, to delete all references to “50 days” therein and replace such text with “60 days”, which extends the period between the record date for stockholders’ meetings and the associated meeting date to 60 days (from 50 days). This description is qualified in its entirety by reference to the full text of Apache’s bylaws, as amended August 6, 2009, which is listed under Item 6 as Exhibit 3.1 and incorporated herein by reference.

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 Apache Corporation, as amended August 6, 2009.

		*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 Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statement of Income, (ii) Consolidated Balance Sheet, (iii) Consolidated Statement of Cash Flows, (iv) Consolidated Statement of Equity, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.


*		Filed herewith

**		Furnished herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	APACHE CORPORATION
Dated: August 7, 2009	/s/ ROGER B. PLANK
	Roger B. Plank
	President (Principal Financial Officer)


Dated: August 7, 2009	/s/ REBECCA A. HOYT
	Rebecca A. Hoyt
	Vice President and Controller (Principal Accounting Officer)