APA 10-Q Quarterly Report June 30, 2010

APACHE CORP

10-Qs and 10-Ks

10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on April 3, 2020
DEF 14A	Filed on April 9, 2019
DEF 14A	Filed on April 9, 2018
DEF 14A	Filed on March 28, 2017
DEF 14A	Filed on March 28, 2016
DEF 14A	Filed on April 2, 2015
DEF 14A	Filed on April 2, 2014
DEF 14A	Filed on April 3, 2013
DEF 14A	Filed on April 3, 2012
DEF 14A	Filed on April 7, 2011
DEF 14A	Filed on March 31, 2010

10-Q 1 h74335e10vq.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 June 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		41-0747868
(State or other jurisdiction of incorporation or organization)		(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 July 31, 2010 364,278,514

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
SIGNATURES
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-10.6
EX-10.7
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)


	For the Quarter				For the Six Months
	Ended June 30,				Ended June 30,
	2010		2009		2010			2009
	(In thousands, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,968,765	$	2,074,344	$	5,662,390		$	3,677,958
Other		3,145		19,034		(17,229	)		49,245

		2,971,910		2,093,378		5,645,161			3,727,203


OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		729,751		573,359		1,368,249			1,153,976
Additional		—		—		—			2,818,161
Asset retirement obligation accretion		24,760		26,483		48,762			53,221
Lease operating expenses		445,949		405,273		886,195			802,762
Gathering and transportation		43,038		33,479		83,403			66,818
Taxes other than income		186,833		115,941		363,771			203,280
General and administrative		91,829		90,905		178,979			175,951
Financing costs, net		55,757		61,155		115,024			119,742

		1,577,917		1,306,595		3,044,383			5,393,911

INCOME (LOSS) BEFORE INCOME TAXES		1,393,993		786,783		2,600,778			(1,666,708	)
Current income tax provision		339,151		218,247		682,125			220,741
Deferred income tax provision (benefit)		194,619		123,816		353,449			(575,229	)


NET INCOME (LOSS)		860,223		444,720		1,565,204			(1,312,220	)
Preferred stock dividends		—		1,420		—			2,840

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	860,223	$	443,300	$	1,565,204		$	(1,315,060	)


NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	2.55	$	1.32	$	4.64		$	(3.92	)

Diluted	$	2.53	$	1.31	$	4.61		$	(3.92	)

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

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


	For the Six Months Ended June 30,
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	1,565,204		$	(1,312,220	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		1,368,249			3,972,137
Asset retirement obligation accretion		48,762			53,221
Provision for (benefit from) deferred income taxes		353,449			(575,229	)
Other		66,939			104,734
Changes in operating assets and liabilities:
Receivables		(103,847	)		(173,502	)
Inventories		(6,812	)		(4,049	)
Drilling advances		21,827			(89,751	)
Deferred charges and other		729			5,871
Accounts payable		49,573			(176,572	)
Accrued expenses		(291,931	)		(376,981	)
Deferred credits and noncurrent liabilities		13,299			(60,930	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		3,085,441			1,366,729

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,937,613	)		(2,117,415	)
Additions to gas gathering, transmission and processing facilities		(256,728	)		(164,723	)
Acquisition of Marathon properties		—			(181,133	)
Acquisition of Devon properties		(1,017,238	)		—
Short-term investments		—			791,999
Restricted cash		—			13,880
Other, net		(6,904	)		(85,399	)

NET CASH USED IN INVESTING ACTIVITIES		(3,218,483	)		(1,742,791	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(55,384	)		147,666
Payments on fixed-rate notes		—			(100,000	)
Dividends paid		(101,065	)		(103,331	)
Common stock activity		21,346			9,971
Treasury stock activity, net		3,591			2,669
Cost of debt and equity transactions		(289	)		(403	)
Other		22,073			9,597

NET CASH USED IN FINANCING ACTIVITIES		(109,728	)		(33,831	)

NET DECREASE IN CASH AND CASH EQUIVALENTS		(242,770	)		(409,893	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		2,048,117			1,181,450

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,805,347		$	771,557


SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	113,099		$	122,120
Income taxes paid, net of refunds		595,472			188,251

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

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)


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

CURRENT ASSETS:
Cash and cash equivalents	$	1,805,347		$	2,048,117
Receivables, net of allowance		1,647,952			1,545,699
Inventories		508,702			533,251
Drilling advances		205,965			230,733
Prepaid taxes		137,556			146,653
Prepaid assets and other		201,418			81,396

		4,506,940			4,585,849


PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		47,078,456			44,267,037
Unproved properties and properties under development, not being amortized		1,968,079			1,479,008
Gas gathering, transmission and processing facilities		3,445,906			3,189,177
Other		524,642			492,511

		53,017,083			49,427,733
Less: Accumulated depreciation, depletion and amortization		(27,893,628	)		(26,527,118	)

		25,123,455			22,900,615

OTHER ASSETS:

Goodwill, net		189,252			189,252
Deferred charges and other		612,760			510,027

	$	30,432,407		$	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)


	June 30,			December 31,
	2010			2009
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	485,601		$	396,564
Accrued operating expense		92,678			90,151
Accrued exploration and development		895,305			923,084
Accrued compensation and benefits		97,250			151,408
Current debt		116,205			117,326
Asset retirement obligation		147,374			146,654
Other		368,422			567,371

		2,202,835			2,392,558

LONG-TERM DEBT		4,896,127			4,950,390


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		3,247,065			2,764,901
Asset retirement obligation		1,874,743			1,637,357
Other		535,877			661,916

		5,657,685			5,064,174


COMMITMENTS AND CONTINGENCIES (Note 9)

SHAREHOLDERS’ EQUITY:
Common stock, $0.625 par, 430,000,000 shares authorized, 345,278,595 and 344,076,790 shares issued, respectively		215,799			215,048
Paid-in capital		4,748,709			4,634,326
Retained earnings		12,900,582			11,436,580
Treasury stock, at cost, 7,479,435 and 7,639,818 shares, respectively		(212,280	)		(216,831	)
Accumulated other comprehensive income (loss)		22,950			(290,502	)

		17,675,760			15,778,621

	$	30,432,407		$	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 B													Other			Total
	Comprehensive			Preferred		Common								Treasury			Comprehensive			Shareholders’
	Income (Loss)			Stock		Stock		Paid-In Capital			Retained 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	$	(1,312,220	)		—		—		—			(1,312,220	)		—			—			(1,312,220	)
Commodity hedges, net of income tax benefit of $108,393		(194,508	)		—		—		—			—			—			(194,508	)		(194,508	)

Comprehensive loss	$	(1,506,728	)

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

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


BALANCE AT DECEMBER 31, 2009				$	—	$	215,048	$	4,634,326		$	11,436,580		$	(216,831	)	$	(290,502	)	$	15,778,621
Comprehensive income:
Net income	$	1,565,204			—		—		—			1,565,204			—			—			1,565,204
Commodity hedges, net of income tax expense of $150,207		313,452			—		—		—			—			—			313,452			313,452

Comprehensive income	$	1,878,656

Common stock dividends ($.30 per share)					—		—		—			(101,204	)		—			—			(101,204	)
Common shares issued					—		751		12,473			—			—			—			13,224
Treasury shares issued, net					—		—		(519	)		—			4,551			—			4,032
Compensation expense					—		—		102,006			—			—			—			102,006
Other					—		—		423			2			—			—			425

BALANCE AT JUNE 30, 2010				$	—	$	215,799	$	4,748,709		$	12,900,582		$	(212,280	)	$	22,950		$	17,675,760

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 June 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

In the first quarter of 2010, Apache announced an agreement to acquire a 51-percent interest in Kitimat LNG Inc’s proposed liquefied natural gas (LNG) export terminal (Kitimat) in British Columbia. The Company also reserved 51 percent of throughput capacity in the terminal. Planned plant gross capacity will be approximately 700 million cubic feet of natural gas per day (MMcf/d), or five million metric tons of LNG per year. This project has the potential to access new markets in the Asia-Pacific region and enable Apache to monetize gas from its Canadian region, including its interest in the Horn River Basin in northeast British Columbia. Kitimat is designed to be linked to the pipeline system servicing Western Canada’s natural gas producing regions proposed by Pacific Trail Pipelines. In association with the Company’s acquisition of interest in the Kitimat project, Apache also acquired a 25.5-percent interest in the proposed pipeline and 350 MMcf/d of net capacity rights. Preliminary gross construction cost of the Kitimat LNG export terminal, which will be refined upon completion of a front-end engineering and design (FEED) study, total C$3 billion and of the pipeline total C$1.1 billion. Apache projects that most of the costs for the LNG export terminal and pipeline will be incurred throughout a three and one-half year construction phase which is expected to begin in the second half of 2011.

During the second quarter Apache received proposals from three contractors on the FEED study and expects to award the contract by the end of the third quarter of 2010. Memorandums of Understanding (MOUs) have been developed and discussions with LNG buyers have been ongoing to market the LNG. Also, negotiations for specific agreements required with First Nations and Canadian federal and provincial governments are underway with completion anticipated during the third quarter of 2010. A final investment decision is expected in 2011, with the first LNG shipments projected as early as the end of 2014.

Gulf of Mexico Shelf Acquisition

On June 9, 2010, Apache completed a $1.05 billion acquisition of oil and gas assets in the Gulf of Mexico shelf from Devon Energy Corporation (Devon). 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 operates 75 percent of the production. 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 we 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 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 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 was approximately $1.2 billion at the time of the Merger Agreement.

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. Completion of the transaction is projected for the third quarter of 2010.

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 for one of the events which would trigger the payment of the fee: in the event that Mariner terminates the Merger Agreement in order to enter into an unsolicited “superior proposal” with another party (refer to Note 9 – Commitments and Contingencies, of Item I of this form 10-Q for further discussion). 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 current 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 fit well with Apache’s existing holdings and provide an inventory of future potential drilling locations, particularly in the Spraberry, Wolfcamp and Wolfberry formation oil plays of the Permian Basin. Additionally, Mariner has accumulated acreage in emerging unconventional shale oil resources in the U.S.

3. SUBSEQUENT EVENTS

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

On July 20, 2010, we announced the signing of 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).

Permian Basin. All of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of West Texas and New Mexico. The assets include interests in 10 field areas in the Permian Basin, (including Block 16/Coy Waha, Block 31, Brown Basset, Empire/Yeso, Pegasus, Southeast Lea, Spraberry, Wilshire, North Misc and Delaware Penn), approximately 405,000 net mineral and fee acres, 358,000 leasehold acres, approximately 3,629 active wells and three gas processing plants, two of which are currently operated by BP. Based on our investigation and review of data provided by BP, these assets produced 15,110 barrels of liquid hydrocarbons (liquids) and 81 MMcf of gas per day in the first six months of 2010. The Permian Basin assets had estimated net proved reserves of 141 MMboe at June 30, 2010 (65 percent liquids).

Western Canada Sedimentary Basin. Substantially all of BP’s Western Canadian upstream 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. Based on our investigation and review of data provided by BP, during the first half of 2010 these properties produced 6,529 barrels of liquids and 240 MMcf of gas per day and had estimated net proved reserves of 224 MMboe at June 30, 2010 (94 percent gas). We currently have operations in approximately half of these 13 field areas.

Western Desert, Egypt. BP’s interests in four development licenses and one exploration concession (East Badr El Din), covering 394,000 net acres south of El Alamein in the Western Desert of Egypt. These properties 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. Based on our investigation and review of data provided by BP, during the first six months of 2010 these properties produced 6,016 barrels of oil and 11 MMcf of gas per day of BP’s production, and 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 we currently hold. 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 acquisition is subject to a number of closing conditions, including regulatory approvals in the U.S., Canada and Egypt. On August 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Additional regulatory approvals are pending. Also, some of the BP Properties are subject to preferential rights to purchase interests held by third parties, and those rights may be exercised before or after we close the acquisition. The 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.

In conjunction with the acquisition, Apache issued 26.45 million shares of common stock and 25.3 million depositary shares, raising net proceeds of $3.5 billion (refer to Note 8 — Capital Stock, of Item 1 of this Form 10-Q for further discussion). The Company plans to fund the acquisition with the proceeds of these offerings and some combination of the following: cash on hand, our existing revolving credit and commercial paper facilities, a 364-day revolving credit facility, the issuance of term debt and the short term use of a bridge loan facility. The Company intends to increase its commercial paper program by $1 billion, the amount of the new 364-day revolving credit facility. We also secured a $5 billion bridge loan facility to backstop our financing requirements. The commitment under the bridge loan facility has been reduced by $3.5 billion, which is the amount of the net proceeds from the common stock and mandatory convertible preferred offerings discussed above. Depending on when the closing of the acquisition of the Permian Basin BP Properties occurs, we may fund a portion of the amount due for those properties by drawing under the bridge loan facility. Any such borrowing would be repaid from the Company’s next debt offering. Under the purchase and sale agreement, Apache advanced $5 billion of the purchase price to BP plc on July 30, 2010, ahead of the anticipated closings. This advance will be returned to Apache or applied to the purchase price at closing. BP plc provided a limited guarantee with respect to the purchase and sale agreements, principally as to the return of the advance.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies for Using Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Management occasionally 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 typically entered into are 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 counterparties, primarily financial institutions, for its derivative transactions. As of June 30, 2010, Apache had positions with 16 counterparties, all but one of which were rated A or higher by Standard & Poor’s and A2 or higher by Moody’s. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should any or all of these counterparties not perform, Apache may not realize the benefit of some or all of its derivative instruments resulting from lower commodity prices.

The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs a material deterioration in its credit ratings, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement.

Commodity Derivative Instruments

As of June 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		1,840	$	70.10		5,474	$	67.37	$	84.51
2011		3,650		70.12		8,575		69.09		90.12
2012		3,292		70.99		5,482		72.17		95.34
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.

As of June 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		45,540		—	$	5.72		14,720		—	$	5.41	$	6.91
2010		—		27,600	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 June 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		21,160	$	(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.

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:


	June 30,		December 31,
	2010		2009
	(In millions)

Current Assets: Prepaid assets and other	$	145	$	13
Other Assets: Deferred charges and other		155		51

Total Derivative Assets	$	300	$	64


Current Liabilities: Other	$	36	$	128
Noncurrent Liabilities: Other		65		202

Total Derivative Liabilities	$	101	$	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.

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:


	Gain (Loss) on Derivatives	For the Quarter Ended					For the Six Months Ended
	Recognized In Income	June 30,					June 30,
		2010		2009			2010			2009
				(In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss)	Oil and Gas Production
into operations (effective portion)	Revenues	$	52	$	52		$	51		$	108
Gain (loss) derivatives recognized in operations (ineffective portion and basis)	Revenues and Other: Other	$	—	$	(1	)	$	(1	)	$	(4	)

Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of June 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 Six Months Ended June 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		(51	)		(33	)		(108	)		(73	)
Net change in derivative fair value		514			346			(196	)		(122	)
Ineffectiveness reclassified into earnings		1			1			1			—


Unrealized gain (loss) on derivatives at end of period	$	197		$	144		$	(91	)	$	(57	)

Based on market prices as of June 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 $197 million ($144 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 June 30, 2010 is a net gain of approximately $109 million ($77 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.

5. ASSET RETIREMENT OBLIGATION

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


	(In millions)

Asset retirement obligation at December 31, 2009	$	1,784
Liabilities incurred		314
Liabilities settled		(125	)
Accretion expense		49


Asset retirement obligation at June 30, 2010		2,022

Less current portion		(147	)

Asset retirement obligation, long-term	$	1,875

The ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. To determine the current present value of this obligation, some key assumptions the Company must estimate include the ultimate productive life of the properties, a risk adjusted discount rate and an inflation factor. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. The period includes $233 million of liabilities incurred related to the Devon acquisition which closed in June, 2010.

6. DEBT

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

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

One of the Company’s Australian subsidiaries has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The facility provides for total commitments of up to $350 million, with availability determined by a borrowing base formula. The borrowing base was initially set at $350 million and will be redetermined upon project completion, as defined in the facility, which is expected to occur in the fourth quarter of 2010, and semi-annually thereafter. The Company has agreed to guarantee the credit facility until project completion. 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 June 30, 2010 was $300 million in accordance with the terms of the facility, down from $350 million on December 31, 2009. 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 maturity on March 31, 2014. 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 June 30, 2010.

At June 30, 2010 and December 31, 2009, there was $1.2 million and $7.3 million, respectively, borrowed on uncommitted overdraft lines in Argentina and the U.S.

As of June 30, 2010, Apache’s senior unsecured long-term debt was rated A3 by Moody’s, A- by Standard & Poor’s and A- by Fitch. The Company has received short-term debt ratings for its commercial paper program of P-2 from Moody’s, A-2 from Standard & Poor’s and F2 from Fitch. Following announcement of the BP asset acquisition, Moody’s put Apache’s A3 senior unsecured debt rating under review for downgrade and Fitch placed the Company’s A- senior unsecured debt rating on rating watch negative.

Financing Costs, Net

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


	For the Quarter Ended						For the Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
				(In millions)

Interest expense	$	75		$	77		$	151		$	156
Amortization of deferred loan costs		1			1			3			3
Capitalized interest		(18	)		(15	)		(35	)		(31	)
Interest income		(2	)		(2	)		(4	)		(8	)

Financing costs, net	$	56		$	61		$	115		$	120

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 six months of 2010. The 2009 year-to-date tax provision includes the impact of the 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 six-month periods ended June 30, 2010 and 2009 is presented in the table below. The loss for the first six 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 June 30,
	2010						2009
	Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	860		338	$	2.55	$	443		336	$	1.32


Effect of Dilutive Securities:
Stock options and other		—		1				—		1


Diluted:
Income attributable to common stock, including assumed conversions	$	860		339	$	2.53	$	443		337	$	1.31


	For the Six Months Ended June 30,
	2010						2009
	Income		Shares		Per Share		Loss			Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	1,565		337	$	4.64	$	(1,315	)		335	$	(3.92	)


Effect of Dilutive Securities:
Stock options and other		—		2				—			—


Diluted:
Income (loss) attributable to common stock, including assumed conversions	$	1,565		339	$	4.61	$	(1,315	)		335	$	(3.92	)

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 3.3 million and 4.1 million for the quarters ending June 30, 2010 and 2009 and 2.9 million and 3.9 million for the six months ended June 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.

Common and Preferred Stock Dividends

For the quarter ending June 30, 2010 and 2009, Apache paid $51 million and $50 million, respectively, in dividends on its common stock. In both six-month periods ended June 30, 2010 and 2009, the Company paid $101 million in dividends on its common stock. In the three-and six-month periods ended June 30, 2009, Apache paid a total of $1.4 million and $2.8 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.

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. Since 2005, two separate share appreciation plans have been approved. A summary of these plans follows:

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

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

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.

Subsequent Events

Common and Depositary Share Offerings

In conjunction with the BP Acquisition, Apache issued 26.45 million shares of common stock at a public offering price of $88.00 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering were approximately $2.3 billion. The initial offering of 21 million shares was increased to 23 million shares and the underwriters exercised their option to purchase an additional 3.45 million shares. The Company also received proceeds of $1.2 billion, after underwriting discounts and before expenses, from the sale of 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00% 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 offered 22 million depositary shares and the underwriters exercised their option to purchase an additional 3.3 million depositary shares. Net proceeds to the Company from the common stock and depositary share offerings totaled approximately $3.5 billion after underwriting discounts and before expenses.

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 $23 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 one million dollars. 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. An appeal by the plaintiffs to the U.S. Supreme Court is possible.

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 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, 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 offences 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 July17, 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 on July 21-22, 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 rights to purchase (“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 has agreed to indemnify BP for these actions.

Environmental Matters

As of June 30, 2010, the Company had an undiscounted reserve for environmental remediation of approximately $24 million. The Company is not aware of any environmental claims existing as of June 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, and 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. See Note 4 — Derivative Instruments and Hedging Activities of this Form 10-Q for further information.

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


	Fair Value Measurements Using
	Quoted Price in				Significant		Total
	Active Markets		Significant Other		Unobservable Inputs		Fair					Carrying
	(Level 1)		Inputs (Level 2)		(Level 3)		Value		Netting ⁽¹⁾			Amount
					(In millions)
June 30, 2010
Assets:
Commodity Derivative Instruments	$	—	$	346	$	—	$	346	$	(46	)	$	300

Liabilities:
Commodity Derivative Instruments		—		147		—		147		(46	)		101

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. See Note 4 — Derivative Instruments and Hedging Activities of this Form 10-Q for a discussion of net amounts recorded on the consolidated balance sheet at June 30, 2010 and December 31, 2009.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Asset Retirement Obligations Incurred in Current Period

Apache 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 investment banking firm, which is a Level 2 fair value measurement. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The following table presents the carrying amounts and estimated fair values of the Company’s debt at June 30, 2010 and December 31, 2009:


	June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In millions)

Total Debt, Net of Unamortized Discount	$	5,012	$	5,774	$	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 six-month periods ended June 30, 2010 and 2009.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
				(In millions)
Comprehensive Income (Loss)
Net income (Loss)	$	860		$	445		$	1,565		$	(1,312	)
Other Comprehensive Income (Loss)
Commodity hedges		103			(323	)		464			(303	)
Income tax related to commodity hedges		(39	)		113			(150	)		108


Total	$	924		$	235		$	1,879		$	(1,507	)

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 June 30, 2010

Oil and Gas Production Revenues	$	962		$	240		$	806	$	452	$	421	$	88	$	—	$	2,969


Operating Income ⁽¹⁾	$	452		$	71		$	548	$	285	$	165	$	18	$	—	$	1,539


Other Income (Expense):
Other																		3
General and administrative																		(92	)
Financing costs, net																		(56	)

Income Before Income Taxes																	$	1,394


For the Six Months Ended June 30, 2010

Oil and Gas Production Revenues	$	1,954		$	493		$	1,547	$	676	$	812	$	180	$	—	$	5,662


Operating Income ⁽¹⁾	$	963		$	166		$	1,041	$	386	$	313	$	43	$	—	$	2,912


Other Income (Expense):
Other																		(17	)
General and administrative																		(179	)
Financing costs, net																		(115	)

Income Before Income Taxes																	$	2,601


Total Assets	$	12,473		$	4,243		$	5,910	$	3,737	$	2,526	$	1,488	$	55	$	30,432


For the Quarter Ended June 30, 2009

Oil and Gas Production Revenues	$	707		$	215		$	655	$	87	$	322	$	88	$	—	$	2,074


Operating Income ⁽¹⁾	$	243		$	63		$	441	$	13	$	140	$	20	$	—	$	920


Other Income (Expense):
Other																		19
General and administrative																		(91	)
Financing costs, net																		(61	)

Income Before Income Taxes																	$	787


For the Six Months Ended June 30, 2009

Oil and Gas Production Revenues	$	1,303		$	425		$	1,075	$	130	$	565	$	180	$	—	$	3,678


Operating Income (Loss) ⁽¹⁾	$	(857	)	$	(1,495	)	$	664	$	—	$	228	$	40	$	—	$	(1,420	)


Other Income (Expense):
Other																		49
General and administrative																		(176	)
Financing costs, net																		(120	)

Loss Before Income Taxes																	$	(1,667	)


Total Assets	$	10,438		$	4,435		$	5,103	$	3,005	$	2,025	$	1,396	$	—	$	26,402


⁽¹⁾		Operating Income (Loss) consists of oil and gas production revenues less depreciation, depletion and amortization, asset retirement obligation accretion, lease operating expenses, gathering and transportation costs, and taxes other than income. The U.S. and Canada operating losses for the six-month period of 2009 include additional depletion of $1.2 billion and $1.6 billion, respectively, to write-down the carrying value of oil and gas properties 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 June 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	$	861,190	$	—	$	2,107,575		$	—		$	2,968,765
Equity in net income (loss) of affiliates		731,011		39,584		(9,370	)		(761,225	)		—
Other		2,090		14,739		(12,647	)		(1,037	)		3,145

		1,594,291		54,323		2,085,558			(762,262	)		2,971,910


OPERATING EXPENSES:
Depreciation, depletion and amortization		234,416		—		495,335			—			729,751
Asset retirement obligation accretion		12,751		—		12,009			—			24,760
Lease operating expenses		172,185		—		273,764			—			445,949
Gathering and transportation costs		10,436		—		32,602			—			43,038
Taxes other than income		32,113		—		154,720			—			186,833
General and administrative		72,030		—		20,836			(1,037	)		91,829
Financing costs, net		49,141		14,116		(7,500	)		—			55,757

		583,072		14,116		981,766			(1,037	)		1,577,917


INCOME BEFORE INCOME TAXES		1,011,219		40,207		1,103,792			(761,225	)		1,393,993
Provision for income taxes		150,996		9,993		372,781			—			533,770


NET INCOME		860,223		30,214		731,011			(761,225	)		860,223
Preferred stock dividends		—		—		—			—			—

INCOME ATTRIBUTABLE TO COMMON STOCK	$	860,223	$	30,214	$	731,011		$	(761,225	)	$	860,223

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


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

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


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

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


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


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

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

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 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	$	1,750,315	$	—	$	3,912,075		$	—		$	5,662,390
Equity in net income (loss) of affiliates		1,195,270		63,603		(15,050	)		(1,243,823	)		—
Other		2,798		29,344		(47,298	)		(2,073	)		(17,229	)

		2,948,383		92,947		3,849,727			(1,245,896	)		5,645,161


OPERATING EXPENSES:
Depreciation, depletion and amortization		448,025		—		920,224			—			1,368,249
Asset retirement obligation accretion		24,720		—		24,042			—			48,762
Lease operating expenses		337,817		—		548,378			—			886,195
Gathering and transportation costs		21,050		—		62,353			—			83,403
Taxes other than income		67,473		—		296,298			—			363,771
General and administrative		144,496		—		36,556			(2,073	)		178,979
Financing costs, net		101,696		28,236		(14,908	)		—			115,024

		1,145,277		28,236		1,872,943			(2,073	)		3,044,383


INCOME BEFORE INCOME TAXES		1,803,106		64,711		1,976,784			(1,243,823	)		2,600,778
Provision for income taxes		237,902		16,158		781,514			—			1,035,574


NET INCOME		1,565,204		48,553		1,195,270			(1,243,823	)		1,565,204
Preferred stock dividends		—		—		—			—			—

INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,565,204	$	48,553	$	1,195,270		$	(1,243,823	)	$	1,565,204

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


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

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


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

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


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


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

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

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


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,184,700		$	(36,071	)	$	1,936,812		$	—		$	3,085,441


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(529,851	)		—			(1,407,762	)		—			(1,937,613	)
Additions to gas gathering, transmission and processing facilities		—			—			(256,728	)		—			(256,728	)
Acquisition of Devon properties		(1,017,238	)		—			—			—			(1,017,238	)
Short-term investments		—			—			—			—			—
Restricted cash for acquisition settlement		—			—			—			—			—
Proceeds from sale of oil & gas properties		—			—			—			—			—
Investment in subsidiaries, net		(79,990	)		—			—			79,990			—
Other, net		(44,697	)		—			37,793			—			(6,904	)

NET CASH USED IN INVESTING ACTIVITIES		(1,671,776	)		—			(1,626,697	)		79,990			(3,218,483	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Debt borrowings		1,696			2,403			18,715			(78,198	)		(55,384	)
Payments on debt		—			—			—			—			—
Dividends paid		(101,065	)		—			—			—			(101,065	)
Common stock activity		21,346			33,295			(31,503	)		(1,792	)		21,346
Treasury stock activity, net		3,591			—			—			—			3,591
Cost of debt and equity transactions		(289	)		—			—			—			(289	)
Other		22,073			—			—			—			22,073

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(52,648	)		35,698			(12,788	)		(79,990	)		(109,728	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(539,724	)		(373	)		297,327			—			(242,770	)

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	$	107,027		$	1,724		$	1,696,596		$	—		$	1,805,347

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


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


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(666,421	)		—			(1,450,994	)		—			(2,117,415	)
Additions to gas gathering, transmission and processing facilities		—			—			(164,723	)		—			(164,723	)
Acquisition of Marathon properties		(181,133	)		—			—			—			(181,333	)
Short-term investments		791,999			—			—			—			791,999
Restricted cash for acquisition settlement		13,880			—			—			—			13,880
Investment in subsidiaries, net		(300,472	)		—			—			300,472			—
Other, net		(26,759	)		—			(58,640	)		—			(85,399	)

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


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

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


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

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


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

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of June 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	$	107,027		$	1,724	$	1,696,596		$	—		$	1,805,347
Receivables, net of allowance		512,646			—		1,135,306			—			1,647,952
Inventories		42,468			—		466,234			—			508,702
Drilling advances		12,292			1,884		191,789			—			205,965
Prepaid taxes		102,341			—		35,215			—			137,556
Prepaid assets and other		(23,929	)		—		225,347			—			201,418

		752,845			3,608		3,750,487			—			4,506,940


PROPERTY AND EQUIPMENT, NET		10,491,336			—		14,632,119			—			25,123,455


OTHER ASSETS:
Intercompany receivable, net		2,051,441			—		(551,901	)		(1,499,540	)		—
Equity in affiliates		12,437,431			1,121,775		99,810			(13,659,016	)		—
Restricted cash		—			—		—			—			—
Goodwill, net		—			—		189,252			—			189,252
Deferred charges and other		182,255			1,002,878		427,627			(1,000,000	)		612,760

	$	25,915,308		$	2,128,261	$	18,547,394		$	(16,158,556	)	$	30,432,407


LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	328,438		$	2,273	$	1,654,430		$	(1,499,540	)	$	485,601
Current Debt		1,000			—		115,205			—			116,205
Accrued exploration and development		239,972			—		655,333			—			895,305
Asset retirement obligation		147,374			—		—			—			147,374
Other accrued expenses		248,793			2,883		306,674			—			558,350

		965,577			5,156		2,731,642			(1,499,540	)		2,202,835

LONG-TERM DEBT		4,063,036			647,194		185,897			—			4,896,127


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,583,293			4,326		1,659,446			—			3,247,065
Asset retirement obligation		1,043,824			—		830,919			—			1,874,743
Other		583,818			250,000		702,059			(1,000,000	)		535,877

		3,210,935			254,326		3,192,424			(1,000,000	)		5,657,685


COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY		17,675,760			1,221,585		12,437,431			(13,659,016	)		17,675,760

	$	25,915,308		$	2,128,261	$	18,547,394		$	(16,158,556	)	$	30,432,407

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
Prepaid taxes		142,675		—			3,978			—			146,653
Prepaid assets and other		8,876		—			72,520			—			81,396

		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
Other accrued expenses		347,104		6,121			455,705			—			808,930

		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 second-quarter 2010 earnings to $860 million, or $2.53 per diluted common share, up from $443 million, or $1.31 per share, in the comparable year-ago period. Apache’s 2010 second-quarter adjusted earnings ⁽¹⁾ , which exclude certain items impacting the comparability of results, were $829 million, or $2.44 per diluted common share, compared to $474 million, or $1.41 per share in the year-earlier period. Net cash provided by operating activities increased to $1.9 billion from $824 million in the second quarter of 2009.

For the first half of 2010, earnings totaled $1.57 billion, or $4.61 per share, compared to a loss of $1.32 billion, or $3.92 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-half adjusted earnings ⁽¹⁾ were $1.54 billion, or $4.54 per diluted common share, compared to $693 million, or $2.05 per share, in the year-earlier period. Net cash provided by operating activities increased to $3.1 billion from $1.4 billion in the first half of 2009.

The improvement in 2010 second-quarter and six-month earnings and cash flow was driven by record second-quarter production, substantially higher oil price realizations and moderate increases in gas price realizations. Second-quarter 2010 production averaged a record 646,866 barrels of oil equivalent per day (boe/d), up 10 percent from 2009, led by Australia’s 60,680 barrels per day (b/d), a nearly six-fold increase over the 2009 flow rate. Australia’s production gains came from the Van Gogh and Pyrenees developments which were commissioned in the first quarter of 2010.

⁽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 Acquisition

On July 20, 2010, we announced the signing of three definitive purchase and sale agreements (BP Purchase 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 in accordance with the BP Purchase Agreements (BP Acquisition).

Permian Basin. All of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of West Texas and New Mexico. The assets include interests in 10 field areas in the Permian Basin, (including Block 16/Coy Waha, Block 31, Brown Basset, Empire/Yeso, Pegasus, Southeast Lea, Spraberry, Wilshire, North Misc and Delaware Penn), approximately 405,000 net mineral and fee acres, 358,000 leasehold acres, approximately 3,629 active wells and three gas processing plants, two of which are currently operated by BP. Based on our investigation and review of data provided by BP, these assets produced 15,110 barrels of liquid hydrocarbons (liquids) and 81 million cubic feet of natural gas per day (MMcf/d) in the first six months of 2010. The Permian Basin assets had estimated net proved reserves of 141 million barrels of oil equivalent (MMboe) at June 30, 2010 (65 percent liquids).

gas, tight gas and coal bed methane in historically productive formations including the Montney, Cadomin and Doig. Based on our investigation and review of data provided by BP, during the first half of 2010 these properties produced 6,529 barrels of liquids and 240 MMcf of gas per day and had estimated net proved reserves of 224 MMboe at June 30, 2010 (94 percent gas). We currently have operations in approximately half of these 13 field areas.

Western Desert, Egypt. BP’s interests in four development licenses and one exploration concession (East Badr El Din) covering 394,000 net acres south of El Alamein in the Western Desert of Egypt. These properties 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. Based on our investigation and review of data provided by BP, during the first six months of 2010 these properties produced 6,016 barrels of oil and 11 MMcf of gas per day of BP’s production, and 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 we currently hold. The Merged Concession Agreement related to the development licenses runs through 2024, subject to a five year extension at the option of the operator.

Common and Depositary Share Offering In conjunction with the acquisition, Apache issued 26.45 million shares of common stock at a public offering price of $88.00 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering were approximately $2.3 billion. The Company also received proceeds, after underwriting discounts and before expenses, of $1.2 billion from the sale of 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00% Mandatory Convertible Preferred Stock, Series D, with an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). Proceeds to the Company from the common stock and depositary share offerings, after underwriting discounts and before expenses, totaled approximately $3.5 billion.

The Company plans to fund the acquisition with the proceeds of these offerings and some combination of the following: cash on hand, our existing revolving credit and commercial paper facilities, a 364-day revolving credit facility, the issuance of term debt and the short term use of a bridge loan facility. The Company intends to increase its commercial paper program by $1 billion, the amount of the new 364-day revolving credit facility. We also secured a $5 billion bridge loan facility to backstop our financing requirements. The commitment under the bridge loan facility has been reduced by $3.5 billion, which is the amount of the net proceeds from the common stock and mandatory convertible preferred offerings discussed above. Depending on when the closing of the acquisition of the Permian Basin BP Properties occurs, we may fund a portion of the amount due for those properties by drawing under the bridge loan facility. Any such borrowing would be repaid from the Company’s next debt offering. Under the purchase and sale agreement, Apache advanced $5 billion of the purchase price to BP plc on July 30, 2010, ahead of the anticipated closings. This advance will be returned to Apache or applied to the purchase price at closing. BP plc provided a limited guarantee with respect to the BP Purchase Agreements, principally as to the return of the advance. The acquisition and related equity offerings are not expected to be accretive to earnings per share in the first several quarters and may be dilutive. They are, however, expected to be accretive to cash flow immediately and are expected to be accretive to per share production growth and neutral to earnings per share for the full year of 2011.

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 16 percent of our worldwide equivalent production in the second 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 Devon property acquisition, the BP property acquisition and the Mariner Merger. After completion of the BP property acquisitions, we expect production from Permian and Canada will rise to 12 and 15 percent of worldwide production, respectively.

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

In April 2010, a deepwater Gulf of Mexico drilling rig, the Deepwater Horizon, operating in the Gulf of Mexico on Mississippi Canyon Block 252, sank after an apparent blowout and fire. As of the date of this filing it appears that the well has been contained as efforts to permanently cap the well proceed. Remediation of the environmental impacts of the spill is ongoing. Neither Apache nor Mariner owns 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 BOEM, 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 BOEM would not consider drilling permits for deepwater wells and related activities for a period of six months. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana issued a preliminary injunction prohibiting the enforcement of the moratorium, which the DOI has appealed to the Fifth Circuit Court of Appeals. On July 8, 2010, the court of appeals denied the government’s

request that the district court’s order be stayed while the appeal is pending. On July 12, 2010, the Secretary of the DOI directed the BOEM to issue a suspension until November 30, 2010 of drilling activities that use subsea blowout preventers or surface blowout preventers on floating facilities, rather than a moratorium based on water depths.

In addition on June 8, 2010, the BOEM issued a Notice to Lessees, NTL-05, focusing on increased safety measures. This NTL specifically affects all drilling wells, workovers and anything with a blowout preventer. It requires:

•

Third party review and certification of blowout preventers/shear rams;

•

Professional engineer certification of well plan and cement procedures; and

•

Chief Executive Officer certification that the operator is in compliance with and is conducting all operations in accordance with all operating regulations found at 30 CFR 250.

On June 18, 2010, the BOEM issued a Notice to Lessees, NTL-06, focusing on operator’s plans for a blowout scenario and worst case discharge scenario. This NTL specifically affects all new drilling wells, and sidetracks that cross lease lines. It requires:

•

Detailed response plans for a blowout event including relief well rig availability and timing to contract a rig, move it onsite and drill a relief well;

•

Calculation of Worst Case Discharge (WCD) scenario including all models, calculations and assumptions used to calculate daily discharge rate; and

•

Measures that operator would propose to enhance the ability to prevent or reduce the likelihood of a blowout.

These regulatory changes effectively halted all permitting activity in the Gulf of Mexico; however, on July 16, 2010, the DOI issued a permit to Apache under NTL-05 to drill a natural gas well in shallow waters off the southeast Texas coast. This permit was the first issued since stricter safety and environmental measures were imposed. While we have seen additional approvals for permits under NTL-05, permits for wells falling under NTL-06 continue to be delayed. At the date of this filing, Apache has received only one permit under NTL-06, and as a result, has declared force majeure on a rig and subsequently released that rig for lack of permits. Apache continues to work with the DOI on other outstanding permit applications.

The drilling suspension, lack of certainty and continuing delays in approval of drilling permits may also result in an exodus of both deepwater and shallow-water drilling rigs as they seek opportunities outside the Gulf of Mexico.

The Gulf of Mexico offshore operations of Mariner and Apache have been impacted, and likely will be impacted in the future, by increased regulatory oversight, which may increase the cost of OCS wells and delay drilling and production therefrom. There may be future changes in laws and regulations, increases in insurance costs or decreases in insurance availability, as well as further delays in offshore exploration and drilling activities in the Gulf of Mexico. Once deepwater drilling activities are permitted to resume, projects may face additional delays because of increased time for permitting and rig availability.

Operating Highlights

United States

Gulf of Mexico Shelf Acquisition On June 9, 2010, Apache completed a $1.05 billion acquisition of oil and gas assets in the Gulf of Mexico shelf from Devon Energy Corporation (Devon). 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 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 operates 75 percent of the production. The acquisition was funded primarily from existing cash balances.

The Company believes that these well-maintained, high-quality assets fit well with Apache’s existing infrastructure and play to the strengths that come with our experience operating on the shelf, exploiting the current production base and capturing upside potential. Many of these properties are geologically complex fields that contain large structures with multiple pay intervals that we believe are under-exploited. The prospect inventory includes high-potential trend exploration opportunities in the Norphlet play and highly prospective exploratory acreage off the Texas coast.

Mariner Energy, Inc. Merger Agreement On April 15, 2010, Apache and Mariner Energy, Inc., a Delaware corporation (Mariner), announced that we have 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 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). In connection with the Merger, Apache expects to issue approximately 17.5 million shares of common stock (an increase of approximately five percent of Apache’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 was approximately $1.2 billion at the time of the Merger Agreement. Apache estimates it will ultimately incur approximately $130 million in costs related to 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 regulatory post-closing approvals are pending. Completion of the transaction is projected for the third quarter of 2010.

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 for one of the events which would trigger the payment of the fee: in the event that Mariner terminates the Merger Agreement in order to enter into an unsolicited “superior proposal” with another party (refer to Note 9 – Commitments and Contingencies, of Item I of this Form 10-Q for further discussion). 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.

Assuming the Merger is approved by Mariner stockholders and is cleared by regulatory authorities, 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. The transaction is not expected to be accretive to earnings per share for the first several quarters and may be dilutive. It is, however, expected to be accretive to Apache’s per-share production growth and cash flow immediately, and is expected to be accretive to earnings per share for the full year of 2011.

Canada

Kitimat LNG Terminal In the first quarter of 2010, Apache announced an agreement to acquire a 51-percent interest in Kitimat LNG Inc’s proposed liquefied natural gas (LNG) export terminal (Kitimat) in British Columbia. The Company also reserved 51 percent of throughput capacity in the terminal. Planned plant gross capacity will be approximately 700 MMcf/d, or five million metric tons of LNG per year. This project has the potential to access new markets in the Asia-Pacific region and enable Apache to monetize gas from its Canadian region, including its interest in the Horn River Basin. Kitimat is designed to be linked to the pipeline system servicing Western Canada’s natural gas producing regions proposed by Pacific Trail Pipelines. In association with the Company’s acquisition of interest in the Kitimat project, Apache also acquired a 25.5-percent interest in the proposed pipeline and 350 MMcf/d of net capacity rights. Preliminary gross construction cost of the Kitimat LNG export terminal, which will be refined upon completion of a front-end engineering and design (FEED) study, total C$3 billion and of the pipeline total C$1.1 billion. Apache projects that most of the costs for the LNG export terminal and pipeline will be incurred throughout the three and one-half year construction phase which is expected to begin in the second half of 2011.

Egypt

Egypt Gross Production 2X Goal On June 16, 2010, the Company announced that new production from its Faghur Basin field discoveries propelled its Egyptian gross-operated oil and gas production above 330,000 boe per day, surpassing the Company’s late-2005 goal of doubling output from Egypt’s Western Desert within five years. The completion of new Kalabsha processing and transportation facilities also helped enable Apache to achieve our goal. When the project was initiated, Apache’s gross-operated Egyptian production was approximately 163,000 boe per day.

Apache invested $4.2 billion in exploration, development and facilities to achieve the “2X” production goal. During that period, the Company also:

•

Discovered 57 new fields;

•

Drilled 869 new wells;

•

Acquired 17,300-square kilometers of three-dimensional (3D) seismic;

•

Designed and constructed gathering facilities and two new gas processing trains for Qasr field gas production;

•

Installed a major strategic gas pipeline compression project on Egypt’s northern gas pipeline;

•

Built a third processing train at the Qarun Concession;

•

Implemented 13 waterflood secondary oil recovery projects; and

•

Completed the first phase of Kalabsha facilities in the Faghur Basin.

Matruh Discovery On May 26, 2010, the Company announced that its second discovery of the year in Egypt’s Matruh Basin – the Samaa-1X – tested 44 MMcf of natural gas and 2,910 barrels of condensate per day from two zones. Eleven additional exploration wells and two appraisal wells are planned during the remainder of 2010. Apache has a 100 percent contractor interest in the Matruh Concession

The Matruh Basin continues to be a successful focus area for Apache, with AEB and Safa reservoirs that have proven to be prolific oil and gas producers. The thickness of the sands and the stacked pay zones present multiple opportunities for further exploration.

The Matruh Concession currently has gross production of 130 MMcf of gas and 18,000 barrels of oil per day from 16 wells. Since early 2009, gross production on the concession has grown from 60 MMcf of gas and 5,000 barrels of oil per day.

Australia

Pyrenees and Van Gogh The second quarter of 2010 marked the first full quarter of oil production from the Pyrenees and Van Gogh developments located offshore Western Australia. The Pyrenees and Van Gogh developments, which contributed 22,347 b/d and 29,046 b/d during the second quarter, respectively, drove Australia oil production to 60,680 b/d.

Wheatstone LNG Project In October 2009, Apache announced an agreement to become a foundation equity partner in Chevron’s Wheatstone LNG hub in Western Australia. Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG facilities with a 75 percent interest. Apache currently owns a 16.25 percent interest in the project and our partner in the Julimar and Brunello fields, Kuwait Foreign Petroleum Exploration Co., k.s.c. (KUFPEC) owns the remaining project interest. The Wheatstone project is targeting a final investment decision (FID) in 2011 and first sales from the facility are projected for 2015. Our net capital for the project is currently estimated to be $1.2 billion for upstream development of the Julimar and Brunello fields and $3.0 billion for the Wheatstone facilities. The investment in the multi-year project will be funded over several years.

Apache is currently pursuing the sale of a small percentage of interests in its Julimar and Brunello field discoveries in conjunction with the sale of LNG to potential gas buyers, including those described below.

On July 19, 2010, Apache announced that it, KUFPEC and KOGAS had signed Heads of Agreements (HoAs) for KOGAS to purchase LNG from and to buy an equity stake in the Wheatstone LNG project in Australia. Under the LNG purchase HoA, KOGAS plans to purchase 1.5 million tons per annum of LNG from Apache, KUFPEC and Chevron for up to 20 years. Approximately 25 percent of the LNG is expected to be purchased from Apache and KUFPEC, with the remainder from Chevron. Apache's share of the sales agreement is expected to be approximately 240,000 tons of LNG per year, or 32 MMcf per day of natural gas. Under the equity HoA and the related transaction with Chevron, KOGAS intends to 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. Under the terms of KOGAS' participation, Apache's interest in the Wheatstone LNG facilities and Julimar and Brunello field discoveries, including the capital funding requirements, would be reduced to 15.4375 percent and 61.75 percent, respectively.

Results of Operations

Oil and Gas Revenues


	For the Quarter Ended June 30,										For the Six Months Ended June 30,
	2010					2009					2010					2009
	$		%			$		%			$		%			$		%
	Value		Contribution			Value		Contribution			Value		Contribution			Value		Contribution
	($ in millions)
Total Oil and Gas Revenues:
United States	$	962		32	%	$	707		34	%	$	1,954		35	%	$	1,303		35	%
Canada		240		8	%		215		10	%		493		9	%		425		12	%

North America		1,202		40	%		922		44	%		2,447		44	%		1,728		47	%

Egypt		806		28	%		655		32	%		1,547		27	%		1,075		29	%
Australia		452		15	%		87		4	%		676		12	%		130		4	%
North Sea		421		14	%		322		16	%		812		14	%		565		15	%
Argentina		88		3	%		88		4	%		180		3	%		180		5	%

International		1,767		60	%		1,152		56	%		3,215		56	%		1,950		53	%

Total ⁽¹⁾	$	2,969		100	%	$	2,074		100	%	$	5,662		100	%	$	3,678		100	%


Total Oil Revenues:
United States	$	604		27	%	$	459		31	%	$	1,198		29	%	$	792		32	%
Canada		94		4	%		79		5	%		191		5	%		136		5	%

North America		698		31	%		538		36	%		1,389		34	%		928		37	%

Egypt		682		30	%		523		35	%		1,307		31	%		840		34	%
Australia		411		19	%		60		4	%		594		14	%		83		3	%
North Sea		417		18	%		319		22	%		804		19	%		560		22	%
Argentina		50		2	%		51		3	%		101		2	%		103		4	%

International		1,560		69	%		953		64	%		2,806		66	%		1,586		63	%

Total ⁽²⁾	$	2,258		100	%	$	1,491		100	%	$	4,195		100	%	$	2,514		100	%


Total Gas Revenues:
United States	$	314		48	%	$	234		42	%	$	680		50	%	$	486		43	%
Canada		139		21	%		131		23	%		289		21	%		281		25	%

North America		453		69	%		365		65	%		969		71	%		767		68	%

Egypt		124		19	%		132		23	%		240		17	%		235		22	%
Australia		41		6	%		27		5	%		82		6	%		47		4	%
North Sea		4		1	%		3		1	%		8		1	%		5		–
Argentina		31		5	%		33		6	%		62		5	%		68		6	%

International		200		31	%		195		35	%		392		29	%		355		32	%

Total ⁽³⁾	$	653		100	%	$	560		100	%	$	1,361		100	%	$	1,122		100	%


Natural Gas Liquids (NGL)
Revenues:
United States	$	44		76	%	$	14		61	%	$	76		72	%	$	25		60	%
Canada		7		12	%		5		22	%		13		12	%		8		19	%

North America		51		88	%		19		83	%		89		84	%		33		79	%

Argentina		7		12	%		4		17	%		17		16	%		9		21	%

Total	$	58		100	%	$	23		100	%	$	106		100	%	$	42		100	%


⁽¹⁾		Included in oil and gas production revenues were a gain of $52.5 million and $51.3 million for the 2010 second quarter and six-month period, respectively, and a gain of $51.6 million and $107.7 million for the 2009 second quarter and six-month period, respectively, from financial derivative hedging activities.

⁽²⁾		Included in oil revenues were a loss of $11.9 million and $26.3 million for the 2010 second quarter and six-month period, respectively, and a gain of $13.1 million and $51.6 million for the 2009 second quarter and six-month period, respectively, from financial derivative hedging activities.

⁽³⁾		Included in natural gas revenues were a gain of $64.4 million and $77.6 million for the 2010 second quarter and six-month period, respectively, and a gain of $38.5 million and $56.1 million for the 2009 second quarter and six-month period, respectively, from financial derivative hedging activities.

Production


	For the Quarter Ended June 30,							For the Six Months Ended June 30,
					Increase							Increase
	2010		2009		(Decrease)			2010		2009		(Decrease)
Oil Volume – b/d:
United States		89,529		88,530		1	%		89,144		87,642		2	%
Canada		14,561		15,833		(8	)%		14,447		16,090		(10	)%

North America		104,090		104,363		—			103,591		103,732		—

Egypt		98,495		95,359		3	%		94,642		89,475		6	%
Australia		60,680		10,478		479	%		43,978		9,164		380	%
North Sea		58,141		59,688		(3	)%		57,995		60,089		(3	)%
Argentina		9,874		11,948		(17	)%		9,897		12,192		(19	)%

International		227,190		177,473		28	%		206,512		170,920		21	%

Total ⁽¹⁾		331,280		281,836		18	%		310,103		274,652		13	%


Natural Gas Volume – Mcf/d:
United States		674,886		662,834		2	%		673,361		637,894		6	%
Canada		339,611		373,796		(9	)%		326,646		365,551		(11	)%

North America		1,014,497		1,036,630		(2	)%		1,000,007		1,003,445		—

Egypt		388,367		376,737		3	%		375,249		347,443		8	%
Australia		203,147		161,069		26	%		205,209		151,607		35	%
North Sea		2,516		2,645		(5	)%		2,540		2,663		(5	)%
Argentina		183,028		192,542		(5	)%		168,953		192,250		(12	)%

International		777,058		732,993		6	%		751,951		693,963		8	%

Total ⁽²⁾		1,791,555		1,769,623		1	%		1,751,958		1,697,408		3	%


Natural Gas Liquids (NGL) Volume – b/d:
United States		11,878		5,483		117	%		9,374		5,198		80	%
Canada		1,996		2,052		(3	)%		1,866		2,082		(10	)%

North America		13,874		7,535		84	%		11,240		7,280		54	%
Argentina		3,118		3,091		1	%		3,204		3,114		3	%

Total		16,992		10,626		60	%		14,444		10,394		39	%


BOE per day ⁽³⁾
United States		213,889		204,485		5	%		210,746		199,156		6	%
Canada		73,159		80,185		(9	)%		70,753		79,097		(11	)%

North America		287,048		284,670		1	%		281,499		278,253		1	%

Egypt		163,223		158,148		3	%		157,184		147,382		7	%
Australia		94,538		37,323		153	%		78,179		34,431		127	%
North Sea		58,560		60,129		(3	)%		58,418		60,533		(3	)%
Argentina		43,497		47,130		(8	)%		41,260		47,348		(13	)%

International		359,818		302,730		19	%		335,041		289,694		16	%

Total		646,866		587,400		10	%		616,540		567,947		9	%


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

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

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

Pricing


	For the Quarter Ended June 30,							For the Six Months Ended June 30,
					Increase							Increase
	2010		2009		(Decrease)			2010		2009		(Decrease)
Average Oil Price – Per barrel:
United States	$	74.20	$	57.00		30	%	$	74.26	$	49.95		49	%
Canada		70.87		55.17		28	%		73.10		46.49		57	%
North America		73.73		56.72		30	%		74.10		49.41		50	%
Egypt		76.08		60.30		26	%		76.27		51.90		47	%
Australia		74.42		63.01		18	%		74.58		49.74		50	%
North Sea		78.78		58.77		34	%		76.58		51.51		49	%
Argentina		55.41		46.17		20	%		56.60		46.73		21	%
International		75.43		58.99		28	%		75.05		51.28		46	%
Total ⁽¹⁾		74.89		58.15		29	%		74.74		50.57		48	%

Average Natural Gas Price – Per Mcf:
United States	$	5.11	$	3.88		32	%	$	5.58	$	4.21		33	%
Canada		4.51		3.86		17	%		4.88		4.26		15	%
North America		4.91		3.88		27	%		5.35		4.23		26	%
Egypt		3.51		3.85		(9	)%		3.54		3.73		(5	)%
Australia		2.22		1.82		22	%		2.22		1.71		30	%
North Sea		17.15		12.24		40	%		17.73		9.82		81	%
Argentina		1.88		1.89		(1	)%		2.01		1.94		4	%
International		2.83		2.92		(3	)%		2.88		2.82		2	%
Total ⁽²⁾		4.01		3.48		15	%		4.29		3.65		18	%

Average NGL Price – Per barrel:
United States	$	40.48	$	27.36		48	%	$	44.63	$	25.90		72	%
Canada		35.76		24.23		48	%		37.97		22.40		70	%
North America		39.80		26.50		50	%		43.52		24.90		75	%
Argentina		25.68		15.91		61	%		30.23		16.51		83	%
Total		37.21		23.42		59	%		40.58		22.39		81	%


⁽¹⁾		Reflects a per barrel decrease of $.39 and $.47 from financial derivative hedging activities for the 2010 second quarter and six-month period, respectively, and an increase of $.51 and $1.04 from financial derivative hedging activities for the 2009 second quarter and six-month period, respectively.

⁽²⁾		Reflects a per Mcf increase of $.39 and $.24 from financial derivative hedging activities for the 2010 second quarter and six-month period, respectively, and an increase of $.24 and $.18 from financial derivative hedging activities for the 2009 second quarter and six-month period, respectively.

Second-Quarter 2010 compared to Second-Quarter 2009

Crude Oil Revenues Second-quarter crude oil revenues of $2.3 billion were $767 million higher than the 2009 period as worldwide production surged 18 percent to 331,280 b/d and prices rose 29 percent. Crude oil accounted for 76 percent of our oil and gas production revenues during the quarter and 51 percent of our equivalent production, compared to 72 and 48 percent, respectively, for the same period last year. Higher production volumes contributed $337 million to the increase in second-quarter revenues, while higher realized prices added another $430 million.

U.S. oil revenues were $145 million higher than the 2009 quarter; $138 million from higher price realizations and $7 million from increased production. Prices in the U.S. were 30 percent higher, while production increased marginally. The Gulf Coast region production was down two percent on natural decline. The Central region production increased 717 b/d on drilling activity and the Permian region increased production five percent on new drilling and acquisitions.

Canada’s revenues increased $15 million, with higher prices contributing $23 million of additional revenues. The benefit from higher prices was partially offset by an eight percent drop in production, primarily from natural decline. Canada’s oil prices averaged $70.87 per barrel, up 28 percent from the 2009 comparative quarter.

Egypt’s crude oil revenues rose $159 million compared to the prior-year quarter as oil price realizations increased 26 percent, boosting revenues by $137 million. Production growth added $22 million. Gross production increased 14 percent while net production was up only three percent, a function of higher prices and the mechanics of our production sharing contracts. Gross production growth was driven by our drilling and recompletion programs at the Matruh, East Bahariya Extension, South Umbarka and Shushan concessions.

Australia’s oil revenues were $351 million higher than the prior-year quarter on a sharp increase in production at the Pyrenees and Van Gogh developments, which together contributed an additional 51,393 b/d, driving total Australia production to 60,680 b/d. The higher production added $340 million to revenue while higher price realizations, which were up 18 percent, added another $11 million.

North Sea crude oil revenues were up $98 million. This was due to a 34 percent increase in prices, raising revenues by $109 million, partially offset by a three percent drop in production, which decreased revenues by $11 million. Production was down primarily on natural decline.

Argentina’s oil revenues totaled $50 million, down slightly from the year-ago period. Production decreased 17 percent on natural decline, lowering revenues by $11 million, mostly offset by 20 percent higher price realizations that contributed $10 million to revenues. Oil realizations averaged $55.41 per barrel, as export price limitations imposed on our Argentine production moderated price realizations as compared to our other operating regions.

Natural Gas Revenues Second-quarter natural gas revenues of $653 million were $93 million higher than the comparable 2009 period, driven primarily by higher realized prices. Average realized prices for the quarter of $4.01 per Mcf, a 15 percent increase from the $3.48 seen in the second quarter of 2009, boosted revenues by $85 million. Worldwide production increased one percent to 1,792 MMcf/d, adding another $8 million.

U.S. natural gas revenues were up $80 million, with a 32 percent rise in realized prices and two percent higher production increasing revenues by $74 million and $6 million, respectively. Natural gas prices averaged $5.11 per Mcf, up from $3.88 from the comparable year-ago period. Gulf Coast region gas production was up five percent with production restored from wells shut-in because of hurricanes, additional production resulting from new drilling and recompletion activity and properties acquired in the Devon acquisition more than offsetting natural decline. Central region production was up two percent from drilling and recompletion activity. A change in natural gas marketing strategy in the Permian region led to a 10 percent reduction in sales volumes. During the quarter we entered into new marketing contracts, and condensate-rich gas production which was previously sold prior to being processed is now being sold after liquids are removed. The result was an increase in the volumes of natural gas liquids (NGL) sold, and an associated decrease in the volumes of natural gas sold. Permian region’s NGL production for the period increased 5,128 b/d to 6,475 b/d, 381 percent higher than the year-ago period.

Canada’s natural gas revenues increased $8 million as a 17 percent increase in price realizations was largely offset by a nine percent decrease in production. Gas price realizations rose $0.65 to $4.51 per Mcf, increasing revenues $22 million. Driven primarily by natural decline, gas production fell to 340 MMcf/d, reducing revenues by $14 million.

Egypt’s natural gas revenues were down $8 million compared to the 2009 second quarter, with a $12 million reduction related to a nine percent price drop partially offset by $4 million of additional revenues attributed to production gains. Gross production was up 14 percent, while net production rose only three percent, a function of the mechanics of our production sharing contracts. The increase in gross production was primarily from drilling and recompletion activity on our Khalda and Matruh concessions.

Australia’s natural gas revenues rose $14 million relative to the prior-year period, with a 26 percent increase in production adding $8 million in revenues and a 22 percent increase in prices contributing another $6 million. Production reached an average of 203 MMcf/d, up on higher customer takes from our Harriet and John Brookes fields.

Argentina’s gas revenues fell $2 million on a five percent decline in production, related to natural decline. Production for the quarter was 183 MMcf/d. Natural gas realizations of $1.88 per Mcf were relatively flat from last year’s second quarter and resulted in a minimal downward impact on revenues.

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 June 30,				For the Quarter Ended June 30,
	2010		2009		2010		2009
	(In millions)				(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	676	$	527	$	11.49	$	9.86
Other assets		53		46		.91		.87
Asset retirement obligation accretion		25		27		.42		.50
Lease operating expenses		446		405		7.58		7.58
Gathering and transportation		43		34		.73		.62
Taxes other than income		187		116		3.17		2.17
General and administrative expenses		92		91		1.56		1.70
Financing costs, net		56		61		.95		1.14


Total	$	1,578	$	1,307	$	26.81	$	24.44

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


	Recurring DD&A
	(In millions)
Second-quarter 2009 DD&A	$	527
Volume change		67
Rate change		82


Second-quarter 2010 DD&A	$	676

Recurring full-cost DD&A expense of $676 million increased $149 million on an absolute dollar basis; $82 million higher on rate and $67 million from higher production. The Company’s full-cost DD&A rate increased $1.63 to $11.49 per boe as the costs to acquire, find and develop reserves continue to exceed our historical cost basis. The recent acquisition of assets on the Gulf of Mexico shelf from Devon, completed in June 2010, also impacted the current quarter full-cost depletion rate.

Lease Operating Expenses (LOE) Second-quarter 2010 LOE increased $41 million, or 10 percent on an absolute dollar basis, as compared to the second quarter of 2009. On a per unit basis, LOE was unchanged. The following table identifies changes in Apache’s LOE rate between the second quarter of 2009 and 2010.


	Per boe
Second-quarter 2009 LOE	$	7.58
FX impact		0.22
Equipment rental – Australia		0.22
Workover costs		0.13
Labor and pumper costs		0.12
Other		0.12
Devon acquisition		0.10
Materials, surface and sub-surface		0.08
Non-recurring repair and maintenance		0.06
Power and fuel costs		0.06
U.S. hurricane repair costs		(0.35	)
Increased production		(0.76	)


Second-quarter 2010 LOE	$	7.58

Gathering and Transportation Gathering and transportation costs totaled $43 million in the second quarter of 2010, up $9 million. On a per unit basis, gathering and transportation costs were up 18 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
	June 30,
	2010		2009
	(In millions)
U.S.	$	11	$	8
Canada		16		13
North Sea		6		6
Egypt		9		6
Argentina		1		1


Total Gathering and Transportation	$	43	$	34

The U.S. increased $3 million primarily from an increase in volumes transported under contracts where charges are paid directly to a third party. Canada’s transportation was up $3 million primarily from the impact of foreign exchange rates and higher gas transportation rates, partially offset by lower transported volumes. Egypt’s costs were up $3 million on an increase in tariff fees.

Taxes other than Income Taxes other than income totaled $187 million, an increase of $71 million. On a per unit basis, taxes other than income increased 46 percent. Higher production decreased the rate by 15 percent, while higher costs increased the rate by 61 percent. A detail of these taxes follows:


	For the Quarter Ended
	June 30,
	2010		2009
	(In millions)
U.K. PRT	$	130	$	73
Severance taxes		28		18
Ad valorem taxes		17		13
Canadian taxes		3		4
Other		9		8


Total Taxes other than Income	$	187	$	116

U.K. Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $57 million higher than the 2009 period on an 85 percent increase in net profits, driven by 34 percent higher realized oil prices and 23 percent lower capital expenditures.

Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The $10 million increase in severance taxes resulted from higher taxable revenues in the U.S. and Australia, consistent with the higher realized oil and natural gas prices.

Ad valorem taxes are assessed on U.S. and Canadian property values. The $4 million increase resulted primarily from higher commodity prices which increased property values over 2009.

General and Administrative Expenses General and administrative expenses (G&A) were $1 million higher on an absolute basis, but on a per unit basis were down $.14 to an average of $1.56 per boe. Lower employee separation costs and stock-based compensation costs were offset by higher administrative costs related to acquisitions, the Kitimat LNG project and various other corporate expenses.

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


	For the Quarter Ended
	June 30,
	2010			2009
	(In millions)
Interest expense	$	75		$	77
Amortization of deferred loan costs		1			1
Capitalized interest		(18	)		(15	)
Interest income		(2	)		(2	)

Financing costs, net	$	56		$	61

Net financing costs fell $5 million, or $.20 on a boe basis. The decrease in absolute dollars is primarily the result of a $2 million decrease in interest expense related to lower average outstanding debt balances and a $3 million increase in capitalized interest related to higher unproved property balances. The $.20 reduction on a unit basis was essentially split evenly between the lower net costs and the impact of higher production.

The provision for income taxes increased $192 million to $534 million, 56 percent above prior year, as income before taxes increased on higher oil and gas production revenues. The effective income tax rate in the second quarter of 2010 was 38.3 percent compared to 43.5 percent in the second quarter of 2009. The 2010 rate was impacted by a $32 million non-cash benefit related to the strengthening U.S. dollar compared to $31 million of expense in 2009.

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

Crude Oil Revenues Year-to-date crude oil revenues of $4.2 billion were $1.7 billion higher than the 2009 period as worldwide production increased 13 percent to 310,103 b/d and prices rose 48 percent over the prior-year period. Crude oil accounted for 74 percent of our oil and gas production revenues during the period and 50 percent of our equivalent production, compared to 68 and 48 percent, respectively, for the same period last year. Higher realized prices added $1.2 billion to our six-month revenues, while higher production volumes contributed $480 million.

U.S. oil revenues were $406 million higher than the comparable six-month period of 2009: $386 million from higher price realizations and $20 million from increased production. Prices in the U.S. jumped 49 percent, while production increased two percent. Central region production increased 18 percent on drilling activity and the Permian region increased production three percent on new drilling and acquisitions. Gulf Coast region production was flat as compared to the prior period.

Canada’s revenues increased $55 million, with higher prices contributing $77 million and decreased production lowering revenues by $22 million. Canada’s oil prices averaged $73.10 per barrel, up 57 percent from the year-ago period. Production fell 10 percent, primarily from natural decline.

Egypt’s crude oil revenues rose $467 million as oil price realizations increased 47 percent, boosting revenues $395 million. Production growth added $72 million, relative to the 2009 period. Gross production increased 16 percent while net production was up only six percent, a function of higher prices and the mechanics of our production sharing contracts. Gross production growth was driven by drilling and recompletion programs at the Matruh, East Bahariya Extension, South Umbarka and Northeast Abu Gharadig (NEAG) Extension concessions.

Australia’s oil revenues were $511 million higher than the prior-year six-month period on a sharp increase in production at the Pyrenees and Van Gogh developments, which together contributed an additional 34,559 b/d, driving total Australia production to 43,978 b/d. The higher production added $470 million to revenue while higher price realizations, which were up 50 percent, adding another $41 million.

North Sea crude oil revenues were up $244 million. This was due to a 49 percent increase in prices, raising revenues by $273 million, partially offset by a three percent drop in production, which decreased revenues by $29 million. Production was down on natural decline.

Argentina’s oil revenues totaled $101 million, down slightly from the year-ago period. Production decreased 19 percent on natural decline lowering revenues by $24 million, which was mostly offset by 21 percent higher price realizations that contributed $22 million of additional revenues. Oil realizations averaged $56.60 per barrel, as export price limitations imposed on our Argentine production moderate price realizations as compared to our other operating regions.

Natural Gas Revenues Natural gas revenues for the six-month period of 2010 of $1.4 billion were $239 million higher than the comparable 2009 period, driven primarily by higher realized prices. Average realized prices for the period of $4.29 per Mcf, an 18 percent increase from the $3.65 seen in the 2009 period, boosted revenues by $197 million. Worldwide production increased three percent to 1,752 MMcf/d, adding another $42 million to revenues.

U.S. natural gas revenues were up $194 million, with a 33 percent rise in realized prices and six percent higher production increasing revenues by $158 million and $36 million, respectively. Natural gas prices averaged $5.58 per Mcf, up from $4.21 in the comparable year-ago period. Gulf Coast region gas production increased 13 percent on new drilling and recompletions, as well as production from acquisitions. Central region production was down four percent on natural decline. Permian region gas production was up marginally.

Canada’s natural gas revenues increased $8 million as a 15 percent increase in price realizations was largely offset by an 11 percent decrease in production. Gas price realizations rose $.62 to $4.88 per Mcf, increasing revenues $42 million. Driven primarily by natural decline, gas production fell to 327 MMcf/d, reducing revenues by $34 million.

Egypt’s natural gas revenues were up $5 million compared to the 2009 period, with $17 million of additional revenues attributed to production gains being partially offset by a $12 million reduction related to a five percent price decline. Gross production was up 20 percent, while net production rose only eight percent, a function of the mechanics of our production sharing contracts. The increase in gross production was primarily from our Khalda and Matruh concessions.

Australia’s natural gas revenues rose $35 million, with a 35 percent increase in production adding $21 million in revenues and a 30 percent increase in prices contributing another $14 million. Production reached an average of 205 MMcf/d in the period on higher customer takes from our Harriet and John Brookes fields.

Argentina’s gas revenues fell $6 million, as 12 percent lower production reduced revenues by $8 million and four percent higher prices added back $2 million. Production for the current period was 169 MMcf/d, down primarily on natural decline. Natural gas realizations rose $.07 to $2.01 per Mcf.

Operating Expenses


	For the Six Months Ended June 30,				For the Six Months Ended June 30,
	2010		2009		2010		2009
	(In millions)				(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	1,263	$	1,063	$	11.32	$	10.34
Additional		—		2,818		—		27.41
Other assets		105		91		.94		.89
Asset retirement obligation accretion		49		53		.44		.52
Lease operating expenses		886		803		7.94		7.81
Gathering and transportation		83		67		.75		.65
Taxes other than income		364		203		3.26		1.98
General and administrative expenses		179		176		1.60		1.71
Financing costs, net		115		120		1.03		1.16


Total	$	3,044	$	5,394	$	27.28	$	52.47

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


	Recurring DD&A
	(In millions)
2009 DD&A	$	1,063
Volume change		104
Rate change		96


2010 DD&A	$	1,263

Recurring full-cost DD&A expense of $1.26 billion increased $200 million on an absolute dollar basis; $104 million from higher production and $96 million on rate. The Company’s full-cost DD&A rate increased $.98 to $11.32 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) LOE for the first six months of 2010 increased $83 million, or 10 percent on an absolute dollar basis, as compared to the same period of 2009. On a per unit basis, LOE increased two percent with the impact of higher production nearly offsetting a 10 percent increase in higher costs. The following table identifies changes in Apache’s LOE rate between the six-month periods ended June 30, 2009 and 2010.


	Per boe
2009 LOE	$	7.81
FX impact		0.33
Equipment rental – Australia		0.18
Workover costs		0.15
Stock-based compensation		0.10
OIL theoretical withdrawal		0.10
Labor and pumper costs		0.08
Materials, surface and sub-surface		0.06
Other		0.05
Power and fuel costs		0.05
U.S. hurricane repair costs		(0.29	)
Increased production		(0.68	)

2010 LOE	$	7.94

Gathering and Transportation Gathering and transportation costs totaled $83 million in the first six months of 2010, up $16 million. On a per unit basis, gathering and transportation costs were up 15 percent as higher costs increased the rate 25 percent and higher production decreased the rate 10 percent. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:


	For the Six Months Ended
	June 30,
	2010		2009
	(In millions)
U.S.	$	21	$	16
Canada		33		24
North Sea		12		13
Egypt		15		12
Argentina		2		2


Total Gathering and Transportation	$	83	$	67

The $5 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 $9 million primarily from the impact of foreign exchange rates and higher gas transportation rates, partially offset by lower transported volumes. Egypt’s costs were up $3 million on an increase in tariff fees.

Taxes other than Income Taxes other than income totaled $364 million, an increase of $161 million. On a per unit basis, taxes other than income increased 65 percent; 79 percent on higher costs, offset by 14 percent decrease in rate on production growth. A detail of these taxes follows:


	For the Six Months Ended
	June 30,
	2010		2009
	(In millions)
U.K. PRT	$	253	$	123
Severance taxes		60		35
Ad valorem taxes		35		21
Canadian taxes		1		8
Other		15		16


Total Taxes other than Income	$	364	$	203

U.K. PRT is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT was $130 million more than the 2009 period on a 105 percent increase in net profits driven by a 49 percent increase in realized oil prices, and 15 percent lower capital expenditures.

Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The $25 million increase in severance taxes resulted from higher taxable revenues in the U.S., consistent with the higher realized oil and natural gas prices.

Ad valorem taxes are assessed on U.S. and Canadian assessed property values. The $14 million increase resulted primarily from an increase in assessments from the prior year.

General and Administrative Expenses General and administrative expenses (G&A) were $3 million higher on an absolute basis, but on a per unit basis were down $.11 to an average of $1.60 per boe. Lower employee separation costs were offset by higher stock-based compensation, higher administrative costs related to acquisitions, the Kitimat LNG project and various other corporate expenses.

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


	For the Six Months Ended
	June 30,
	2010			2009
	(In millions)
Interest expense	$	151		$	156
Amortization of deferred loan costs		3			3
Capitalized interest		(35	)		(31	)
Interest income		(4	)		(8	)

Financing costs, net	$	115		$	120

Net financing costs fell $5 million, primarily the result of a $5 million decrease in interest expense. On a per boe basis, net financing costs were down $.13, with approximately two-thirds of the decline in the boe rate attributable to higher production.

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 discrete items were recorded in the first half 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 significant discrete tax events occurred during the second quarter of 2009.

The provision for income taxes for the first six months of 2010 was an expense of $1.0 billion compared to a benefit of $354 million in the 2009 period. The benefit resulted from the non-cash write-down of the carrying value of our proved oil and gas properties previously discussed. The effective income tax rate was 39.8 percent compared to 21.3 percent in 2009, impacted by the magnitude of the tax benefit related to the write-down. We recorded a $25 million benefit to tax expense in 2010 related to foreign currency fluctuations, compared to a $26 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					For the Six Months
	Ended June 30,					Ended June 30,
	2010			2009		2010			2009
	(In millions, except per share data)
Income (Loss) Attributable to Common Stock (GAAP)	$	860		$	443	$	1,565		$	(1,315	)

Adjustments:
Foreign currency fluctuation impact on deferred tax expense		(31	)		31		(25	)		26
Additional depletion, net of tax ⁽¹⁾		—			—		—			1,982

Adjusted Earnings (Non-GAAP)	$	829		$	474	$	1,540		$	693


Adjusted Earnings Per Share (Non-GAAP)
Basic	$	2.45		$	1.41	$	4.57		$	2.07

Diluted	$	2.44		$	1.41	$	4.54		$	2.05


Average Number of Common Shares
Basic		337,618			335,637		337,273			335,372

Diluted		339,377			337,365		339,282			337,198


⁽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 highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash flows, and potentially our liquidity, if costs do not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactive as commodity prices in the short-term.

Our long-term operating cash flows are 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. Apache’s ability to access the debt and equity capital markets is supported by its investment-grade credit ratings.

We believe the liquidity and capital resource alternatives available to Apache, combined with internally-generated cash flows, will be adequate to fund our short-term and long-term operations, including our capital spending program, repayment of debt maturities and any amount that may ultimately be paid in connection with contingencies.

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

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

Sources and Uses of Cash

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


	For the Six Months Ended
	June 30,
	2010			2009
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	3,085		$	1,367
Sale of short-term investments		—			792
Net commercial paper and bank loan borrowings		—			148
Restricted cash		—			14
Common stock issuances		25			13
Other		22			9

		3,132			2,343


Uses of Cash and Cash Equivalents:
Capital expenditures ⁽¹⁾	$	2,195		$	2,283
Oil and gas acquisitions		1,017			181
Payments on fixed-rate notes		—			100
Dividends		101			103
Net commercial paper and bank loan repayments		55			—
Other		7			86

		3,375			2,753


Increase (decrease) in cash and cash equivalents	$	(243	)	$	(410	)


⁽¹⁾		The table presents capital expenditures on a cash basis; therefore, the amounts differ from those discussed elsewhere in this document, which include accruals.

Net Cash Provided by Operating Activities Cash flows are our primary source of capital and liquidity and are impacted, both in the short-term and the long-term, by highly volatile oil and natural gas prices.

Crude oil realizations averaged $74.74 for the first six months of 2010, up 48 percent from 2009 levels. Natural gas price realizations averaged $4.29 per Mcf, 18 percent higher than the comparable 2009 period.

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.

Net cash provided by operating activities for the first six months of 2010 totaled $3.1 billion, up $1.7 billion from the first six months of 2009. The increase reflects the impact of higher oil and gas revenues (up $2.0 billion) with higher commodity prices contributing $1.4 billion, and a nine percent increase in daily equivalent production adding another $552 million. Also positively impacting operating cash flows was the change in working capital during the first six months of 2010 compared to same period of 2009.

For a detailed discussion of commodity prices, production, costs and expenses, refer to the “Results of Operations” of this Item 2. For additional detail of changes in operating assets and liabilities, see the Statement of Consolidated Cash Flows in Item 1, Financial Statements of this Quarterly Form 10-Q.

Capital Expenditures We fund exploration and development activities primarily through operating cash flows and budget capital expenditures based on projected cash flows. Capital expenditures totaled $3.6 billion for the first six months of 2010, compared to $2.3 billion for the comparable period last year. The following table details capital expenditures for each country in which we do business for the six months ended June 30, 2010 and 2009:


	For the Six Months
	Ended
	June 30,
	2010		2009
	(In millions)
Exploration and Development Costs:
United States	$	618	$	569
Canada		365		210

North America		983		779


Egypt		305		389
Australia		295		285
North Sea		230		216
Argentina		94		82
Chile		14		4

International		938		976

Worldwide Exploration and Development Costs		1,921		1,755


Gathering Transmission and Processing Facilities:
Canada		72		56
Egypt		90		95
Australia		90		13
Argentina		1		1

Total Gathering Transmission and Processing Facility Cost		253		165


Asset Retirement Costs		315		94

Capitalized Interest		35		31


Capital Expenditures, excluding acquisitions		2,524		2,045


Acquisitions – Oil and Gas Properties		1,033		243


Total Capital Expenditures	$	3,557	$	2,288

Exploration and development (E&D) expenditures were $166 million, or nine percent, higher than the 2009 comparable six-month period. The U.S. accounted for 32 percent of total E&D activity in the first six months of 2010 and 2009. Canada accounted for 19 percent of worldwide E&D expenditures in the first six months of 2010, up $155 million from the comparable 2009 period, primarily on increased drilling activity in the Horn River Basin. Egypt accounted for 16 percent of worldwide E&D spending for the first six months of 2010, compared to 22 percent in the prior-year period, down $84 million on lower drilling activity and reduction of well costs. Australia’s E&D expenditures were up slightly and represented 15 percent of total expenditures. North Sea’s E&D expenditures increased $14 million and represented 12 percent of worldwide E&D expenditures. Argentina, which represented five percent of E&D spending, increased E&D expenditures $12 million. Chile’s E&D expenditures increased $10 million and represented less than one percent of worldwide E&D expenditure spending.

Gathering, transmission and processing (GTP) facility expenditures totaled $253 million, in the first half of 2010. GTP expenditures in Australia during the first six months of 2010 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 phase of the Kalabsha oil processing facility.

On June 9, 2010, we completed the acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon. The acquisition is effective as of January 1, 2010.

Dividends In both six-month periods ended June 30, 2010 and 2009, the Company paid $101 million in dividends on its common stock. In the first six months of 2009, Apache paid a total of $2.8 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.

Liquidity

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


	June 30,			December 31,
	2010			2009
	(In millions of dollars, except as indicated)
Cash and cash equivalents	$	1,805		$	2,048
Total debt		5,012			5,067
Shareholders’ equity		17,676			15,779
Available committed borrowing capacity		2,300			2,300
Floating-rate debt/total debt		6	%		7	%
Percent of total debt-to-capitalization		22	%		24	%

Cash and Cash Equivalents We had $1.8 billion in cash and cash equivalents as of June 30, 2010, compared to $2.0 billion at December 31, 2009. Approximately $1.7 billion of the cash was held by foreign subsidiaries, with the remaining balance held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid investment grade securities with maturities of three months or less at the time of purchase.

Debt As of June 30, 2010, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $5.0 billion. Current debt includes $115 million of loans under the Apache PVG Pty Ltd facility due over the next 12 months and $1.2 million borrowed under uncommitted overdraft lines in Argentina and the U.S.

Available committed borrowing capacity As of June 30, 2010, the Company had unsecured committed revolving syndicated bank credit facilities totaling $2.3 billion, which mature in May 2013. These consist of a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. Since there are no outstanding borrowings or commercial paper at June 30, 2010, the full $2.3 billion of unsecured credit facilities are available to the Company.

The Company has available a $1.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100 percent backstop.

The outstanding balance under the facility as of June 30, 2010 was $300 million, in accordance with the terms of the facility. Also, under the terms of the agreement, the facility amount will be further reduced semi-annually until maturity on March 31, 2014, with $60 million and $55 million of the outstanding balance due on December 31, 2010, and June 30, 2011, respectively. This $115 million is classified as current debt at June 30, 2010.

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

Percent of total debt to capitalization The Company’s June 30, 2010 debt-to-capitalization ratio was 22 percent, down from 24 percent at December 31, 2009.

Credit Rating As of June 30, 2010, Apache’s senior unsecured long-term debt was rated A3 by Moody’s, A- by Standard & Poor’s and A- by Fitch. The Company has received short-term debt ratings for its commercial paper program of P-2 from Moody’s, A-2 from Standard & Poor’s and F2 from Fitch. Following announcement of the BP asset acquisition, Moody’s put Apache’s A3 senior unsecured debt rating under review for downgrade and Fitch placed the Company’s A- senior unsecured debt rating on rating watch negative.

Impact of Recent Acquisitions

Common and Depositary Share Offering In conjunction with the acquisition of BP Properties, Apache issued 26.45 million shares of common stock at a public offering price of $88.00 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering were approximately $2.3 billion. The initial offering of 21 million shares was increased to 23 million shares and the underwriters exercised their option to purchase an additional 3.45 million shares. The Company also received proceeds of $1.2 billion, after underwriting discounts and before expenses, from the sale of 25.3 million depositary shares, each representing a 1/20 ^th interest in a share of Apache’s 6.00% Mandatory Convertible Preferred Stock, Series D, with an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). The Company offered 22 million depositary shares and the underwriters exercised their option to purchase an additional 3.3 million depositary shares. Proceeds to the Company from the common stock and depositary share offerings totaled approximately $3.5 billion after underwriting discounts and before expenses.

The Company plans to fund the asset acquisition with the proceeds of these offerings and a combination of the following: cash on hand, our existing revolving credit and commercial paper facilities, a 364-day revolving credit facility, the issuance of term debt and the short term use of a bridge loan facility. The Company intends to increase its commercial paper program by $1 billion, the amount of the new 364-day revolving credit facility. We also secured a $5 billion bridge loan facility to backstop our financing requirements. The commitment under the bridge loan facility has been reduced by $3.5 billion, which is the amount of the net proceeds from the common stock and mandatory convertible preferred offerings discussed above. Depending on when the closing of the acquisition of the Permian Basin BP Properties occurs, we may fund a portion of the amount due for those properties by drawing under the bridge loan facility. Any such borrowing would be repaid from the Company’s next debt offering. Under the purchase and sale agreement, Apache advanced $5 billion of the purchase price to BP plc on July 30, 2010, ahead of the anticipated closings. This advance will be returned to Apache or applied to the purchase price at closing. BP plc provided a limited guarantee with respect to the BP Purchase Agreements, principally as to the return of the advance. The transaction is effective July 1, 2010, with closing subject to certain preferential rights as well as normal regulatory approvals and conditions in the U.S., Canada and Egypt. On August 3, 2010, the U.S. Department of Justice and the Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. We anticipate the transactions will close in the third and fourth quarters of 2010.

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 which 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 has in place for its Gulf of Mexico operations a Region Spill Response Plan (the Plan), which details procedures for rapid and effective response to spill events that may occur as a result of Apache’s operations. 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 Bureau of Ocean Energy Management, Regulatory and Enforcement (formerly, the Minerals Management Service). 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 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 (including skimmers, fast response vessels, 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. MSRC has contracts in place with many environmental contractors around the country, in addition to hundreds of other companies which provide support services during spill response. In the event of a spill, MSRC will activate these contracts as necessary to provide additional resources or support services requested by its customers. In addition, CGA maintains a contract with Airborne Support Inc. (ASI), which provides aircrafts and dispersant capabilities for CGA member companies. Apache’s annual fees 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 and MSRC 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 is the world’s largest oil spill preparedness and response organization, dedicated to providing resources to respond to oil spills efficiently and effectively on a global basis. In addition, resources of other organizations are available to Apache as a non-member, such as those of National Response Corporation (NRC) and MSRC, albeit at a higher cost.

In light of the current events in the Gulf of Mexico, Apache is participating in a number of industry-wide task forces, which 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 acquisition 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 gives 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.

While the Merger (discussed above), if consummated, will increase our holdings in the U.S., we believe that following the Merger Apache will maintain asset diversity, as production from our international locations is projected to increase for the next several years as longer-term projects to develop significant discoveries are completed.

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, Mariner’s, or the combined company’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 dramatically since the first six months of 2009, rising 48 percent to $74.74 per barrel in first six months 2010 from $50.57 per barrel in first six months 2009. Our average natural gas price realizations have also trended upward, increasing 18 percent to $4.29 per Mcf in the first six months of 2010 from $3.65 per Mcf in the first six months 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 second quarter and first six 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 nine and 11 percent, respectively.

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

On June 30, 2010, the Company had open natural gas derivative hedges in an asset position with a fair value of $294 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $114 million, while a 10 percent decrease in prices would increase the fair value by approximately $114 million. The Company also had open oil derivatives in a liability position with a fair value of $95 million. A 10 percent increase in oil prices would increase the liability by approximately $190 million, while a 10 percent decrease in prices would move the derivatives to an asset position of $88 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2010. See Note 4 – Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Item 1 of this quarterly report for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 94 percent of the Company’s debt. At June 30, 2010, total debt included $301 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 six percent of our total debt outstanding at June 30, 2010. The impact on cash flow of a 10 percent change in the floating interest rate from that at June 30, 2010, would be approximately $103,500 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 June 30, 2010, would result in a cumulative foreign currency net loss or gain, respectively, of approximately $54 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 and the BP Acquisition;

•

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 following completion of the BP Acquisition;

•

the affect on the BP Acquisition and/or our liabilities in the event one or more BP entities becomes the subject of a bankruptcy case;

•

the affect on our common stock due to a failure to complete the BP Acquisition;

•

regulatory approvals and third party consents required for the consummation of the BP Acquisition by Apache may not be received in a timely manner;

•

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 June 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 and June 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 and our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2010. For the quarter ending June 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.

A drilling moratorium in the U.S. Gulf of Mexico, or other regulatory initiatives in response to the current oil spill 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 “BOEM”) of the U.S. Department of the Interior 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 July 12, 2010, the BOEM issued a new moratorium that applies to deep-water drilling operations that use subsea blowout preventers or surface blowout preventers on floating facilities. The new moratorium will last until November 30, 2010, or until such earlier time that the BOEM determines that deep-water drilling operations can proceed safely. The BOEM is also 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 the moratorium or any new guidelines, regulations or legislation, a prolonged suspension of drilling activity in the U.S. Gulf of Mexico and other areas, 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, as the acquirer of certain of BP’s operations. 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 will not be resolved before closing.*

			Because of the relatively short time period between signing the BP Purchase Agreements and the expected closing of the BP Acquisition, several significant matters commonly resolved prior to closing such an acquisition have been reserved for after closing. For example, title review with respect to most of the BP Properties will not be completed until after closing. In addition, we will not have sufficient time before closing to conduct a full assessment of any environmental and legal liabilities with respect to the BP Properties. As a result, we may discover title defects or adverse environmental or other conditions after we have closed the BP Acquisition and after expiration of 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 conditions by BP for such matters. In addition, not all environmental or other conditions that may be identified will be the subject of contractual remedies, however, such contractual remedies may not be adequate for any liabilities we incur.

			*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 were 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. In addition, the preliminary revenue and direct operating expense estimates with respect to the BP Properties were provided by BP, are unaudited, and have not been reviewed by our independent accountants. We cannot assure you that these preliminary estimates are accurate, and when we file separate financial statements and pro forma financial information following consummation of the BP Acquisition, such amounts 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 Title 11 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. Furthermore, if any of the BP entities were to become the subject of such a case or proceeding, and we were unable to consummate the BP Acquisition, we may not be able to collect all or a portion of the full $5.0 billion we have deposited with BP plc pending completion of the acquisition.

			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.

			We will incur significant transaction and BP Acquisition-related costs in connection with the financing of the BP Acquisition, and may be unable to complete alternative financing before closing the BP Acquisition.

			We expect to incur, until the closing of the BP Acquisition, significant non-recurring costs associated with the financing of the BP Acquisition, including obtaining and maintaining the committed Bridge Facility that assures our ability to pay the consideration for the BP Acquisition. In addition, we will be subject to numerous market risks in connection with our plan to raise alternative financing to fund the purchase price of the BP Acquisition prior to closing, including risks related to general economic conditions and changes in the costs of capital. In the event less than all of the BP Acquisition purchase price, or applicable portions thereof, is available to us when due and payable, we will be required to draw under the Bridge Facility in order to complete the BP Acquisition.

			*The failure to complete the BP Acquisition could adversely affect the market price of our common stock and otherwise have an adverse effect on us.*

			There are a number of conditions to the completion of the BP Acquisition contained in the BP Purchase Agreements that must be satisfied for the transactions to close, and there can be no assurance that the conditions will be satisfied. If we do not complete the acquisition under one or more of the BP Purchase Agreements, the market price of our common stock will likely fall to the extent that the market price reflects an expectation that all of the transactions will be completed. Further, a failed transaction may result in negative publicity and/or negative impression of us in the investment community and may affect our relationships with creditors and other business partners.

			If the BP Acquisition is not completed, we also must pay costs related to the BP Acquisition including, among others, legal, accounting and financial advisory, as well as certain fees and expenses with respect to the committed Bridge Facility whether the BP Acquisition is completed or not. We also could be subject to litigation related to the failure to complete the BP Acquisition or other factors, which may adversely affect our business, financial results and stock price. In addition, if the BP Acquisition is not completed, we intend to use the net proceeds in connection with our offerings of common stock, depositary shares and the subsequent debt financing we expect to undertake, for general corporate purposes. However, we would be subject to significant earnings per share dilution and significantly increased leverage as a result.

			*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.

			The instrument governing our revolving credit facility limits, the Bridge Facility limits, and 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 thereunder (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 bookrunners, 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)


†*10.2		Amendment to Apache Corporation 401(k) Plan, dated July 14, 2010.

†*10.3		Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated July 14, 2010, except as otherwise specified.

†*10.4		Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated July 13, 2010, effective December 31, 2009.

†*10.5		Apache Corporation Income Continuance Plan, as amended and restated July 14, 2010, effective January 1, 2009.

†*10.6		Apache Corporation Deferred Delivery Plan, as amended and restated July 13, 2010, effective January 1, 2009.

†*10.7		Apache Corporation Outside Directors’ Retirement Plan, as amended and restated July 14, 2010, effective January 1, 2009.

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

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

*31.2		Certification (pursuant to 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 June 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: August 6, 2009		/ s / ROGER B. PLANK
		Roger B. Plank
		President
		(Principal Financial Officer)

Dated: August 6, 2009		/ s / REBECCA A. HOYT
		Rebecca A. Hoyt
		Vice President and Controller
		(Principal Accounting Officer)

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 June 30, 2010

Exhibits