APA 10-Q Quarterly Report Sept. 30, 2010

APACHE CORP

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10-Q 1 h76481e10vq.htm FORM 10-Q 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 September 30, 2010


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

For the transition period from to

Commission File Number 1-4300

APACHE CORPORATION

(exact name of registrant as specified in its charter)


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

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

Registrant’s Telephone Number, Including Area Code: ( 713) 296-6000

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

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

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


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

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

Number of shares of registrant’s common stock outstanding as of October 31, 2010...................364,591,339

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. [REMOVED AND RESERVED]
	ITEM 5. OTHER INFORMATION
	ITEM 6. EXHIBITS
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION


		ITEM 1 — FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)


	For the Quarter					For the Nine Months
	Ended September 30,					Ended September 30,
	2010			2009		2010			2009
	(In thousands, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,046,445		$	2,325,705	$	8,708,835		$	6,003,663
Other		(33,786	)		6,726		(51,015	)		55,971


		3,012,659			2,332,431		8,657,820			6,059,634


OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		786,237			625,898		2,154,486			1,779,874
Additional		—			—		—			2,818,161
Asset retirement obligation accretion		24,783			26,053		73,545			79,274
Lease operating expenses		506,556			445,535		1,392,751			1,248,297
Gathering and transportation		42,840			36,232		126,243			103,050
Taxes other than income		158,627			183,931		522,398			387,211
General and administrative		96,908			82,492		275,887			258,443
Financing costs, net		59,350			61,684		174,374			181,426


		1,675,301			1,461,825		4,719,684			6,855,736


INCOME (LOSS) BEFORE INCOME TAXES		1,337,358			870,606		3,938,136			(796,102	)
Current income tax provision		206,709			262,430		888,834			483,171
Deferred income tax provision (benefit)		352,384			166,160		705,833			(409,069	)


NET INCOME (LOSS)		778,265			442,016		2,343,469			(870,204	)
Preferred stock dividends		13,276			1,420		13,276			4,260


INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	764,989		$	440,596	$	2,330,193		$	(874,464	)


NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	2.14		$	1.31	$	6.78		$	(2.61	)

Diluted	$	2.12		$	1.30	$	6.72		$	(2.61	)

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 Nine Months
	Ended September 30,
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	2,343,469		$	(870,204	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		2,154,486			4,598,035
Asset retirement obligation accretion		73,545			79,274
Provision for (benefit from) deferred income taxes		705,833			(409,069	)
Other		109,928			140,527
Changes in operating assets and liabilities:
Receivables		(207,073	)		(228,095	)
Inventories		(21,066	)		11,897
Drilling advances		13,989			(49,569	)
Deferred charges and other		(137,055	)		868
Accounts payable		138,853			(183,884	)
Accrued expenses		(351,431	)		(351,153	)
Deferred credits and noncurrent liabilities		(23,284	)		(59,156	)


NET CASH PROVIDED BY OPERATING ACTIVITIES		4,800,194			2,679,471


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,040,609	)		(2,761,327	)
Additions to gas gathering, transmission and processing facilities		(328,223	)		(203,783	)
Acquisition of Marathon properties		—			(181,133	)
Acquisition of Devon properties		(1,017,718	)		—
Acquisition of BP properties and facilities		(2,472,339	)		—
Acquisitions — other		(60,239	)		(77,210	)
Short-term investments		—			791,999
Deposit related to acquisition of BP properties		(3,500,000	)		—
Restricted cash		—			13,880
Other, net		(36,767	)		(98,096	)


NET CASH USED IN INVESTING ACTIVITIES		(10,455,895	)		(2,515,670	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(37,426	)		230,176
Fixed-rate debt borrowings		1,484,040			—
Payments on fixed-rate notes		—			(100,000	)
Proceeds from issuance of common stock		2,257,772			—
Proceeds from issuance of mandatory convertible preferred stock		1,227,050			—
Dividends paid		(151,735	)		(155,125	)
Common stock activity, net		28,478			19,028
Treasury stock activity, net		4,190			5,344
Cost of debt and equity transactions		(16,617	)		(618	)
Other		23,271			13,308


NET CASH PROVIDED BY FINANCING ACTIVITIES		4,819,023			12,113


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(836,678	)		175,914

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		2,048,117			1,181,450


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,211,439		$	1,357,364


SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	176,104		$	199,570
Income taxes paid, net of refunds		968,897			461,024

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

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)


	September 30,			December 31,
	2010			2009
	(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,211,439		$	2,048,117
Receivables, net of allowance		1,756,874			1,545,699
Inventories		528,725			533,251
Drilling advances		213,195			230,733
Derivative instruments		218,119			13,218
Prepaid taxes		254,242			146,653
Prepaid assets and other		67,866			68,178


		4,250,460			4,585,849


PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		50,097,256			44,267,037
Unproved properties and properties under development, not being amortized		2,791,504			1,479,008
Gas gathering, transmission and processing facilities		3,592,400			3,189,177
Other		543,851			492,511


		57,025,011			49,427,733
Less: Accumulated depreciation, depletion and amortization		(28,678,895	)		(26,527,118	)


		28,346,116			22,900,615

OTHER ASSETS:

Goodwill, net		189,252			189,252
Deposit related to acquisition of BP properties		3,500,000			—
Deferred charges and other		642,521			510,027


	$	36,928,349		$	28,185,743

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

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)


	September 30,			December 31,
	2010			2009
	(In thousands, except per share data)
LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	598,037		$	396,564
Accrued operating expense		101,881			90,151
Accrued exploration and development		1,028,134			923,084
Accrued compensation and benefits		125,168			151,408
Current debt		135,369			117,326
Asset retirement obligation		153,298			146,654
Derivative instruments		58,956			128,219
Other		325,887			439,152

		2,526,730			2,392,558


LONG-TERM DEBT		6,380,579			4,950,390


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		3,581,675			2,764,901
Asset retirement obligation		1,948,718			1,637,357
Other		545,265			661,916


		6,075,658			5,064,174


COMMITMENTS AND CONTINGENCIES (Note 9)

SHAREHOLDERS’ EQUITY:
Preferred stock, no par value, 5,000,000 shares authorized, 6% Cumulative Mandatory Convertible, Series D, $1,000 per share liquidation preference, 1,265,000 shares issued and outstanding		1,227,050			—
Common stock, $0.625 par, 430,000,000 shares authorized, 365,885,145 and 344,076,790 shares issued, respectively		228,678			215,048
Paid-in capital		6,870,445			4,634,326
Retained earnings		13,610,838			11,436,580
Treasury stock, at cost, 1,460,329 and 7,639,818 shares, respectively		(41,457	)		(216,831	)
Accumulated other comprehensive income (loss)		49,828			(290,502	)


		21,945,382			15,778,621


	$	36,928,349		$	28,185,743

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 D		Series B													Other			Total
	Comprehensive			Preferred		Preferred		Common		Paid-In			Retained			Treasury			Comprehensive			Shareholders’
	Income (Loss)			Stock		Stock		Stock		Capital			Earnings			Stock			Income (Loss)			Equity
	(In thousands)
BALANCE AT DECEMBER 31, 2008				$	—	$	98,387	$	214,221	$	4,472,826		$	11,929,827		$	(228,304	)	$	21,764		$	16,508,721
Comprehensive loss:
Net loss	$	(870,204	)		—		—		—		—			(870,204	)		—			—			(870,204	)
Commodity hedges, net of income tax benefit of $124,671		(228,470	)		—		—		—		—			—			—			(228,470	)		(228,470	)

Comprehensive loss	$	(1,098,674	)

Dividends:
Preferred					—		—		—		—			(4,260	)		—			—			(4,260	)
Common ($.45 per share)					—		—		—		—			(151,040	)		—			—			(151,040	)
Common stock activity, net					—		—		721		3,778			—			—			—			4,499
Treasury stock activity, net					—		—		—		(5,706	)		—			8,832			—			3,126
Compensation expense					—		—		—		95,731			—			—			—			95,731
Other					—		—		—		(2,781	)		—			—			—			(2,781	)


BALANCE AT SEPTEMBER 30, 2009				$	—	$	98,387	$	214,942	$	4,563,848		$	10,904,323		$	(219,472	)	$	(206,706	)	$	15,355,322


BALANCE AT DECEMBER 31, 2009				$	—	$	—	$	215,048	$	4,634,326		$	11,436,580		$	(216,831	)	$	(290,502	)	$	15,778,621
Comprehensive income:
Net income	$	2,343,469			—		—		—		—			2,343,469			—			—			2,343,469
Commodity hedges, net of income tax expense of $152,101		340,330			—		—		—		—			—			—			340,330			340,330

Comprehensive income	$	2,683,799

Dividends:
Preferred					—		—		—		—			(13,276	)		—			—			(13,276	)
Common ($.45 per share)					—		—		—		—			(155,936	)		—			—			(155,936	)
Mandatory convertible preferred stock issued					1,227,050		—		—		—			—			—			—			1,227,050
Common stock issuance					—		—		12,781		2,074,711			—			170,280			—			2,257,772
Common stock activity, net					—		—		849		18,053			—			—			—			18,902
Treasury stock activity, net					—		—		—		700			—			5,094			—			5,794
Compensation expense					—		—		—		142,652			—			—			—			142,652
Other					—		—		—		3			1			—			—			4


BALANCE AT SEPTEMBER 30, 2010				$	1,227,050	$	—	$	228,678	$	6,870,445		$	13,610,838		$	(41,457	)	$	49,828		$	21,945,382

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

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

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

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2010, Apache’s significant accounting policies are consistent with those discussed in Note 1 of its consolidated financial statements contained in the Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Use of Estimates

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

2. ACQUISITIONS

Kitimat LNG Terminal

During the first quarter of 2010 Apache’s wholly-owned subsidiary, Apache Canada Ltd., entered into an agreement with Galveston LNG, Inc. and its wholly-owned subsidiary to acquire a 51–percent interest in Kitimat LNG Inc.’s planned liquefied natural gas (LNG) export terminal (Kitimat LNG terminal) and a 25.5-percent interest in a related proposed pipeline. The Kitimat LNG terminal is to be to be located at Bish Cove near the Port of Kitimat, north of Vancouver, British Columbia. Gross throughput capacity is estimated to be approximately 700 million cubic feet of natural gas per day (MMcf/d), or five million metric tons of LNG per year, of which Apache has reserved 51 percent. The proposed 300-mile pipeline will originate in Summit Lake, British Columbia, and is designed to link the Kitimat LNG terminal to the pipeline system currently servicing western Canada’s natural gas producing regions. Apache will have rights to 350 MMcf/d of the capacity in the proposed pipeline. The project has the potential to open new markets in the Asia-Pacific region for gas from Apache’s Canadian operations, including the Horn River Basin area in northeast British Columbia.

Gross construction costs, which will be refined upon completion of a front-end engineering and design (FEED), are currently estimated at around C$3 billion for the LNG terminal and C$1.1 billion for the pipeline and would be incurred throughout what is projected to be a three and one-half year construction phase, with initial LNG shipments currently projected for 2015. Completion of the FEED study and a final investment decision are expected in 2011.

Devon Gulf of Mexico Shelf Acquisition

On June 9, 2010, Apache completed an acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon Energy Corporation (Devon) for $1.05 billion, subject to normal post-closing adjustments. The acquisition was effective as of January 1, 2010. The acquired assets include 477,000 net acres across 150 blocks and estimated proved reserves of 41 million barrels of oil equivalent (MMboe). Approximately half of the estimated net proved reserves were liquid hydrocarbons, and seven major fields account for 90 percent of the estimated proved reserves. Virtually all of the production is located in fields in water depths less than 500 feet, and Apache now operates 75 percent of the production. Apache allocated $361 million of the purchase price to unproved property and $4 million to gas plant facilities. Apache also recorded abandonment obligations for the properties of $233 million. The acquisition was funded primarily from existing cash balances.

Mariner Energy, Inc. Merger Agreement

On April 15, 2010, Apache and Mariner Energy, Inc., a Delaware corporation (Mariner), announced that they had entered into a definitive agreement pursuant to which Apache will acquire Mariner in a stock and cash transaction. The Agreement and Plan of Merger dated April 14, 2010 (as amended by amendment No. 1 dated August 2, 2010, referred to as the Merger Agreement), by and among Apache, Mariner and Apache Deepwater LLC (formerly known as ZMZ Acquisitions LLC), a Delaware limited liability company and wholly owned subsidiary of Apache (Merger Sub), contemplates a merger (the Merger) whereby Mariner will be merged with and into Merger Sub, with Merger Sub surviving the Merger as a wholly owned subsidiary of Apache.

The total amount of cash and shares of Apache common stock that will be paid and issued, respectively, pursuant to the Merger Agreement is fixed, and Mariner stockholders will be entitled to receive (on an aggregate basis) 0.17043 of a share of Apache common stock, par value $0.625 per share, and $7.80 in cash for each share of Mariner common stock (the Mixed Consideration). Mariner stockholders have the right to elect to receive all cash ($26.00 per share), all Apache common stock (0.24347 of a share of Apache common stock) or the Mixed Consideration, subject to proration procedures as provided in the Merger Agreement.

Upon completion of the Merger, each outstanding employee option to purchase Mariner common stock will be converted into a fully vested option to purchase 0.24347 shares of Apache common stock.

In connection with the Merger, Apache expects to issue approximately 17.5 million shares of common stock (an increase of approximately five percent of the Company’s outstanding common shares) and pay cash of approximately $800 million to Mariner stockholders. Apache intends to fund the cash portion of the consideration with existing cash balances and commercial paper. Upon consummation of the Merger, Apache will assume Mariner’s debt, which had a fair value of approximately $1.6 billion as of September 30, 2010.

The Merger Agreement has been approved by the boards of directors of Apache, Mariner, and Merger Sub. The completion of the Merger is subject to certain conditions, including: (i) the adoption of the Merger Agreement by the stockholders of Mariner; (ii) with certain materiality exceptions, the accuracy of the representations and warranties made by Apache and Mariner; (iii) the effectiveness of a registration statement on Form S-4 associated with the issuance of its common stock in the Merger, and the approval of the listing of these shares on the New York Stock Exchange; (iv) the termination or expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (HSR Act); (v) the delivery of customary opinions from counsel to Apache and Mariner that the Merger will be treated as a tax-free reorganization for U.S. federal income tax purposes; (vi) compliance by Apache and Mariner with their respective obligations under the Merger Agreement; and (vii) the absence of legal impediments prohibiting the Merger. On May 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the HSR Act. Additional post-closing regulatory approvals are pending. The registration statement on Form S-4 was effective as of October 5, 2010. Mariner is holding a special meeting of stockholders on November 10, 2010, to consider and vote to approve and adopt the merger agreement. Assuming approval by shareholders and satisfactory completion of all remaining conditions, Apache expects the merger to close on November 10.

The Merger Agreement contains customary representations and warranties that the parties have made to each other as of specific dates. Apache and Mariner have each agreed to certain covenants in the Merger Agreement. Among other covenants, Mariner has agreed, subject to certain exceptions, not to initiate, solicit, negotiate, provide information in furtherance of, approve, recommend or enter into an Acquisition Proposal (as defined in the Merger Agreement).

The Merger Agreement also contains certain termination rights for both Apache and Mariner, including if the Merger is not completed by January 31, 2011. In the event of a termination of the Merger Agreement, under certain circumstances, Mariner may be required to pay Apache a termination fee of $67 million (less any Apache expenses previously reimbursed by Mariner). In connection with the settlement of two stockholder lawsuits, on August 2, 2010, Apache and Mariner amended the Merger Agreement to eliminate the termination fee in the event that Mariner terminates the Merger Agreement in order to enter into an unsolicited “superior proposal” with another party. For further discussion of these lawsuits, please refer to Note 9— Commitments and Contingencies of this Form 10-Q. In addition, under certain circumstances, the Merger Agreement requires each of Apache and Mariner to reimburse the other’s expenses, up to $7.5 million, in the event the Merger Agreement is terminated. Any reimbursement of expenses by Mariner to Apache will reduce the amount of any termination fee paid by Mariner to Apache.

At year-end 2009, Mariner had estimated proved reserves of 181 MMboe. Mariner’s oil and gas properties are primarily located in the Gulf of Mexico deepwater and shelf, the Permian Basin and onshore in the Gulf Coast, encompassing 541,000 net developed and 623,000 net undeveloped acres at December 31, 2009. Mariner’s deepwater Gulf of Mexico portfolio includes over 99 blocks, seven discoveries in development and more than 50 drilling prospects. The Permian Basin and Gulf of Mexico shelf assets are complementary to Apache’s existing holdings and provide an inventory of future potential drilling locations particularly in the Spraberry and Wolfcamp formation oil plays of the Permian Basin. Additionally, Mariner has accumulated acreage in emerging unconventional shale oil resources in the U.S.

Assuming the Merger is approved by Mariner stockholders and satisfactory completion of all remaining conditions, the transaction will be accounted for as a business combination, with Mariner’s assets and liabilities reflected in Apache’s financial statements at fair value.

Agreement to acquire Permian Basin, Egypt and Canada properties from BP

In July 2010 Apache entered into three definitive purchase and sale agreements to acquire the properties described below (BP Properties) from subsidiaries of BP plc (collectively referred to as “BP”) for aggregate consideration of $7.0 billion, subject to customary adjustments (BP Acquisition). The effective date of the transactions was July 1, 2010. Preferential purchase rights for approximately $653 million of the value of the BP properties in the Permian Basin have been exercised and, accordingly, the purchase price for the BP properties has been reduced to approximately $6.4 billion. Certain rights of first refusal in Canada totaling approximately $1.6 billion are the subject of a court proceeding, as discussed further in Note 9 — Commitments and Contingencies of this Form 10-Q.

Permian Basin On August 10, 2010, Apache completed the acquisition of substantially all of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of west Texas and New Mexico. The acquired assets, net of preferential purchase rights exercised, include interests in several field areas, including Block 16/Coy Waha, Brown Basset, Empire/Yeso, Pegasus, Southeast Lea, Spraberry, Wilshire, North Misc and Delaware Penn, approximately 405,000 net mineral and fee acres, approximately 351,000 leasehold acres and a gas processing plant. The Permian Basin assets had estimated net proved reserves of 124 MMboe at June 30, 2010 (64 percent liquid hydrocarbons, or “liquids”). The agreed-upon purchase price of $3.1 billion was reduced by $653 million for the exercise of preferential rights to purchase. Apache allocated $621 million of the purchase price to unproved property and $75 million to gas plant facilities. Apache also recorded abandonment obligations for the properties of $12 million. BP will continue to operate the properties on Apache’s behalf through November 30, 2010.

Western Canada Sedimentary Basin On October 8, 2010, Apache completed the acquisition of substantially all of BP’s Western Canadian upstream natural gas assets, including approximately 1,278,000 net mineral and leasehold acres, interests in approximately 1,600 active wells, and eight operated and 14 non-operated gas processing plants. The position includes many drilling opportunities ranging from conventional to several unconventional targets, including shale gas, tight gas and coal bed methane in historically productive formations including the Montney, Cadomin and Doig. These properties had estimated net proved reserves of 224 MMboe at June 30, 2010 (94 percent gas). The purchase price was $3.25 billion. Certain rights of first refusal are the subject of a court proceeding, as discussed in Note 9 — Commitments and Contingencies of this Form 10-Q.

Western Desert, Egypt On November 4, 2010, Apache completed the acquisition of BP’s interests in four development licenses and one exploration concession (East Badr El Din) in the Western Desert of Egypt. These properties, covering 394,000 net acres south of El Alamein, are operated by Gulf of Suez Petroleum Company, a joint venture between BP and the Government of Egypt. The transaction includes BP’s interests in 65 active wells, a 24-inch gas line to Dashour, a liquefied petroleum gas plant in Dashour, a gas processing plant in Abu Gharadig and a 12-inch oil export line to the El Hamra Terminal on the Mediterranean Sea. These properties had estimated net proved reserves of 20 MMboe at June 30, 2010 (59 percent liquids). The BP Properties in Egypt are complementary to the over 11 million gross acres in 21 separate concessions in the Western Desert that Apache currently holds. The Merged Concession Agreement related to the development licenses runs through 2024, subject to a five-year extension at the option of the operator. The purchase price of the Egypt properties was $650 million, of which $250 million was paid in a deposit to BP on July 30, 2010, with the balance paid upon closing.

The BP Acquisition is subject to certain post-closing requirements relating to, among other things, resolution of title, environmental and legal issues and any exercise of preferential purchase rights after closing.

The Company financed the BP Acquisition by issuing 26.45 million shares of common stock and 25.3 million depositary shares, raising net proceeds of $3.5 billion; securing a bridge loan facility; issuing new term debt and commercial paper; and using existing cash balances. For further discussion of these debt instruments and equity issuances, please see Note 6 — Debt and Note 8 — Capital Stock, respectively, of this Form 10-Q.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to the Devon and BP Permian Basin acquisitions included in Apache’s statement of consolidated operations for the quarter and nine months ended September 30, 2010, were $135 million and $155 million, respectively. Direct expenses attributable to the acquisitions included in the statement of consolidated operations for the same periods were $35 million and $40 million, respectively.

The following table presents pro forma information for Apache as if the acquisition of properties from Devon and the BP Acquisition had occurred at the beginning of January 1, 2009:


	For the Quarter Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In millions, except per share amounts)
Revenues and Other	$	3,327	$	2,784	$	9,668	$	6,994


Net Income (Loss)	$	841	$	503	$	2,559	$	(859	)
Preferred Stock Dividends		19		20		57		61

Income (Loss) Attributable to Common Stock		822		483		2,502		(920	)


Net Income (Loss) per Common Share — Basic	$	2.25	$	1.33	$	6.88	$	(2.54	)

Net Income (Loss) per Common Share — Diluted	$	2.22	$	1.33	$	6.76	$	(2.54	)

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the acquisitions and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what our consolidated results of operations actually would have been had we completed the acquisitions on January 1, 2009. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma consolidated results reflect pro forma adjustments for additional depreciation expense related to the fair value adjustment to property, plant and equipment acquired, additional asset retirement obligation accretion expense related to the assets acquired, pro forma interest expense associated with $1.5 billion principal amount of senior unsecured 5.1-percent notes maturing September 1, 2040, to fund a portion of the purchase price of the BP Acquisition and amortization of the associated deferred financing costs, capitalization of interest expense, increased general and administrative expense as a result of the purchase of the properties, issuance of 26.45 million shares of Apache common stock to partially fund the BP Acquisition, issuance of 25.3 million depositary shares each representing a 1/20th interest in a share of 6.00-percent Mandatory Convertible Preferred Stock, Series D, to partially fund the BP Acquisition and the related preferred dividends, and applicable income tax impacts.

3. 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. Apache manages the variability in cash flows by entering into hedges on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices. Derivative instruments entered into are typically designated as cash flow hedges.

Counterparty Risk

The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2010, Apache had derivative positions with 17 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate its exposure to an increase in counterparty credit risk. Should any or all of these counterparties not perform, Apache may not realize the benefit on some or all of its derivative instruments resulting from lower commodity prices.

The Company executes commodity derivative transactions under master agreements that allow payables to offset receivables with the same counterparty. In general, if a party to a derivative transaction incurs a material deterioration in its credit ratings, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer of contracts to another counterparty or terminate the arrangement.

Commodity Derivative Instruments

As of September 30, 2010, Apache had the following open crude oil derivative positions:


	Fixed-Price Swaps				Collars
			Weighted				Weighted		Weighted
Production			Average				Average		Average
Period	Mbbls		Fixed Price ⁽¹⁾		Mbbls		Floor Price ⁽¹⁾		Ceiling Price ⁽¹⁾
2010		920	$	70.10		2,990	$	68.02	$	85.44
2011 ⁽²⁾		3,650		70.12		16,605		68.43		93.18
2012		3,292		70.99		9,142		69.30		98.11
2013		1,451		72.01		2,416		78.02		103.06
2014		76		74.50		—		—		—


⁽¹⁾		Crude oil prices represent a weighted average of several contracts entered into on a per barrel basis. Crude oil contracts are primarily settled against NYMEX WTI Cushing Index.

⁽²⁾		Subsequent to September 30, 2010, Apache entered into additional crude oil hedges totaling 8,030 thousands of barrels (Mbbls) for 2011. After consideration of these hedges, the weighted average floor and ceiling prices for the 2011 production period positions are $68.94 and $96.05 per barrel, respectively.

As of September 30, 2010, Apache had the following open natural gas derivative positions:


	Fixed-Price Swaps						Collars
					Weighted						Weighted		Weighted
Production	MMBtu		GJ		Average		MMBtu		GJ		Average		Average
Period	(in 000’s)		(in 000’s)		Fixed Price ⁽¹⁾		(in 000’s)		(in 000’s)		Floor Price ⁽¹⁾		Ceiling Price ⁽¹⁾
2010		24,840		—	$	5.64		7,360		—	$	5.41	$	6.91
2010		—		13,800	C$	5.37		—		—		—		—
2011		46,538		—	$	6.13		9,125		—	$	5.00	$	8.85
2011		—		51,100	C$	6.26		—		3,650	C$	6.50	C$	7.10
2012		19,215		—	$	6.51		21,960		—	$	5.54	$	7.30
2012		—		43,920	C$	6.61		—		7,320	C$	6.50	C$	7.27
2013		1,825		—	$	7.05		6,825		—	$	5.35	$	6.67
2014		755		—	$	7.23		—		—		—		—


⁽¹⁾		U.S. natural gas prices represent a weighted average of several contracts entered into on a per million British thermal units (MMBtu) basis and are settled primarily against NYMEX Henry Hub and various Inside FERC indices. The Canadian natural gas prices represent a weighted average of AECO Index prices and are shown in Canadian dollars. The Canadian gas contracts are entered into on a per gigajoule (GJ) basis and are settled against AECO Index.

As of September 30, 2010, Apache had the following open natural gas financial basis swap contracts:


			Weighted
	MMBtu		Average
Production Period	(in 000’s)		Price Differential ⁽¹⁾
2010		10,580	$	(0.54	)
2011		18,250	$	(0.30	)
2012		10,980	$	(0.36	)


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

Subsequent to September 30, 2010, Apache North Sea Ltd entered into a physical sales contract to deliver 20 thousand barrels of oil per day in 2011, settled against Platts Dated Brent with a floor price of $70 and an average ceiling price of $98.56. These sales are in the normal course of business and will be recognized in oil and gas revenues.

Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet

The Company accounts for derivative instruments and hedging activity in accordance with Accounting Standards Codification (ASC) Topic 815, “Derivatives and Hedging,” and all derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The fair market value of the Company’s derivative assets and liabilities are as follows:


	September 30,		December 31,
	2010		2009
	(In millions)
Current Assets: Derivative instruments	$	218	$	13
Other Assets: Deferred charges and other		159		51

Total Derivative Assets	$	377	$	64


Current Liabilities: Derivative instruments	$	59	$	128
Noncurrent Liabilities: Other		90		202

Total Derivative Liabilities	$	149	$	330

The methods and assumptions used to estimate the fair values of the Company’s commodity derivative instruments and gross amounts of commodity derivative assets and liabilities are more fully discussed in Note 10 — Fair Value Measurements of this Form 10-Q.

Commodity Derivative Activity Recorded in Statement of Consolidated Operations

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


		For the Quarter				For the Nine Months
		Ended				Ended
	Gain (Loss) on Derivatives	September 30,				September 30,
	Recognized In Income	2010		2009		2010			2009
				(In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)	Oil and Gas Production Revenues	$	53	$	49	$	104		$	157
Gain (loss) derivatives recognized in operations (ineffective portion and basis)	Revenues and Other: Other	$	—	$	—	$	(1	)	$	(3	)

Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of September 30, 2010, substantially all of the Company’s derivative instruments were designated as cash flow hedges in accordance with ASC Topic 815. A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders’ equity related to Apache’s cash flow hedges is presented in the table below:


	For the Nine Months Ended September 30,
	2010						2009
	Before tax			After tax			Before tax			After tax
				(In millions)
Unrealized gain (loss) on derivatives at beginning of period	$	(267	)	$	(170	)	$	212		$	138
Realized amounts reclassified into earnings		(104	)		(67	)		(157	)		(107	)
Net change in derivative fair value		596			407			(195	)		(121	)
Ineffectiveness reclassified into earnings		—			—			(1	)		(1	)


Unrealized gain (loss) on derivatives at end of period	$	225		$	170		$	(141	)	$	(91	)

Based on market prices as of September 30, 2010, the Company’s net unrealized income in accumulated other comprehensive income (loss) for commodity derivatives designated as cash flow hedges totaled a gain of $225 million ($170 million after tax). Gains and losses on hedges will be realized in future earnings through mid-2014, contemporaneously with the related sales of natural gas and crude oil production applicable to specific hedges. Included in accumulated other comprehensive income (loss) as of September 30, 2010 is a net gain of approximately $158 million ($114 million after tax) that applies to the next 12 months; however, estimated and actual amounts are likely to vary materially as a result of changes in market conditions.

4. DEPOSIT RELATED TO ACQUISITION OF BP PROPERTIES

At September 30, 2010, a $3.5 billion deposit, of which $3.25 billion was related to the purchase of the BP Canadian properties and $250 million was related to the BP Egyptian properties, was recorded as a long-term asset on Apache’s consolidated balance sheet. For additional information on the transactions, please see Note 2 – Acquisitions of this Form 10-Q. Subsequent to September 30, 2010, both acquisitions were closed, and the associated deposits were applied to the purchase price of the assets.

5. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine months ended September 30, 2010:


	(In millions)
Asset retirement obligation at December 31, 2009	$	1,784
Liabilities incurred		385
Liabilities settled		(198	)
Revisions		57
Accretion expense		74


Asset retirement obligation at September 30, 2010		2,102

Less current portion		(153	)

Asset retirement obligation, long-term	$	1,949

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

In September 2010 the Bureau of Ocean Management, Regulation and Enforcement (BOEMRE, formerly known as the Minerals Management Service), a division of the U.S. Department of the Interior, issued Notice to Lessees (NTL) No. 2010-G05, which includes guidelines for decommissioning idle infrastructure on active leases in the Gulf of Mexico within a specified period of time. The Company is currently evaluating the impact of these new guidelines on its financial statements.

6. DEBT

As of September 30, 2010, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2011 and $2.3 billion matures in May 2013. These consist of a new $1.0 billion 364-day facility, a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. Since there are no outstanding borrowings or commercial paper at quarter-end, the full $3.3 billion of committed credit capacity is available to the Company.

The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2011 and 2013.

On July 20, 2010, in connection with the acquisition of certain BP properties, the Company entered into a term loan agreement that initially provided a $5.0 billion unsecured bridge facility with a September 29, 2010, maturity, unless extended at the Company’s option until December 29, 2010. The commitment under the facility was subsequently reduced by $3.5 billion to reflect receipt of the net proceeds from the issuance of common and preferred stock on July 28, 2010, as discussed in Note 8 — Capital Stock of this Form 10-Q. On August 10, 2010, the Company borrowed $1.0 billion under the bridge facility to finance a portion of the consideration for the acquisition and subsequently repaid the bridge facility borrowings and terminated the bridge facility on August 20, 2010. Apache incurred $6 million of loan costs related to this bridge facility that were charged to financing costs upon termination of the facility.

On August 13, 2010, Apache entered into a $1.0 billion 364-day syndicated revolving credit facility. The credit facility is subject to covenants, events of default and representations and warranties that are substantially similar to those in Apache’s existing revolving credit facilities. It may be used for acquisitions and for general corporate purposes or to support the Company’s commercial paper program.

The facility will terminate and all amounts outstanding will be due on August 12, 2011, unless Apache requests a 364-day extension, which is subject to lender approval, as defined, or Apache elects a one-year term out option. Loans under the facility will bear interest at a base rate, as defined, or at LIBOR plus a margin, which varies based upon prices reported in the credit default swap market with respect to Apache’s one-year indebtedness and the rating for Apache’s senior, unsecured long-term debt. Based upon prices for Apache’s one-year credit default swaps and its current senior unsecured long-term debt rating, the margin at September 30, 2010, would be .75 percent. Apache must also pay a commitment fee on the undrawn portion of the facility which is based on its senior, unsecured long term debt rating. The commitment fee is currently .125 percent.

On August 20, 2010, the Company issued $1.5 billion principal amount of senior unsecured 5.1-percent notes maturing September 1, 2040. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The proceeds were used to repay borrowings under the Company’s bridge facility and commercial paper program.

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 Company agreed to guarantee the credit facility until the subsidiary satisfied the contractual “completion test” as defined in the Syndicated Facility Agreement. Elements of this completion test include among other things , physical completion of the facilities, minimum cumulative production volumes and satisfaction of the Debt Service Reserve Account. Under the terms of the Debt Service Reserve Account, the subsidiary is required to deposit an amount equal to 50 percent of the next debt reduction amount plus three months of interest.

The borrowing base was initially set at $350 million and will be redetermined upon project completion, as defined in the facility, and semi-annually thereafter. The subsidiary expects to satisfy the completion test in the fourth quarter of 2010. In the event project completion does not occur by December 31, 2010, pursuant to the terms of the facility, the lenders may require repayment of outstanding amounts in the first quarter of 2011. The outstanding balance under the facility as of September 30, 2010, was $300 million. Under the terms of the agreement, the facility amount was reduced initially on June 30, 2010, and will be further reduced semi-annually thereafter until the earlier of maturity on March 31, 2014, or the date on which the remaining proved reserves fall below 25 percent of the initial proved reserves. As $60 million and $55 million of the existing balance will be repaid by December 31, 2010, and June 30, 2011, respectively, $115 million has been classified as current debt at September 30, 2010.

At September 30, 2010 and December 31, 2009, there was $20.4 million and $7.3 million, respectively, borrowed on uncommitted overdraft lines in Argentina and Canada.

Financing Costs, Net

Financing costs incurred during the periods noted comprised the following:


	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
				(In millions)
Interest expense	$	86		$	77		$	237		$	233
Amortization of deferred loan costs		7			1			10			4
Capitalized interest		(29	)		(14	)		(64	)		(45	)
Interest income		(5	)		(2	)		(9	)		(10	)

Financing costs, net	$	59		$	62		$	174		$	182

7. INCOME TAXES

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. There were no significant discrete tax events that occurred during the first nine months of 2010. The 2009 year-to-date tax provision includes the impact of a non-cash write-down of proved oil and gas properties, which was recognized as a discrete item in the first quarter of 2009.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is in Administrative Appeals with the United States Internal Revenue Service (IRS) regarding the 2004 through 2007 tax years and under audit for the 2008 tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

8. CAPITAL STOCK

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and nine-month periods ended September 30, 2010 and 2009 is presented in the table below. The loss for the first nine months of 2009 reflects a $1.98 billion after-tax write-down of the carrying value of the Company’s March 31, 2009, proved property balances in the U.S. and Canada.


	For the Quarter Ended September 30,
	2010						2009
	Income		Shares		Per Share		Income		Shares		Per Share
			(In thousands, except per share amounts)
Basic:
Income attributable to common stock	$	764,989		356,718	$	2.14	$	440,596		336,159	$	1.31


Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock		13,276		9,258				—		—
Stock options and other		—		1,463				—		1,713


Diluted:
Income attributable to common stock, including assumed conversions	$	778,265		367,439	$	2.12	$	440,596		337,872	$	1.30


	For the Nine Months Ended September 30,
	2010						2009
	Income		Shares		Per Share		Loss			Shares		Per Share
			(In thousands, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	2,330,193		343,826	$	6.78	$	(874,464	)		335,637	$	(2.61	)


Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock		13,276		3,120				—			—
Stock options and other		—		1,838				—			—


Diluted:
Income (loss) attributable to common stock, including assumed conversions	$	2,343,469		348,784	$	6.72	$	(874,464	)		335,637	$	(2.61	)

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 3.7 million and 2.4 million for the quarters ending September 30, 2010 and 2009, respectively, and 3.2 million and 4.0 million for the nine months ended September 30, 2010 and 2009, respectively. The provisions of ASC Topic 260, “Earnings Per Share,” state that unvested share-based payment awards that contain rights to receive non-forfeitable dividends or dividend equivalents are participating securities prior to vesting and are required to be included in the earnings allocations in computing basic EPS under the two-class method. These participating securities had a negligible impact on earnings per share for the periods presented.

Issuance of Common Stock

On July 28, 2010, in conjunction with Apache’s acquisition of properties from BP plc, the Company issued 26.45 million shares of common stock at a public offering price of $88 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering totaled approximately $2.3 billion.

Mandatory Convertible Preferred Stock, Series D

Also on July 28, 2010, Apache issued 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D (Preferred Share), or 1.265 million Preferred Shares. The Company received proceeds of approximately $1.2 billion, after underwriting discounts and before expenses, from the sale.

Each Preferred Share has an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). When and if declared by the Board of Directors, Apache will pay cumulative dividends on each Preferred Share at a rate of 6.00 percent per annum on the initial liquidation preference. Dividends will be paid in cash quarterly on February 1, May 1, August 1 and November 1 of each year, commencing on November 1, 2010, and until and including May 1, 2013. The final dividend payment on August 1, 2013, may be paid or delivered, as the case may be, in cash, shares of Apache common stock, or a combination thereof, at the election of the Company.

The Preferred Shares may be converted, at the option of the holder, into 9.164 shares of Apache common stock at any time prior to July 15, 2013. If not converted prior to that time, each Preferred Share will automatically convert on August 1, 2013, into a minimum of 9.164 or a maximum of 11.364 shares of Apache common stock depending on the volume-weighted average price per share of Apache’s common stock over the ten trading day period ending on, and including, the third scheduled trading day immediately preceding the mandatory conversion. Upon conversion, a minimum of 11.6 million Apache common shares and a maximum of 14.4 million common shares will be issued.

Common and Preferred Stock Dividends

For the quarter ending September 30, 2010 and 2009, Apache paid $51 million and $50 million, respectively, in dividends on its common stock. For the nine-month periods ended September 30, 2010 and 2009, the Company paid $152 million and $151 million, respectively. In the three- and nine-month periods ended September 30, 2009, Apache paid a total of $1.4 million and $4.3 million, respectively, in dividends on its Series B Preferred Stock issued in August 1998. The Company redeemed all outstanding shares of its Series B Preferred Stock on December 30, 2009. Dividend payments on the Company’s Series D Preferred Stock commenced on November 1, 2010.

Stock-Based Compensation

Share Appreciation Plans

The Company utilizes share appreciation plans from time to time to provide incentives for substantially all full-time employees to increase Apache’s share price within a stated measurement period. To achieve the payout under those plans, the Company’s stock price must close at or above a stated threshold for 10 out of any 30 consecutive trading days before the end of the stated period. The provisions of ASC 718, “Compensation — Stock Compensation,” dictate that expense should be amortized over the requisite service period, and should the stated threshold not be met before the end of the stated period, any unamortized expense must be immediately recognized. 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 September 30, 2010, neither share price threshold had been met. If the interim goal of $162 is not met prior to December 31, 2010, the Company estimates that $42 million of unamortized expense would be immediately recognized at year-end, of which approximately one-third would be capitalized.

	•		On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan, with a target to increase Apache’s share price to $108 by the end of 2008 and an interim goal of $81 to be achieved by the end of 2007. Awards under the plan were payable in four equal annual installments to eligible employees remaining with the Company. Apache’s share price exceeded the interim $81 threshold for the 10-day requirement on June 14, 2007. The final installment was awarded in June 2010. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008. The third installment was awarded in March 2010, and the final installment will be awarded in March 2011.

2010 Performance Program and Restricted Stock Awards

To provide long-term incentives for Apache employees to deliver competitive returns to our stockholders, in November 2009, the Company’s Board of Directors approved the 2010 Performance Program, pursuant to the 2007 Omnibus Equity Compensation Plan. Eligible employees were granted initial conditional restricted stock units totaling 541,440 units. The ultimate number of restricted stock units to be awarded will be based upon measurement of the total shareholder return of Apache common stock as compared to a designated peer group during a three-year performance period. Should any restricted stock units be awarded at the end of the three-year performance period, December 31, 2012, 50 percent of restricted stock units awarded will immediately vest, and an additional 25 percent will vest on the two succeeding anniversaries following the end of the performance period. In January 2010 the Company’s Board of Directors also approved one-time restricted stock unit awards totaling 502,470 shares to eligible Apache employees, with one-third of the units granted immediately vesting and an additional one-third vesting on each of the first and second anniversaries of the grant date.

9. COMMITMENTS AND CONTINGENCIES

Legal Matters

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $11 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position or results of operations after consideration of recorded accruals. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position or results of operations.

Argentine Environmental Claims

In connection with the acquisition from Pioneer in 2006, the Company acquired a subsidiary of Pioneer in Argentina (PNRA) that is involved in various administrative proceedings with environmental authorities in the Neuquén Province relating to permits for and discharges from operations in that province. In addition, PNRA was named in a suit initiated against oil companies operating in the Neuquén basin entitled Asociación de Superficiarios de la Patagonia v YPF S.A., et. al., originally filed on August 21, 2003, in the Argentine National Supreme Court of Justice. The plaintiffs, a private group of landowners, have also named the national government and several provinces as third parties. The lawsuit alleges injury to the environment generally by the oil and gas industry. The plaintiffs principally seek from all defendants, jointly, (i) the remediation of contaminated sites, of the superficial and underground waters, and of soil that allegedly was degraded as a result of deforestation, (ii) if the remediation is not possible, payment of an indemnification for the material and moral damages claimed from defendants operating in the Neuquén basin, of which PNRA is a small portion, (iii) adoption of all the necessary measures to prevent future environmental damages, and (iv) the creation of a private restoration fund to provide coverage for remediation of potential future environmental damages. Much of the alleged damage relates to operations by the Argentine state oil company, which conducted oil and gas operations throughout Argentina prior to its privatization, which began in 1990. While the plaintiffs will seek to make all oil and gas companies operating in the Neuquén basin jointly liable for each others’ actions, PNRA will defend on an individual basis and attempt to require the plaintiffs to delineate damages by company. PNRA intends to defend itself vigorously in the case. It is not certain exactly how or what the court will do in this matter as it is the first of its kind. While it is possible PNRA may incur liabilities related to the environmental claims, no reasonable prediction can be made as PNRA’s exposure related to this lawsuit is not currently determinable.

Louisiana Restoration

Numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages from contamination and cleanup. Many of these lawsuits claim small amounts, while others assert claims in excess of $1 million. Also, some lawsuits or claims are being settled or resolved, while others are still being filed. Any exposure, therefore, related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend the cases.

Hurricane-Related Litigation

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

Australia Gas Pipeline Force Majeure

The Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas to customers under various long-term contracts. Company subsidiaries believe that the event was a force majeure, and as a result, the subsidiaries and their joint venture participants have declared force majeure under those contracts. On December 16, 2009, a customer, Burrup Fertilisers Pty Ltd, filed a lawsuit on behalf of itself and certain of its underwriters at Lloyd’s of London and other insurers, against the Company and its subsidiaries in Texas state court, asserting claims for negligence, breach of contract, alter ego, single business enterprise, res ipsa loquitur, and gross negligence/exemplary damages. Other customers have threatened to file suit challenging the declaration of force majeure under their contracts. Contract prices under their contracts are significantly below current spot prices for natural gas in Australia. In the event it is determined that the pipeline explosion was not a force majeure, Company subsidiaries believe that liquidated damages should be the extent of the damages under those long-term contracts with such provisions. Approximately 90 percent of the natural gas volumes sold by Company subsidiaries under long-term contracts have liquidated damages provisions. Contractual liquidated damages under the long-term contracts with such provisions would not be expected to exceed $200 million AUD. In their Harris County petition, Burrup Fertilisers and its underwriters and insurers seek to recover unspecified actual damages, cost of repair and replacement, exemplary damages, lost profits, loss of business goodwill, value of the gas lost under the GSA, interest and court costs. No assurance can be given that Burrup Fertilisers and other customers would not assert claims in excess of contractual liquidated damages, and exposure related to such claims is not currently determinable. While an adverse judgment against Company subsidiaries (and Company, in the case of the Burrup Fertilisers lawsuit) is possible, the Company and Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims.

In December 2008, the Senate Economics Committee of the Parliament of Australia released its findings from public hearings concerning the economic impact of the gas shortage following the explosion on Varanus Island and the government’s response. The Committee concluded, among other things, that the macroeconomic impact to Western Australia will never be precisely known, but cited to a range of estimates from $300 million AUD to $2.5 billion AUD consisting in part of losses alleged by some parties who have long-term contracts with Company subsidiaries (as described above), but also losses alleged by third parties who do not have contracts with Company subsidiaries (but who may have purchased gas that was re-sold by customers or who may have paid more for energy following the explosion or who lost wages or sales due to the inability to obtain energy or the increased price of energy). A timber industry group, whose members do not have a contract with Company subsidiaries, has announced that it intends to seek compensation for its members and their subcontractors from Company subsidiaries for $20 million AUD in losses allegedly incurred as a result of the gas supply shortage following the explosion. In Johnson Tiles Pty Ltd v. Esso Australia Pty Ltd [2003] VSC 27 (Supreme Court of Victoria, Gillard J presiding), which concerned a 1998 explosion at an Esso natural gas processing plant at Longford in East Gippsland, Victoria, the Court held that Esso was not liable for $1.3 billion AUD of pure economic losses suffered by claimants that had no contract with Esso, but was liable to such claimants for reasonably foreseeable property damage which Esso settled for $32.5 million plus costs. In reaching this decision the Court held that third-party claimants should have protected themselves from pure economic losses, through the purchase of insurance or the installation of adequate backup measures, in case of an interruption in their gas supply from Esso. While an adverse judgment against Company subsidiaries is possible if litigation is filed, Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims. Exposure related to any such potential claims is not currently determinable.

On October 10, 2008, the Australia National Offshore Petroleum Safety Authority (NOPSA) released a self-titled “Final Report” of the findings of its investigation into the pipeline explosion, prepared at the request of the Western Australian Department of Industry and Resources (DoIR). NOPSA concluded in its report that the evidence gathered to date indicates that the main causal factors in the incident were: (1) ineffective anti-corrosion coating at the beach crossing section of the 12-inch sales gas pipeline, due to damage and/or dis-bondment from the pipeline; (2) ineffective cathodic protection of the wet-dry transition zone of the beach crossing section of the 12-inch sales gas pipeline; and (3) ineffective inspection and monitoring by Company subsidiaries of the beach crossing and shallow water section of the 12-inch sales gas pipeline. NOPSA further concluded that the investigation identified that Apache Northwest Pty Ltd and its co-licensees may have committed offenses under the Petroleum Pipelines Act 1969, Sections 36A & 38(b) and the Petroleum Pipelines Regulations 1970, Regulation 10, and that some findings may also constitute non-compliance with pipeline license conditions. NOPSA states in its report that an application for renewal of the pipeline license covering the area of the Varanus Island facility was granted in May 1985 with 21 years validity, and an application for renewal of the license was submitted to DoIR by Company subsidiaries in December 2005 and remains pending.

Company subsidiaries disagree with NOPSA’s conclusions and believe that the NOPSA report is premature, based on an incomplete investigation and misleading. In a July 17, 2008, media statement, DoIR acknowledged, “The pipelines and Varanus Island facilities have been the subject of an independent validation report [by Lloyd’s Register] which was received in August 2007. NOPSA has also undertaken a number of inspections between 2005 and the present.” These and numerous other inspections, audits and reviews conducted by top international consultants and regulators did not identify any warnings that the pipeline had a corrosion problem or other issues that could lead to its failure. Company subsidiaries believe that the explosion was not reasonably foreseeable, and was not within the reasonable control of Company’s subsidiaries or able to be reasonably prevented by Company subsidiaries.

On January 9, 2009, the governments of Western Australia and the Commonwealth of Australia announced a joint inquiry to consider the effectiveness of the regulatory regime for occupational health and safety and integrity that applied to operations and facilities at Varanus Island and the role of DoIR, NOPSA and the Western Australian Department of Consumer and Employment Protection (DoCEP). The joint inquiry’s report was published in June 2009.

On May 8, 2009, the government of Western Australia announced that its Department of Mines and Petroleum (DMP) will carry out “the final stage of investigations into the Varanus Island gas explosion.” Inspectors were appointed under the Petroleum Pipelines Act to coordinate the final stage of the investigations. Their report has been delivered to the Minister for Mines and Petroleum, but neither the report nor its contents have been made available to Company subsidiaries for their review and comment.

On May 28, 2009, the DMP filed a prosecution notice in the Magistrates Court of Western Australia, charging Apache Northwest Pty Ltd and its co-licensees with failure to maintain a pipeline in good condition and repair under the Petroleum Pipelines Act 1969, Section 38(b). The maximum fine associated with the alleged offense is $50,000 AUD. The Company subsidiary does not believe that the charge has merit and plans to vigorously pursue its defenses.

Seismic License

In December 1996 the Company and Fairfield Industries Incorporated entered into a Master Licensing Agreement for the licensing of seismic data relating to certain blocks in the Gulf of Mexico. The Company and Fairfield also entered into supplemental agreements specifying the data to be licensed to the Company as well as the consideration due Fairfield. In February 2009 the Company filed an action in Texas state court seeking a declaration of the parties’ contractual obligations. The Company and its subsidiary, GOM Shelf LLC, have also asserted a claim to recover damages for certain overpayments to Fairfield under the parties’ agreements. Fairfield and a related entity, Fairfield Royalty Corporation, counterclaimed. As a result of a nonbinding mediation in July 2010, the parties have resolved the matter amicably, which resolution did not have a material affect on the Company.

Mariner Stockholder Lawsuits

In connection with the Merger, two shareholder lawsuits styled as class actions have been filed against Mariner and its board of directors. The lawsuits are entitled City of Livonia Employees’ Retirement System, Individually and on Behalf of All Others Similarly Situated vs. Mariner Energy, Inc, et al., (filed April 16, 2010, in the District Court of Harris County, Texas), and Southeastern Pennsylvania Transportation Authority, individually, and on behalf of all those similarly situated , vs. Scott D. Josey, et.al., (filed April 21, 2010, in the Court of Chancery in the State of Delaware). The Southeastern Pennsylvania Transportation Authority lawsuit also names Apache and its wholly owned subsidiary, ZMZ Acquisitions LLC (the Merger Sub) as defendants. The complaints generally allege that (1) Mariner’s directors breached their fiduciary duties in negotiating and approving the Merger and by administering a sale process that failed to maximize shareholder value and (2) Mariner, and in the case of the Southeastern Pennsylvania Transportation Authority complaint, Apache and the Merger Sub, aided and abetted Mariner’s directors in breaching their fiduciary duties. The City of Livonia Employees’ Retirement System complaint also alleges that Mariner’s directors and executives stand to receive substantial financial benefits if the transaction is consummated on its current terms. Pending court approval, these lawsuits have been settled in principle and are not expected to have a material impact on Apache.

Marbob Energy Corporation and Concho Resources Lawsuits

Marbob Energy Corporation, Concho Resources and other parties have filed lawsuits against BP America Inc, BP America Production Company (“BP”), and ZPZ Delaware I LLC (“ZPZ”), Apache’s wholly owned subsidiary, in New Mexico seeking a declaratory judgment that Plaintiffs are entitled to receive preferential purchase rights (“PPR”) notices on certain of the properties that are included in the Purchase and Sale Agreement between BP and ZPZ and injunctive relief to force BP promptly to issue to Plaintiffs PPR notices on those properties. Plaintiffs do not seek monetary damages, other than fees and costs incurred in bringing these actions. Apache agreed to indemnify BP for these actions. On October 15, 2010, the parties settled the dispute on commercial terms. Apache’s subsidiary acquired a 50-percent interest in the subject acreage in its previously announced acquisition of BP’s oil and gas operations, acreage and infrastructure in the Permian Basin of West Texas and New Mexico. The subsidiary acquired an additional 10-percent interest and became operator as a result of the settlement of the dispute with Marbob Energy Corporation and Concho Resources. As a result of the settlement, Concho will own approximately 40 percent of the subject acreage.

Escheat Audits

The State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property), has notified numerous companies, including Apache Corporation, that the State intends to examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. The review will be conducted by Kelmar Associates on behalf of the State. At least 30 other states have retained their own consultants and have sent similar notifications. The scope of each state’s audit varies. The State of Delaware advises, for example, that the scope of its examination will be for the period 1981 through the present. It is possible that one or more of the State audits could extend to all 50 states.

NAL GP Ltd Lawsuit

In a lawsuit commenced on September 23, 2010, and styled as NAL GP Ltd., Applicant, and BP Canada Energy Company, BP Canada Energy, and Apache Corporation, Respondents, Action No. 1001-14115, in the Court of Queen’s Bench of Alberta, Judicial District of Calgary, NAL GP Ltd. (“NAL”) seeks, among other things, interim injunctive relief to freeze the 15-day notice period concerning NAL’s rights of first refusal relating to certain of the Canadian assets involved in the transaction between BP and Apache announced July 20, 2010, and further a hearing concerning the allocated values associated with such assets (approximately $1.6 billion USD in the aggregate). Apache Corporation was wrongly named as a respondent in the proceeding, and so Apache Canada Ltd. has appeared in the proceeding. A hearing on NAL’s application was held on September 27, 2010. On September 28, 2010, the Court dismissed NAL’s application in its entirety. NAL has filed an appeal. Along with BP, Apache Canada Ltd. intends to continue to defend against NAL’s claims vigorously.

Environmental Matters

As of September 30, 2010, the Company had an undiscounted reserve for environmental remediation of approximately $23 million. The Company is not aware of any environmental claims existing as of September 30, 2010, which have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

10. FAIR VALUE MEASUREMENTS

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

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable and Accounts Payable

The carrying amounts approximate fair value because of the short-term nature or maturity of these instruments.

Commodity Derivative Instruments

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps and options. The Company uses a market approach to estimate the fair values of derivative instruments, utilizing published commodity futures price strips for the underlying commodities as of the date of the estimate. The fair values of the Company’s derivative instruments are not actively quoted in the open market and are valued using forward commodity price curves provided by a reputable third party. These valuations are Level 2 inputs. For further information regarding Apache’s derivative instruments and hedging activities, please see Note 3 — Derivative Instruments and Hedging Activities of this Form 10-Q.

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


	Fair Value Measurements Using
	Quoted
	Price in		Significant		Significant
	Active		Other		Unobservable		Total
	Markets		Inputs		Inputs		Fair					Carrying
	(Level 1)		(Level 2)		(Level 3)		Value		Netting ⁽¹⁾			Amount
	(In millions)
September 30, 2010
Assets:
Commodity Derivative Instruments	$	—	$	459	$	—	$	459	$	(82	)	$	377

Liabilities:
Commodity Derivative Instruments		—		231		—		231		(82	)		149

December 31, 2009
Assets:
Commodity Derivative Instruments	$	—	$	75	$	—	$	75	$	(11	)	$	64

Liabilities:
Commodity Derivative Instruments		—		341		—		341		(11	)		330


⁽¹⁾		The derivative fair values above are based on analysis of each contract as required by ASC 820. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. For a discussion of net amounts recorded on the consolidated balance sheet at September 30, 2010, and December 31, 2009, please see Note 3 — Derivative Instruments and Hedging Activities of this Form 10-Q.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Asset Retirement Obligations Incurred in Current Period

Apache uses an income approach to estimate the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. AROs incurred in the current period were Level 3 fair value measurements. A summary of changes in the ARO liability is provided in Note 5 — Asset Retirement Obligation of this Form 10-Q.

Debt

The Company’s debt is recorded at the carrying amount on its consolidated balance sheet. In accordance with ASC 825, “Financial Instruments,” disclosure of the fair value of total debt is required for interim reporting. Apache uses a market approach to determine the fair value of Apache’s fixed-rate debt using estimates provided by an independent financial data services firm, which is a Level 2 fair value measurement. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The following table presents the carrying amounts and estimated fair values of the Company’s debt at September 30, 2010 and December 31, 2009:


	September 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In millions)
Total Debt, Net of Unamortized Discount	$	6,516	$	7,482	$	5,067	$	5,635

11. COMPREHENSIVE INCOME (LOSS)

The following table presents the components of Apache’s comprehensive income (loss) for the three-month and nine-month periods ended September 30, 2010 and 2009.


	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)
Comprehensive Income (Loss):
Net income (Loss)	$	778		$	442		$	2,343		$	(870	)
Other Comprehensive Income (Loss):
Commodity hedges		29			(51	)		493			(354	)
Income tax related to commodity hedges		(2	)		17			(152	)		125


Total	$	805		$	408		$	2,684		$	(1,099	)

12. BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. The Company has production in six countries: the United States, Canada, Egypt, Australia, the United Kingdom (U.K.) and Argentina. Apache also has exploration interests in Chile. Financial information for each country is presented below:


	United														Other
	States			Canada			Egypt		Australia		U.K.		Argentina		International		Total
	(In millions)
For the Quarter Ended September 30, 2010

Oil and Gas Production Revenues	$	1,060		$	231		$	822	$	431	$	410	$	92	$	—	$	3,046


Operating Income ⁽¹⁾	$	440		$	63		$	561	$	267	$	186	$	10	$	—	$	1,527


Other Income (Expense):
Other																		(34	)
General and administrative																		(97	)
Financing costs, net																		(59	)

Income Before Income Taxes																	$	1,337


For the Nine Months Ended September 30, 2010

Oil and Gas Production Revenues	$	3,015		$	723		$	2,369	$	1,108	$	1,222	$	272	$	—	$	8,709


Operating Income ⁽¹⁾	$	1,403		$	229		$	1,601	$	653	$	500	$	53	$	—	$	4,439


Other Income (Expense):
Other																		(51	)
General and administrative																		(276	)
Financing costs, net																		(174	)

Income Before Income Taxes																	$	3,938


Total Assets	$	15,968		$	7,722		$	5,585	$	3,736	$	2,329	$	1,529	$	59	$	36,928


For the Quarter Ended September 30, 2009

Oil and Gas Production Revenues	$	802		$	214		$	697	$	116	$	411	$	86	$	—	$	2,326


Operating Income ⁽¹⁾	$	295		$	52		$	477	$	15	$	152	$	17	$	—	$	1,008


Other Income (Expense):
Other																		7
General and administrative																		(82	)
Financing costs, net																		(62	)

Income Before Income Taxes																	$	871


For the Nine Months Ended September 30, 2009

Oil and Gas Production Revenues	$	2,105		$	639		$	1,773	$	245	$	976	$	266	$	—	$	6,004


Operating Income (Loss) ⁽¹⁾	$	(561	)	$	(1,443	)	$	1,141	$	15	$	379	$	57	$	—	$	(412	)


Other Income (Expense):
Other																		56
General and administrative																		(259	)
Financing costs, net																		(181	)

Loss Before Income Taxes																	$	(796	)


Total Assets	$	10,579		$	4,549		$	5,273	$	3,147	$	2,271	$	1,406	$	—	$	27,225


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

13. SUPPLEMENTAL GUARANTOR INFORMATION

Apache Finance Canada Corporation (Apache Finance Canada) is a subsidiary of Apache and has issued approximately $300 million of publicly-traded notes due in 2029 and an additional $350 million of publicly-traded notes due in 2015 that are fully and unconditionally guaranteed by Apache. The following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.

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

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 30, 2010


						All Other
			Apache			Subsidiaries
	Apache		Finance			of Apache			Reclassifications
	Corporation		Canada			Corporation			& Eliminations			Consolidated
						(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	960,260	$	—		$	2,086,185		$	—		$	3,046,445
Equity in net income (loss) of affiliates		539,883		(13,113	)		(9,114	)		(517,656	)		—
Other		19,106		(1,429	)		(50,427	)		(1,036	)		(33,786	)

		1,519,249		(14,542	)		2,026,644			(518,692	)		3,012,659


OPERATING EXPENSES:
Depreciation, depletion and amortization		282,721		—			503,516			—			786,237
Asset retirement obligation accretion		12,630		—			12,153			—			24,783
Lease operating expenses		220,092		—			286,464			—			506,556
Gathering and transportation costs		10,439		—			32,401			—			42,840
Taxes other than income		39,456		—			119,171			—			158,627
General and administrative		79,866		—			18,078			(1,036	)		96,908
Financing costs, net		31,120		14,116			14,114			—			59,350

		676,324		14,116			985,897			(1,036	)		1,675,301


INCOME (LOSS) BEFORE INCOME TAXES		842,925		(28,658	)		1,040,747			(517,656	)		1,337,358
Provision (benefit) for income taxes		64,660		(6,431	)		500,864			—			559,093


NET INCOME (LOSS)		778,265		(22,227	)		539,883			(517,656	)		778,265
Preferred stock dividends		13,276		—			—			—			13,276

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	764,989	$	(22,227	)	$	539,883		$	(517,656	)	$	764,989

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


					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
					(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	728,072	$	—	$	1,597,633		$	—		$	2,325,705
Equity in net income (loss) of affiliates		315,186		8,480		(8,100	)		(315,566	)		—
Other		1,240		14,824		(8,302	)		(1,036	)		6,726

		1,044,498		23,304		1,581,231			(316,602	)		2,332,431


OPERATING EXPENSES:
Depreciation, depletion and amortization		228,120		—		397,778			—			625,898
Asset retirement obligation accretion		15,607		—		10,446			—			26,053
Lease operating expenses		193,952		—		251,583			—			445,535
Gathering and transportation costs		8,526		—		27,706			—			36,232
Taxes other than income		27,408		—		156,523			—			183,931
General and administrative		64,001		—		19,527			(1,036	)		82,492
Financing costs, net		58,295		14,110		(10,721	)		—			61,684

		595,909		14,110		852,842			(1,036	)		1,461,825


INCOME BEFORE INCOME TAXES		448,589		9,194		728,389			(315,566	)		870,606
Provision for income taxes		6,573		8,814		413,203			—			428,590


NET INCOME		442,016		380		315,186			(315,566	)		442,016
Preferred stock dividends		1,420		—		—			—			1,420

INCOME ATTRIBUTABLE TO COMMON STOCK	$	440,596	$	380	$	315,186		$	(315,566	)	$	440,596

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2010


					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
					(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,710,575	$	—	$	5,998,260		$	—		$	8,708,835
Equity in net income (loss) of affiliates		1,735,153		50,490		(24,164	)		(1,761,479	)		—
Other		21,904		27,915		(97,725	)		(3,109	)		(51,015	)

		4,467,632		78,405		5,876,371			(1,764,588	)		8,657,820


OPERATING EXPENSES:
Depreciation, depletion and amortization		730,746		—		1,423,740			—			2,154,486
Asset retirement obligation accretion		37,350		—		36,195			—			73,545
Lease operating expenses		557,909		—		834,842			—			1,392,751
Gathering and transportation costs		31,489		—		94,754			—			126,243
Taxes other than income		106,929		—		415,469			—			522,398
General and administrative		224,362		—		54,634			(3,109	)		275,887
Financing costs, net		132,816		42,352		(794	)		—			174,374

		1,821,601		42,352		2,858,840			(3,109	)		4,719,684


INCOME BEFORE INCOME TAXES		2,646,031		36,053		3,017,531			(1,761,479	)		3,938,136
Provision for income taxes		302,562		9,727		1,282,378			—			1,594,667


NET INCOME		2,343,469		26,326		1,735,153			(1,761,479	)		2,343,469
Preferred stock dividends		13,276		—		—			—			13,276

INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,330,193	$	26,326	$	1,735,153		$	(1,761,479	)	$	2,330,193

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


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
							(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,913,223		$	—		$	4,090,440		$	—		$	6,003,663
Equity in net income (loss) of affiliates		(323,601	)		(526,463	)		133,123			716,941			—
Other		1,632			44,138			13,272			(3,071	)		55,971

		1,591,254			(482,325	)		4,236,835			713,870			6,059,634


OPERATING EXPENSES:
Depreciation, depletion and amortization		1,871,151			—			2,726,884			—			4,598,035
Asset retirement obligation accretion		48,082			—			31,192			—			79,274
Lease operating expenses		540,759			—			707,538			—			1,248,297
Gathering and transportation costs		24,222			—			78,828			—			103,050
Taxes other than income		69,696			—			317,515			—			387,211
General and administrative		210,178			—			51,336			(3,071	)		258,443
Financing costs, net		169,706			42,338			(30,618	)		—			181,426

		2,933,794			42,338			3,882,675			(3,071	)		6,855,736


INCOME {LOSS) BEFORE INCOME TAXES		(1,342,540	)		(524,663	)		354,160			716,941			(796,102	)
Provision (benefit) for income taxes		(472,336	)		(131,323	)		677,761			—			74,102


NET LOSS		(870,204	)		(393,340	)		(323,601	)		716,941			(870,204	)
Preferred stock dividends		4,260			—			—			—			4,260

LOSS ATTRIBUTABLE TO COMMON STOCK	$	(874,464	)	$	(393,340	)	$	(323,601	)	$	716,941		$	(874,464	)

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2010


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
							(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(1,173,773	)	$	(43,324	)	$	6,017,291		$	—		$	4,800,194


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(846,356	)		—			(2,194,253	)		—			(3,040,609	)
Additions to gas gathering, transmission and processing facilities		—			—			(328,223	)		—			(328,223	)
Acquisition of Devon properties		(1,017,718	)		—			—			—			(1,017,718	)
Acquisition of BP properties		(2,472,339	)		—			—			—			(2,472,339	)
Acquisitions — other		(28,767	)		—			(31,472	)		—			(60,239	)
Deposit related to acquisition of BP properties		—			—			(3,500,000	)		—			(3,500,000	)
Investment in subsidiaries, net		686,996			—			—			(686,996	)		—
Other, net		(33,236	)		—			(3,531	)		—			(36,767	)

NET CASH USED IN INVESTING ACTIVITIES		(3,711,420	)		—			(6,057,479	)		(686,996	)		(10,455,895	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		—			64			(37,490	)		—			(37,426	)
Intercompany borrowings		—			2,411			(687,119	)		684,708			—
Fixed-rate debt borrowings		1,484,040			—			—			—			1,484,040
Proceeds from issuance of common stock		2,257,772			—			—			—			2,257,772
Proceeds from issuance of depositary shares		1,227,050			—			—			—			1,227,050
Dividends paid		(151,735	)		—			—			—			(151,735	)
Common stock activity, net		28,478			38,757			(41,045	)		2,288			28,478
Treasury stock activity, net		4,190			—			—			—			4,190
Cost of debt and equity transactions		(16,617	)		—			—			—			(16,617	)
Other		23,457			—			(186	)		—			23,271

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,856,635			41,232			(765,840	)		686,996			4,819,023


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(28,558	)		(2,092	)		(806,028	)		—			(836,678	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		646,751			2,097			1,399,269			—			2,048,117


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	618,193		$	5		$	593,241		$	—		$	1,211,439

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


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
							(In thousands)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	983,028		$	(22,377	)	$	1,718,820		$	—		$	2,679,471


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(845,180	)		—			(1,916,147	)		—			(2,761,327	)
Additions to gas gathering, transmission and processing facilities		—			—			(203,783	)		—			(203,783	)
Acquisition of Marathon properties		(181,133	)		—			—			—			(181,133	)
Acquisitions — other		(14,609	)		—			(62,601	)		—			(77,210	)
Short-term investments		791,999			—			—			—			791,999
Restricted cash for acquisition settlement		13,880			—			—			—			13,880
Investment in subsidiaries, net		(308,246	)		—			—			308,246			—
Other, net		(30,770	)		—			(67,326	)		—			(98,096	)


NET CASH USED IN INVESTING ACTIVITIES		(574,059	)		—			(2,249,857	)		308,246			(2,515,670	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		996			60			531,533			(302,413	)		230,176
Payments on fixed-rate notes		—			—			(100,000	)		—			(100,000	)
Dividends paid		(155,125	)		—			—			—			(155,125	)
Common stock activity		19,028			20,606			(14,773	)		(5,833	)		19,028
Treasury stock activity, net		5,344			—			—			—			5,344
Cost of debt and equity transactions		(618	)		—			—			—			(618	)
Other		2,672			—			10,636			—			13,308

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(127,703	)		20,666			427,396			(308,246	)		12,113


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		281,266			(1,711	)		(103,641	)		—			175,914

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


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	423,292		$	3		$	934,069		$	—		$	1,357,364

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of September 30, 2010


					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
					(In thousands)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	618,193	$	5	$	593,241		$	—		$	1,211,439
Receivables, net of allowance		600,753		—		1,156,121			—			1,756,874
Inventories		42,649		—		486,076			—			528,725
Drilling advances		9,091		1,813		202,291			—			213,195
Derivative instruments		89,703		—		128,416			—			218,119
Prepaid taxes		232,885		—		21,357			—			254,242
Prepaid assets and other		2,963,693		—		(2,895,827	)		—			67,866

		4,556,967		1,818		(308,325	)		—			4,250,460


PROPERTY AND EQUIPMENT, NET		13,218,345		—		15,127,771			—			28,346,116


OTHER ASSETS:
Intercompany receivable, net		1,038,592		—		473,756			(1,512,348	)		—
Equity in affiliates		13,034,749		1,222,258		88,054			(14,345,061	)		—
Goodwill, net		—		—		189,252			—			189,252
Deposit related to acquisition of BP properties		—		—		3,500,000			—			3,500,000
Deferred charges and other		167,427		1,002,799		472,295			(1,000,000	)		642,521

	$	32,016,080	$	2,226,875	$	19,542,803		$	(16,857,409	)	$	36,928,349

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	383,020	$	2,323	$	1,725,042		$	(1,512,348	)	$	598,037
Current Debt		—		—		135,369			—			135,369
Accrued exploration and development		258,760		—		769,374			—			1,028,134
Asset retirement obligation		153,298		—		—			—			153,298
Derivative instruments		48,086		—		10,870			—			58,956
Other		247,080		12,523		293,333			—			552,936

		1,090,244		14,846		2,933,988			(1,512,348	)		2,526,730

LONG-TERM DEBT		5,547,464		647,216		185,899			—			6,380,579


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,725,088		4,501		1,852,086			—			3,581,675
Asset retirement obligation		1,109,853		—		838,865			—			1,948,718
Other		598,049		250,000		697,216			(1,000,000	)		545,265

		3,432,990		254,501		3,388,167			(1,000,000	)		6,075,658


COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY		21,945,382		1,310,312		13,034,749			(14,345,061	)		21,945,382

	$	32,016,080	$	2,226,875	$	19,542,803		$	(16,857,409	)	$	36,928,349

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2009


						All Other
						Subsidiaries
	Apache		Apache			of Apache			Reclassifications
	Corporation		Finance Canada			Corporation			& Eliminations			Consolidated
						(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	646,751	$	2,097		$	1,399,269		$	—		$	2,048,117
Receivables, net of allowance		576,379		—			969,320			—			1,545,699
Inventories		50,946		—			482,305			—			533,251
Drilling advances		13,103		1,095			216,535			—			230,733
Derivative instruments		4,303		—			8,915			—			13,218
Prepaid taxes		142,675		—			3,978			—			146,653
Prepaid assets and other		4,573		—			63,605			—			68,178

		1,438,730		3,192			3,143,927			—			4,585,849


PROPERTY AND EQUIPMENT, NET		9,009,753		—			13,890,862			—			22,900,615


OTHER ASSETS:
Intercompany receivable, net		1,973,243		—			(482,366	)		(1,490,877	)		—
Equity in affiliates		11,132,891		980,709			98,615			(12,212,215	)		—
Goodwill, net		—		—			189,252			—			189,252
Deferred charges and other		133,557		1,003,037			373,433			(1,000,000	)		510,027

	$	23,688,174	$	1,986,938		$	17,213,723		$	(14,703,092	)	$	28,185,743


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	258,507	$	(88	)	$	1,629,022		$	(1,490,877	)	$	396,564
Accrued exploration and development		244,188		—			678,896			—			923,084
Current debt		—		—			117,326			—			117,326
Asset retirement obligation		146,654		—			—			—			146,654
Derivative instruments		109,990		—			18,229			—			128,219
Other		237,114		6,121			437,476			—			680,711

		996,453		6,033			2,880,949			(1,490,877	)		2,392,558


LONG-TERM DEBT		4,062,339		647,152			240,899			—			4,950,390


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,347,642		4,429			1,412,830			—			2,764,901
Asset retirement obligation		817,507		—			819,850			—			1,637,357
Other		685,612		250,000			726,304			(1,000,000	)		661,916

		2,850,761		254,429			2,958,984			(1,000,000	)		5,064,174

COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		15,778,621		1,079,324			11,132,891			(12,212,215	)		15,778,621

	$	23,688,174	$	1,986,938		$	17,213,723		$	(14,703,092	)	$	28,185,743


ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Apache Corporation, a Delaware corporation formed in 1954, together with its subsidiaries (collectively, Apache) is one of the world’s largest independent oil and gas companies with exploration and production interests in the United States, Canada, Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea) and Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego.

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

Earnings and Cash Flow

Record production and higher relative prices drove third-quarter 2010 earnings to $765 million, or $2.12 per diluted common share, up from $441 million or $1.30 per share, in the comparable year-ago period. Apache’s 2010 third-quarter adjusted earnings ⁽¹⁾ , which exclude certain items impacting the comparability of results, were $792 million, or $2.19 per diluted common share, compared to $534 million, or $1.58 per share in the year-earlier period. Net cash provided by operating activities increased to $1.7 billion from $1.3 billion in the third quarter of 2009.

For the nine-month period ending September 30, 2010, earnings totaled $2.33 billion, or $6.72 per share, compared to a loss of $874 million, or $2.61 per share in 2009. The 2009 results reflect the impact of a $1.98 billion non-cash after-tax write-down of the carrying value of our U.S. and Canadian proved oil and gas properties. Apache’s 2010 first nine months adjusted earnings ⁽¹⁾ were $2.33 billion, or $6.72 per diluted common share, compared to $1.2 billion, or $3.62 per share, in the year-earlier period. Net cash provided by operating activities increased to $4.8 billion from $2.7 billion in the first nine months of 2009.

The improvement in 2010 third-quarter and nine-month earnings and cash flow relative to the 2009 periods was driven by record third-quarter production and substantially higher price realizations. Third-quarter 2010 production averaged a record 667,460 barrels of oil equivalent per day (boe/d), up 10 percent from 2009. Third-quarter oil production averaged a record 336,795 b/d led by Australia’s Van Gogh and Pyrenees developments, which helped push Australia’s oil production to 56,876 barrels per day (b/d), 46,026 b/d more than the third quarter of 2009. Natural gas production was flat period over period.


⁽¹⁾		See Results of Operations — Non-GAAP Measures — Adjusted Earnings for a description of Adjusted Earnings, which is not a U.S. Generally Accepted Accounting Principles (GAAP) measure, and reconciliation to this measure from Income (Loss) Attributable to Common Stock, which is presented in accordance with GAAP.

BP Asset Acquisitions

Permian Basin On August 10, 2010, Apache completed the acquisition of BP’s oil and gas operations, acreage and related infrastructure in the Permian Basin of west Texas and New Mexico. The acquired assets, net of preferential purchase rights exercised, include interests in several field areas with estimated proved reserves of 124 million barrels of oil equivalent (MMboe), 64 percent liquids, approximately 405,000 net mineral and fee acres, approximately 351,000 leasehold acres and a gas processing plant. First-half 2010 net production averaged 21,800 boe/d. The Company believes that the acreage provides prospective areas with substantial opportunities for new drilling. The agreed-upon purchase price of $3.1 billion was reduced by $653 million for the exercise of preferential rights to purchase. The effective date of the transaction was July 1, 2010, and BP will continue to operate the properties on Apache’s behalf through November 30, 2010.

Western Canada Sedimentary Basin On October 8, 2010, Apache completed its acquisition of substantially all of BP’s Western Canadian upstream natural gas assets, including approximately 1.3 million net mineral and leasehold acres with significant positions in several emerging unconventional plays, including the Montney, Cadomin and Doig. The acquired assets had estimated proved reserves of 224 MMboe (94 percent gas) at June 30, 2010, and first-half 2010 net production of 46,500 boe/d. The effective date of the transaction is July 1, 2010, and Apache Canada Ltd. will take over operations on November 1, 2010. Apache Canada Ltd. paid $3.25 billion for the properties. Certain rights of first refusal are the subject of a court proceeding, as discussed in Note 9 — Commitments and Contingencies of the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10-Q.

Western Desert, Egypt On November 4, 2010, the Company completed its acquisition of BP’s assets in the Western Desert of Egypt. The assets acquired include interests in four development licenses and one exploration concession (East Badr El Din) covering 394,000 net acres south of El Alamein, interests in 65 active wells, and considerable pipeline and processing facilities. These properties had estimated net proved reserves of 20 MMboe (59 percent liquids) as of June 30, 2010, and produced 6,016 b/d and 11 million cubic feet of natural gas per day (MMcf/d) during the first six months of 2010. The purchase price of the Egypt properties was $650 million, of which $250 million was paid in a deposit to BP on July 30, 2010, with the balance paid upon closing.

The Company financed the BP Acquisition by issuing 26.45 million shares of common stock and 25.3 million depositary shares, raising net proceeds of $3.5 billion; securing a bridge loan facility; issuing new term debt and commercial paper; and using existing cash balances. For further discussion of these debt instruments and equity issuances, please see Note 6 - Debt and Note 8 - Capital Stock, respectively, of this Form 10-Q.

Mariner Energy Merger

On April 15, 2010, Apache Corporation and Mariner Energy announced a definitive agreement pursuant to which Apache will acquire Mariner in a stock and cash transaction. At year-end 2009, Mariner had estimated proved reserves of 181 MMboe on properties primarily located in the Gulf of Mexico deepwater and shelf, the Permian Basin and onshore the Gulf Coast encompassing 541,000 net developed and 623,000 net undeveloped acres. During third quarter of 2010 Mariner produced an average 51 Mboe/d, of which 38 percent were liquid hydrocarbons.

The proposed transaction is subject to post-closing regulatory approvals, and a special Mariner shareholder meeting has been scheduled for November 10 to consider and vote to approve the transaction. Should the transaction be approved, Apache expects to issue approximately 17.5 million shares of common stock and pay cash consideration of approximately $800 million to Mariner shareholders. Additionally, Apache will assume Mariner’s debt, which had a fair value of approximately $1.6 billion as of September 30, 2010.

Production following Closing of Recent Acquisitions and Mariner Merger Upon closing of the acquisition of the offshore Gulf of Mexico properties from Devon, the acquisition of BP Properties and following consummation of the Merger with Mariner, a larger percentage of Apache’s total production will be contributed from offshore Gulf of Mexico properties. Apache’s offshore Gulf of Mexico properties contributed 17 percent of our worldwide equivalent production in the third quarter of 2010. We expect Gulf of Mexico deepwater and shelf properties to contribute approximately 19 percent of our worldwide production following the completion of the Mariner Merger.

Impact of Deepwater Horizon explosion and oil spill on Gulf of Mexico operations

In April 2010 a deepwater drilling rig, the Deepwater Horizon, operating in the Gulf of Mexico on Mississippi Canyon Block 252 sank after an apparent blowout and fire, resulting in a large oil spill. Although the well has been capped, remediation of the environmental impacts of the spill is ongoing. Apache does not own an interest in the field.

As a result of the incident and spill, the U.S. Department of the Interior (DOI) issued a series of reforms to the oversight and management of offshore exploration drilling activities on the federal Outer Continental Shelf (the OCS). On May 30, 2010, the Bureau of Ocean Energy Management, Regulatory and Enforcement (the BOEMRE, formerly the Minerals Management Service) of the DOI announced, as a result of the Deepwater Horizon incidents, a Moratorium Notice to Lessees and Operators (Moratorium NTL), which directed oil and gas lessees and operators to cease drilling new deepwater (depths greater than 500 feet) wells on the OCS, and put oil and gas lessees and operators on notice that, with certain exceptions, the BOEMRE would not consider drilling permits for deepwater wells and related activities. On October 12, 2010, the DOI formally lifted the moratorium, although no new permits for deepwater drilling have been issued as of the date of this filing.

In addition, the BOEMRE issued two Notice to Lessees (NTLs), NTL-05 and NTL-06, which focused on increased safety measures and an operator’s plans for a blowout scenario and worst-case discharge scenario. These regulatory changes had effectively halted all permitting activity in the Gulf of Mexico until the DOI on July 16, 2010, issued a permit to Apache under NTL-05 to drill a natural gas well in shallow waters off the southeast coast of Texas. Apache continues to operate under these new rules, and, as of the date of this filing, the Company has received numerous permits under NTL-05 and approval for seven wells that required both NTL-05 and NTL-06 approval. Apache is working with the DOI on other outstanding permit applications.

Operating Highlights

Canada

Kitimat LNG Terminal During the first quarter of 2010 Apache’s wholly-owned subsidiary, Apache Canada Ltd., entered into an agreement with Galveston LNG, Inc. and its wholly-owned subsidiary to acquire a 51–percent interest in Kitimat LNG Inc.’s planned liquefied natural gas (LNG) export terminal (Kitimat LNG terminal) and a 25.5-percent interest in a related proposed pipeline. The Kitimat LNG terminal is to be to be located at Bish Cove near the Port of Kitimat, north of Vancouver, British Columbia. Gross throughput capacity is estimated to be approximately 700 million cubic feet of natural gas per day (MMcf/d), or five million metric tons of LNG per year, of which Apache has reserved 51 percent. The proposed 300-mile pipeline will originate in Summit Lake, British Columbia, and is designed to link the Kitimat LNG terminal to the pipeline system currently servicing western Canada’s natural gas producing regions. Apache will have rights to 350 MMcf/d of the capacity in the proposed pipeline. The project has the potential to open new markets in the Asia-Pacific region for gas from Apache’s Canadian operations, including the Horn River Basin area in northeast British Columbia.

Egypt

Faghur Basin On August 18, 2010, the Company announced two new oil discoveries and a significant appraisal in the Faghur Basin in the far southwest of Egypt’s Western Desert that test-flowed a combined 8,855 b/d and 4.9 MMcf/d.

•

The Pepi-1X well, drilled approximately six miles south of Apache’s Phiops Field, test-flowed at 4,216 b/d and 4.9 MMcf/d.

•

The Buchis South-1X, also about six miles south of Phiops, test-flowed 1,647 b/d.

•

The Faghur-8X step-out appraisal well extended the Faghur Field by 1.6 miles to the east, with one well test-flowing at an average rate of 2,992 b/d.

Apache has drilled five discoveries among eight exploration wells in the Faghur Basin during 2010. Drilling is underway on two wells, and five additional exploration wells are planned. We continue to evaluate 3-D seismic surveys to identify exploration opportunities in the basin, which extends across portions of several Apache-operated concessions.

The Kalabsha oil processing facilities in the Faghur Basin were expanded to 40 thousand barrels of oil per day (Mb/d) in 2010 to meet the needs of these discoveries. These facilities also contributed to the region’s achievement of its goal to double the Company’s gross production in five years. The Company met this goal on May 31, 2010, by, among other things, drilling 869 new wells, constructing new compression and processing facilities and acquiring 3.8 million acres of 3-D seismic during the program.

Australia

Balnaves Discovery On October 14, 2010, Apache announced that three successful wells appraising the Balnaves-1 discovery in License WA-356-P offshore Western Australia will trigger development planning by subsidiary Apache Julimar Ltd Pty. Balnaves is an oil accumulation in the Mungaroo formation in a separate reservoir beneath the large gas reservoirs of the Brunello gas field. The recent Balnaves-3 appraisal well test-flowed 9,076 b/d and 13 MMcf/d from a 16-foot (5-meter) perforated section, confirming good reservoir deliverability. The Balnaves-1 discovery was drilled in 2009 as part of a series of gas exploration and appraisal wells in the Julimar-Brunello complex. Balnaves-1 encountered 64 feet (19.4 meters) of net oil pay in the B20 sand — a light, high-quality oil accumulation at about 10,600 to 10,700 feet (3,230 to 3,260 meters) below sea level. Balnaves-2 was a sidetrack from the discovery, and Balnaves-4 was a sidetrack from Balnaves-3. The Company has a 65-percent interest in the Balnaves discovery.

Macedon Field On September 23, 2010, Apache announced plans to develop the Macedon gas field in the Exmouth Basin in Western Australia. Four offshore production wells will supply gas to an onshore gas processing plant with a capacity of 200 MMcf/d, with first production expected in 2013. After gas is processed at the facility, it will be sent via pipeline for sale in Western Australia’s domestic gas market. Apache has a 28.57-percent interest in the project; BHP Billiton owns the remaining interest and will operate the project. Apache’s share of the estimated $1.5 billion cost is approximately $430 million.

Van Gogh and Pyrenees Oil Developments In February 2010 first oil was produced from the Apache-operated Van Gogh oil field (Apache 52.5 percent) and the BHP-Billiton operated Pyrenees oil field (Apache 28.57 percent). The Van Gogh and Pyrenees developments utilize Floating Production Storage and Offtake (FPSO) vessels and together added 52.5 Mb/d to Apache’s third-quarter 2010 net oil production. The Van Gogh field incurred downtime for 18 days in October 2010 for unplanned maintenance.

Wheatstone LNG Project In October 2009, subsidiaries of Apache, Kuwait Foreign Petroleum Exploration Co., k.s.c. (KUFPEC)signed an exclusive agreement with Chevron to supply gas from the Julimar and Brunello discoveries and become foundation equity partners in the Chevron-operated Wheatstone project facilities in Western Australia. Apache and KUFPEC will supply natural gas from their Julimar and Brunello fields to provide 25 percent of the inlet gas to trains 1 and 2 of the LNG facilities. Apache will assume a 16.25 percent interest equity interest and KUFPEC an 8.75 percent equity interest in the project. Chevron will retain a 75-percent equity interest and remain the project operator. The project, which is currently in the front-end engineering and design (FEED) phase, has the potential to open new markets for gas produced off Western Australia, as well as prices higher than we have historically received for our gas in Western Australia. As a foundation partner, Apache will also have the opportunity to participate in future expansion of the project providing additional options for gas commercialization. Our net capital investment is currently estimated at $1.2 billion for upstream development of the Julimar and Brunello fields and around $3.0 billion for the Wheatstone facilities. The investment in the multi-year project would be funded over several years and a final investment decision (FID) is expected in 2011, upon completion of the FEED. First sales from the facility are projected for 2015.

In July 2010 a nonbinding Heads of Agreement (HOA) was signed with Korea Gas Corporation (KOGAS) to take delivery of 1.5 million tons per annum (MTPA) of LNG, for up to 20 years, from the Wheatstone foundation partners and to acquire an equity share of the field licenses and LNG facilities. Approximately 16.25 percent of the LNG will be purchased from Apache, with the remainder from KUFPEC and Chevron. KOGAS would also acquire a five percent interest in the entire Wheatstone project, comprising a five percent interest in: Apache’s and KUFPEC’s Julimar and Brunello field interests; Chevron’s Wheatstone field licenses; and the Wheatstone project facilities. Apache’s interest in the Wheatstone LNG facilities and its Julimar and Brunello fields, including the capital funding requirements, would be reduced from 16.25 to 15.4375 percent and from 65 to 61.75 percent, respectively.

In October 2010 Apache, KUFPEC and a Chevron subsidiary signed an agreement with Tokyo Electric Power Company (TEPCO) to market LNG produced from their respective fields on a comingled basis. Chevron and TEPCO entered into a nonbinding HOA in December 2009 for the delivery of 3.1 MTPA of LNG from the Wheatstone facilities, for up to 20 years. Approximately 16.25 percent of the LNG under the arrangements with TEPCO will be purchased from Apache.

Results of Operations

Oil and Gas Revenues


	For the Quarter Ended September 30,										For the Nine Months Ended September 30,
	2010					2009					2010					2009
	$		%			$		%			$		%			$		%
	Value		Contribution			Value		Contribution			Value		Contribution			Value		Contribution
								($ in millions)
Total Oil and Gas Revenues:
United States	$	1,060		35	%	$	802		35	%	$	3,015		35	%	$	2,105		35	%
Canada		231		8	%		214		9	%		723		8	%		639		11	%

North America		1,291		43	%		1,016		44	%		3,738		43	%		2,744		46	%

Egypt		822		27	%		697		30	%		2,369		27	%		1,773		30	%
Australia		431		14	%		116		5	%		1,108		13	%		245		4	%
North Sea		410		13	%		411		17	%		1,222		14	%		976		16	%
Argentina		92		3	%		86		4	%		272		3	%		266		4	%

International		1,755		57	%		1,310		56	%		4,971		57	%		3,260		54	%

Total ⁽¹⁾	$	3,046		100	%	$	2,326		100	%	$	8,709		100	%	$	6,004		100	%


Total Oil Revenues:
United States	$	663		29	%	$	524		31	%	$	1,861		29	%	$	1,316		31	%
Canada		88		4	%		86		5	%		279		4	%		221		5	%

North America		751		33	%		610		36	%		2,140		33	%		1,537		36	%

Egypt		697		30	%		565		33	%		2,004		31	%		1,406		33	%
Australia		391		17	%		74		4	%		985		15	%		156		4	%
North Sea		406		18	%		407		24	%		1,211		19	%		967		23	%
Argentina		52		2	%		49		3	%		152		2	%		153		4	%

International		1,546		67	%		1,095		64	%		4,352		67	%		2,682		64	%

Total ⁽²⁾	$	2,297		100	%	$	1,705		100	%	$	6,492		100	%	$	4,219		100	%


Total Gas Revenues:
United States	$	345		50	%	$	257		43	%	$	1,026		50	%	$	743		43	%
Canada		136		20	%		123		21	%		425		21	%		405		24	%

North America		481		70	%		380		64	%		1,451		71	%		1,148		67	%

Egypt		125		18	%		132		22	%		365		18	%		367		21	%
Australia		40		6	%		42		7	%		123		6	%		89		5	%
North Sea		4		1	%		4		1	%		11		1	%		9		1	%
Argentina		33		5	%		32		6	%		95		4	%		99		6	%

International		202		30	%		210		36	%		594		29	%		564		33	%

Total ⁽³⁾	$	683		100	%	$	590		100	%	$	2,045		100	%	$	1,712		100	%


Natural Gas Liquids (NGL) Revenues:
United States	$	52		78	%	$	21		68	%	$	128		74	%	$	46		63	%
Canada		7		11	%		5		16	%		19		11	%		13		18	%

North America		59		89	%		26		84	%		147		85	%		59		81	%

Argentina		7		11	%		5		16	%		25		15	%		14		19	%

Total	$	66		100	%	$	31		100	%	$	172		100	%	$	73		100	%


⁽¹⁾		Financial derivative hedging activities increased oil and gas production revenues by $53.0 million and $104.3 million for the 2010 third quarter and nine-month period, respectively, and by $49.6 million and $157.3 million for the 2009 third quarter and nine-month period, respectively.

⁽²⁾		Financial derivative hedging activities reduced oil revenues by $6.3 million and $32.6 million for the 2010 third quarter and nine-month period, respectively, and increased oil revenues by $3.3 million and $54.9 million for the 2009 third quarter and nine-month period, respectively.

⁽³⁾		Financial derivative hedging activities increased natural gas revenues by $59.3 million and $136.9 million for the 2010 third quarter and nine-month period, respectively, and by $46.3 million and $102.4 million for the 2009 third quarter and nine-month period, respectively.

Production


	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
					Increase							Increase
	2010		2009		(Decrease)			2010		2009		(Decrease)
Oil Volume — b/d:
United States		97,824		88,213		11	%		92,069		87,835		5	%
Canada		13,868		14,595		(5	)%		14,252		15,586		(9	)%

North America		111,692		102,808		9	%		106,321		103,421		3	%

Egypt		99,818		93,550		7	%		96,387		90,848		6	%
Australia		56,876		10,849		424	%		48,324		9,732		397	%
North Sea		58,764		67,288		(13	)%		58,254		62,515		(7	)%
Argentina		9,645		11,026		(13	)%		9,812		11,799		(17	)%

International		225,103		182,713		23	%		212,777		174,894		22	%

Total ⁽¹⁾		336,795		285,521		18	%		319,098		278,315		15	%


Natural Gas Volume — Mcf/d:
United States		736,523		699,062		5	%		694,646		658,507		5	%
Canada		334,945		371,516		(10	)%		329,443		367,562		(10	)%

North America		1,071,468		1,070,578		—			1,024,089		1,026,069		—

Egypt		380,598		372,312		2	%		377,051		355,824		6	%
Australia		197,090		225,349		(13	)%		202,473		176,457		15	%
North Sea		2,372		2,983		(20	)%		2,483		2,771		(10	)%
Argentina		202,381		183,504		10	%		180,219		189,303		(5	)%

International		782,441		784,148		—			762,226		724,355		5	%

Total ⁽²⁾		1,853,909		1,854,726		—			1,786,315		1,750,424		2	%


Natural Gas Liquids (NGL) Volume — b/d:
United States		16,499		7,019		135	%		11,776		5,812		103	%
Canada		2,134		2,166		(1	)%		1,956		2,110		(7	)%

North America		18,633		9,185		103	%		13,732		7,922		73	%
Argentina		3,047		3,291		(7	)%		3,151		3,174		(1	)%

Total		21,680		12,476		74	%		16,883		11,096		52	%


BOE per day ⁽³⁾
United States		237,076		211,742		12	%		219,619		203,397		8	%
Canada		71,827		78,680		(9	)%		71,115		78,957		(10	)%

North America		308,903		290,422		6	%		290,734		282,354		3	%

Egypt		163,251		155,602		5	%		159,228		150,152		6	%
Australia		89,724		48,408		85	%		82,070		39,142		110	%
North Sea		59,159		67,785		(13	)%		58,668		62,977		(7	)%
Argentina		46,423		44,901		3	%		43,000		46,523		(8	)%

International		358,557		316,696		13	%		342,966		298,794		15	%

Total		667,460		607,118		10	%		633,700		581,148		9	%


⁽¹⁾		Approximately 11 percent of worldwide oil production was subject to financial derivative hedges for the 2010 third quarter and nine-month period, and 12 percent and nine percent for the 2009 third quarter and nine-month period, respectively.

⁽²⁾		Approximately 23 and 24 percent of worldwide natural gas production was subject to financial derivative hedges for the 2010 third quarter and nine-month period, respectively, and eight percent for the 2009 third quarter and nine-month period, respectively.

⁽³⁾		The table shows reserves on a barrel of oil equivalent basis (boe) in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.

Pricing


	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
					Increase							Increase
	2010		2009		(Decrease)			2010		2009		(Decrease)
Average Oil Price — Per barrel:
United States	$	73.67	$	64.57		14	%	$	74.05	$	54.89		35	%
Canada		69.01		63.79		8	%		71.76		51.95		38	%
North America		73.09		64.46		13	%		73.74		54.45		35	%
Egypt		75.91		65.64		16	%		76.15		56.67		34	%
Australia		74.80		73.70		1	%		74.66		58.74		27	%
North Sea		75.25		65.76		14	%		76.13		56.68		34	%
Argentina		57.31		48.53		18	%		56.84		47.29		20	%
International		74.66		65.13		15	%		74.91		56.15		33	%
Total ⁽¹⁾		74.14		64.89		14	%		74.52		55.52		34	%

Average Natural Gas Price — Per Mcf:
United States	$	5.10	$	3.99		28	%	$	5.41	$	4.13		31	%
Canada		4.42		3.61		22	%		4.72		4.04		17	%
North America		4.89		3.86		27	%		5.19		4.10		27	%
Egypt		3.57		3.86		(8	)%		3.55		3.78		(6	)%
Australia		2.20		2.04		8	%		2.21		1.85		19	%
North Sea		16.54		14.89		11	%		17.35		11.66		49	%
Argentina		1.79		1.89		(5	)%		1.93		1.92		1	%
International		2.80		2.92		(4	)%		2.86		2.85		—
Total ⁽²⁾		4.01		3.46		16	%		4.19		3.58		17	%

Average NGL Price — Per barrel:
United States	$	34.11	$	33.20		3	%	$	39.66	$	28.87		37	%
Canada		34.18		24.22		41	%		36.58		23.03		59	%
North America		34.12		31.08		10	%		39.22		27.32		44	%
Argentina		26.39		15.44		71	%		28.98		16.13		80	%
Total		33.03		26.96		23	%		37.31		24.12		55	%


⁽¹⁾		Reflects a per-barrel decrease of $.20 and $.37 from financial derivative hedging activities for the 2010 third quarter and nine-month period, respectively, and an increase of $.13 and $.72 from financial derivative hedging activities for the 2009 third quarter and nine-month period, respectively.

⁽²⁾		Reflects a per-Mcf increase of $.35 and $.28 from financial derivative hedging activities for the 2010 third quarter and nine-month period, respectively, and an increase of $.27 and $.21 from financial derivative hedging activities for the 2009 third quarter and nine-month period, respectively.

Third-Quarter 2010 compared to Third-Quarter 2009

Oil and Gas Revenues

Crude Oil Revenues Third-quarter crude oil revenues of $2.3 billion were $592 million higher than the 2009 period on the strength of an 18-percent increase in worldwide production and a 14-percent increase in price. Production averaged 336,795 b/d, while prices averaged $74.14 per barrel. Crude oil accounted for 75 percent of our oil and gas production revenues during the quarter and 50 percent of our equivalent production, compared to 73 and 47 percent, respectively, for the same period last year. Higher production volumes contributed $349 million to the increase in third-quarter revenues, while higher realized prices added another $243 million.

Worldwide oil production increased 51.3 Mb/d, driven by a 46.0 Mb/d increase in Australia’s production. The Van Gogh and Pyrenees developments brought on line in the first quarter of 2010 added 52.5 Mb/d; this increase was partially offset by natural declines and downtime in the region. Total U.S. production increased 11 percent, or 9.6 Mb/d. The Gulf Coast region production was up six percent, or 3.2 Mb/d, primarily from drilling and recompletion activity and properties acquired in the second-quarter 2010 Devon acquisition. The Central region production increased 1.6 Mb/d on drilling activity, while the Permian region rose 4.8 Mb/d on new drilling and properties acquired from BP in August 2010. In Egypt, gross production increased 14 percent while net production was up only seven percent, a function of the mechanics of our production-sharing contracts. Net production increased 6.3 Mb/d with production gains across numerous concessions, particularly the East Bahariya Extension, Matruh and Shushan. The production gains in the Shushan area were related to increased capacity at Kalabsha oil processing facilities. During 2010 capacity was increased from 8 Mb/d at the beginning of the year to 40 Mb/d by the end of the third quarter. This additional capacity allowed us to produce oil from earlier discoveries in the Faghur Basin. Also, infrastructure enhancements allowed us to direct more Matruh condensate-rich gas to the Salam Gas Plant, which has more capacity to process and extract condensate. Production decreased 8.5 Mb/d in the North Sea on natural decline and downtime. Argentina’s production was down 1.4 Mb/d, or 13 percent, and Canada was down .7 Mb/d, or five percent, on natural decline.

Natural Gas Revenues Third-quarter natural gas revenues of $683 million were $93 million higher than the comparable 2009 period as a result of a 16-percent increase in realized prices. Realized prices for the quarter averaged $4.01 per Mcf, an increase of $.55 from third-quarter 2009 prices.

Worldwide production remained relatively unchanged at 1,854 MMcf/d. Total U.S. gas production was up 37.5 MMcf/d, or five percent. Permian region production rose 18.3 MMcf/d on the properties acquired from BP in August 2010 and drilling and recompletion activity, which more than offset natural decline and a change in the region’s marketing strategy. During the second quarter of 2010 we amended certain gas sales contracts to sell natural gas after extraction of NGL. The result was an increase in our NGL volumes and a decrease in natural gas volumes sold. Central region production was up nine percent, or 17.5 MMcf/d, from drilling and recompletion activity. Gulf Coast region production rose 1.7 MMcf/d, with additional production from properties acquired from Devon in the second quarter of 2010 and drilling and recompletion activity essentially offset by the impact of natural decline and downtime. Argentina production was up 18.9 MMcf/d, or 10 percent, on new drilling and recompletion activity. Canada production was 36.6 MMcf/d lower, with natural decline partially offset by drilling and recompletion activity. Production in Australia was down 28.3 MMcf/d on lower customer takes from our Harriet and John Brookes fields. In Egypt, gross production was up seven percent, while net production rose only two percent, a function of the mechanics of our production-sharing contracts. The 8.3 MMcf/d increase in net production was primarily from an increase in Khalda volumes processed through the Obaiyed gas plant and drilling and recompletion activity on our Matruh concession.

Operating Expenses

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


	For the Quarter Ended				For the Quarter Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In millions)				(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment Recurring	$	730	$	576	$	11.90	$	10.31
Other assets		56		50		.90		.90
Asset retirement obligation accretion		25		26		.40		.47
Lease operating expenses		506		446		8.25		7.98
Gathering and transportation		43		36		.70		.65
Taxes other than income		159		184		2.58		3.29
General and administrative expenses		97		82		1.58		1.48
Financing costs, net		59		62		.97		1.10


Total	$	1,675	$	1,462	$	27.28	$	26.18

Depreciation, Depletion and Amortization (DD&A) The following table details the changes in recurring DD&A of oil and gas properties between the third quarters of 2010 and 2009:


	Recurring DD&A
	(In millions)
Third-quarter 2009 DD&A	$	576
Volume change		76
Rate change		78


Third-quarter 2010 DD&A	$	730

Recurring full-cost DD&A expense of $730 million increased $154 million on an absolute dollar basis: $78 million higher on rate and $76 million from higher production. The Company’s full-cost DD&A rate increased $1.59 to $11.90 per boe as the costs to acquire, find and develop reserves exceed our historical cost basis. The recent acquisitions of assets in the Permian Basin from BP and on the Gulf of Mexico shelf from Devon also impacted the current quarter full-cost depletion rate.

Lease Operating Expenses (LOE) Our third-quarter 2010 LOE increased $61 million from third quarter 2009, or 14 percent on an absolute dollar basis. On a per-unit basis LOE increased three percent, with a 13-percent increase on higher cost offset by a 10-percent decline related to increased production. The rate was impacted between the third quarter of 2010 and 2009 by the items below:


	Per boe
Third-quarter 2009 LOE	$	7.98
Equipment rental		0.20
Power and fuel costs		0.11
Repair and maintenance		0.11
FX impact		0.09
Workover costs		0.08
Devon acquisition, net of associated production		0.04
BP acquisition, net of associated production		0.02
Other		0.02
Other increased production		(0.40	)


Third-quarter 2010 LOE	$	8.25

Gathering and Transportation Gathering and transportation costs totaled $43 million in the third quarter of 2010, up $7 million. On a per-unit basis, gathering and transportation costs were up eight percent as the impact from higher costs was partially offset by a decrease in rate related to higher production. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:


	For the Quarter Ended
	September 30,
	2010		2009
	(In millions)
U.S.	$	11	$	9
Canada		18		14
North Sea		7		7
Egypt		6		5
Argentina		1		1


Total Gathering and Transportation	$	43	$	36

Canada’s transportation was up $4 million primarily from the impact of foreign exchange rates and additional volumes transported from new wells in the Horn River Basin. The U.S. increased $2 million primarily from an increase in volumes transported under contracts where charges are paid directly to a third party. Egypt’s costs were up $1 million on an increase in tariff fees.

Taxes other than Income Taxes other than income totaled $159 million, a decrease of $25 million. A detail of these taxes follows:


	For the Quarter Ended
	September 30,
	2010		2009
	(In millions)
U.K. PRT	$	94	$	133
Severance taxes		33		26
Ad valorem taxes		19		13
Canadian taxes		3		5
Other		10		7


Total Taxes other than Income	$	159	$	184

U.K. Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $39 million lower than the 2009 period on a 29-percent decrease in net profits, driven by an 82-percent increase in capital expenditures.

Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The $7 million increase in severance taxes resulted from higher taxable revenues in the U.S., consistent with higher production and prices.

Ad valorem taxes are assessed on U.S. and Canadian property values. The $6 million increase resulted primarily from increased taxable properties related to the Devon and BP Permian Basin acquisitions.

General and Administrative Expenses General and administrative expenses (G&A) were $15 million higher on an absolute basis, or $.10 on a per-unit basis, as a result of higher legal, consulting and other administrative costs related to acquisitions ($8 million) and the Kitimat LNG project ($2 million), as well as an increase in stock-based compensation ($1 million) and various other corporate expenses ($4 million).

Financing Costs, Net Financing costs incurred during the period noted comprised the following:


	For the Quarter Ended
	September 30,
	2010			2009
	(In millions)
Interest expense	$	86		$	77
Amortization of deferred loan costs		7			1
Capitalized interest		(29	)		(14	)
Interest income		(5	)		(2	)

Financing costs, net	$	59		$	62

Net financing costs fell $3 million, or $.13 on a boe basis, primarily as a result of activity related to the acquisition of BP properties discussed above. Interest expense increased as a result of the 5.1-percent notes due in 2040 issued in August 2010. In addition, loan costs of $6 million related to the unsecured bridge facility were fully amortized during the quarter.

The provision for income taxes increased $131 million to $559 million as income before taxes increased on higher oil and gas production revenues. The effective income tax rate in the third quarter of 2010 was 41.8 percent compared to 49.2 percent in the third quarter of 2009. The 2010 rate was impacted by a $27 million non-cash expense related to the weakening U.S. dollar compared to $93 million non-cash charge related to the effect of the weakening U.S. dollar in 2009.

Year-to-Date 2010 compared to Year-to-Date 2009

Oil and Gas Revenues

Crude Oil Revenues Year-to-date 2010 crude oil revenues of $6.5 billion were $2.3 billion higher than the 2009 period on a 34-percent rise in price and a 15-percent increase in worldwide production. Production averaged 319,098 b/d, with prices averaging $74.52 per barrel. Crude oil represented 75 percent of our oil and gas production revenues during the period and 50 percent of our equivalent production, compared to 70 and 48 percent, respectively, for the same period last year. Higher realized prices contributed $1.44 billion to the increase in nine-month revenues, while higher production volumes added another $830 million.

Worldwide oil production increased 40.8 Mb/d, driven by the Van Gogh and Pyrenees developments in Australia, which were brought online in the first quarter of 2010. These developments, which added 40.6 Mb/d to the nine-month production period, were the primary factor driving Australia’s production to 48.3 Mb/d, up 38.6 Mb/d from the comparative year-ago nine-month period. In Egypt, gross production increased 15 percent, while net production was up only six percent, a function of the mechanics of our production-sharing contracts. Net production increased 5.5 Mb/d on production gains across numerous concessions, particularly the Shushan and Matruh. The production gains in the Shushan area were related to the additional capacity at the Kalabsha oil processing facility, as discussed in the quarterly comparisons. The gains at Matruh were attributed to the infrastructure improvements discussed in the quarterly comparisons. Total U.S. production increased five percent, or 4.2 Mb/d. The Gulf Coast region production was up 1.2 Mb/d primarily from drilling and recompletion activity and properties acquired in the Devon acquisition. Central region production increased .8 Mb/d on drilling activity, while the Permian region rose 2.2 Mb/d on new drilling and acquisitions. Production decreased 4.2 Mb/d in the North Sea on natural decline and downtime. Argentina declined 2.0 Mb/d on natural decline. Canada’s production dropped 1.3 Mb/d on declines in several areas.

Natural Gas Revenues Natural gas revenues for the nine-month period of 2010 of $2.0 billion were $333 million higher than the comparable 2009 period as a result of a 17-percent increase in realized prices and a two-percent increase in production volumes. The $.61 per Mcf increase in realized prices for the nine-month period of 2010, which averaged $4.19 per Mcf, added $291 million to revenues. Worldwide production rose to 1,786 MMcf/d, adding another $41 million to revenues.

Worldwide gas production rose 35.9 MMcf/d on increases in the U.S., Australia and Egypt. Total U.S. production was up 36.2 MMcf/d, or five percent. Gulf Coast region production was up 29.0 MMcf/d, with additional production resulting from new drilling, recompletion activity and properties acquired from Devon more than offsetting natural decline and downtime. Permian region production was up 6.7 MMcf/d on drilling and acquisitions, partially offset by natural decline and a change in the region’s natural gas marketing strategy as previously discussed. The new marketing strategy resulted in an increase in volumes of NGL sold, and an associated decrease in the volumes of natural gas sold. Production in Australia was up 26.0 MMcf/d on higher customer takes from our John Brookes field. In Egypt, gross production was up 15 percent, while net production rose only six percent, a function of our production-sharing contracts. The 21.2 MMcf/d increase in net production relative to the 2009 nine-month period was attributable to several factors: a successful drilling and recompletion program on our Matruh concession; a full nine months of processing through trains three and four at the Salam Gas Plant that were brought on line during the first half of 2009, plus completion of a 2009 project to increase compression in the Northern Gas Pipeline; and an increase in Khalda volumes processed through the Obaiyed gas plant. The additional capacity enabled Apache to increase production from previous discoveries on our Khalda Concession Qasr field and Jade and Falcon fields on our Matruh Concession. Natural decline pushed Canada’s production down 38.1 MMcf/d. Argentina’s production was down 9.1 MMcf/d on natural decline.

Operating Expenses


	For the Nine Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In millions)				(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment Recurring	$	1,994	$	1,638	$	11.52	$	10.33
Additional		—		2,818		—		17.76
Other assets		161		142		.93		.89
Asset retirement obligation accretion		74		79		.43		.50
Lease operating expenses		1,393		1,248		8.05		7.87
Gathering and transportation		126		103		.73		.65
Taxes other than income		522		387		3.02		2.44
General and administrative expenses		276		259		1.59		1.63
Financing costs, net		174		182		1.01		1.14


Total	$	4,720	$	6,856	$	27.28	$	43.21

Depreciation, Depletion and Amortization (DD&A) The following table details the changes in recurring DD&A of oil and gas properties between the nine-month periods of 2010 and 2009:


	Recurring DD&A
	(In millions)
2009 DD&A	$	1,638
Volume change		185
Rate change		171


2010 DD&A	$	1,994

Recurring full-cost DD&A expense of $1.99 billion increased $356 million on an absolute dollar basis: $185 million from higher production and $171 million on rate. The Company’s full-cost DD&A rate increased $1.19 to $11.52 per boe. The increase in rate is the result of adding new reserves, through both drilling and acquisitions, at a cost per boe that is higher than the average historical cost of reserves at the beginning of the period.

In the first quarter of 2009 we recorded a $2.82 billion ($1.98 billion net of tax) 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. Until December 31, 2009, the rules generally required pricing future oil and gas production at the unescalated oil and gas prices and costs in effect at the end of each fiscal quarter. Effective December 31, 2009, estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month in the prior 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. The rules also generally require the estimation of future costs in effect at the end of each fiscal quarter. Write-downs required by these rules do not impact cash flow from operating activities.

Lease Operating Expenses (LOE) Our first nine months of 2010 LOE increased $145 million from the first nine months of 2009, or 12 percent, on an absolute dollar basis. On a per-unit basis, LOE increased $.18, or two percent, with an 11-percent increase on higher costs mostly offset by a nine-percent increase in production. The rate was impacted between the first nine months of 2010 and 2009 by the items below:


	Per boe
2009 LOE	$	7.87
FX impact		0.24
Equipment rental		0.18
Workover costs		0.13
Labor and pumper costs		0.09
Stock-based compensation		0.08
Devon acquisition, net of associated production		0.07
Other		(0.01	)
Other increased production		(0.60	)


2010 LOE	$	8.05

Gathering and Transportation Gathering and transportation costs totaled $126 million in the first nine months of 2010, up $23 million. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:


	For the Nine Months
	Ended
	September 30,
	2010		2009
	(In millions)
U.S.	$	32	$	25
Canada		50		38
North Sea		19		20
Egypt		21		17
Argentina		4		3


Total Gathering and Transportation	$	126	$	103

The $7 million increase in the U.S. resulted primarily from an increase in volumes transported under contracts where charges are paid directly to a third party. Canada’s transportation was up $12 million primarily from the impact of foreign exchange rates, higher gas transportation rates and additional volumes transported from new wells in the Horn River Basin. Egypt’s costs were up $4 million on an increase in tariff fees.

Taxes other than Income Taxes other than income totaled $522 million, an increase of $135 million. A detail of these taxes follows:


	For the Nine Months Ended
	September 30,
	2010		2009
	(In millions)
U.K. PRT	$	346	$	256
Severance taxes		93		61
Ad valorem taxes		54		34
Canadian taxes		4		13
Other		25		23

Total Taxes other than Income	$	522	$	387

U.K. PRT is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $90 million more than the 2009 period on a 34-percent increase in net profits driven by a 34-percent increase in realized oil prices.

Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The $32 million increase in severance taxes resulted from higher taxable revenues in the U.S., consistent with higher prices and production.

Ad valorem taxes are assessed on U.S. and Canadian property values. The $20 million increase comprised an $18 million increase in the U.S. as a result of increased taxable property assessments in the Permian Basin, higher commodity prices and additional properties related to the Devon and BP Permian Basin acquisitions, and a $2 million increase in Canada resulting from an increase in the property tax rate and foreign exchange fluctuations.

General and Administrative Expenses G&A were $17 million higher on an absolute basis, but on a per-unit basis were down $.04. Lower employee separation costs ($39 million) were offset by higher administrative costs related to acquisitions ($16 million), higher stock-based compensation ($13 million), an increase in other incentive compensation ($9 million), administrative costs for the Kitimat LNG project ($4 million) and various other corporate expenses ($14 million).

Financing Costs, Net Financing costs incurred during the periods noted comprised the following:


	For the Nine Months Ended
	September 30,
	2010			2009
	(In millions)
Interest expense	$	237		$	233
Amortization of deferred loan costs		10			4
Capitalized interest		(64	)		(45	)
Interest income		(9	)		(10	)

Financing costs, net	$	174		$	182

Net financing costs fell $8 million, or $.13 on a boe basis, primarily as a result of activity related to the acquisition of BP properties discussed above. Interest expense increased as a result of the 5.1-percent notes due in 2040 issued in August 2010. In addition, loan costs of $6 million related to the unsecured bridge facility were fully amortized during the quarter.

Provision for Income Taxes During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year, after consideration of discrete items. No material discrete items were recorded in the first nine months of 2010. The Company’s first-quarter 2009 non-cash write-down of the carrying value of its proved oil and gas properties was deemed a discrete event. No other significant discrete tax events occurred during 2009.

The provision for income taxes for the first nine months of 2010 was $1.6 billion compared to $74 million in the 2009 period. The 2010 nine-month effective income tax rate was 40.5 percent. The calculation of the 2009 effective income tax rate is not meaningful because of the magnitude of the non-cash write-down of the carrying value of our proved oil and gas properties. Absent the write-down, the 2009 effective rate would have been 45 percent. We recorded a $2 million charge to tax expense in 2010 related to foreign currency fluctuations, compared to a $116 million expense in 2009.

Non-GAAP Measures

The Company makes reference to some measures in discussion of its financial and operating highlights that are not required by or presented in accordance with GAAP. Management uses these measures in assessing operating results and believes the presentation of these measures provides information useful in assessing the Company’s financial condition and results of operations. These non-GAAP measures should not be considered as alternatives to GAAP measures and may be calculated differently from, and therefore may not be comparable to, similarly-titled measures used at other companies.

Adjusted Earnings

To assess the Company’s operating trends and performance, management uses Adjusted Earnings, which is net income excluding certain items that management believes affect the comparability of operating results. Management believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings for items that may obscure underlying fundamentals and trends. The reconciling items below are the types of items management excludes and believes are frequently excluded by analysts when evaluating the operating trends and comparability of the Company’s results.


	For the Quarter Ended				For the Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In millions, except per share data)
Income (Loss) Attributable to Common Stock (GAAP)	$	765	$	441	$	2,330	$	(874	)

Adjustments:
Foreign currency fluctuation impact on deferred tax expense		27		93		2		116
Additional depletion, net of tax ⁽¹⁾		—		—		—		1,981

Adjusted Earnings (Non-GAAP)	$	792	$	534	$	2,332	$	1,223


Adjusted Earnings Per Share (Non-GAAP)
Basic	$	2.22	$	1.59	$	6.78	$	3.64

Diluted	$	2.19	$	1.58	$	6.72	$	3.62


Average Number of Common Shares
Basic		357		336		344		336

Diluted		367		338		349		337


⁽¹⁾		Additional depletion (non-cash write-down of the carrying value of proved property) recorded in 2009 was $2,818 million pre-tax, for which a deferred tax benefit of $837 million was recognized. The tax effect of the write-down of the carrying value of proved property (additional depletion) in 2009 was calculated utilizing the statutory rates in effect in each country where a write-down occurred.

Capital Resources and Liquidity

Net cash provided by operating activities (operating cash flows or cash flows) is our primary source of liquidity. Our cash flows, both in the short-term and the long-term, are impacted by fluctuations in oil and natural gas prices. Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash flows, and potentially our liquidity, if costs do not trend downward as well. Apache enters into hedges on a portion of its crude oil and natural gas production to help manage these fluctuations. For information regarding our current hedges, please refer to Note 3 — Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10-Q. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactive as commodity prices in the short-term.

Our long-term operating cash flows are also dependent in part on reserve replacement and the level of costs required for ongoing operations. Our business, as with other extractive industries, is a depleting one in which each unit produced must be replaced or the Company and our reserves, a critical source of future liquidity, will shrink. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities or our ability to acquire additional reserves at reasonable costs.

We may also elect to utilize available committed borrowing capacity, debt and equity capital markets or proceeds from the occasional sale of nonstrategic assets for all other liquidity and capital resource needs, including the funding of significant acquisitions.

Our primary uses of cash are exploration, development and acquisition of oil and gas properties, costs necessary to maintain ongoing operations, repayment of principal and interest on outstanding debt and payment of dividends. We fund our exploration and development activities primarily through net cash flows and budget our capital expenditures based on projected cash flows.

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.

See Part II, Item 1A, “Risk Factors” of this Form 10-Q and Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors Related to Our Business and Operations,” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Sources and Uses of Cash and Cash Equivalents

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


	For the Nine Months Ended
	September 30,
	2010			2009
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	4,800		$	2,679
Fixed-rate borrowings		1,484			—
Proceeds from issuance of common stock		2,258			—
Proceeds from issuance of mandatory convertible preferred stock		1,227			—
Sale of short-term investments		—			792
Net commercial paper and bank loan borrowings		—			230
Restricted cash		—			14
Common and treasury stock activity		32			24
Other		23			13

		9,824			3,752


Uses of Cash and Cash Equivalents:
Capital expenditures ⁽¹⁾	$	3,369		$	3,042
Oil and gas acquisitions		3,550			181
Deposit related to acquisition of BP properties		3,500			—
Payments on fixed-rate notes		—			100
Dividends		152			155
Net commercial paper and bank loan repayments		37			—
Other		53			98

		10,661			3,576

Increase (decrease) in cash and cash equivalents	$	(837	)	$	176


⁽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 Operating cash flows for the first nine months of 2010 totaled $4.8 billion, up $2.1 billion from the first nine months of 2009. The increase in 2010 cash flows is primarily attributable to higher commodity prices, higher sales volumes and the impact of changes of working capital. These benefits were partially offset by increases in lease operating expenses, taxes other than income and current income tax expenses.

Factors affecting operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, ARO accretion and deferred income tax expense. For a discussion of commodity prices, production, costs and expenses, refer to the “Results of Operations” of this Item 2. For additional detail of changes in operating assets and liabilities, see the Statement of Consolidated Cash Flows in Part I, Item 1, Financial Statements of this Form 10-Q.

Fixed-Rate Borrowings On August 20, 2010, the Company issued $1.5 billion principal amount of senior unsecured 5.1-percent notes maturing September 1, 2040. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The proceeds were used to repay borrowings under the Company’s bridge facility and commercial paper program.

Proceeds from Issuance of Common Stock On July 28, 2010, in conjunction with Apache’s acquisition of properties from BP plc, the Company issued 26.45 million shares of common stock at a public offering price of $88 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering totaled approximately $2.3 billion.

Proceeds from Issuance of Mandatory Convertible Preferred Stock On July 28, 2010, Apache issued 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D, with an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). The Company received proceeds of approximately $1.2 billion, after underwriting discounts and before expenses, from the sale.

Capital Expenditures (Accrual Basis) Capital expenditures, including acquisitions, totaled $7.1 billion for the first nine months of 2010, compared to $2.9 billion for the comparable period last year. The following table details capital expenditures for each country in which we do business for the nine months ended September 30, 2010 and 2009:


	For the Nine Months
	Ended September 30,
	2010		2009
	(In millions)
Exploration and Development Expenditures:
United States	$	1,039	$	748
Canada		593		313

North America		1,632		1,061


Egypt		510		535
Australia		401		421
North Sea		437		293
Argentina		167		109
Chile		20		4

International		1,535		1,362

Worldwide Exploration and Development Expenditures		3,167		2,423


Gathering Transmission and Processing Facility Expenditures:
Canada		107		69
Egypt		111		110
Australia		102		23
Argentina		2		2

Total Gathering Transmission and Processing Facility Expenditures		322		204


Capitalized Interest		64		45


Capital Expenditures, excluding acquisitions	$	3,553	$	2,672


Acquisition Capital Expenditures	$	3,550	$	258

Worldwide exploration and development (E&D) expenditures were $744 million, or 31 percent, higher than the 2009 comparable nine-month period. E&D expenditures in the U.S. rose $291 million, or 39 percent, primarily on drilling activity in the Central and Permian regions, and accounted for 33 percent of total E&D activity in the first nine months of 2010, up from 31 percent in 2009. Canada E&D expenditures totaled $593 million, representing 19 percent of nine-month 2010 worldwide E&D expenditures. The $280 million increase from the comparable 2009 period was primarily associated with increased drilling activity in the Horn River Basin. Egypt accounted for 16 percent of worldwide E&D spending for the first nine months of 2010, compared to 22 percent in the prior-year period, down $25 million on less drilling activity and lower well costs. Australia’s E&D expenditures were down $20 million and represented 13 percent of total expenditures. North Sea’s E&D expenditures increased $144 million and represented 14 percent of worldwide E&D expenditures. Argentina’s E&D expenditures, which represented five percent of E&D spending, rose $58 million on increased drilling activity. Chile’s E&D expenditures increased $16 million and represented less than one percent of worldwide E&D expenditure spending.

Gathering, transmission and processing (GTP) facility expenditures totaled $322 million in the first nine months of 2010. GTP expenditures in Australia consisted of construction activity at the Devil Creek gas plant and the FEED study for the Wheatstone LNG project. Activity in Canada was centered in the Horn River Basin, with expenditures for compressor stations, a water treatment facility, gathering systems and a gas processing plant. Expenditures in Egypt included the initial phases of the Kalabsha oil processing facility.

Oil and Gas Acquisitions On June 9, 2010, we completed the acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon for $1.05 billion. The acquisition was effective as of January 1, 2010. On August 10, 2010, Apache completed the acquisition of all of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of West Texas and New Mexico. Apache paid $2.5 billion for the Permian properties, net of preferential purchase rights exercised by partners. The effective date of the transaction was July 1, 2010.

Deposit Related to Acquisition of BP Properties At September 30, 2010, a $3.5 billion deposit, of which $3.25 billion was related to the purchase of the BP Canadian properties and $250 million was related to the BP Egyptian properties, was recorded as a long-term asset on Apache’s consolidated balance sheet. For additional information on the transactions, please see Note 2 – Acquisitions of the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10-Q. Subsequent to September 30, 2010, both acquisitions were closed, and the associated deposits were applied to the purchase price of the assets.

Dividends For the nine-month periods ended September 30, 2010 and 2009, the Company paid $152 million and $151 million, respectively, in dividends on its common stock. In the first nine months of 2009, Apache paid a total of $4.3 million in dividends on its Series B Preferred Stock issued in August 1998. The Company redeemed all outstanding shares of its Series B Preferred Stock on December 30, 2009. Dividend payments on the Company’s Series D Preferred Stock commenced on November 1, 2010.

Liquidity

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


	September 30,			December 31,
	2010			2009
	(In millions, except as indicated)
Cash and cash equivalents	$	1,211		$	2,048
Total debt		6,516			5,067
Shareholders’ equity		21,945			15,779
Available committed borrowing capacity		3,300			2,300
Floating-rate debt/total debt		5	%		7	%
Percent of total debt-to-capitalization		23	%		24	%

Cash and Cash Equivalents We had $1.2 billion in cash and cash equivalents as of September 30, 2010, compared to $2.0 billion at December 31, 2009. Approximately $590 million of the cash was held by foreign subsidiaries, with the remaining balance held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid investment grade securities with maturities of three months or less at the time of purchase.

Debt As of September 30, 2010, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $6.5 billion. Current debt includes $115 million of loans under the Apache PVG Pty Ltd facility due over the next 12 months and $20.4 million borrowed under uncommitted overdraft lines in Argentina and Canada.

On July 20, 2010, in connection with the acquisition of certain BP properties, the Company entered into a term loan agreement that initially provided a $5.0 billion unsecured bridge facility with a September 29, 2010, maturity, unless extended at the Company’s option until December 29, 2010. The commitment under the facility was subsequently reduced by $3.5 billion to reflect receipt of the net proceeds from the issuance of common and preferred stock on July 28, 2010, as discussed in Note 8 — Capital Stock of the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10-Q. On August 10, 2010, the Company borrowed $1.0 billion under the bridge facility to finance a portion of the consideration for the acquisition and subsequently repaid the bridge facility borrowings and terminated the bridge facility on August 20, 2010. Apache incurred $6 million of loan costs related to this bridge facility that were charged to financing costs upon termination of the facility.

The Company was in compliance with the terms of all credit facilities as of September 30, 2010.

Available committed borrowing capacity As of September 30, 2010, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2011 and $2.3 billion matures in May 2013. These consist of a new $1.0 billion 364-day facility, a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. Since there are no outstanding borrowings or commercial paper at quarter-end, the full $3.3 billion of committed credit capacity is available to the Company.

The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100-percent backstop.

Percent of total debt to capitalization The Company’s September 30, 2010, debt-to-capitalization ratio was 23 percent, down from 24 percent at December 31, 2009.

Impact of Mariner Merger in Fourth-Quarter 2010

On April 15, 2010, Apache and Mariner announced that they entered into a definitive agreement pursuant to which Apache will acquire Mariner in a stock and cash transaction. The Merger Agreement, by and among Apache, Mariner and the Merger Sub, contemplates a Merger whereby Mariner will be merged into Merger Sub, with Merger Sub surviving the Merger as a wholly owned subsidiary of Apache. For a detailed discussion of the Merger, please see Note 2 — Acquisitions of the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10-Q.

If the outstanding conditions for closing the Merger are satisfied, including the adoption of the Merger Agreement by stockholders of Mariner, Apache expects to issue approximately 17.5 million shares of common stock (an increase of approximately five percent in our outstanding common shares) and pay cash of approximately $800 million to Mariner stockholders. Apache intends to fund the cash portion of the consideration with existing cash balances and commercial paper. Upon consummation of the Merger, Apache will assume Mariner’s debt, which had a fair value of approximately $1.6 billion as of September 30, 2010. Apache estimates it will ultimately incur approximately $130 million in costs related to the Merger.

Additional information about Apache

Insurance

We maintain insurance coverage that includes coverage for physical damage to our oil and gas properties, third party liability, workers’ compensation and employers’ liability, general liability, sudden pollution and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

In general, our current insurance policies covering physical damage to our oil and gas assets provide $250 million per occurrence with an additional $250 million per year. Coverage for damage to our U.S. Gulf of Mexico assets specifically resulting from a named windstorm, however, is subject to a maximum of $250 million per named windstorm, includes a self-insured retention of 40 percent of the losses above a $100 million deductible, and is limited to no more than two storms per year. In addition, our policies covering physical damage to our North Sea oil and gas assets provide $250 million per occurrence with an additional $750 million per year.

Our various insurance policies also provide coverage for, among other things, liability related to negative environmental impacts of a sudden pollution event in the amount of $750 million per occurrence, charterer’s legal liability, in the amount of $1 billion per occurrence, aircraft liability in the amount of $750 million per occurrence, and general liability, employer’s liability and auto liability in the amount of $500 million per occurrence. Our service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

Our insurance policies generally renew in January and June of each year, with the next renewals scheduled for 2011. In light of the recent catastrophic accident in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.

Remediation Plans and Procedures

Apache adopted a Region Spill Response Plan (the Plan) for its Gulf of Mexico operations to ensure a rapid and effective response to spill events that may occur on Apache-operated properties. Periodically, drills are conducted to measure and maintain the effectiveness of the Plan. These drills include the participation of spill response contractors, representatives of the Clean Gulf Associates (CGA, described below), and representatives of governmental agencies. The primary association available to Apache in the event of a spill is CGA. Apache has received approval for the Plan from the BOEMRE. Apache personnel review the Plan annually and update where necessary.

Apache is a member of, and has an employee representative on the executive committee of, CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. To this end, CGA has bareboat chartered (an arrangement for the hiring of a boat with no crew or provisions included) its marine equipment to the Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, which is funded by grants from the Marine Preservation Association. MSRC maintains CGA’s equipment (currently including 13 shallow water skimmers, four fast response vessels with skimming capabilities, nine fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities and dispersant inventory) at various staging points around the Gulf of Mexico in its ready state, and in the event of a spill, MSRC stands ready to mobilize all of this equipment to CGA members. MSRC also handles the maintenance and mobilization of CGA non-marine equipment. In addition, CGA maintains a contract with Airborne Support Inc. (ASI), which provides aircraft and dispersant capabilities for CGA member companies. Apache’s annual fees to CGA for 2009 consisted of $213,445 based on a $12,800 per capita charge plus $200,645 based on annual production of approximately 24 million barrels of oil equivalent.

In the event that CGA resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited has access to resources from the Global Response Network, a collaboration of seven major oil industry funded spill response organizations worldwide. Oil Spill Response Limited has equipment stockpiles in Bahrain, Singapore and Southampton that currently include approximately 153 skimmers, booms (of approximately 12,000 meters), two Hercules aircraft for equipment deployment and aerial dispersant spraying, two additional aircraft, dispersant spray systems and dispersant, floating storage tanks, all terrain vehicles (ATV) and various other equipment. If necessary, Oil Spill Response Limited’s resources may be, and have been, deployed to areas across the globe, such as the Gulf of Mexico. In addition, resources of other organizations are available to Apache as a non-member, such as those of MSRC and National Response Corporation (NRC), albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment, currently including 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 240 skimming systems, six self-propelled skimming vessels, seven mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels and dispersant aircraft. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland work boats, vacuum transfer units and mobile communication centers. NRC has access to a vessel fleet of more than 328 offshore vessels and supply boats worldwide, as well as access to hundreds of tugs and oil barges from its tug and barge clients. The equipment and resources available to these companies changes from time-to-time and current information is generally available on each of the companies’ websites.

In light of the current events in the Gulf of Mexico, Apache is participating in a number of industry-wide task forces that are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.

Competitive Conditions

The oil and gas business is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, gas and natural gas liquids. Our competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies and participants in other industries supplying energy and fuel to industrial, commercial and individual consumers.

Certain of our competitors may possess financial or other resources substantially larger than we possess or have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for leases or drilling rights.

However, we believe our diversified portfolio of core assets, which is comprised of large acreage positions and well established production bases across six countries, and our balanced production mix between oil and gas give us a strong competitive position relative to many of our competitors who do not possess similar political, geographic and production diversity. Our global position provides a large inventory of geologic and geographic opportunities in the six countries in which we have producing operations to which we can reallocate capital investments in response to changes in local business environments and markets. It also reduces the risk that we will be materially impacted by an event in a specific area or country.

Environmental Compliance

As an owner or lessee and operator of oil and gas properties, we are subject to numerous federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.

We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We have established operating procedures and training programs designed to limit the environmental impact of our field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, we do not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on our capital expenditures, earnings or competitive position.

Changes to existing, or additions of, laws, regulations, enforcement policies or requirements in one or more of the countries or regions in which we operate could require us to make additional capital expenditures. While the recent events in the U.S. Gulf of Mexico have resulted in the enactment of, and may result in the enactment of additional, laws or requirements regulating the discharge of materials into the environment, we do not believe that any such regulations or laws enacted or adopted as of this date will have a material adverse impact on Apache’s cost of operations, earnings or competitive position.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather and climate. Our average crude oil realizations have increased 34 percent to $74.52 per barrel in the first nine months of 2010 from $55.52 per barrel in the comparable period of 2009. Our average natural gas price realizations have also trended upward, increasing 17 percent to $4.19 per Mcf from $3.58 per Mcf in the comparable period of 2009.

Global oil prices are generally priced in U.S. dollars, with a weaker U.S. dollar often leading to higher prices and a stronger U.S. dollar often resulting in lower prices.

We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. For the third quarter and first nine months of 2010 our natural gas production was subject to financial derivative hedges of approximately 23 and 24 percent, respectively, and our crude oil production was subject to financial derivative hedges of approximately 11 percent in both periods.

Apache may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from the Company’s price-risk management activities are recognized in oil and gas production revenues when the associated production occurs. Apache does not generally hold or issue derivative instruments for trading purposes.

On September 30, 2010, the Company had open natural gas derivative hedges in an asset position with a fair value of $454 million. A 10-percent increase in natural gas prices would reduce the fair value by approximately $87 million, while a 10-percent decrease in prices would increase the fair value by approximately $87 million. The Company also had open oil derivatives in a liability position with a fair value of $226 million. A 10-percent increase in oil prices would increase the liability by approximately $238 million, while a 10-percent decrease in prices would decrease the liability by approximately $217 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2010. For notional volumes and terms associated with the Company’s derivative contracts, please see Note 3 — Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10-Q.

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 September 30, 2010, total debt included $320 million of floating-rate debt. As a result, Apache’s annual interest costs in 2010 will fluctuate based on short-term interest rates on what is approximately five percent of our total debt outstanding at September 30, 2010. The impact on cash flow of a 10-percent change in the floating interest rate from that at September 30, 2010, would be approximately $148,800 per quarter.

Foreign Currency Risk

The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts, and the majority of our gas production is sold under fixed-price Australian dollar contracts. Approximately half of our costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil and gas prices and costs, such as equipment rentals and services, are generally denominated in Canadian dollars but heavily influenced by U.S. markets. Our North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars, but are converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, Egyptian pounds and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other,” or, as is the case when we remeasure our foreign tax liabilities, as a component of the Company’s provision for income taxes on the statement of consolidated operations in Item 1 of this quarterly report. A 10-percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, Egyptian pound and Argentine peso as of September 30, 2010, would result in a cumulative foreign currency net loss or gain, respectively, of approximately $13 million.

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, 2009, 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;

	•		approval of the Mariner Merger by Mariner stockholders and the timing of the closing of the Merger;

	•		the satisfaction of the closing conditions of the Mariner Merger;

	•		negative effects from the pendency of the Mariner Merger;

	•		the retention of key employees of Mariner;

	•		the integration of Mariner following completion of the Merger;

	•		the diversion of management’s time on issues related to the Mariner Merger and the BP Acquisition;

	•		the integration of the BP Properties;

	•		preferential purchase rights may be exercised with respect to certain of the BP Properties

	•		increased scrutiny from regulatory agencies due to the BP Acquisition;

	•		the significant transaction and BP Acquisition related costs associated with the BP Acquisition;

	•		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, other risks and uncertainties detailed in our first-quarter 2010 earnings release, and other filings that we make with the Securities and Exchange Commission.

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 September 30, 2010, 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.

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, 2009 (filed with the SEC on March 1, 2010) and Part I, Item 1 of each of our Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31, 2010, June 30, 2010, and September 30, 2010, for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

Please refer to the risk factors as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. For the nine months ending September 30, 2010, Apache notes the following additional risk factors:

Our operations involve a high degree of operational risk, particularly risk of personal injury, damage or loss of equipment and environmental accidents.

Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:

	•		drilling well blowouts, explosions and cratering;

	•		pipeline ruptures and spills;

	•		fires;

	•		formations with abnormal pressures;

	•		equipment malfunctions; and

	•		hurricanes, which could affect our operations in areas such as the Gulf Coast and deepwater Gulf of Mexico, and other natural disasters.

Failure or loss of equipment, as the result of equipment malfunctions or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flow and, in turn, our results of operations could be materially and adversely affected.

Risks Relating to the Mariner Merger

Uncertainty about the effect of the Merger on Mariner Energy, Inc.’s (Mariner) employees may have an adverse effect on Mariner and consequently Apache.

The uncertainty created by the pending Merger may impair Mariner’s ability to attract, retain and motivate key personnel until the Merger is completed as current and prospective employees may experience uncertainty about their future roles with Apache. If key employees of Mariner depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become Apache employees, Apache’s ability to realize the anticipated benefits of the Merger could be reduced or delayed.

The pendency of the Merger could adversely affect Apache.

We may not realize the benefits we anticipated from the Merger.

Certain costs relating to the Merger, including certain investment banking, financing, legal and accounting fees and expenses, must be paid even if the Merger is not completed.

Time demands and commitments related to the Merger may distract management and other employees from current day-to-day responsibilities, preventing Apache from realizing benefits from other existing opportunities.

The Devon and Mariner transactions will increase our exposure to Gulf of Mexico operations.

Our recent acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon Energy Corporation has increased our exposure to Gulf of Mexico operations. Following the completion of the Mariner Merger, an even larger percentage of our exploration and production operations will be related to offshore Gulf of Mexico properties. Greater offshore concentration proportionately increases risks from delays or higher costs common to offshore activity, including severe weather, availability of specialized equipment and compliance with environmental and other laws and regulations.

Any additional deepwater drilling laws and regulations, delays in the processing and approval of permits and other related developments resulting from the recently lifted deepwater drilling moratorium in the Gulf of Mexico could adversely affect Apache’s and Mariner’s business.

As has been widely reported, on April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, leading to the oil spill currently affecting the Gulf of Mexico. In response to this incident, the Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE) of the U.S. Department of the Interior (DOI) issued a notice on May 30, 2010, implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. Implementation of the moratorium was blocked by a U.S. district court, which was subsequently affirmed on appeal, but on July12, 2010, the BOEMRE issued a new moratorium that applied to deep-water drilling operations that use subsea blowout preventers or surface blowout preventers on floating facilities. The DOI lifted this moratorium on October 12, 2010. The BOEMRE is expected to issue new safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico, and potentially in other geographic regions, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. This incident could also result in drilling suspensions or other regulatory initiatives in other areas of the U.S. and abroad. Although it is difficult to predict the ultimate impact of any new guidelines, regulations or legislation, a prolonged suspension of drilling activity in other areas of the U.S. and abroad, new regulations and increased liability for companies operating in this sector could adversely affect Apache’s and Mariner’s operations in the U.S. Gulf of Mexico as well as in other offshore locations.

Risks Related to the BP Acquisition

The Mariner and BP transactions will expose us to additional risks and uncertainties with respect to the acquired businesses and their operations.

Although the acquired Mariner and BP businesses will generally be subject to risks similar to those to which we are subject in our existing businesses, the Mariner and BP transactions may increase these risks. For example, the increase in the scale of our operations may increase our operational risks. Recent publicity associated with the oil spill in the Gulf of Mexico resulting from the fire and explosion onboard the Deepwater Horizon, which was under contract to BP, may cause regulatory agencies to scrutinize our operations more closely. This additional scrutiny may adversely affect our operations.

We may have difficulty combining the operations of both Mariner and the BP Properties, and the anticipated benefits of these transactions may not be achieved.

Achieving the anticipated benefits of the Mariner and BP transactions will depend in part upon whether we can successfully integrate the operations of Mariner and the BP Properties with ours. Our ability to integrate the operations of Mariner and the BP Properties successfully will depend on our ability to monitor operations, coordinate exploration and development activities, control costs, attract, retain and assimilate qualified personnel and maintain compliance with regulatory requirements. The difficulties of integrating the operations of Mariner and the BP Properties may be increased by the necessity of combining organizations with distinct cultures and widely dispersed operations. The integration of operations following these transactions will require the dedication of management and other personnel, which may distract their attention from the day-to-day business of the combined enterprise and prevent us from realizing benefits from other opportunities. Completing the integration process may be more expensive than anticipated, and we cannot assure you that we will be able to effect the integration of these operations smoothly or efficiently or that the anticipated benefits of the transactions will be achieved.

Several significant matters in the BP Acquisition were not resolved before closing.

Because of the relatively short time period between signing the BP Purchase Agreements and the closing of the acquisition of the BP Properties, several significant matters commonly resolved prior to closing such an acquisition have been reserved for after closing. We did not have sufficient time before closing on the BP Properties to conduct a full title review and environmental assessment. Although remedies are limited for title, we may discover adverse environmental or other conditions after closing and after the time periods specified in the BP Purchase Agreements during which we may be able to seek, in certain cases, indemnification from or cure of the defect or adverse condition by BP for such matters.

The reserves, production, revenue and direct operating expense estimates with respect to the BP Properties may differ materially from the actual amounts.

The reserves and production estimates with respect to the BP Properties mentioned in this Form 10-Q are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. These estimates of reserves and production are based on estimates of our engineers without review by an independent petroleum engineering firm. Data used to make these estimates was furnished by BP or obtained from publicly available sources. We cannot assure you that these estimates of proved reserves and production are accurate. After such data is reviewed by an independent petroleum engineering firm, the BP Acquisition reserves and production may differ materially from the amounts indicated in this Form 10-Q.

The BP Acquisition and/or our liabilities could be adversely affected in the event one or more of the BP entities become the subject of a bankruptcy case.

In light of the extensive costs and liabilities related to the current oil spill in the Gulf of Mexico, there has been public speculation as to whether one or more of the BP entities will become the subject of a case or proceeding under Title11 of the United States Code or any other relevant insolvency law or similar law (which we collectively refer to as “Insolvency Laws”). In the event that one or more of the BP entities were to become the subject of such a case or proceeding, a court may find that the BP Purchase Agreements are executory contracts, in which case such BP entities may, subject to relevant Insolvency Laws, have the right to reject the agreements and refuse to perform their future obligations under them. In this event, our ability to enforce our rights under the BP Purchase Agreements could be adversely affected.

Additionally, in a case or proceeding under relevant Insolvency Laws, a court may find that the sale of the BP Properties constitutes a constructive fraudulent conveyance that should be set aside. While the tests for determining whether a transfer of assets constitutes a constructive fraudulent conveyance vary among jurisdictions, such a determination generally requires that the seller received less than a reasonably equivalent value in exchange for such transfer or obligation and the seller was insolvent at the time of the transaction, or was rendered insolvent or left with unreasonably small capital to meet its anticipated business needs as a result of the transaction. The applicable time periods for such a finding also vary among jurisdictions, but generally range from two to six years. If a court were to make such a determination in a proceeding under relevant Insolvency Laws, our rights under the BP Purchase Agreements, and our rights to the BP Properties, could be adversely affected.

Our ability to declare and pay dividends is subject to limitations.

The payment of future dividends on our capital stock is subject to the discretion of our board of directors, which considers, among other factors, our operating results, overall financial condition, credit-risk considerations and capital requirements, as well as general business and market conditions. Our board of directors is not required to declare dividends on our common stock and may decide not to declare dividends.

Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including the common stock. In the event that any of our indentures or other financing agreements in the future restrict our ability to pay dividends in cash on the mandatory convertible preferred stock, we may be unable to pay dividends in cash on the common stock unless we can refinance amounts outstanding under those agreements.

In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is defined as the amount by which our total assets exceeds the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid from our net profits for the then current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock.

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. [REMOVED AND RESERVED]

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

	2.1		Purchase and Sale Agreement by and between BP America Production Company and ZPZ Delaware I LLC dated July 20, 2010 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300)

	2.2		Partnership Interest and Share Purchase and Sale Agreement by and between BP Canada Energy and Apache Canada Ltd. dated July 20, 2010 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300)

	2.3		Purchase and Sale Agreement by and among BP Egypt Company, BP Exploration (Delta) Limited and ZPZ Egypt Corporation LDC dated July 20, 2010 (incorporated by reference to Exhibit 2.3 to Registrant’s Current Report on Form 8-K/A filed on July 20, 2010, SEC File No. 001-4300)

	2.4		Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, Mariner Energy, Inc. and ZMZ Acquisitions LLC (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated April 14, 2010, filed April 16, 2010, SEC File No. 001-4300).

	2.5		Amendment No. 1 dated as of August 2, 2010 to the Agreement and Plan of Merger dated as of April 14, 2010 by and among Apache Corporation, ZMZ Acquisitions LLC and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated August 2, 2010, filed on August 3, 2010, SEC File No. 001-4300)

	3.1		Restated Certificate of Incorporation of Registrant, dated February 23, 2010, as filed with the Secretary of State of Delaware on February 23, 2010 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).

	3.2		Certificate of Designations of the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300)

	3.3		Bylaws of Registrant, as amended August 6, 2009 (incorporated by reference to Exhibit 3.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended June 30, 2009, SEC File No. 001-4300).

	4.1		Form of certificate for the 6.00% Mandatory Convertible Preferred Stock, Series D(incorporated by reference to Exhibit A of Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300)

	4.2		Deposit Agreement, dated as of July 28, 2010, between Apache Corporation and Wells Fargo Bank, N.A., as depositary, on behalf of all holders from time to time of the receipts issued there under (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300)

	4.3		Form of Depositary Receipt for the Depositary Shares (incorporated by reference to Exhibit A to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).

	10.1		Term Loan Agreement dated July 20, 2010 by and among Apache Corporation, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., Bank of America, N.A., and Goldman Sachs Bank USA, as co-syndication agents, J.P. Morgan Securities Inc., Citigroup Global Markets Inc., Banc of America Securities, LLC and Goldman Sachs Bank USA, as co-lead arrangers and joint book runners, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300)

	*12.1		Statement of computation of ratio of earnings to fixed charges and combined fixed charges and preferred stock dividends.

	*31.1		Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.

	*31.2		Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.

	*32.1		Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

	**101		The following materials from the Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Cash Flows, (iii) Consolidated Balance Sheet, (iv) Statement of Consolidated Shareholders’ Equity, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.


†		Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.

*		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: November 8, 2010	/s/ ROGER B. PLANK
	Roger B. Plank
	President (Principal Financial Officer)



Dated: November 8, 2010	/s/ REBECCA A. HOYT
	Rebecca A. Hoyt
	Vice President and Controller (Principal Accounting Officer)

TABLE OF CONTENTS

Part I Financial Informationprint Item 1 Financial Statementsprint Item 2 Management S Discussion and Analysis Of Financial Condition and Results Of Operationsprint Item 3 Quantitative and Qualitative Disclosures About Market Riskprint Item 4 Controls and Proceduresprint Part II Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 3. Defaults Upon Senior Securitiesprint Item 4. [removed and Reserved]print Item 5. Other Informationprint Item 6. Exhibitsprint

Exhibits

EX-12.1 EX-31.1 EX-31.2 EX-32.1

Supplier name	Ticker
EOG Resources, Inc.	EOG
DISH Network Corporation	DISH
Honeywell International Inc.	HON
Xylem Inc.	XYL
Raytheon Technologies Corporation	RTX
Markel Corporation	MKL
Jacobs Engineering Group Inc.	J
Ecopetrol S.A.	EC

APA 10-Q Quarter ended Sept. 30, 2010

Exhibits