Edgar Filing: APACHE CORP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

¨	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

LOGO

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 x No ¨

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 x No ¨

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.

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

Number of shares of registrant’s common stock outstanding as of October 31, 2012 391,283,519

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

(Unaudited)


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,141	$	4,282	$	12,554	$	12,515
Other		38		46		133		76

		4,179		4,328		12,687		12,591

OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		1,300		1,045		3,803		2,984
Additional		729		20		1,898		46
Asset retirement obligation accretion		60		39		172		114
Lease operating expenses		801		661		2,178		1,946
Gathering and transportation		86		72		235		221
Taxes other than income		167		244		627		663
General and administrative		124		112		384		327
Merger, acquisitions & transition		7		4		29		15
Financing costs, net		40		37		125		123

		3,314		2,234		9,451		6,439

INCOME BEFORE INCOME TAXES		865		2,094		3,236		6,152
Current income tax provision		544		473		1,729		1,692
Deferred income tax provision		141		619		174		1,065

NET INCOME		180		1,002		1,333		3,395
Preferred stock dividends		19		19		57		57

INCOME ATTRIBUTABLE TO COMMON STOCK	$	161	$	983	$	1,276	$	3,338

NET INCOME PER COMMON SHARE:
Basic	$	0.41	$	2.56	$	3.29	$	8.70
Diluted	$	0.41	$	2.50	$	3.27	$	8.49

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		391		384		388		384
Diluted		393		400		390		400

DIVIDENDS DECLARED PER COMMON SHARE	$	0.17	$	0.15	$	0.51	$	0.45

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited)


	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
NET INCOME	$	180		$	1,002		$	1,333		$	3,395

OTHER COMPREHENSIVE INCOME (LOSS):
Commodity cash flow hedge activity, net of tax:
Reclassification of (gain) loss on settled derivative instruments		(59	)		(4	)		(151	)		32
Change in fair value of derivative instruments		(41	)		275			71			181
Derivative hedge ineffectiveness reclassified into earnings		—			(9	)		—			(10	)

		(100	)		262			(80	)		203

COMPREHENSIVE INCOME		80			1,264			1,253			3,598
Preferred stock dividends		19			19			57			57

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	61		$	1,245		$	1,196		$	3,541

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

(Unaudited)


	For the Nine Months Ended September 30,
	2012			2011
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,333		$	3,395
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,701			3,030
Asset retirement obligation accretion		172			114
Provision for deferred income taxes		174			1,065
Other		62			(34	)
Changes in operating assets and liabilities:
Receivables		128			(417	)
Inventories		29			(35	)
Drilling advances		(334	)		(23	)
Deferred charges and other		(200	)		(54	)
Accounts payable		168			119
Accrued expenses		(814	)		(38	)
Deferred credits and noncurrent liabilities		3			49

NET CASH PROVIDED BY OPERATING ACTIVITIES		6,422			7,171

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(6,387	)		(4,758	)
Additions to gas gathering, transmission and processing facilities		(586	)		(472	)
Acquisition of Cordillera Energy Partners III, LLC		(2,666	)		—
Equity investment in Yara Pilbara Holdings Pty Limited		(439	)		—
Acquisitions, other		(122	)		(509	)
Proceeds from sale of oil and gas properties		26			202
Other, net		(386	)		(89	)

NET CASH USED IN INVESTING ACTIVITIES		(10,560	)		(5,626	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		1,827			(940	)
Fixed rate debt borrowings		2,991			—
Payments on fixed rate debt		(400	)		—
Dividends paid		(246	)		(230	)
Other		(11	)		77

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,161			(1,093	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		23			452

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		295			134

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	318		$	586

SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	130		$	165
Income taxes paid, net of refunds		1,876			1,335

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Unaudited)


	September 30, 2012			December 31, 2011
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	318		$	295
Receivables, net of allowance		2,976			3,079
Inventories		774			655
Drilling advances		573			229
Derivative instruments		104			304
Prepaid assets and other		299			241

		5,044			4,803

PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		74,743			67,805
Unproved properties and properties under development, not being amortized		9,196			5,530
Gathering, transmission and processing facilities		5,758			5,175
Other		930			709

		90,627			79,219
Less: Accumulated depreciation, depletion and amortization		(39,463	)		(33,771	)

		51,164			45,448

OTHER ASSETS:
Goodwill		1,114			1,114
Deferred charges and other		1,488			686

	$	58,810		$	52,051

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,137		$	1,048
Current debt		964			431
Current asset retirement obligation		434			447
Derivative instruments		56			113
Other current liabilities		2,799			2,924

		5,390			4,963

LONG-TERM DEBT		10,670			6,785

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		7,602			7,197
Asset retirement obligation		3,794			3,440
Other		640			673

		12,036			11,310

COMMITMENTS AND CONTINGENCIES (Note 8)
SHAREHOLDERS’ EQUITY:
Preferred stock, no par value, 10,000,000 shares authorized, 6% Cumulative Mandatory Convertible, Series D, $1,000 per share liquidation preference, 1,265,000 shares issued and outstanding		1,227			1,227
Common stock, $0.625 par, 860,000,000 shares authorized, 392,345,358 and 385,249,885 shares issued, respectively		245			241
Paid-in capital		9,783			9,066
Retained earnings		19,578			18,500
Treasury stock, at cost, 1,072,757 and 1,132,242 shares, respectively		(30	)		(32	)
Accumulated other comprehensive loss		(89	)		(9	)

		30,714			28,993

	$	58,810		$	52,051

The accompanying notes to consolidated financial statements

are an integral part of this statement.

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY

(Unaudited)


	Series D Preferred Stock		Common Stock		Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
	(In millions)
BALANCE AT DECEMBER 31, 2010	$	1,227	$	240	$	8,864		$	14,223		$	(36	)	$	(141	)	$	24,377
Net income		—		—		—			3,395			—			—			3,395
Commodity hedges, net of tax		—		—		—			—			—			203			203
Dividends:
Preferred		—		—		—			(57	)		—			—			(57	)
Common ($0.45 per share)		—		—		—			(173	)		—			—			(173	)
Common stock activity, net		—		1		28			—			—			—			29
Treasury stock activity, net		—		—		2			—			4			—			6
Compensation expense		—		—		125			—			—			—			125
Other		—		—		(2	)		—			—			—			(2	)

BALANCE AT SEPTEMBER 30, 2011	$	1,227	$	241	$	9,017		$	17,388		$	(32	)	$	62		$	27,903

BALANCE AT DECEMBER 31, 2011	$	1,227	$	241	$	9,066		$	18,500		$	(32	)	$	(9	)	$	28,993
Net income		—		—		—			1,333			—			—			1,333
Commodity hedges, net of tax		—		—		—			—			—			(80	)		(80	)
Dividends:
Preferred		—		—		—			(57	)		—			—			(57	)
Common ($0.51 per share)		—		—		—			(198	)		—			—			(198	)
Common shares issued		—		3		598			—			—			—			601
Common stock activity, net		—		1		(12	)		—			—			—			(11	)
Treasury stock activity, net		—		—		1			—			2			—			3
Compensation expense		—		—		130			—			—			—			130

BALANCE AT SEPTEMBER 30, 2012	$	1,227	$	245	$	9,783		$	19,578		$	(30	)	$	(89	)	$	30,714

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 Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, which contains a summary of the Company’s significant accounting policies and other disclosures. Additionally, the Company’s financial statements for prior periods include reclassifications that were made to conform to the current-period presentation.

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2012, 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, 2011.

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 at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, assessing asset retirement obligations, and the estimate of income taxes. Actual results could differ from those estimates.

Oil and Gas Property

The Company follows the full-cost method of accounting for its oil and gas properties. Under this method of accounting, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly associated with these activities, and oil and gas property acquisitions are capitalized. The net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum and adjusted for cash flow hedges. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. For a discussion of the calculation of estimated future net cash flows, please refer to Note 14—Supplemental Oil and Gas Disclosures in Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as “Additional depreciation, depletion and amortization” in the accompanying statement of consolidated operations. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. At March 31, 2012, and June 30, 2012, the Company recorded a $521 million ($390 million net of tax) and $641 million ($480 million net of tax) non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties, respectively. At September 30, 2012, the Company recorded an additional $721 million ($539 million net of tax) non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down as of March 31, 2012, June 30, 2012, and September 30, 2012, would have been $656 million ($491 million net of tax), $744 million ($557 million net of tax), and $779 million ($583 million net of tax), respectively.

New Pronouncements Issued But Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under U.S. GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing U.S. GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. The Company does not expect the adoption of this amendment to impact its consolidated financial statements.

2.	ACQUISITIONS AND DIVESTITURES

2012 Activity

Cordillera Energy Partners III, LLC

On April 30, 2012, Apache completed the acquisition of Cordillera Energy Partners III, LLC (Cordillera), a privately-held exploration and production company, in a stock and cash transaction. Cordillera’s properties include approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. The effective date of the transaction was September 1, 2011.

Apache issued 6,272,667 shares of common stock and paid approximately $2.7 billion of cash to the sellers as consideration for the transaction. The cash paid at closing was funded with a portion of the proceeds from the Company’s April 2012 public note offering. For further discussion of this equity issuance, please see Note 9—Capital Stock of this Form 10-Q. For further discussion of the note offering, please see Note 6—Debt and Financing Costs of this Form 10-Q.

The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained, but no later than one year from the acquisition date.


	(In millions)
Current assets	$	56
Proved properties		1,040
Unproved properties		2,288
Gathering, transmission and processing facilities		1

Total assets acquired	$	3,385

Current liabilities		86
Non-current obligations		5

Total liabilities assumed	$	91

Net assets acquired	$	3,294

Yara Pilbara Holdings Pty Limited

On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in Yara Pilbara Holdings Pty Limited (YPHPL, formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. YPHPL is the owner of an ammonia plant on the Burrup Peninsula of Western Australia. Apache has supplied gas to the plant since operations commenced in 2006. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. In addition, Apache also acquired an interest in a planned technical ammonia nitrate plant to be developed with Yara. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

2011 Activity

Mobil North Sea Limited Acquisition

On December 30, 2011, Apache completed the acquisition of Mobil North Sea Limited (Mobil North Sea). The assets acquired include: operated interests in the Beryl, Nevis, Nevis South, Skene and Buckland fields; operated interest in the Beryl/Brae gas pipeline and the SAGE gas plant; non-operated interests in the Maclure, Scott and Telford fields; and Benbecula (west of Shetlands) exploration acreage. This acquisition was funded with existing cash on hand.

The transaction was accounted for using the acquisition method of accounting. The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained, but no later than one year from the acquisition date.


	(In millions)
Current assets	$	208
Proved properties		2,341
Unproved properties		476
Gathering, transmission and processing facilities		338
Goodwill⁽¹⁾		82

Total assets acquired	$	3,445

Current liabilities		148
Asset retirement obligation		517
Deferred income tax liabilities		1,533
Other long-term obligations		1

Total liabilities assumed	$	2,199

Net assets acquired	$	1,246

⁽¹⁾	Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. Goodwill is not deductible for tax purposes.

3.	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

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

Counterparty Risk

The use of derivative instruments exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2012, Apache had derivative positions with 17 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.

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

Derivative Instruments

As of September 30, 2012, Apache had the following open crude oil derivative positions:


	Fixed-Price Swaps				Collars
Production Period	Mbbls		Weighted Average Fixed Price⁽¹⁾		Mbbls		Weighted Average Floor Price ⁽¹⁾		Weighted Average Ceiling Price⁽¹⁾
2012		941	$	74.32		2,808	$	77.66	$	103.08
2013		1,972		74.29		5,701		82.84		111.63
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. Approximately 31 percent of 2012 collars and 58 percent of 2013 collars are settled against Dated Brent.

As of September 30, 2012, Apache had the following open natural gas derivative positions:


	Fixed-Price Swaps						Collars
Production Period	MMBtu (in 000’s)		GJ (in 000’s)		Weighted Average Fixed Price⁽¹⁾		MMBtu (in 000’s)		GJ (in 000’s)		Weighted Average Floor Price ⁽¹⁾		Weighted Average Ceiling Price ⁽¹⁾
2012		11,386		—	$	6.24		5,520		—	$	5.54	$	7.30
2012		—		11,040	C$	6.61		—		1,840	C$	6.50	C$	7.27
2013		10,095		—	$	6.74		6,825		—	$	5.35	$	6.67
2014		1,295		—	$	6.72		—		—	$	—	$	—

⁽¹⁾

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

Fair Value Measurements

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps and options. The Company uses a market approach to estimate the fair values of its derivative instruments. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The Company’s derivatives are not actively quoted in the open market but are valued utilizing commodity futures price strips for the underlying commodities, which are provided by a reputable third party. For additional information regarding fair value measurements, please see Note 11—Fair Value Measurements of our Annual Report on Form 10-K for the year ended December 31, 2011.

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting⁽¹⁾			Carrying Amount
	(In millions)
September 30, 2012
Assets:
Commodity Derivative Instruments	$	—	$	138	$	—	$	138	$	(28	)	$	110

Liabilities:
Commodity Derivative Instruments		—		87		—		87		(28	)		59

December 31, 2011
Assets:
Commodity Derivative Instruments	$	—	$	428	$	—	$	428	$	(96	)	$	332

Liabilities:
Commodity Derivative Instruments		—		250		—		250		(96	)		154

⁽¹⁾	The derivative fair values are based on analysis of each contract on a gross basis, even where the legal right of offset exists.

Derivative Assets and Liabilities Recorded in the Consolidated Balance Sheet

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 carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	September 30, 2012		December 31, 2011
	(In millions)
Current Assets: Derivative instruments	$	104	$	304
Other Assets: Deferred charges and other		6		28

Total Assets	$	110	$	332

Current Liabilities: Derivative instruments	$	56	$	113
Noncurrent Liabilities: Other		3		41

Total Liabilities	$	59	$	154

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 Recognized in Income	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	Gain (Loss) on Derivatives Recognized in Income	2012		2011		2012		2011
		(In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)	Oil and Gas Production Revenues	$	83	$	11	$	202	$	(36	)
Gain on derivatives recognized in operations (ineffective portion and basis)	Revenues and Other: Other	$	1	$	15	$	1	$	16

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders’ equity related to Apache’s cash flow hedges is presented in the table below:


	For the Nine Months Ended September 30,
	2012						2011
	Before tax			After tax			Before tax			After tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of period	$	145		$	113		$	(54	)	$	(19	)
Realized amounts reclassified into earnings		(202	)		(151	)		36			32
Net change in derivative fair value		97			71			304			181
Ineffectiveness reclassified into earnings		(1	)		—			(16	)		(10	)

Unrealized gain on derivatives at end of period	$	39		$	33		$	270		$	184

Gains and losses on existing hedges will be realized in future earnings through mid-2014, in the same period as the related sales of natural gas and crude oil production occur. Included in accumulated other comprehensive income as of September 30, 2012, is a net gain of approximately $37 million ($31 million after tax) that applies to the next 12 months; however, estimated and actual amounts are likely to vary materially as a result of changes in market conditions.

4.	OTHER CURRENT LIABILITIES

The following table provides detail of our other current liabilities:


	September 30, 2012		December 31, 2011
	(In millions)
Accrued operating expenses	$	201	$	221
Accrued exploration and development		1,668		1,430
Accrued compensation and benefits		167		180
Accrued interest		132		143
Accrued income taxes		399		533
Accrued United Kingdom Petroleum Revenue Tax		46		284
Other		186		133

Total Other current liabilities	$	2,799	$	2,924

5.	ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine-month period ended September 30, 2012:


	(In millions)
Asset retirement obligation at December 31, 2011	$	3,887
Liabilities incurred		383
Liabilities acquired		33
Liabilities settled		(418	)
Accretion expense		172
Revisions in estimated liabilities		171

Asset retirement obligation at September 30, 2012		4,228

Less current portion		(434	)

Asset retirement obligation, long-term	$	3,794

6.	DEBT AND FINANCING COSTS

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt:


	September 30, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	64	$	64	$	31	$	31
Commercial paper		1,792		1,792		—		—
Notes and debentures		9,778		11,705		7,185		8,673

Total Debt	$	11,634	$	13,561	$	7,216	$	8,704

The Company’s debt is recorded at the carrying amount, net of unamortized discount, on its consolidated balance sheet. The carrying amount of the Company’s money market lines of credit and commercial paper approximates fair value because the interest rates are variable and reflective of market rates. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).

As of September 30, 2012, current debt included $500 million 5.25-percent notes and $400 million 6.00-percent notes due within the next 12 months and $64 million borrowed on uncommitted overdraft lines in Argentina. As of December 31, 2011, there was $31 million drawn on uncommitted overdraft lines in Argentina and $400 million 6.25-percent notes outstanding that were subsequently repaid in April 2012.

In April 2012 the Company issued $400 million principal amount of senior unsecured 1.75-percent notes maturing April 15, 2017, $1.1 billion principal amount of senior unsecured 3.25-percent notes maturing April 15, 2022, and $1.5 billion principal amount of senior unsecured 4.75-percent notes maturing April 15, 2043. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to fund the cash portion of the purchase price paid to acquire Cordillera, repay the $400 million 6.25-percent notes that matured on April 15, 2012, and for general corporate purposes.

On June 4, 2012, the Company entered into a new Global Credit Facility consisting of a $1.7 billion revolving syndicated bank credit facility for the U.S., a $300 million revolving syndicated bank credit facility for Australia, and a $300 million revolving syndicated bank credit facility for Canada, which replaced the Company’s existing syndicated bank credit facilities that were scheduled to mature in May 2013. The new facilities are scheduled to mature on June 4, 2017. There were no changes to the Company’s $1.0 billion U.S. credit facility that matures on August 12, 2016.

The terms of the new credit facilities are substantially similar to those in Apache’s $1.0 billion revolving credit facility dated August 12, 2011. The facilities will be used for general corporate purposes.

In June 2012, the Company increased the size of its commercial paper program to $3.0 billion. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities, which expire in 2016 and 2017. As of September 30, 2012, the Company had $1.8 billion in commercial paper outstanding, compared with no outstanding commercial paper as of December 31, 2011.

Financing Costs

Financing costs incurred during the periods comprised the following:


	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Interest expense	$	132		$	109		$	371		$	326
Amortization of deferred loan costs		2			1			5			4
Capitalized interest		(90	)		(69	)		(241	)		(193	)
Interest income		(4	)		(4	)		(10	)		(14	)

Financing costs, net	$	40		$	37		$	125		$	123

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. Accordingly, the Company recorded the income tax impact of a $521 million, $641 million, and $721 million non-cash write-down of its Canadian proved oil and gas properties as a discrete item in the first, second, and third quarters of 2012, respectively.

As a part of the increase in the corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent announced in March 2011, the U.K. government also proposed that the corporation income tax relief attributable to decommissioning expenditures in the North Sea remain at 50 percent. The related legislation concerning decommissioning expenditures was then introduced in Finance Bill 2012 and was enacted on July 17, 2012, upon receiving Royal Assent. As a result of this enacted legislation, the Company recorded a discrete non-recurring tax charge of $118 million in the third quarter of 2012.

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 2008 tax years and under audit for the 2009 and 2010 tax years. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

8.	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 $20 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, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. 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, results of operations, or liquidity.

Argentine Environmental Claims

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, in 2006 the Company acquired a subsidiary of Pioneer Natural Resources in Argentina (PNRA) that is involved in various administrative proceedings with environmental authorities in the Neuquén Province relating to permits for and discharges from operations in that province. In addition, PNRA was named in a suit initiated against oil companies operating in the Neuquén basin entitled Asociación de Superficiarios de la Patagonia v. YPF S.A., et. al., originally filed on August 21, 2003, in the Argentine National Supreme Court of Justice relating to various environmental and remediation claims. The plaintiff in that case, known as ASSUPA, has recently asserted similar lawsuits and claims against numerous oil and gas producers relating to other geographic areas of Argentina, including claims against a Company subsidiary relating to the Austral Basin. While it is possible that the Company subsidiary may incur liabilities related to these claims, no reasonable prediction can be made as the Company subsidiary’s overall exposure related to these claims is not currently determinable. No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

U.S. Royalty Litigation

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, two potential class action lawsuits are pending in respect of oil and gas royalties paid by the Company: Foster v. Apache Corporation, Civil Action No. CIV-10-0573-HE, in the United States District Court for the Western District of Oklahoma, and Joyce Holder Trust v. Apache Corporation, Civil Action No. 4:11-cv-03872, in the United States District Court for the Southern District of Texas, Houston Division. In the Foster case, on August 20, 2012, the United States District Court for the Western District of Oklahoma denied plaintiff’s motion for class certification. The plaintiff has filed a motion for reconsideration, which is pending. In the Holder case, following a class certification hearing in the United States District Court for the Southern District of Texas, the parties resolved the matter with no material impact on the Company’s financial position, results of operations, or liquidity, and with the settlement providing for denial of class certification and dismissal of the case.

Louisiana Restoration

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages for contamination and cleanup.

In the lawsuit captioned Ardoin Limited Partnership et al. v. Meridian Resources & Exploration et al., Case No. 10-18692, in the District Court of Cameron Parish, Louisiana, prior to trial the court granted Apache’s motions to dismiss the plaintiffs’ claims against Apache. Plaintiffs then settled with the other defendant in the case, BP America, Inc. (BP). BP has demanded that Apache indemnify it for the amount of its settlement with plaintiffs, which is not material to Apache. Apache has rejected BP’s indemnity claim and, further, Apache has demanded that Wagner Oil Company (which purchased Apache’s interest in the subject property) indemnify Apache from and against BP’s claim.

In the lawsuit filed on May 4, 2010, against Phoenix Exploration Company LP (Phoenix) captioned Belle Isle, L.L.C. v. Anadarko Petroleum Corporation et al., Docket No. 121742, in the District Court of St. Mary Parish, Louisiana, plaintiff’s experts have estimated the cost of remediation to be approximately $87 million, and plaintiffs claim additional damages for canal restoration, among other things, all of which is disputed by the Company. No other material change in the status of these matters has occurred since the filing of Apache’s most recent Annual Report on Form 10-K for its 2011 fiscal year.

Hurricane-Related Litigation

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, on May 27, 2011, in the case styled Comer et al. v. Murphy Oil USA, Inc. et al., Case No. 1:11-cv-220 HS0-JMR, in the United States District Court for the Southern District of Mississippi, the District Court has granted defendants’ motion to dismiss plaintiffs’ claims, and plaintiffs have appealed the decision to the United States Court of Appeals for the Fifth Circuit. No other material change in the status of this matter has occurred since the filing of Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

Australia Gas Pipeline Force Majeure

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, in 2008 Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas in Australia to customers under various long-term contracts. No material change in the status of these matters has occurred since the filing of Apache’s most recent Annual Report on Form 10-K for its 2011 fiscal year except as follows:

•

The prosecution notice that was filed on May 28, 2009, by the Department of Mines and Petroleum against Apache Northwest Pty Ltd and its co-licensees was dismissed by the Magistrates Court of Western Australia on March 29, 2012.

•

The June 2009 report prepared by the inspectors appointed by the government of Western Australia under the Petroleum Pipelines Act to coordinate the final stages of the investigation into the Varanus Island gas explosion, as described in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, was published by the State government on May 24, 2012. Company subsidiaries disagree with the inspectors’ June 2009 conclusions. Two other government reports were not published by the State and are not referenced by the inspectors. The Magistrates Court of Western Australia subsequently ordered that both such reports could be released on the basis that the inspectors’ June 2009 report “came with some limitations” and the two other government reports “together were part and parcel if not the main reason or the only reason…certainly a significant contribution to the reason for the matter not proceeding to prosecution and trial.” In the first such report, the State’s senior investigator said in February 2009 that the prospects of a successful prosecution of Apache for failing to maintain the pipeline “would be slight.” In the second such report, the State’s lead corrosion expert concluded in July 2011 that Apache “had reasonable grounds to believe that the pipeline was in good repair” prior to the explosion.

•

In the case captioned Alcoa of Australia Limited v. Apache Energy Limited, Apache Northwest Pty Ltd, Tap (Harriet) Pty Ltd, and Kufpec Australia Pty Ltd, Civ. 1481 of 2011, in the Supreme Court of Western Australia, on June 20, 2012, the Supreme Court struck out Alcoa’s claim that the liquidated damages provisions under two long-term contracts are unenforceable as a penalty and also struck out Alcoa’s claim for damages for breach of statutory duty. The Company subsidiaries have filed an appeal in the Supreme Court of Western Australia Court of Appeal asking that Alcoa’s remaining tort claim for economic loss be dismissed or, alternatively, struck out. The appeal is pending.

•

In the case captioned Burrup Fertilisers Pty Ltd v. Apache Corporation, Apache Energy Limited, and Apache Northwest Pty Ltd, Cause No. 2009-79834, in the District Court of Harris County, Texas, Apache Corporation has filed a motion to dismiss on the ground of forum non conveniens, which is pending.

Breton Lawsuit

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, on October 4, 2011, plaintiffs filed suit in Breton Energy, L.L.C. et al. v. Mariner Energy Resources, Inc., et al., Case 4:11-cv-03561, in the United States District Court for the Southern District of Texas, Houston Division, seeking compensation from defendants for allegedly depriving plaintiffs, either negligently or intentionally, of rights to hydrocarbons in a reservoir described by plaintiffs as a common reservoir in West Cameron Blocks 171 and 172 offshore Louisiana in the Gulf of Mexico. On September 27, 2012, the court dismissed plaintiffs’ claims on various grounds, including for failure to state a claim upon which relief may be granted, while granting plaintiffs leave to amend their complaint within 30 days. On October 29, 2012, the plaintiffs filed an amended complaint. No other material change in the status of this matter has occurred since the filing of Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

Escheat Audits

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, the State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property), has notified numerous companies, including Apache Corporation, that the State intends to examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. No material change in the status of this matter has occurred since the filing of Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

Burrup-Related Gas Supply Lawsuits

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, on May 19, 2011, a lawsuit captioned Oswal v. Apache Corporation, Cause No. 2011-30302, in the District Court of Harris County, Texas, was filed in which plaintiff Pankaj Oswal, in his personal capacity and as trustee for the Burrup Trust, asserts claims against the Company under the Australian Trade Practices Act. Apache Corporation has filed a motion to dismiss on the ground of forum non conveniens, which is pending. No other material change in the status of this matter has occurred since the filing of Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

Also as more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, this lawsuit is one of a number of legal actions involving the Burrup Fertilisers Pty Ltd ammonia plant in Western Australia. In one of these legal actions—a case captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2011 4653, in the Supreme Court of Victoria—Oswal’s wife, Radhika Oswal, was granted leave on April 20, 2012, to add Apache Fertilisers Pty Ltd as a defendant.

Concerning the action filed by Tap (Harriet) Pty Ltd (Tap) against Burrup Fertilisers Pty Ltd et al., Civ. 2329 of 2009, in the Supreme Court of Western Australia, as more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, a Company subsidiary purchased Tap, which then modified its agreement to supply gas to the ammonia plant and resolved both Tap’s claims against Burrup Fertilisers and Burrup Fertilisers’ counterclaims against Tap in the Tap action.

Environmental Matters

As of September 30, 2012, the Company had an undiscounted reserve for environmental remediation of approximately $102 million. The Company is not aware of any environmental claims existing as of September 30, 2012, that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. 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.

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, Apache Canada Ltd. asserted a claim against BP Canada arising out of the acquisition of certain Canadian properties under the parties’ Partnership Interest and Share Purchase and Sale Agreement dated July 20, 2010. The parties have resolved the matter on commercial terms with no material impact on the Company’s financial position, results of operations, or liquidity.

As more fully described in Note 8 of the financial statements in Apache’s Annual Report on Form 10-K for its 2011 fiscal year, on May 25, 2011, a panel of the Bureau of Ocean Energy Management (BOEM) published a report dated May 23, 2011, and titled “OCS G-2580, Vermilion Block 380 Platform A, Incidents of Noncompliance.” The report concerned the BOEM’s investigation of a fire on the Vermillion 380 A platform located in the Gulf of Mexico. At the time of the incident, Mariner operated the platform. A small amount of hydrocarbons spilled from the platform into the surrounding water as a result of the incident, and 13 workers were rescued after evacuating the platform. The BOEM concluded in its investigation that the fire was caused by Mariner’s failure to adequately maintain or operate the platform’s heater-treater in a safe condition. The BOEM also identified other safety deficiencies on the platform. On December 27, 2011, the BOEM issued several Incidents of Non-Compliance, which may provide the basis for the assessment of civil penalties against Mariner. The Company, which acquired Mariner, effective November 10, 2010, filed an appeal on August 31, 2012, contesting several of the Incidents of Non-Compliance. No other material change in the status of this matter has occurred since the filing of Apache’s Annual Report on Form 10-K for its 2011 fiscal year.

9.	CAPITAL STOCK

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the quarters and nine-month periods ended September 30, 2012 and 2011 is presented in the table below.


	For the Quarter Ended September 30,
	2012						2011
	Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	161		391	$	0.41	$	983		384	$	2.56

Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock		—		—				19		14
Stock options and other		—		2				—		2

Diluted:
Income attributable to common stock, including assumed conversions	$	161		393	$	0.41	$	1,002		400	$	2.50


	For the Nine Months Ended September 30,
	2012						2011
	Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	1,276		388	$	3.29	$	3,338		384	$	8.70

Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock		—		—				57		14
Stock options and other		—		2				—		2

Diluted:
Income attributable to common stock, including assumed conversions	$	1,276		390	$	3.27	$	3,395		400	$	8.49

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 5.1 million and 3.3 million for the quarters ending September 30, 2012 and 2011, and 4.1 million and 2.4 million for the nine months ended September 30, 2012 and 2011, respectively. For the quarter and nine months ended September 30, 2012, 14.3 million shares related to the assumed conversion of the Mandatory Convertible Preferred Stock were also anti-dilutive.

Issuance of Common and Preferred Shares

On April 30, 2012, in conjunction with Apache’s acquisition of Cordillera, the Company issued 6,272,667 shares of common stock to the sellers.

Common and Preferred Stock Dividends

For the quarter and nine months ended September 30, 2012, Apache paid $67 million and $189 million, respectively, in dividends on its common stock. For the quarter and nine months ended September 30, 2011, Apache paid $58 million and $173 million, respectively, in dividends on its common stock.

For the quarter and nine months ended September 30, 2012, Apache paid $19 million and $57 million, respectively, in dividends on its Series D Preferred Stock. For the quarter and nine months ended September 30, 2011, Apache paid $19 million and $57 million, respectively, in dividends on its Series D Preferred Stock.

10.

BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. At September 30, 2012, the Company had production in six countries: the United States, Canada, Egypt, Australia, offshore the United Kingdom (U.K.) in the North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. Financial information for each country is presented below:


	United States		Canada			Egypt		Australia		North Sea		Argentina		Other International			Total
	(In millions)
For the Quarter Ended September 30, 2012
Oil and Gas Production Revenues	$	1,533	$	318		$	1,143	$	397	$	624	$	126	$	—		$	4,141

Operating Income (Loss) ⁽¹⁾	$	495	$	(744	)	$	781	$	231	$	236	$	6	$	(7	)	$	998

Other Income (Expense):
Other																		38
General and administrative																		(124	)
Merger, acquisitions & transition																		(7	)
Financing costs, net																		(40	)

Income Before Income Taxes																	$	865

For the Nine Months Ended September 30, 2012
Oil and Gas Production Revenues	$	4,525	$	966		$	3,403	$	1,211	$	2,060	$	389	$	—		$	12,554

Operating Income (Loss) ⁽¹⁾	$	1,692	$	(1,903	)	$	2,380	$	683	$	752	$	51	$	(14	)	$	3,641

Other Income (Expense):
Other																		133
General and administrative																		(384	)
Merger, acquisitions & transition																		(29	)
Financing costs, net																		(125	)

Income Before Income Taxes																	$	3,236

Total Assets	$	29,786	$	7,349		$	7,208	$	5,876	$	6,581	$	1,823	$	187		$	58,810

For the Quarter Ended September 30, 2011
Oil and Gas Production Revenues	$	1,548	$	388		$	1,214	$	461	$	547	$	124	$	—		$	4,282

Operating Income (Loss)⁽¹⁾	$	718	$	81		$	893	$	288	$	222	$	19	$	(20	)	$	2,201

Other Income (Expense):
Other																		46
General and administrative																		(112	)
Merger, acquisitions & transition																		(4	)
Financing costs, net																		(37	)

Income Before Income Taxes																	$	2,094

For the Nine Months Ended September 30, 2011
Oil and Gas Production Revenues	$	4,485	$	1,223		$	3,615	$	1,303	$	1,549	$	340	$	—		$	12,515

Operating Income (Loss) ⁽¹⁾	$	2,086	$	264		$	2,679	$	823	$	685	$	50	$	(46	)	$	6,541

Other Income (Expense):
Other																		76
General and administrative																		(327	)
Merger, acquisitions & transition																		(15	)
Financing costs, net																		(123	)

Income Before Income Taxes																	$	6,152

Total Assets	$	23,039	$	8,443		$	6,574	$	4,446	$	3,166	$	1,732	$	82		$	47,482

⁽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. Canada’s operating loss for the three and nine months ended September 30, 2012, includes additional depletion of $721 million and $1.9 billion, respectively, to write-down the carrying value of oil and gas properties.

11.

SUPPLEMENTAL GUARANTOR INFORMATION

In December 1999, Apache Finance Canada Corporation (Apache Finance Canada) issued approximately $300 million of publicly-traded notes due in 2029. In May 2003, Apache Finance Canada issued an additional $350 million of publicly-traded notes due in 2015. Both are fully and unconditionally guaranteed by Apache. The following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.

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

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Quarter Ended September 30, 2012


	Apache Corporation		Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,030	$	—		$	3,111	$	—		$	4,141
Equity in net income (loss) of affiliates		41		(271	)		71		159			—
Other		—		18			21		(1	)		38

		1,071		(253	)		3,203		158			4,179

OPERATING EXPENSES:
Depreciation, depletion and amortization		349		—			1,680		—			2,029
Asset retirement obligation accretion		20		—			40		—			60
Lease operating expenses		277		—			524		—			801
Gathering and transportation		15		—			71		—			86
Taxes other than income		52		—			115		—			167
General and administrative		97		—			28		(1	)		124
Merger, acquisitions & transition		7		—			—		—			7
Financing costs, net		20		14			6		—			40

		837		14			2,464		(1	)		3,314

INCOME (LOSS) BEFORE INCOME TAXES		234		(267	)		739		159			865
Provision (benefit) for income taxes		54		(67	)		698		—			685

NET INCOME (LOSS)		180		(200	)		41		159			180
Preferred stock dividends		19		—			—		—			19

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	161	$	(200	)	$	41	$	159		$	161

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	61	$	(200	)	$	41	$	159		$	61

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Quarter Ended September 30, 2011


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,097	$	—	$	3,185		$	—		$	4,282
Equity in net income (loss) of affiliates		821		188		65			(1,074	)		—
Other		18		148		(119	)		(1	)		46

		1,936		336		3,131			(1,075	)		4,328

OPERATING EXPENSES:
Depreciation, depletion and amortization		323		—		742			—			1,065
Asset retirement obligation accretion		18		—		21			—			39
Lease operating expenses		199		—		462			—			661
Gathering and transportation		13		—		59			—			72
Taxes other than income		49		—		195			—			244
General and administrative		86		—		27			(1	)		112
Merger, acquisitions & transition		3		—		1			—			4
Financing costs, net		33		14		(10	)		—			37

		724		14		1,497			(1	)		2,234

INCOME (LOSS) BEFORE INCOME TAXES		1,212		322		1,634			(1,074	)		2,094
Provision (benefit) for income taxes		210		69		813			—			1,092

NET INCOME (LOSS)		1,002		253		821			(1,074	)		1,002
Preferred stock dividends		19		—		—			—			19

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	983	$	253	$	821		$	(1,074	)	$	983

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,245	$	253	$	821		$	(1,074	)	$	1,245

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2012


	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,070		$	—		$	9,484	$	—		$	12,554
Equity in net income (loss) of affiliates		813			(672	)		176		(317	)		—
Other		(1	)		52			85		(3	)		133

		3,882			(620	)		9,745		(320	)		12,687

OPERATING EXPENSES:
Depreciation, depletion and amortization		997			—			4,704		—			5,701
Asset retirement obligation accretion		57			—			115		—			172
Lease operating expenses		708			—			1,470		—			2,178
Gathering and transportation		38			—			197		—			235
Taxes other than income		146			—			481		—			627
General and administrative		302			—			85		(3	)		384
Merger, acquisitions & transition		23			—			6		—			29
Financing costs, net		71			42			12		—			125

		2,342			42			7,070		(3	)		9,451

INCOME (LOSS) BEFORE INCOME TAXES		1,540			(662	)		2,675		(317	)		3,236
Provision (benefit) for income taxes		207			(166	)		1,862		—			1,903

NET INCOME (LOSS)		1,333			(496	)		813		(317	)		1,333
Preferred stock dividends		57			—			—		—			57

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,276		$	(496	)	$	813	$	(317	)	$	1,276

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,196		$	(496	)	$	813	$	(317	)	$	1,196

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2011


					All Other
	Apache Corporation		Apache Finance Canada		Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
					(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,230	$	—	$	9,285		$	—		$	12,515
Equity in net income (loss) of affiliates		2,687		163		17			(2,867	)		—
Other		23		109		(53	)		(3	)		76

		5,940		272		9,249			(2,870	)		12,591

OPERATING EXPENSES:
Depreciation, depletion and amortization		938		—		2,092			—			3,030
Asset retirement obligation accretion		52		—		62			—			114
Lease operating expenses		603		—		1,343			—			1,946
Gathering and transportation		37		—		184			—			221
Taxes other than income		140		—		523			—			663
General and administrative		262		—		68			(3	)		327
Merger, acquisitions & transition		10		—		5			—			15
Financing costs, net		104		42		(23	)		—			123

		2,146		42		4,254			(3	)		6,439

INCOME (LOSS) BEFORE INCOME TAXES		3,794		230		4,995			(2,867	)		6,152
Provision (benefit) for income taxes		399		50		2,308			—			2,757

NET INCOME (LOSS)		3,395		180		2,687			(2,867	)		3,395
Preferred stock dividends		57		—		—			—			57

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,338	$	180	$	2,687		$	(2,867	)	$	3,338

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,541	$	180	$	2,687		$	(2,867	)	$	3,541

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Nine Months Ended September 30, 2012


	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,755		$	(86	)	$	4,753		$	—		$	6,422

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(2,330	)		—			(4,057	)		—			(6,387	)
Additions to gas gathering, transmission and processing facilities		(28	)		—			(558	)		—			(586	)
Acquisition of Cordillera		(2,666	)		—			—			—			(2,666	)
Equity investment in Yara Pilbara Holdings Pty Limited		—			—			(439	)		—			(439	)
Acquisitions, other		(56	)		—			(66	)		—			(122	)
Proceeds from sale of oil and gas properties		20			—			6			—			26
Investment in subsidiaries, net		(541	)		—			—			541			—
Other		(340	)		—			(46	)		—			(386	)

NET CASH USED IN INVESTING ACTIVITIES		(5,941	)		—			(5,160	)		541			(10,560	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		1,792			—			35			—			1,827
Intercompany borrowings		—			—			572			(572	)		—
Fixed rate debt borrowings		2,991			—			—			—			2,991
Payments on fixed rate debt		(400	)		—			—			—			(400	)
Dividends paid		(246	)		—			—			—			(246	)
Other		40			82			(164	)		31			(11	)

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,177			82			443			(541	)		4,161

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(9	)		(4	)		36			—			23

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		41			5			249			—			295

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	32		$	1		$	285		$	—		$	318

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Nine Months Ended September 30, 2011


							All Other
	Apache Corporation			Apache Finance Canada			Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,573		$	(34	)	$	5,632		$	—		$	7,171

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,280	)		—			(3,478	)		—			(4,758	)
Additions to gas gathering, transmission and processing facilities		—			—			(472	)		—			(472	)
Acquisitions, other		(416	)		—			(93	)		—			(509	)
Proceeds from sales of oil and gas properties		6			—			196			—			202
Investment in subsidiaries, net		1,256			—			—			(1,256	)		—
Other		(65	)		—			(24	)		—			(89	)

NET CASH USED IN INVESTING ACTIVITIES		(499	)		—			(3,871	)		(1,256	)		(5,626	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(928	)		—			(12	)		—			(940	)
Intercompany borrowings		—			(1	)		(1,248	)		1,249			—
Dividends paid		(230	)		—			—			—			(230	)
Other		97			35			(62	)		7			77

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,061	)		34			(1,322	)		1,256			(1,093	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		13			—			439			—			452

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		6			—			128			—			134

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	19		$	—		$	567		$	—		$	586

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEET

September 30, 2012


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
					(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	31	$	1	$	286		$	—		$	318
Receivables, net of allowance		799		—		2,177			—			2,976
Inventories		73		—		701			—			774
Drilling advances		17		1		555			—			573
Derivative instruments		54		—		50			—			104
Prepaid assets and other		3,904		—		(3,605	)		—			299

		4,878		2		164			—			5,044

PROPERTY AND EQUIPMENT, NET		17,720		—		33,444			—			51,164

OTHER ASSETS:
Intercompany receivable, net		4,504		—		(2,361	)		(2,143	)		—
Equity in affiliates		20,761		741		89			(21,591	)		—
Goodwill, net		—		—		1,114			—			1,114
Deferred charges and other		179		1,002		1,307			(1,000	)		1,488

	$	48,042	$	1,745	$	33,757		$	(24,734	)	$	58,810

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	670	$	1	$	2,609		$	(2,143	)	$	1,137
Current debt		899		—		65			—			964
Asset retirement obligation		434		—		—			—			434
Derivative instruments		20		—		36			—			56
Other current liabilities		793		12		1,994			—			2,799

		2,816		13		4,704			(2,143	)		5,390

LONG-TERM DEBT		10,022		647		1			—			10,670

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,878		5		4,719			—			7,602
Asset retirement obligation		1,006		—		2,788			—			3,794
Other		606		250		784			(1,000	)		640

		4,490		255		8,291			(1,000	)		12,036

COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		30,714		830		20,761			(21,591	)		30,714

	$	48,042	$	1,745	$	33,757		$	(24,734	)	$	58,810

APACHE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2011


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
					(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	41	$	5	$	249		$	—		$	295
Receivables, net of allowance		773		—		2,306			—			3,079
Inventories		51		—		604			—			655
Drilling advances		11		—		218			—			229
Derivative instruments		113		—		191			—			304
Prepaid assets and other		3,859		—		(3,618	)		—			241

		4,848		5		(50	)		—			4,803

PROPERTY AND EQUIPMENT, NET		12,262		—		33,186			—			45,448

OTHER ASSETS:
Intercompany receivable, net		3,931		—		(1,908	)		(2,023	)		—
Equity in affiliates		20,214		1,372		99			(21,685	)		—
Goodwill, net		—		—		1,114			—			1,114
Deferred charges and other		158		1,002		526			(1,000	)		686

	$	41,413	$	2,379	$	32,967		$	(24,708	)	$	52,051

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	609	$	1	$	2,461		$	(2,023	)	$	1,048
Current debt		400		—		31			—			431
Asset retirement obligation		434		—		13			—			447
Derivative instruments		76		—		37			—			113
Other current liabilities		614		5		2,305			—			2,924

		2,133		6		4,847			(2,023	)		4,963

LONG-TERM DEBT		6,137		647		1			—			6,785

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,622		5		4,570			—			7,197
Asset retirement obligation		936		—		2,504			—			3,440
Other		592		250		831			(1,000	)		673

		4,150		255		7,905			(1,000	)		11,310

COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		28,993		1,471		20,214			(21,685	)		28,993

	$	41,413	$	2,379	$	32,967		$	(24,708	)	$	52,051

ITEM 2 –

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, offshore the United Kingdom (U.K.) in the North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

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, “Financial Statements” 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 Annual Report on Form 10-K for our 2011 fiscal year.

Financial Overview

Throughout 2012, Apache’s results have been impacted by the significant fall in North American natural gas prices compared to the prior year. However, our overall results continue to be supported by our strategy to maintain a portfolio balanced across crude oil and natural gas in North American and international markets. Our projects balance the spectrum of geologic types and risks in a variety of geographies. This allows us to redeploy capital dollars to parts of our portfolio that offer higher investment returns while reducing capital projects better deferred in today’s environment. We have invested $2.9 billion and $7.8 billion for exploration and development activities in the third quarter and first nine months of 2012, respectively, and will continue to review our capital program and spending levels in order to maintain our rate of return focus and manage our balance sheet.

Earnings totaled $161 million, or $0.41 per diluted common share, in the third quarter of 2012, compared with $983 million, or $2.50 per diluted share, in the third quarter of 2011. Earnings for the first nine months of 2012 totaled $1.3 billion, or $3.27 per diluted share. These earnings reflect the impact of non-cash after-tax write-downs of the carrying value of our Canadian proved oil and gas properties totaling $390 million, $480 million, and $539 million in the first, second, and third quarters of 2012, respectively. For additional discussion on these write-downs, refer to “Results of Operations—Depreciation, Depletion and Amortization” in this Item 2.

Apache’s adjusted earnings, which exclude certain items impacting the comparability of results, were $861 million in the third quarter of 2012, down from $1.2 billion in the prior-year quarter, and $2.9 billion for the first nine months of 2012, down from $3.5 billion in the prior-year comparative period. Adjusted earnings is not a financial measure prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings and a reconciliation of adjusted earnings to income attributable to common stock, the most directly comparable GAAP financial measure, please see “Non-GAAP Measures” in this Item 2.

Total daily production of oil, natural gas, and natural gas liquids averaged 771 thousand barrels of oil equivalent per day (Mboe/d) in the third quarter of 2012, up two percent compared with the third quarter of 2011. Increased production in the quarter was tempered by downtime resulting from Hurricane Isaac in the Gulf of Mexico and planned turnaround activities and downhole pump issues in the North Sea, which reduced third quarter production approximately 25 Mboe/d. Although production was higher than the prior-year quarter, oil and gas production revenues decreased three percent from the prior-year quarter to $4.1 billion on a 15-percent decline in natural gas realizations, partially offset by a one-percent rise in crude oil realizations.

Natural gas price realizations in North America have fallen 27 percent since the third quarter of 2011, and we believe weak natural gas prices in North America will continue to pressure gas revenues for the remainder of the year. Our natural gas production outside of North America, where third-quarter 2012 prices averaged 13 percent higher than the comparative 2011 quarter, boosted worldwide natural gas realizations. Over one-third of our natural gas is produced outside of North America, which emphasizes the benefit of having a balanced geographic base.

Third-quarter 2012 worldwide crude oil prices rose one percent from the prior-year quarter. Crude oil and liquids combined represented 51 percent of our production but provided 81 percent of our $4.1 billion of oil and gas revenues. Crude oil drove 87 percent of our combined crude and liquids production and 96 percent of the related revenues.

Operational Developments

Apache has a significant producing asset base as well as large undeveloped acreage positions that provide a platform for organic growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. With an inventory of more than 67,000 future drilling locations identified in the onshore United States alone, we are well positioned to grow through an

active drilling program in the coming years as we shift our drilling and exploration focus to targeting oil and liquids-rich gas plays. We are also continuing to advance several longer-term, individually significant development projects. Notable operational developments include:

United States

•

For the third quarter of 2012, our Permian region’s active drilling program continues to set new highs for net production, reaching 112 Mboe/d, up 18 percent from the prior-year quarter. Over 70 percent of this production was from crude oil and natural gas liquids (NGL).

•

The Central region also saw record production in the third quarter as we ramp up activity across our nearly two million gross acres. Production was up 55 percent relative to the prior-year quarter as we realized the benefits of our active oil and liquids-rich drilling program and a full quarter of Cordillera production. During the quarter we operated an average of 24 drilling rigs, drilling 40 wells with 100 percent success.

•

On October 3, 2012, Apache announced that our Gulf of Mexico (GOM) production facilities were back online following suspended operations due to Hurricane Isaac. GOM production was deferred for six weeks in August and September, impacting third-quarter volumes from our Deepwater, Shelf, and Gulf Coast Onshore regions by an estimated 13 Mboe/d for the full quarter.

North Sea

•

In September 2012, Apache announced that a Beryl field development well test-flowed at 8,161 barrels of oil per day (b/d) and 5.9 million cubic feet of natural gas per day (MMcf/d). The well contained 71 feet of net oil pay and began producing at the end of August. The well also encountered 245 feet of net pay in three additional zones that will be produced at a later date. A 3-D seismic survey of the Beryl field commenced in early August and, when completed, will further refine our drilling plans for these recently acquired assets. Apache has a 50-percent interest in the field.

•

Apache announced that the jacket for the Forties Alpha Satellite Platform was installed in September 2012, with a fully commissioned topside and bridge scheduled to be delivered during the second quarter of 2013. Once complete, the platform will provide Apache with full-fluid processing and contain 18 new production well slots that will facilitate additional drilling in the field beginning in the third quarter of 2013. With this platform, we will continue to develop the Forties field that was forecasted by the previous operator to cease production this year.

•

On October 3, 2012, Apache announced that North Sea production has recovered following platform maintenance activities completed during the third quarter. These planned turnarounds and continued downhole pump issues deferred nearly 12 Mboe/d during the period.

•

On November 1, 2012, Apache announced that the U.K. Department of Energy & Climate Change awarded 11 new North Sea licenses to Apache. The Company was also awarded an interest in another non-operated license. These awards cover 19 full or partial blocks (approximately 613,000 gross acres). Included in these blocks is all of the available acreage around our Beryl field plus two key licenses near the Forties field.

Australia

•

In October 2012, an Apache subsidiary announced that three major contracts with a total value of AUD$325 million net to Apache have been awarded for the development of the Julimar subsea facilities. Gas from the Julimar Development Project (JDP) will feed into the Wheatstone LNG project. Apache has a 65-percent interest in the JDP and is the operator. Apache has a 13-percent interest in the Chevron-operated Wheatstone project. The value of the contracts were within budgetary expectations and represented the final significant subsea contracts to be awarded for the JDP.

•

Also in October 2012, a planned three-week maintenance turnaround at the Yara Australia Pty Ltd (Yara) operated ammonia plant on the Burrup Peninsula of Western Australia was extended to nine weeks, the result of an unforeseen equipment problem. Yara expects production at the Burrup plant to resume in the second half of November 2012.

Egypt

•

During the quarter, the Company’s operations continued unabated with an average of 26 rigs in Egypt, drilling 68 wells during the period, including 11 exploratory wells. In addition, during the quarter we experienced faster government approvals of development leases as compared to the prior year, where we experienced delays of nine months or more. Our exploration efforts made several discoveries, continuing recent successes identifying opportunities in deeper drilling horizons.

•

In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it is providing reinsurance for the Overseas Private Investment Corporation’s (OPIC) political risk insurance policy to Apache Corporation and its subsidiaries for oil and gas sector investments in Egypt. This provision of long-term reinsurance to OPIC will allow Apache to maintain the level of insurance coverage that has been in place since 2004. MIGA is providing $150 million to OPIC for its $300 million coverage to Apache. The reinsurance will be provided for an additional 13 years against the risks of expropriation and breach of contract.

New Ventures

•

In September 2012, Apache announced that the Mbawa 1 offshore exploration well in Kenya encountered natural gas. The well encountered 170 feet of natural gas pay in three zones; however, no oil was encountered. Apache and its partners in the Kenya L8 Joint Venture are analyzing the well data to determine the potential for future exploration activities. Apache has a 50-percent interest in the Mbawa well and Block L8 and is the operator.

•

On October 18, 2012, Apache signed a production sharing contract with Staatsolie Maatschappij Suriname NV (Staatsolie) for block 53 off the northwest coast of Suriname. The contract offers Staatsolie the opportunity to purchase a stake in the development phase of up to 20 percent. Under the agreement, if a commercial find is made and brought into production, Apache will receive reimbursement for exploration phase costs. The two-phase exploration period under the contract includes an investment by Apache of approximately $230 million and drilling at least two wells.

Results of Operations

Oil and Gas Revenues


	For the Quarter Ended September 30,										For the Nine Months Ended September 30,
	2012					2011					2012					2011
	$		%			$		%			$		%			$		%
	Value		Contribution			Value		Contribution			Value		Contribution			Value		Contribution
	($ in millions)
Total Oil Revenues:
United States	$	1,143		35	%	$	1,040		33	%	$	3,409		35	%	$	3,008		32	%
Canada		115		4	%		105		3	%		361		3	%		355		4	%

North America		1,258		39	%		1,145		36	%		3,770		38	%		3,363		36	%

Egypt		1,021		32	%		1,054		33	%		3,028		31	%		3,149		34	%
Australia		303		9	%		411		12	%		947		10	%		1,167		12	%
North Sea		571		18	%		542		17	%		1,876		19	%		1,535		16	%
Argentina		67		2	%		60		2	%		203		2	%		170		2	%

International		1,962		61	%		2,067		64	%		6,054		62	%		6,021		64	%

Total⁽¹⁾	$	3,220		100	%	$	3,212		100	%	$	9,824		100	%	$	9,384		100	%

Total Gas Revenues:
United States	$	288		36	%	$	399		43	%	$	837		36	%	$	1,185		43	%
Canada		186		24	%		256		28	%		547		23	%		792		29	%

North America		474		60	%		655		71	%		1,384		59	%		1,977		72	%

Egypt		122		15	%		159		17	%		375		16	%		464		17	%
Australia		94		12	%		50		5	%		264		11	%		136		5	%
North Sea		44		6	%		5		1	%		148		7	%		14		1	%
Argentina		54		7	%		57		6	%		168		7	%		147		5	%

International		314		40	%		271		29	%		955		41	%		761		28	%

Total⁽²⁾	$	788		100	%	$	926		100	%	$	2,339		100	%	$	2,738		100	%

Natural Gas Liquids (NGL)
Revenues:
United States	$	102		76	%	$	109		75	%	$	279		71	%	$	292		74	%
Canada		17		13	%		27		19	%		58		15	%		76		19	%

North America		119		89	%		136		94	%		337		86	%		368		93	%

Egypt		—		—			1		1	%		—		0	%		2		1	%
North Sea		9		7	%		—		—			36		9	%		—		—
Argentina		5		4	%		7		5	%		18		5	%		23		6	%

International		14		11	%		8		6	%		54		14	%		25		7	%

Total	$	133		100	%	$	144		100	%	$	391		100	%	$	393		100	%

Total Oil and Gas Revenues:
United States	$	1,533		37	%	$	1,548		36	%	$	4,525		36	%	$	4,485		36	%
Canada		318		8	%		388		9	%		966		8	%		1,223		10	%

North America		1,851		45	%		1,936		45	%		5,491		44	%		5,708		46	%

Egypt		1,143		28	%		1,214		28	%		3,403		27	%		3,615		29	%
Australia		397		9	%		461		11	%		1,211		10	%		1,303		10	%
North Sea		624		15	%		547		13	%		2,060		16	%		1,549		12	%
Argentina		126		3	%		124		3	%		389		3	%		340		3	%

International		2,290		55	%		2,346		55	%		7,063		56	%		6,807		54	%

Total	$	4,141		100	%	$	4,282		100	%	$	12,554		100	%	$	12,515		100	%

⁽¹⁾	Financial derivative hedging activities decreased oil revenues $22 million and $126 million for the 2012 third quarter and nine-month period, respectively, and $82 million and $301 million for the 2011 third quarter and nine-month period, respectively.

⁽²⁾	Financial derivative hedging activities increased natural gas revenues $105 million and $328 million for the 2012 third quarter and nine-month period, respectively, and $65 million and $190 million for the 2011 third quarter and nine-month period, respectively.

Production


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
						Increase							Increase
	2012		2011			(Decrease)			2012		2011		(Decrease)
Oil Volume – b/d:
United States		133,001		120,353			11	%		128,884		117,135		10	%
Canada		15,075		13,027			16	%		15,311		14,040		9	%

North America		148,076		133,380			11	%		144,195		131,175		10	%

Egypt		97,546		103,289			(6	%)		98,648		103,913		(5	%)
Australia		28,191		39,400			(28	%)		29,690		38,248		(22	%)
North Sea		57,296		57,838			(1	%)		63,058		54,097		17	%
Argentina		9,885		9,461			4	%		9,701		9,577		1	%

International		192,918		209,988			(8	%)		201,097		205,835		(2	%)

Total⁽¹⁾		340,994		343,368			(1	%)		345,292		337,010		2	%

Natural Gas Volume – Mcf/d:
United States		863,433		857,993			1	%		841,859		865,474		(3	%)
Canada		604,442		619,897			(2	%)		617,530		633,031		(2	%)

North America		1,467,875		1,477,890			(1	%)		1,459,389		1,498,505		(3	%)

Egypt		329,793		376,259			(12	%)		354,856		368,898		(4	%)
Australia		215,317		187,852			15	%		217,053		183,470		18	%
North Sea		54,478		2,497			NM			62,061		2,257		NM
Argentina		213,745		223,929			(5	%)		216,399		209,206		3	%

International		813,333		790,537			3	%		850,369		763,831		11	%

Total⁽²⁾		2,281,208		2,268,427			1	%		2,309,758		2,262,336		2	%

Natural Gas Liquids (NGL)
Volume – b/d:
United States		39,076		21,919			78	%		30,385		21,001		45	%
Canada		6,036		6,120			(1	%)		6,063		6,220		(3	%)

North America		45,112		28,039			61	%		36,448		27,221		34	%

Egypt		—		(4	)		NM			—		66		NM
North Sea		1,470		14			NM			1,797		5		NM
Argentina		3,006		3,008			0	%		3,022		3,024		0	%

International		4,476		3,018			48	%		4,819		3,095		56	%

Total		49,588		31,057			60	%		41,267		30,316		36	%

BOE per day⁽³⁾
United States		315,982		285,271			11	%		299,578		282,381		6	%
Canada		121,851		122,463			0	%		124,296		125,765		(1	%)

North America		437,833		407,734			7	%		423,874		408,146		4	%

Egypt		152,512		165,995			(8	%)		157,791		165,461		(5	%)
Australia		64,078		70,708			(9	%)		65,866		68,826		(4	%)
North Sea		67,845		58,269			16	%		75,198		54,478		38	%
Argentina		48,515		49,790			(3	%)		48,790		47,471		3	%

International		332,950		344,762			(3	%)		347,645		336,236		3	%

Total		770,783		752,496			2	%		771,519		744,382		4	%

⁽¹⁾	Approximately 12 and 14 percent of worldwide oil production was subject to financial derivative hedges for the third quarter and nine-month period of 2012, respectively, and 28 and 29 percent for the comparative 2011 third quarter and nine-month periods, respectively.

⁽²⁾	Approximately 13 percent of worldwide natural gas production was subject to financial derivative hedges for the third quarter and nine-month period of 2012, and 15 and 16 percent for the comparative 2011 third quarter and nine-month periods, respectively.

⁽³⁾	The table shows production 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.

NM – Not meaningful

Pricing


	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
	2012		2011		Increase (Decrease)			2012		2011		Increase (Decrease)
Average Oil Price - Per barrel:
United States	$	93.38	$	93.86		(1	%)	$	96.53	$	94.05		3	%
Canada		82.92		88.34		(6	%)		85.96		92.77		(7	%)
North America		92.32		93.32		(1	%)		95.41		93.91		2	%
Egypt		113.72		110.96		2	%		112.02		111.02		1	%
Australia		116.79		113.40		3	%		116.39		111.78		4	%
North Sea		108.44		101.85		6	%		108.60		103.90		5	%
Argentina		73.44		69.27		6	%		76.36		65.08		17	%
International		110.54		107.03		3	%		109.87		107.15		3	%
Total⁽¹⁾		102.62		101.71		1	%		103.83		102.00		2	%
Average Natural Gas Price - Per Mcf:
United States	$	3.63	$	5.06		(28	%)	$	3.63	$	5.02		(28	%)
Canada		3.33		4.49		(26	%)		3.23		4.58		(29	%)
North America		3.51		4.82		(27	%)		3.46		4.83		(28	%)
Egypt		4.04		4.60		(12	%)		3.86		4.61		(16	%)
Australia		4.76		2.88		65	%		4.45		2.71		64	%
North Sea		8.65		21.43		(60	%)		8.67		22.87		(62	%)
Argentina		2.78		2.74		1	%		2.84		2.57		11	%
International		4.21		3.71		13	%		4.10		3.65		12	%
Total⁽²⁾		3.76		4.44		(15	%)		3.70		4.43		(16	%)
Average NGL Price - Per barrel:
United States	$	28.25	$	54.36		(48	%)	$	33.51	$	51.03		(34	%)
Canada		31.01		46.93		(34	%)		35.02		44.47		(21	%)
North America		28.62		52.74		(46	%)		33.76		49.53		(32	%)
Egypt		—		—		NM			—		66.37		NM
North Sea		65.45		65.45		0	%		73.60		65.45		12	%
Argentina		16.25		26.45		(39	%)		21.15		28.20		(25	%)
International		32.41		26.62		22	%		40.71		29.06		40	%
Total		28.96		50.20		(42	%)		34.57		47.44		(27	%)

⁽¹⁾	Reflects a per-barrel decrease of $0.71 and $1.33 from derivative activities for the 2012 third quarter and nine-month period, respectively, and a decrease of $2.58 and $3.27 from derivative activities for the comparative 2011 third quarter and nine-month period, respectively.

⁽²⁾	Reflects a per-Mcf increase of $0.50 and $0.52 from derivative activities for the 2012 third quarter and nine-month period, respectively, and an increase of $0.31 from derivative activities for each of the comparative 2011 third quarter and nine-month period.

NM – Not meaningful

Third-Quarter 2012 compared to Third-Quarter 2011

Crude Oil Revenues Crude oil revenues for the third quarter of 2012 totaled $3.2 billion, an $8 million increase from the comparative 2011 quarter, primarily the result of a one-percent increase in average realized prices. Crude oil accounted for 78 percent of oil and gas production revenues and 44 percent of worldwide production in the third quarter of 2012. Higher realized prices increased third-quarter 2012 revenues by $30 million compared to the prior-year quarter, while lower production volumes reduced revenues by $22 million.

Crude oil prices realized in the third quarter of 2012 averaged $102.62 per barrel, compared with $101.71 in the comparative prior-year quarter. International Dated Brent crudes and Heavy and Light Louisiana Sweet crudes from the Gulf Coast continue to be priced at a premium to WTI-based prices. We are realizing these premium prices on approximately 70 percent of our crude oil production. Our Egypt, Australia and North Sea regions, which comprise approximately 54 percent of our worldwide oil production, receive International Dated Brent pricing with third-quarter 2012 oil realizations averaging $112.54 compared with third-quarter 2011 realizations of $108.81. Our Gulf Coast regions, which comprise 16 percent of our worldwide oil production, had price realizations averaging $104.49 per barrel, as compared to 2011 realizations of $105.74 per barrel.

Worldwide production decreased two thousand barrels of oil per day (Mb/d) from the third quarter of 2011 to 341 Mb/d in the third quarter of 2012, driven by decreased international production and partially offset by increased U.S. production. Australia production decreased 11 Mb/d as a result of natural decline from our Pyrenees and Van Gogh fields. Egypt gross production decreased four percent from the year-ago period on natural decline while net production was down six percent. North Sea production decreased 1 Mb/d, as volumes from the newly-acquired Beryl assets largely offset the impact of third-quarter maintenance and turnaround activities. In the U.S., production increased 11 percent on new drilling and recompletion activity as well as acquisitions. The Permian region was up 10 Mb/d on increased drilling activity, primarily in the Deadwood, Spraberry, and Wolfcamp plays. The Central region was up 9 Mb/d on production from properties added in the Cordillera acquisition. The GOM onshore and offshore regions were down 6 Mb/d on Hurricane Isaac downtime and natural decline.

Natural Gas Revenues Gas revenues for the third quarter of 2012 totaled $788 million, down 15 percent from the third quarter of 2011. A one-percent increase in average production added $4 million to natural gas revenues as compared to the prior-year quarter, while a 15-percent decline in average realized prices decreased revenues by $142 million. Natural gas accounted for 19 percent of our oil and gas production revenues and 49 percent of our equivalent production.

Worldwide production grew 13 MMcf/d between the periods on production increases in the North Sea and Australia. North Sea production grew 52 MMcf/d on production from the recently-acquired Beryl assets. Daily production in Australia increased 27 MMcf/d on new contracts associated with the completion of facilities at Devil Creek. Production in the U.S. rose 5 MMcf/d on volumes from newly-acquired properties and increased drilling and recompletion activity. Volume gains were offset by production associated with divested properties, downtime associated with Hurricane Isaac, and natural decline resulting from our shift away from gas-focused drilling. Egypt gross production increased two percent while net production decreased 12 percent, a product of the terms of our production sharing contracts. Daily production in Canada was down 15 MMcf/d reflecting the impact of natural decline, plant maintenance, and lower gas-focused drilling and recompletion activity.

Year-to-Date 2012 compared to Year-to-Date 2011

Crude Oil Revenues Crude oil revenues for the first nine months of 2012 totaled $9.8 billion, $440 million higher than the comparative 2011 period, the result of a two-percent increase in average realized prices and a two-percent increase in worldwide production. Crude oil accounted for 78 percent of oil and gas production revenues and 45 percent of worldwide production, compared with 75 percent and 45 percent, respectively, in the 2011 period. Higher production volumes added $271 million to the increase in revenues compared to the first nine months of 2011, while higher realized prices contributed an additional $169 million.

Crude oil prices realized in the first nine months of 2012 averaged $103.83 per barrel, compared with $102.00 in the comparative prior-year period. Our Egypt, Australia, North Sea, and GOM regions, which comprise approximately 72 percent of our worldwide oil production averaged oil realizations of $111.00 compared with realizations of $108.42 in the 2011 period.

Worldwide production increased 8 Mb/d to 345 Mb/d in the first nine months of 2012, driven by increased production in the U.S. and the North Sea. In the U.S., production increased 10 percent on new drilling and recompletion activity as well as from acquisitions. The Permian region was up 9 Mb/d on increased drilling activity, primarily in the Deadwood, Spraberry, and Wolfcamp plays. The Central region was up 5 Mb/d on production from properties added in the Cordillera acquisition. Production in the GOM onshore and offshore regions was down 2 Mb/d on Hurricane Isaac downtime. North Sea production increased 9 Mb/d, as volumes from the newly-acquired Beryl assets more than offset the impact of third-quarter maintenance activities. Australia production decreased 9 Mb/d as a result of natural decline from our Pyrenees and Van Gogh fields. Egypt gross production was down two percent over the year-ago period while net production was down five percent, a product of the terms of our production sharing contracts.

Natural Gas Revenues Gas revenues for the first nine months of 2012 totaled $2.3 billion, down 15 percent from the comparative 2011 period. A two-percent increase in average production added $56 million to natural gas revenues, while a 16-percent decrease in average realized prices reduced revenues by $455 million. Natural gas accounted for 19 percent of our oil and gas production revenues and 50 percent of our equivalent production, compared to 22 and 51 percent, respectively, for the 2011 period. As a whole our international regions, which contribute approximately one-third of our worldwide gas production, benefitted from higher realized prices as compared to the first nine months of 2011.

Worldwide production grew 47 MMcf/d between the periods on production increases in the North Sea, Australia, and Argentina. North Sea production grew 60 MMcf/d on production from the recently-acquired Beryl assets. Daily production in Australia increased 34 MMcf/d on new contracts associated with the recently completed facilities at Devil Creek. Argentina’s production was up 7 MMcf/d from recompletions and new drilling, primarily associated with the country’s Gas Plus program. Daily production in the U.S. and Canada decreased 24 MMcf/d and 16 MMcf/d, respectively, as drilling and recompletion activity shifted from gas to liquids-rich properties. The production decrease in the U.S. was partially offset by volumes associated with properties acquired from Cordillera.

Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and a boe basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on their relevance.


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2012		2011		2012		2011		2012		2011		2012		2011
	(In millions)				(Per boe)				(In millions)				(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	1,206	$	973	$	17.00	$	14.07	$	3,535	$	2,777	$	16.72	$	13.67
Additional		729		20		10.27		0.29		1,898		46		8.98		0.23
Other assets		94		72		1.33		1.04		268		207		1.27		1.02
Asset retirement obligation accretion		60		39		0.84		0.57		172		114		0.81		0.56
Lease operating costs		801		661		11.30		9.54		2,178		1,946		10.30		9.57
Gathering and transportation costs		86		72		1.22		1.02		235		221		1.11		1.09
Taxes other than income		167		244		2.36		3.53		627		663		2.97		3.26
General and administrative expense		124		112		1.76		1.61		384		327		1.82		1.61
Merger, acquisitions & transition		7		4		0.10		0.05		29		15		0.14		0.07
Financing costs, net		40		37		0.56		0.54		125		123		0.59		0.60

Total	$	3,314	$	2,234	$	46.74	$	32.26	$	9,451	$	6,439	$	44.71	$	31.68

Depreciation, Depletion and Amortization (DD&A) The following table details the changes in DD&A of oil and gas properties between the third quarters and nine-month periods of 2012 and 2011:


	For the Quarter Ended September 30,		For the Nine Months Ended September 30,
	(In millions)		(In millions)
2011 DD&A	$	973	$	2,777
Volume change		36		154
DD&A Rate change		197		604

2012 DD&A	$	1,206	$	3,535

Oil and gas property recurring DD&A expense of $1.2 billion in the third quarter of 2012 increased $233 million compared to the prior-year quarter on an absolute dollar basis: $197 million on rate, $36 million from higher volumes. The Company’s oil and gas property recurring DD&A rate increased $2.93 to $17.00 per boe compared to the prior-year period, reflecting acquisition and drilling costs that exceed our historical basis and lower proved reserve estimates on a decline in natural gas prices.

Oil and gas property recurring DD&A expense of $3.5 billion in the first nine months of 2012 increased $758 million compared to the prior-year period on an absolute dollar basis: $604 million on rate and $154 million from higher volumes. The Company’s oil and gas property recurring DD&A rate increased $3.05 to $16.72 per boe compared to the prior-year period, reflecting acquisition and drilling costs that exceed our historical basis and lower proved reserve estimates on a decline in natural gas prices.

In addition, we recorded non-cash write-downs on the carrying value of our proved oil and gas property balances in Canada of $521 million ($390 million net of tax), $641 million ($480 million net of tax), and $721 million ($539 million net of tax) as of March 31, 2012, June 30, 2012, and September 30, 2012, respectively. 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, net of related tax effects and discounted 10 percent per annum and adjusted for cash flow hedges. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. If average natural gas prices in the fourth quarter of 2012 are lower than average prices in the fourth quarter of 2011, we will likely record an additional write-down in Canada. The Company also recorded $8 million and $20 million of additional DD&A in the third quarter of 2012 and 2011, respectively, associated with impairments of new venture seismic activity in countries where Apache is pursuing exploration opportunities but has not yet established a presence. For the nine months ended September 30, 2012 and 2011, the Company recorded $15 million and $46 million of additional DD&A, respectively.

Lease Operating Expenses (LOE) LOE increased $140 million, or 21 percent, and $232 million, or 12 percent, on an absolute dollar basis, for the quarter and nine-month period ended September 30, 2012, relative to the comparable periods of 2011. On a per unit basis, LOE increased 18 percent to $11.30 per boe for the third quarter of 2012, as compared to the same prior-year period, and eight percent to $10.30 per boe for the first nine months of 2012, as compared to the prior-year nine-month period. LOE per boe for the third quarter of 2012 was significantly impacted by production downtime and higher costs associated with repairs at our Grand Isle 43 complex and major facility turnarounds in the North Sea and Canada. The following table identifies changes in Apache’s LOE rate between the third quarters and nine-month periods of 2012 and 2011.


For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	Per boe				Per boe
2011 LOE	$	9.54		2011 LOE	$	9.57
Repairs and maintenance		0.74		Labor and pumper costs		0.33
Labor and pumper costs		0.52		Repairs and maintenance		0.23
Workovers		0.33		Non-operated costs		0.16
Other		0.10		Workovers		0.11
Acquisitions⁽¹⁾		(0.37	)	Other		(0.01	)
Other decreased production		0.44		Acquisitions⁽¹⁾		(0.19	)
				Other decreased production		0.10

2012 LOE	$	11.30		2012 LOE	$	10.30

⁽¹⁾	Per-unit impact of acquisitions is shown net of associated production.

Gathering and Transportation Gathering and transportation costs totaled $86 million and $235 million in the third quarter and first nine months of 2012, respectively, up $14 million from both the third quarter and first nine months of 2011. On a per-unit basis, gathering and transportation costs of $1.22 and $1.11 for the third quarter and first nine months of 2012, respectively, were up 20 percent and two percent, respectively. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
	(In millions)
Canada	$	38	$	39	$	121	$	125
U.S.		20		17		52		47
Egypt		9		7		29		25
North Sea		18		7		28		19
Argentina		1		2		5		5

Total Gathering and transportation	$	86	$	72	$	235	$	221

North Sea costs for the quarter and first nine months of 2012 increased $11 million and $9 million, respectively, as compared to prior-year periods, on the acquisition of Mobil North Sea at the end of 2011. The U.S. costs for the third quarter and first nine months of 2012 increased $3 million and $5 million, respectively, as compared to the same prior-year periods primarily as a result of increased production in the Central region from our acquisition of Cordillera. Canada’s costs for the third quarter and first nine months of 2012 decreased $1 million and $4 million, respectively, as compared to the same prior-year periods primarily from decreased activity in the region.

Taxes other than Income Taxes other than income totaled $167 million and $627 million for the third quarter and first nine months of 2012, a decrease of $77 million and $36 million, respectively, from the comparative prior-year periods. The following table presents a comparison of these expenses:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2012		2011		2012		2011
	(In millions)
U.K. PRT	$	62	$	149	$	332	$	386
Severance taxes		56		54		162		159
Ad valorem taxes		26		25		75		78
Other		23		16		58		40

Total Taxes other than income	$	167	$	244	$	627	$	663

The North Sea Petroleum Revenue Tax (PRT) is assessed on qualifying fields in the U.K. North Sea. For the third quarter of 2012, U.K. PRT was $87 million lower than the 2011 period based on a decrease in net receipts, primarily driven by lower revenues as a result of lower production on qualifying fields during the third quarter. Severance and ad valorem tax expense remained relatively flat, consistent with revenue.

U.K. PRT for the first nine months of 2012 was $54 million lower when compared to the 2011 period based on a decrease in net receipts, primarily driven by lower revenues during the period. For the first nine months of 2012, property acquisitions increased severance taxes by $3 million as compared to the first nine months of 2011. Ad valorem taxes for the first nine months of 2012 decreased $3 million on lower realized oil and gas prices in Canada as compared to the prior-year period.

General and Administrative Expenses General and administrative expenses (G&A) for the third quarter and first nine months of 2012 increased $12 million and $57 million, respectively, from the comparable 2011 periods on additional expenses relating to personnel, office, and information technology costs in support of our major development projects, increased exploration activities, and acquisitions.

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


	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
	(In millions)
Interest expense	$	132		$	109		$	371		$	326
Amortization of deferred loan costs		2			1			5			4
Capitalized interest		(90	)		(69	)		(241	)		(193	)
Interest income		(4	)		(4	)		(10	)		(14	)

Financing costs, net	$	40		$	37		$	125		$	123

Net financing costs were up $3 million and $2 million in the third quarter and first nine months of 2012, respectively, compared to the same 2011 periods. The $23 million and $45 million increases in interest expense in the third quarter and first nine months of 2012 are associated with $3.0 billion of debt issued in April 2012. The $21 million and $48 million increases in capitalized interest in the third quarter of 2012 and the first nine months of 2012, respectively, are a direct result of higher unproved property balances from the Mobil North Sea and Cordillera acquisitions.

Provision for Income Taxes The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. Accordingly, the Company recorded the income tax impact of a $521 million, $641 million, and $721 million non-cash write-down of its Canadian proved oil and gas properties as a discrete item in the first, second, and third quarters of 2012, respectively.

The 2012 third-quarter provision for income taxes was $685 million, representing an effective income tax rate of 79 percent for the quarter. This effective rate reflects the impact of the $721 million Canadian non-cash write-down discussed above, the North Sea decommissioning tax rate adjustment charge, and foreign currency fluctuations on deferred taxes. Excluding these items, the third-quarter 2012 effective rate would have been 45 percent, an increase from 44 percent in the third quarter of 2011.

The 2012 first nine-months provision for income taxes was $1.9 billion, representing an effective income tax rate of 59 percent for the period. This effective rate reflects the impact of three quarterly Canadian non-cash write-downs discussed above, the North Sea decommissioning tax rate adjustment charge, and foreign currency fluctuations on deferred taxes. Excluding these items, the effective rate for the first nine months of 2012 would have been 43 percent, an increase from 42 percent in the comparative 2011 period. This difference was driven primarily by an increase in the U.K. corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent, which was enacted in the third quarter of 2011.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. We may also elect to utilize available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets for all other liquidity and capital resource needs.

Apache’s operating cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash flows, and potentially our liquidity if spending does not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile and have less impact than commodity prices in the short-term.

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proven reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities and/or our ability to acquire additional reserves at reasonable costs.

We believe the liquidity and capital resource alternatives available to Apache, combined with internally-generated cash flows, will be adequate to fund 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.

For additional information, please 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 our 2011 fiscal year.

Sources and Uses of Cash

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


	For the Nine Months Ended September 30,
	2012		2011
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	6,422	$	7,171
Sale of oil and gas properties		26		202
Fixed rate debt borrowings		2,991		—
Net commercial paper and bank loan borrowings		1,827		—
Other		—		77

		11,266		7,450

Uses of Cash and Cash Equivalents:
Capital expenditures⁽¹⁾	$	6,973	$	5,230
Acquisitions		2,788		509
Equity investment in Yara Pilbara Holdings Pty Limited (YPHPL)		439		—
Payments of fixed rate debt		400		—
Net commercial paper and bank loan repayments		—		940
Dividends		246		230
Other		397		89

		11,243		6,998

Increase in cash and cash equivalents	$	23	$	452

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

Net Cash Provided by Operating Activities Cash flows are our primary source of capital and liquidity and are impacted, both in the short-term and the long-term, by volatile oil and natural gas prices. The factors in determining operating cash flow are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation (ARO) accretion and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash provided by operating activities for the first nine months of 2012 totaled $6.4 billion, down $749 million from the first nine months of 2011. The decrease reflects the impact of a change in working capital during the first nine months of 2012.

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

Sale of Oil and Gas Properties During the first nine months of 2012, Apache completed the sale of certain properties in the U.S. and Canada for $26 million. In June 2011 Apache completed the sale of certain properties in Canada and the U.S. for $202 million.

Fixed Rate Debt Borrowings In April 2012 Apache issued $3 billion principal amount of senior unsecured notes. For further discussion of the note offering, please see Note 6—Debt of this Form 10-Q.

Capital Expenditures We fund exploration and development (E&D) activities primarily through operating cash flows and budget capital expenditures based on projected cash flows. We routinely adjust our capital budget on a quarterly basis in response to changing market conditions and operating cash flow forecasts.

Historically, we have used a combination of operating cash flows, borrowings under lines of credit and the commercial paper program and, from time to time, issues of public debt or common stock to fund significant acquisitions.

The following table details capital expenditures for each country in which we do business:


	For the Nine Months Ended September 30,
	2012		2011
	(In millions)
E&D Costs:
United States	$	3,608	$	1,976
Canada		459		609

North America		4,067		2,585

Egypt		809		674
Australia		518		445
North Sea		703		618
Argentina		222		245
Other International		84		49

International		2,336		2,031

Worldwide E&D Costs		6,403		4,616

Gathering Transmission and Processing Facilities (GTP):
United States		57		9
Canada		138		113
Egypt		15		74
Australia		338		255
Argentina		12		7

Total GTP Costs		560		458

Asset Retirement Costs		556		288
Capitalized Interest		241		193

Capital Expenditures, excluding acquisitions		7,760		5,555

Acquisitions, including GTP		3,421		493
Asset Retirement Costs - Acquired		33		75

Total Capital Expenditures	$	11,214	$	6,123

Worldwide E&D expenditures for the first nine months of 2012 totaled $6.4 billion, or 39 percent above the first nine months of 2011. E&D spending in North America, which was up 57 percent, totaled 64 percent of worldwide E&D spending. Expenditures in the U.S. increased 83 percent primarily on increased drilling activity in the Permian region, particularly in the Deadwood area, and in our Central region where our active horizontal drilling program in the Granite Wash and Cherokee plays continued to expand. U.S. expenditures also reflect an increase in leasehold acquisition efforts where we have spent over $600 million to gain new acreage positions in several prospects, including the Mississippian Lime play in Kansas and Nebraska, the Williston Basin play in Montana and multiple offshore blocks in the GOM Deepwater and Shelf regions. E&D spending in Canada decreased 25 percent from the prior year period as our drilling program has been re-focused to oil and liquids-rich plays given current North American gas prices.

E&D expenditures outside of North America increased 15 percent when compared to the first nine-months of 2011. E&D spending in Egypt was up $135 million on continued drilling activity across all its major basins. North Sea expenditures were up $85 million driven by Beryl field development activity. Australian expenditures were up $73 million, or 16 percent, as development activities ramped up in the third quarter of 2012.

We invested $560 million in GTP in the first nine months of 2012 compared to $458 million in the first nine months of 2011. The increase is primarily related to Australia, driven by the purchase of the Ningaloo Vision floating production storage and offloading vessel (FPSO) and expenditures for the Wheatstone LNG project.

We acquired $3.4 billion of oil and gas properties in the first nine months of 2012 compared to $493 million in the prior-year period. Acquisitions occur as attractive opportunities arise and, therefore, vary from year to year. For information regarding our acquisitions, please see Note 2 – Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q.

Equity Investment in YPHPL On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in YPHPL (formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

Payments of Fixed Rate Debt During the second quarter of 2012 Apache repaid the $400 million in aggregate principal amount of 6.25-percent notes that matured on April 15, 2012.

Dividends For the nine-month periods ended September 30, 2012 and 2011, the Company paid $189 million and $173 million, respectively, in dividends on its common stock. In each of the first nine months of 2012 and 2011, the Company also paid $57 million in dividends on its Series D Preferred Stock.

Liquidity

The following table presents a summary of our key financial indicators at the dates presented:


	September 30, 2012			December 31, 2011
	(In millions of dollars, except as indicated)
Cash and cash equivalents	$	318		$	295
Total debt		11,634			7,216
Shareholders’ equity		30,714			28,993
Available committed borrowing capacity		1,508			3,300
Floating-rate debt/total debt		16	%		0.4	%
Percent of total debt-to-capitalization		27	%		20	%

Cash and cash equivalents We had $318 million in cash and cash equivalents as of September 30, 2012, compared to $295 million at December 31, 2011. Approximately $276 million of the cash was held by foreign subsidiaries, with the remaining $42 million held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly-liquid investment grade securities with maturities of three months or less at the time of purchase.

Debt As of September 30, 2012, outstanding debt, which consisted of notes, debentures, commercial paper, and uncommitted bank lines, totaled $11.6 billion. Current debt includes $500 million 5.25-percent notes and $400 million 6.00-percent notes due within the next 12 months and $64 million borrowed under uncommitted overdraft lines in Argentina.

In April 2012 the Company issued $400 million principal amount of senior unsecured 1.75-percent notes maturing April 15, 2017, $1.1 billion principal amount of senior unsecured 3.25-percent notes maturing April 15, 2022, and $1.5 billion principal amount of senior unsecured 4.75-percent notes maturing April 15, 2043. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. We used the proceeds to fund the cash portion of the purchase price to acquire Cordillera, repay the $400 million in aggregate principal amount of 6.25-percent notes that matured on April 15, 2012, and for general corporate purposes.

Available committed borrowing capacity As of September 30, 2012, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2016 and $2.3 billion matures in June 2017. The facilities consist of a $1.7 billion facility and a $1.0 billion facility in the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. As of September 30, 2012, available borrowing capacity under the Company’s credit facilities was $1.5 billion.

The Company has available a $3.0 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 committed credit facilities, which expire in 2016 and 2017. As of September 30, 2012, the Company had $1.8 billion in commercial paper outstanding, compared with no outstanding commercial paper as of December 31, 2011.

The Company was in compliance with the terms of all credit facilities as of September 30, 2012.

Percent of total debt–to-capitalization The Company’s September 30, 2012 debt-to-capitalization ratio was 27 percent, up from 20 percent at December 31, 2011.

Non-GAAP Measures

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

Adjusted Earnings

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


	For the Quarter Ended September 30,					For the Nine Months Ended September 30,
	2012		2011			2012		2011
	(In millions, except per share data)
Income Attributable to Common Stock (GAAP)	$	161	$	983		$	1,276	$	3,338

Adjustments:
Canada proved property write-down, net of tax⁽¹⁾		539		—			1,409		—
North Sea decommissioning tax rate adjustment		118		—			118		—
Unrealized foreign currency fluctuation impact on deferred tax expense		39		(99	)		40		(68	)
Merger, acquisitions & transition, net of tax⁽²⁾		4		2			17		9
North Sea income tax rate increase		—		274			—		218

Adjusted Earnings (Non-GAAP)	$	861	$	1,160		$	2,860	$	3,497

Net Income per Common Share – Diluted (GAAP)	$	0.41	$	2.50		$	3.27	$	8.49

Adjustments:
Canada proved property write-down, net of tax⁽¹⁾		1.33		—			3.49		—
North Sea decommissioning tax rate adjustment		0.30		—			0.30		—
Unrealized foreign currency fluctuation impact on deferred tax expense		0.10		(0.25	)		0.11		(0.17	)
Merger, acquisitions & transition, net of tax⁽²⁾		0.02		0.01			0.05		0.02
North Sea income tax rate increase		—		0.69			—		0.55

Adjusted Earnings Per Share – Diluted (Non-GAAP)	$	2.16	$	2.95		$	7.22	$	8.89

⁽¹⁾

A write-down of our Canadian proved property balances of $521 million, $641 million, and $721 million pre-tax was recorded in the first, second, and third quarters of 2012, for which a tax benefit of $131 million, $161 million, and $182 million was recognized, respectively. The tax effect was calculated utilizing the Canadian statutory rate currently in effect.

⁽²⁾

Merger, acquisitions & transition costs recorded in the third quarter of 2012 and 2011 totaled $7 million and $4 million pre-tax, respectively, for which a tax benefit of $3 million and $2 million was recognized, respectively. For the first nine months of 2012 and 2011, merger, acquisitions & transition costs totaled $29 million and $15 million, respectively, for which a tax benefit of $12 million and $6 million was recognized, respectively. The tax effect was calculated utilizing the statutory rates in effect in each country where costs were incurred.

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 political climate. Our average crude oil realizations have increased one percent to $102.62 per barrel in the third quarter of 2012 from $101.71 per barrel in the comparable period of 2011. Our average natural gas price realizations have fallen, decreasing 15 percent to $3.76 per Mcf from $4.44 per Mcf in the comparable period of 2011.

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 manage fluctuations in cash flows resulting from changes in commodity prices. For the third quarter and first nine months of 2012, approximately 13 percent of our natural gas production in both periods, and approximately 12 and 14 percent, respectively, of our crude oil production was subject to financial derivative hedges.

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

On September 30, 2012, the Company had open natural gas derivative hedges in an asset position with a fair value of $138 million. A 10-percent increase in natural gas prices would reduce the fair value by approximately $13 million, while a 10-percent decrease in prices would increase the fair value by approximately $13 million. The Company also had open oil derivatives in a liability position with a fair value of $87 million. A 10-percent increase in oil prices would increase the liability by approximately $82 million, while a 10-percent decrease in prices would decrease the liability by approximately $67 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2012. See Note 3 – Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 84 percent of the Company’s debt. At September 30, 2012, total debt included $1.9 billion of floating-rate debt. As a result, Apache’s annual interest costs will fluctuate based on short-term interest rates on approximately 16 percent of our total debt outstanding at September 30, 2012. The impact on cash flow of a 10-percent change in the floating interest rate based on debt balances at September 30, 2012, would be approximately $461,000 per quarter.

Foreign Currency Risk

The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts, and gas production is sold largely under fixed-price Australian dollar contracts. Approximately half the 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, and Argentine pesos are converted to U.S. dollar equivalents based on 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 re-measure our foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A 10-percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, and Argentine peso as of September 30, 2012, would result in a foreign currency net loss or gain, respectively, of approximately $190 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, 2011, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

•

the market prices of oil, natural gas, NGLs and other products or services;

•

our commodity hedging arrangements;

•

the integration of acquisitions;

•

the supply and demand for oil, natural gas, NGLs and other products or services;

•

production and reserve levels;

•

drilling risks;

•

economic and competitive conditions;

•

the availability of capital resources;

•

capital expenditure and other contractual obligations;

•

currency exchange rates;

•

weather conditions;

•

inflation rates;

•

the availability of goods and services;

•

legislative or regulatory changes;

•

the impact on our operations due to the change in government in Egypt;

•

terrorism or cyber attacks;

•

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 in our third-quarter 2012 earnings release, other factors disclosed under Part II, Item 1A—Risk Factors of this Form 10-Q and the Form 10-Q for the quarter ended June 30, 2012, 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 Thomas P. Chambers, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2012, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the period covered by this Quarterly Report on Form 10-Q that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Please refer to both Part I, Item 3 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (filed with the SEC on February 29, 2012) and Part I, Item 1 of this Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2012 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, 2011, and as noted above in Part I, Item 3 of this Form 10-Q. For the nine months ending September 30, 2012, Apache notes the following updated 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:

•

well blowouts, explosions, and cratering;

•

pipeline ruptures and spills;

•

fires;

•

formations with abnormal pressures;

•

equipment malfunctions;

•

hurricanes and/or cyclones, which could affect our operations in areas such as on- and offshore the Gulf Coast and Australia, and other natural disasters; and

•

surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

Failure or loss of equipment, as the result of equipment malfunctions, cyber attacks, 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, or ground water contamination from hydraulic fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout, pipeline rupture, or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives 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 flows and, in turn, our results of operations could be materially and adversely affected.

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have experienced cyber attacks, we have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.

MINE SAFETY DISCLOSURES

None

ITEM 5.

OTHER INFORMATION

None

ITEM 6.

EXHIBITS



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

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

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

*101.INS –		XBRL Instance Document.

*101.SCH –		XBRL Taxonomy Schema Document.

*101.CAL –		XBRL Calculation Linkbase Document.

*101.LAB –		XBRL Label Linkbase Document.

*101.PRE –		XBRL Presentation Linkbase Document.

*101.DEF –		XBRL Definition Linkbase Document.

*		Filed herewith

SIGNATURES

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


						APACHE CORPORATION

Dated: November 7, 2012						/s/ THOMAS P. CHAMBERS
						Thomas P. Chambers
						Executive Vice President and Chief Financial Officer
						(Principal Financial Officer)

Dated: November 7, 2012						/s/ REBECCA A. HOYT
						Rebecca A. Hoyt
						Vice President, Chief Accounting Officer and Controller
						(Principal Accounting Officer)