Apache 10Q 2011 Q3 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2011


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

For the transition period from to

Commission File Number 1-4300

APACHE CORPORATION

(exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

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). Yesþ Noo

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


Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yeso Noþ

Number of shares of registrant’s common stock outstanding as of October 31, 2011 384,059,497

PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)


	For the Quarter					For the Nine Months
	Ended September 30,					Ended September 30,
	2011		2010			2011		2010
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,282	$	3,047		$	12,515	$	8,709
Other		46		(34	)		76		(51	)

		4,328		3,013			12,591		8,658


OPERATING EXPENSES:
Depreciation, depletion and amortization		1,065		787			3,030		2,155
Asset retirement obligation accretion		39		25			114		74
Lease operating expenses		661		507			1,946		1,393
Gathering and transportation		72		43			221		126
Taxes other than income		244		158			663		522
General and administrative		112		89			327		260
Merger, acquisitions & transition		4		8			15		16
Financing costs, net		37		59			123		174

		2,234		1,676			6,439		4,720


INCOME BEFORE INCOME TAXES		2,094		1,337			6,152		3,938
Current income tax provision		473		207			1,692		889
Deferred income tax provision		619		352			1,065		706


NET INCOME		1,002		778			3,395		2,343
Preferred stock dividends		19		13			57		13

INCOME ATTRIBUTABLE TO COMMON STOCK	$	983	$	765		$	3,338	$	2,330


NET INCOME PER COMMON SHARE:
Basic	$	2.56	$	2.14		$	8.70	$	6.78
Diluted	$	2.50	$	2.12		$	8.49	$	6.72

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		384		357			384		344
Diluted		400		367			400		349

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

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,
	2011			2010
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	3,395		$	2,343
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		3,030			2,155
Asset retirement obligation accretion		114			74
Provision for deferred income taxes		1,065			706
Other		(34	)		109
Changes in operating assets and liabilities:
Receivables		(417	)		(207	)
Inventories		(35	)		(21	)
Drilling advances		(23	)		14
Deferred charges and other		(54	)		(137	)
Accounts payable		119			139
Accrued expenses		(38	)		(352	)
Deferred credits and noncurrent liabilities		49			(23	)


NET CASH PROVIDED BY OPERATING ACTIVITIES		7,171			4,800


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,758	)		(3,041	)
Additions to gas gathering, transmission and processing facilities		(472	)		(328	)
Acquisition of Devon properties		—			(1,018	)
Acquisition of BP properties and facilities		—			(2,472	)
Acquisitions, other		(509	)		(60	)
Proceeds from sale of oil and gas properties		202			—
Deposit related to acquisition of BP properties		—			(3,500	)
Other, net		(89	)		(37	)


NET CASH USED IN INVESTING ACTIVITIES		(5,626	)		(10,456	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(940	)		(37	)
Fixed-rate debt borrowings		—			1,484
Proceeds from issuance of common stock		—			2,258
Proceeds from issuance of mandatory convertible preferred stock		—			1,227
Dividends paid		(230	)		(152	)
Common stock activity		47			29
Treasury stock activity, net		4			4
Cost of debt and equity transactions		(2	)		(17	)
Other		28			23

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,093	)		4,819


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		452			(837	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		134			2,048


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	586		$	1,211


SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	165		$	176
Income taxes paid, net of refunds		1,335			969

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

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)


	September 30,			December 31,
	2011			2010
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	586		$	134
Receivables, net of allowance		2,560			2,134
Inventories		566			564
Drilling advances		277			259
Prepaid assets and other		587			389

		4,576			3,480


PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		63,086			57,904
Unproved properties and properties under development, not being amortized		5,315			5,048
Gathering, transmission and processing facilities		4,684			4,212
Other		675			582

		73,760			67,746
Less: Accumulated depreciation, depletion and amortization		(32,624	)		(29,595	)

		41,136			38,151

OTHER ASSETS:
Goodwill		1,032			1,032
Deferred charges and other		738			762

	$	47,482		$	43,425

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	852		$	779
Accrued operating expense		158			163
Accrued exploration and development		1,329			1,367
Accrued compensation and benefits		143			231
Current debt		417			46
Current asset retirement obligation		327			407
Derivative instruments		50			194
Accrued income taxes		267			2
Other		481			335

		4,024			3,524


LONG-TERM DEBT		6,785			8,095


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		5,535			4,249
Asset retirement obligation		2,603			2,465
Other		632			715

		8,770			7,429


COMMITMENTS AND CONTINGENCIES (Note 7)

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, 385,171,811 and 383,668,297 shares issued, respectively		241			240
Paid-in capital		9,017			8,864
Retained earnings		17,388			14,223
Treasury stock, at cost, 1,144,416 and 1,276,555 shares, respectively		(32	)		(36	)
Accumulated other comprehensive income (loss)		62			(141	)

		27,903			24,377

	$	47,482		$	43,425

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

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


																Accumulated
			Series D													Other			Total
	Comprehensive		Preferred		Common		Paid-In			Retained			Treasury			Comprehensive			Shareholders’
	Income		Stock		Stock		Capital			Earnings			Stock			Income (Loss)			Equity
							(In millions)
BALANCE AT DECEMBER 31, 2009			$	—	$	215	$	4,634		$	11,437		$	(217	)	$	(290	)	$	15,779
Comprehensive income:
Net income	$	2,343		—		—		—			2,343			—			—			2,343
Commodity hedges, net of income tax expense of $152		340		—		—		—			—			—			340			340

Comprehensive income	$	2,683

Dividends:
Preferred				—		—		—			(13	)		—			—			(13	)
Common ($0.45 per share)				—		—		—			(156	)		—			—			(156	)
Mandatory convertible preferred stock issued				1,227		—		—			—			—			—			1,227
Common stock issuance				—		13		2,075			—			170			—			2,258
Common stock activity, net				—		1		18			—			—			—			19
Treasury shares issued, net				—		—		1			—			5			—			6
Compensation expense				—		—		142			—			—			—			142


BALANCE AT SEPTEMBER 30, 2010			$	1,227	$	229	$	6,870		$	13,611		$	(42	)	$	50		$	21,945

BALANCE AT DECEMBER 31, 2010			$	1,227	$	240	$	8,864		$	14,223		$	(36	)	$	(141	)	$	24,377
Comprehensive income:
Net income	$	3,395		—		—		—			3,395			—			—			3,395
Commodity hedges, net of income tax expense of $121		203		—		—		—			—			—			203			203

Comprehensive income	$	3,598

Dividends:
Preferred				—		—		—			(57	)		—			—			(57	)
Common ($0.45 per share)				—		—		—			(173	)		—			—			(173	)
Common stock activity, net				—		1		28			—			—			—			29
Treasury shares issued, 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

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 Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010, 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, 2011, Apache’s significant accounting policies are consistent with those discussed in Note 1 of its consolidated financial statements contained in the Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010.

Use of Estimates

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

New Pronouncements Issued But Not Yet Adopted

In May 2011 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, which amends FASB Accounting Standards Codification (ASC) Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance clarifies many requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In June 2011 the FASB issued ASU No. 2011-05, which amends ASC Topic 220, “Comprehensive Income.” This ASU requires companies to present items of net income, items of other comprehensive income (OCI) and total comprehensive income in either one continuous statement or two separate but consecutive statements. Companies will no longer be allowed to present OCI in the statement of stockholders’ equity, and reclassification adjustments between OCI and net income must be presented separately on the face of the financial statements. The guidance in ASU No. 2011-05 is effective for interim and annual periods beginning after December 15, 2011. The amendment provides only for a change in presentation of financial statements; therefore, adoption will have no impact on the Company’s financial position or results of operations.

In September 2011 the FASB issued ASU No. 2011-08, which amends ASC Topic 350-20, “Intangible Assets — Goodwill and Other.” The amended guidance provides the option to first assess qualitative factors to determine whether it is more likely than not (a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount. If, after considering the totality of events and circumstances, the qualitative assessment does not indicate that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. The guidance in ASU No. 2011-08 is effective for interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

2. ACQUISITIONS AND DIVESTITURES

2011 Activity

During the first nine months of 2011 Apache completed $493 million of oil and gas property acquisitions and $202 million of oil and gas property sales. In addition, the Company has entered into the following material transactions:

Kitimat LNG Project

In 2010 Apache Canada Ltd. (Apache Canada) and EOG Resources Canada, Inc. (EOG Canada), through their subsidiaries, purchased 51-percent and 49-percent interests, respectively, in a planned liquefied natural gas (LNG) export terminal (Kitimat LNG facility) and 25.5-percent and 24.5-percent interests, respectively, in Pacific Trail Pipelines Limited Partnership (PTP), a partnership that owns a related proposed pipeline. In February 2011, in order to align ownership and interests on the planned facility and pipeline development, Apache Canada and EOG Canada agreed to purchase Pacific Northern Gas Ltd.’s (PNG) remaining interest in PTP for $50 million. Following the close of the acquisition, Apache Canada and EOG Canada owned 51-percent and 49-percent interests, respectively, in PTP and secured full ownership in the proposed pipeline to transport natural gas from production areas to the Kitimat LNG facility. Under the terms of the agreement, PNG will operate and maintain the pipeline under a seven-year agreement with provisions for five-year renewals.

In March 2011, Apache Canada and EOG Canada announced that Encana Corporation agreed to purchase a 30-percent working interest ownership in both the Kitimat LNG facility and PTP. Under the new ownership agreement, Apache Canada retained a 40-percent interest in both the facility and the related pipeline while EOG Canada retained a 30-percent interest.

ExxonMobil United Kingdom North Sea Asset Acquisition

On September 21, 2011, Apache announced an agreement to acquire assets from Exxon Mobil Corporation’s U.K. subsidiary, Mobil North Sea LLC, for $1.75 billion. The fields have net production of approximately 19,000 barrels of oil and natural gas liquids and 58 million cubic feet of natural gas per day. At year-end 2010, estimated proved reserves totaled 68 million barrels of oil equivalent. The assets to be 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.

The transaction is projected to close by year-end 2011 with an effective date of January 1, 2011. The acquisition is subject to regulatory approvals in the United Kingdom (U.K.). The Company expects to fund this transaction at closing with cash.

2010 Activity

During 2010 Apache completed the following material transactions:

Gulf of Mexico Shelf Acquisition

In June 2010 Apache completed an acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon Energy Corporation (Devon) for $1.05 billion, subject to normal post-closing adjustments. The acquisition was effective January 1, 2010, and was funded primarily from existing cash balances.

BP Acquisitions

In July 2010 Apache entered into three definitive purchase and sale agreements to acquire properties from subsidiaries of BP plc (collectively referred to as “BP”) for aggregate consideration of $7.0 billion. The effective date of the transactions was July 1, 2010. The acquisition of BP’s oil and gas operations, related infrastructure and acreage in the Permian Basin of west Texas and New Mexico was completed on August 10, 2010, for an agreed-upon purchase price of $3.1 billion. Apache completed the acquisition of substantially all of BP’s western Canadian upstream natural gas assets on October 8, 2010, for $3.25 billion. On November 4, 2010, the Company completed the acquisition of BP’s interests in four development licenses and one exploration concession in the Western Desert of Egypt for $650 million. Preferential purchase rights for $658 million of the value of the Permian Basin properties were exercised, and accordingly, the aggregate purchase price for all three transactions was reduced to approximately $6.4 billion, subject to normal post-closing adjustments.

The acquisitions were funded with a combination of common stock, mandatory convertible preferred shares, new term debt, commercial paper and existing cash balances.

Mariner Energy, Inc. Merger

In November 2010 Apache acquired Mariner Energy, Inc. (Mariner), an independent exploration and production company, in a stock and cash transaction totaling $2.7 billion and assumed approximately $1.7 billion of Mariner’s debt. Mariner’s oil and gas properties are primarily located in the Gulf of Mexico deepwater and shelf, the Permian Basin and onshore in the Gulf Coast region. The transaction was accounted for using the acquisition method of accounting, which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. Certain assets and liabilities may be adjusted as additional information is obtained, but no later than one year from the acquisition date.

Pro Forma Impact of Acquisitions (Unaudited)

The Devon and BP Permian acquisitions were completed during the second and third quarters of 2010 respectively. The remaining BP acquisitions and Mariner merger were completed subsequent to the third quarter of 2010. The following table presents pro forma information for Apache as if the acquisitions and merger occurred prior to January 1, 2010:


	For the Quarter		For the Nine Months
	Ended September 30,		Ended September 30,
	2010		2010
	(In millions)
Revenues and Other	$	3,447	$	10,241


Net Income	$	812	$	2,542
Preferred Stock Dividends		19		57

Income Attributable to Common Stock		793		2,485


Net Income per Common Share — Basic	$	2.08	$	6.52

Net Income per Common Share — Diluted	$	2.02	$	6.41

Apache’s historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the acquisitions and merger and were factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company’s consolidated results of operations actually would have been had the acquisitions and merger been completed prior to January 1, 2010. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. Adjustments and assumptions made for this pro forma calculation are consistent with those used in the Company’s annual pro forma information as more fully described in Note 2 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year.

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. Management believes it is prudent to manage the variability in cash flows by 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, 2011, Apache had derivative positions with 20 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, 2011, Apache had the following open natural gas derivative positions:


			Fixed-Price Swaps				Collars
					Weighted						Weighted		Weighted
Production	MMBtu		GJ		Average		MMBtu		GJ		Average		Average
Period	(in 000’s)		(in 000’s)		Fixed Price⁽¹⁾		(in 000’s)		(in 000’s)		Floor Price⁽¹⁾		Ceiling Price⁽¹⁾
2011		19,965		—	$	5.97		2,300		—	$	5.00	$	8.85
2011		—		12,880	C $	6.26		—		920	C $	6.50	C $	7.10
2012		48,349		—	$	6.22		21,960		—	$	5.54	$	7.30
2012		—		43,920	C $	6.61		—		7,320	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.

As of September 30, 2011, Apache had the following open crude oil derivative positions:


	Fixed-Price Swaps				Collars
			Weighted				Weighted		Weighted
Production			Average				Average		Average
Period	Mbbls		Fixed Price⁽¹⁾		Mbbls		Floor Price⁽¹⁾		Ceiling Price⁽¹⁾
2011		1,405	$	74.87		7,503	$	69.22	$	96.82
2012		4,110		73.40		12,628		76.42		101.06
2013		1,972		74.29		2,416		78.02		103.06
2014		76		74.50		—		—		—


	⁽¹⁾		Crude oil prices represent a weighted average of several contracts entered into on a per barrel basis. Crude oil contracts are primarily settled against NYMEX WTI Cushing Index. A portion of 2011 and 2012 contracts are settled against Dated Brent.

In addition to the amounts reflected above, Apache North Sea Ltd. entered into a physical sales contract to deliver 20,000 barrels of oil per day in 2011, settled against Dated Brent with a floor price of $70 per barrel and an average ceiling price of $98.56 per barrel. This contract is not reflected in the above table because the associated sales are in the normal course of business and are recognized in oil and gas revenues on an accrual basis.

Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet

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


	September 30,		December 31,
	2011		2010
	(In millions)
Current Assets: Prepaid assets and other	$	306	$	167
Other Assets: Deferred charges and other		93		139

Total Assets	$	399	$	306

Current Liabilities: Derivative instruments	$	50	$	194
Noncurrent Liabilities: Other		25		124

Total Liabilities	$	75	$	318

The methods and assumptions used to estimate the fair values of the Company’s commodity derivative instruments and gross amounts of commodity derivative assets and liabilities are more fully discussed in Note 9 — Fair Value Measurements of this Form 10-Q.

Derivative Activity Recorded in Statement of Consolidated Operations

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


		For the Quarter				For the Nine Months
		Ended				Ended
		September 30,				September 30,
	Gain (Loss) on Derivatives	2011		2010		2011			2010
	Recognized In Income	(In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)	Oil and Gas Production Revenues	$	11	$	53	$	(36	)	$	104
Gain (loss) on derivatives recognized in operations (ineffective portion and basis)	Revenues and Other: Other	$	15	$	—	$	16		$	(1	)

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,
	2011						2010
	Before			After			Before			After
	Tax			Tax			Tax			Tax
	(In millions)
Unrealized loss on derivatives at beginning of period	$	(54	)	$	(19	)	$	(267	)	$	(170	)
Realized amounts reclassified into earnings		36			32			(104	)		(67	)
Net change in derivative fair value		304			181			596			407
Ineffectiveness reclassified into earnings		(16	)		(10	)		—			—

Unrealized gain on derivatives at end of period	$	270		$	184		$	225		$	170

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, 2011, is a net gain of approximately $213 million ($146 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. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the quarter ended September 30, 2011:


	(In millions)
Asset retirement obligation at December 31, 2010	$	2,872
Liabilities incurred		288
Liabilities acquired		75
Liabilities settled		(419	)
Accretion expense		114

Asset retirement obligation at September 30, 2011		2,930

Less current portion		(327	)


Asset retirement obligation, long-term	$	2,603

5. DEBT AND FINANCING COSTS

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt at September 30, 2011 and December 31, 2010:


	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In millions)
Money market lines of credit	$	17	$	17	$	46	$	46
Commercial paper		—		—		913		913
Notes and debentures		7,185		8,398		7,182		7,870

Total Debt	$	7,202	$	8,415	$	8,141	$	8,829

The Company’s debt is recorded at the carrying amount on its consolidated balance sheet, net of unamortized discount. The carrying amount of the Company’s money market lines of credit and commercial paper approximates fair value because the interest rates are 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, 2011, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $2.3 billion matures in May 2013 and $1.0 billion matures in August 2016. The facilities consist of a $1.5 billion facility, a $1.0 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia, and a $150 million facility in Canada. As of September 30, 2011, available borrowing capacity under the Company’s credit facilities was $3.3 billion. The U.S. credit facilities are used to support Apache’s commercial paper program.

On August 16, 2011, Apache entered into a $1.0 billion five-year syndicated revolving credit facility. The credit facility is subject to covenants, events of default and representations and warranties that are substantially similar to those in Apache’s other revolving credit facilities. The facility may be used for acquisitions and for general corporate purposes or to support the Company’s commercial paper program. Loans under the facility will bear interest at a base rate, as defined in the credit agreement, or at the London Inter-Bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating.

The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under Apache’s U.S. credit facilities, which expire in 2013 and 2016. As of September 30, 2011, the Company had no commercial paper outstanding, down from $913 million outstanding as of December 31, 2010.

As of September 30, 2011, current debt included $400 million 6.25-percent notes due within the next 12 months and $17 million borrowed under uncommitted overdraft lines in Argentina. On December 31, 2010, current debt included $46 million drawn on uncommitted overdraft lines in the U.S. and Argentina.

Financing Costs

Financing costs incurred during the periods comprised the following:


	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In millions)
Interest expense	$	109		$	86		$	326		$	237
Amortization of deferred loan costs		1			7			4			10
Capitalized interest		(69	)		(29	)		(193	)		(64	)
Interest income		(4	)		(5	)		(14	)		(9	)

Financing costs, net	$	37		$	59		$	123		$	174

6. 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 Apache operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

In March 2011 the U.K. government proposed an increase in the corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent. The legislation received Royal Assent and was enacted on July 19, 2011. As a result of the enacted legislation, the Company recorded a tax charge of $305 million in the third quarter of 2011. Of this amount, $274 million is related to periods prior to the third quarter. Specifically, $218 million resulted from the remeasurement of our U.K. deferred tax liability as of December 31, 2010, and $56 million is related to operating results through the second quarter of 2011.

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. 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.

7. COMMITMENTS AND CONTINGENCIES

Legal Matters

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

Argentine Environmental Claims

As more fully described in Note 8 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for the 2010 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 entitledAsociación de Superficiarios de la Patagonia v. YPF S.A., et. al., originally filed on August 21, 2003, in the Argentine National Supreme Court of Justice relating to various environmental and remediation claims. No material change in the status of these matters has occurred since the filing of Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year.

Louisiana Restoration

As more fully described in Note 8 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year, numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages for contamination and cleanup. No material change in the status of these matters has occurred since the filing of Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year.

Hurricane-Related Litigation

On May 27, 2011, a lawsuit captionedComer 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, was filed in which certain named residents of Mississippi, as plaintiffs, allege that the oil, coal, and chemical industries are responsible for global warming, which they claim caused or increased the effect of Hurricane Katrina, allegedly resulting among other things in economic losses and increased insurance premiums. Plaintiffs seek class certification, damages for losses sustained, a declaration that state law tort claims are not preempted by federal law, and punitive and exemplary damages. Apache is one of numerous defendants. A similar action filed by Comeret al. was previously dismissed as explained in detail in Note 8 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year.

Australia Gas Pipeline Force Majeure

As more fully described in Note 8 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year, 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 Amended Annual Report on Form 10-K/A for its 2010 fiscal year, except as follows:

Apache Northwest Pty Ltd (Apache Northwest) and Apache Energy Limited (Apache Energy) were served with a lawsuit captionedAlcoa of Australia Limited vs. 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. The lawsuit concerns the pipeline explosion at Varanus Island in Western Australia on June 3, 2008, that interrupted deliveries of natural gas to Alcoa under two long-term contracts. Alcoa challenges the declaration of force majeure and the validity of the liquidated damages provisions in the contracts. Alcoa asserts claims based on breach of contract, statutory duties, and duty of care. Alcoa seeks approximately $158 million AUD in general damages or, alternatively, approximately $5.7 million AUD in liquidated damages. Apache Northwest and Apache Energy do not believe that Alcoa’s claims have merit and will vigorously pursue their defenses against such claims.

In reference to the pipeline license described in Note 8 of the financial statements in Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year, the application by Apache Northwest, Kufpec Australia Pty Ltd, and Tap (Harriet) Pty Ltd for renewal and variation of the pipeline license covering the area of the Varanus Island facility was granted on April 19, 2011, by the Government of Western Australia, Department of Mines and Petroleum. The period of the license is 21 years commencing April 20, 2011.

Escheat Audits

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

Burrup-Related Gas Supply Lawsuits

On May 19, 2011, a lawsuit captionedOswal 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. This lawsuit is one of a number of legal actions involving the Burrup Fertilisers Pty Ltd (Burrup Fertilisers) ammonia plant in Western Australia (the Burrup plant) founded by Oswal. Oswal’s shares, and those of his wife, together representing 65 percent of Burrup Holdings Limited (which owns Burrup Fertilisers), are being offered for sale by externally-appointed administrators in Australia as a result of alleged events of default on loans made to the Oswals by the Australia and New Zealand Banking Group Ltd (ANZ). In the Texas lawsuit, plaintiff Oswal alleges, among other things, that the Company induced him to make certain investments relating to the Burrup plant. Plaintiff Oswal seeks damages in the amount of $491 million USD. The Company believes that the claims are without merit and intends to vigorously defend against them. The Texas lawsuit relates to a pending action filed by Tap (Harriet) Pty Ltd against Burrup Fertilisers Pty Ltdet al., Civ 2329 of 2009, in the Supreme Court of Western Australia, seeking a declaratory judgment regarding its contractual rights and obligations under a gas sales agreement between Burrup Fertilisers and the Harriet Joint Venture (comprised of a Company subsidiary and two joint venture partners, Tap (Harriet) Pty Ltd and Kufpec Australia Pty Ltd). The Company and the Company’s subsidiary, each of which has been added as a defendant by counterclaim, are diligently pursuing their claims and defenses.

Environmental Matters

As of September 30, 2011, the Company had an undiscounted reserve for environmental remediation of approximately $131 million. The Company is not aware of any environmental claims existing as of September 30, 2011, that have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Apache Canada Ltd. has 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 dispute centers on Apache Canada Ltd.’s identification of Alleged Adverse Conditions, as that term is defined in the parties’ agreement, and more specifically the contention that liabilities associated with such conditions were retained by BP Canada as seller. Apache Canada Ltd. is diligently pursuing this claim.

On May 25, 2011, a panel of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) published a report dated May 23, 2011, and titled “Vermilion Block, Production Platform A: An Investigation of the September 2, 2010 Incident in the Gulf of Mexico.” The report concerned the BOEMRE’s investigation of a fire on the Vermilion 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 evacuated to safety by jumping into the water where they were later rescued. The BOEMRE 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 BOEMRE also identified other safety deficiencies on the platform. The BOEMRE has recommended that several Incidents of Non-Compliance be issued to Mariner, which may provide the basis for the assessment of civil penalties against Mariner. Effective November 10, 2010, Mariner was acquired by Apache.

8. 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, 2011 and 2010 is presented in the table below.


	For the Quarter Ended September 30,
	2011						2010
	Income		Shares		Per Share		Income		Shares		Per Share
			(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	983		384	$	2.56	$	765		357	$	2.14


Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock		19		14				13		9
Stock options and other		—		2				—		1


Diluted:
Income attributable to common stock, including assumed conversions	$	1,002		400	$	2.50	$	778		367	$	2.12


	For the Nine Months Ended September 30,
	2011						2010
	Income		Shares		Per Share		Income		Shares		Per Share
			(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	3,338		384	$	8.70	$	2,330		344	$	6.78


Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock		57		14				13		3
Stock options and other		—		2				—		2


Diluted:
Income attributable to common stock, including assumed conversions	$	3,395		400	$	8.49	$	2,343		349	$	6.72

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 3.3 million and 3.7 million for the quarters ending September 30, 2011 and 2010, and 2.4 million and 3.2 million for the nine months ended September 30, 2011 and 2010, respectively.

Issuance of Common and Preferred Shares

In July 2010, in conjunction with Apache’s acquisition of properties from BP, the Company issued 26.45 million shares of common stock, as well as 25.3 million depositary shares, each representing a 1/20^th interest in a share of Apache’s 6.00% Mandatory Convertible Preferred Stock, Series D, or 1.265 million Preferred Shares. Each outstanding Preferred Share will, on August 1, 2013, automatically convert into a minimum of 9.164 or a maximum of 11.364 shares of Apache common stock depending on an average underlying price of the common stock immediately preceding the conversion.

In November 2010, in connection with the Mariner merger, Apache issued 17.3 million shares of common stock in exchange for Mariner common and restricted stock. For further discussion of the BP acquisitions and Mariner merger, please see Note 2 — Acquisitions and Divestitures of this Form 10-Q.

On May 5, 2011, Apache stockholders approved amendments to the Certificate of Incorporation increasing the number of common shares authorized for issuance from 430 million to 860 million and increasing the number of preferred shares authorized for issuance from five million to 10 million.

Common and Preferred Stock Dividends

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, 2010, the Company paid $51 million and $152 million, respectively.

For the quarter and nine months ended September 30, 2011, Apache paid a total of $19 million and $57 million, respectively, in dividends on its Series D Preferred Stock issued in July 2010. Dividends of $13 million were accrued on the Series D Preferred Stock in the third quarter of 2010 and paid in November 2010.

9. FAIR VALUE MEASUREMENTS

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

Cash, Cash Equivalents, Accounts Receivable and Accounts Payable

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

Commodity Derivative Instruments

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps and options. The Company 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 further information regarding Apache’s derivative instruments and hedging activities, please see Note 3 — Derivative Instruments and Hedging Activities of this Form 10-Q.

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


	Fair Value Measurements Using
	Quoted
	Price in		Significant		Significant
	Active		Other		Unobservable		Total
	Markets		Inputs		Inputs		Fair					Carrying
	(Level 1)		(Level 2)		(Level 3)		Value		Netting⁽¹⁾			Amount
	(In millions)
September 30, 2011
Assets:
Commodity Derivative Instruments	$	—	$	432	$	—	$	432	$	(33	)	$	399

Liabilities:
Commodity Derivative Instruments		—		108		—		108		(33	)		75

December 31, 2010
Assets:
Commodity Derivative Instruments	$	—	$	454	$	—	$	454	$	(148	)	$	306

Liabilities:
Commodity Derivative Instruments		—		466		—		466		(148	)		318


(1)		The derivative fair values above are based on analysis of each contract on a gross basis, even where the legal right of offset exits, as required by ASC Topic 820. The carrying amounts of derivative assets and liabilities reported on the consolidated balance sheet are determined by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. See Note 3 — Derivative Instruments and Hedging Activities of this Form 10-Q for a discussion of amounts recorded on the consolidated balance sheet at September 30, 2011, and December 31, 2010.

10. COMPREHENSIVE INCOME

The following table presents the components of Apache’s comprehensive income for the quarter and nine-month periods ended September 30, 2011 and 2010.


	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
				(In millions)
Net income	$	1,002		$	778		$	3,395		$	2,343
Other comprehensive income (loss):
Commodity hedges		397			29			324			492
Income tax related to commodity hedges		(135	)		(2	)		(121	)		(152	)


Total comprehensive income	$	1,264		$	805		$	3,598		$	2,683

11. 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, 2011, the Company had operations in the United States, Canada, Egypt, the United Kingdom North Sea, Australia and Argentina. Financial information for each country is presented below:


	United													Other
	States		Canada		Egypt			Australia		North Sea		Argentina		International			Total
							(In millions)
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	$	1549	$	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


For the Quarter Ended September 30, 2010
Oil and Gas Production Revenues	$	1,061	$	231	$	822		$	431	$	410	$	92	$	—		$	3,047


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


Other Income (Expense):
Other																		(34	)
General and administrative																		(89	)
Merger, acquisitions & transition																		(8	)
Financing costs, net																		(59	)

Income Before Income Taxes																	$	1,337


For the Nine Months Ended September 30, 2010

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


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


Other Income (Expense):
Other																		(51	)
General and administrative																		(260	)
Merger, acquisitions & transition																		(16	)
Financing costs, net																		(174	)

Income Before Income Taxes																	$	3,938


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


⁽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.

12. SUPPLEMENTAL GUARANTOR INFORMATION

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

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

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 30, 2011


					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
					(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,097	$	—	$	3,185		$	—		$	4,282
Equity in net income 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 BEFORE INCOME TAXES		1,212		322		1,634			(1,074	)		2,094
Provision for income taxes		210		69		813			—			1,092


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


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

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


						All Other
			Apache			Subsidiaries
	Apache		Finance			of Apache			Reclassifications
	Corporation		Canada			Corporation			& Eliminations			Consolidated
						(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	960	$	—		$	2,087		$	—		$	3,047
Equity in net income (loss) of affiliates		540		(13	)		(9	)		(518	)		—
Other		19		(1	)		(51	)		(1	)		(34	)

		1,519		(14	)		2,027			(519	)		3,013


OPERATING EXPENSES:
Depreciation, depletion and amortization		283		—			504			—			787
Asset retirement obligation accretion		13		—			12			—			25
Lease operating expenses		220		—			287			—			507
Gathering and transportation		10		—			33			—			43
Taxes other than income		39		—			119			—			158
General and administrative		72		—			18			(1	)		89
Merger, acquisitions & transition		8		—			—			—			8
Financing costs, net		31		14			14			—			59

		676		14			987			(1	)		1,676


INCOME (LOSS) BEFORE INCOME TAXES		843		(28	)		1,040			(518	)		1,337
Provision (benefit) for income taxes		65		(6	)		500			—			559


NET INCOME (LOSS)		778		(22	)		540			(518	)		778
Preferred stock dividends		13		—			—			—			13


INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	765	$	(22	)	$	540		$	(518	)	$	765

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2011


					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
					(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,230	$	—	$	9,285		$	—		$	12,515
Equity in net income 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 BEFORE INCOME TAXES		3,794		230		4,995			(2,867	)		6,152
Provision for income taxes		399		50		2,308			—			2,757


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


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

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


					All Other
			Apache		Subsidiaries
	Apache		Finance		of Apache			Reclassifications
	Corporation		Canada		Corporation			& Eliminations			Consolidated
					(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,711	$	—	$	5,998		$	—		$	8,709
Equity in net income (loss) of affiliates		1,735		50		(24	)		(1,761	)		—
Other		22		28		(98	)		(3	)		(51	)

		4,468		78		5,876			(1,764	)		8,658


OPERATING EXPENSES:
Depreciation, depletion and amortization		731		—		1,424			—			2,155
Asset retirement obligation accretion		38		—		36			—			74
Lease operating expenses		558		—		835			—			1,393
Gathering and transportation		31		—		95			—			126
Taxes other than income		107		—		415			—			522
General and administrative		208		—		55			(3	)		260
Merger, acquisitions & transition		16		—		—			—			16
Financing costs, net		133		42		(1	)		—			174

		1,822		42		2,859			(3	)		4,720


INCOME BEFORE INCOME TAXES		2,646		36		3,017			(1,761	)		3,938
Provision for income taxes		303		10		1,282			—			1,595


NET INCOME		2,343		26		1,735			(1,761	)		2,343
Preferred stock dividends		13		—		—			—			13


INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,330	$	26	$	1,735		$	(1,761	)	$	2,330

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2011


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& 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	)
Common stock activity		47			35			(42	)		7			47
Treasury stock activity, net		4			—			—			—			4
Cost of debt and equity transactions		(2	)		—			—			—			(2	)
Other		48			—			(20	)		—			28

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 STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2010


							All Other
				Apache			Subsidiaries
	Apache			Finance			of Apache			Reclassifications
	Corporation			Canada			Corporation			& Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(1,174	)	$	(43	)	$	6,017		$	—		$	4,800


CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(847	)		—			(2,194	)		—			(3,041	)
Additions to gas gathering, transmission and processing facilities		—			—			(328	)		—			(328	)
Acquisition of Devon properties		(1,018	)		—			—			—			(1,018	)
Acquisition of BP properties		(2,472	)		—			—			—			(2,472	)
Acquisition — other		(29	)		—			(31	)		—			(60	)
Deposit related to acquisition of BP Properties		—			—			(3,500	)		—			(3,500	)
Investment in subsidiaries, net		687			—			—			(687	)		—
Other		(33	)		—			(4	)		—			(37	)
															��
NET CASH USED IN INVESTING ACTIVITIES		(3,712	)		—			(6,057	)		(687	)		(10,456	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		—			—			(37	)		—			(37	)
Intercompany borrowings		—			2			(687	)		685			—
Fixed-rate debit borrowings		1,484			—			—			—			1,484
Proceeds from issuance of common stock		2,258			—			—			—			2,258
Proceeds from issuance of mandatory convertible preferred stock		1,227			—			—			—			1,227
Dividends paid		(152	)		—			—			—			(152	)
Common stock activity		29			39			(41	)		2			29
Treasury stock activity, net		4			—			—			—			4
Cost of debt and equity transactions		(17	)		—			—			—			(17	)
Other		24			—			(1	)		—			23

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,857			41			(766	)		687			4,819


NET DECREASE IN CASH AND CASH EQUIVALENTS		(29	)		(2	)		(806	)		—			(837	)

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		647			2			1,399			—			2,048


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	618		$	—		$	593		$	—		$	1,211

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2011


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

CURRENT ASSETS:
Cash and cash equivalents	$	19	$	—	$	567		$	—		$	586
Receivables, net of allowance		665		—		1,895			—			2,560
Inventories		56		—		510			—			566
Drilling advances		11		1		265			—			277
Prepaid assets and other		3,548		—		(2,961	)		—			587

		4,299		1		276			—			4,576

PROPERTY AND EQUIPMENT, NET		12,498		—		28,638			—			41,136


OTHER ASSETS:
Intercompany receivable, net		3,447		—		(1,745	)		(1,702	)		—
Equity in affiliates		19,299		1,341		87			(20,727	)		—
Goodwill, net		—		—		1,032			—			1,032
Deferred charges and other		210		1,003		525			(1,000	)		738

	$	39,753	$	2,345	$	28,813		$	(23,429	)	$	47,482

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	522	$	1	$	2,031		$	(1,702	)	$	852
Current debt		400		—		17			—			417
Accrued exploration and development		297		—		1,032			—			1,329
Current asset retirement obligation		317		—		10			—			327
Derivative instruments		16		—		34			—			50
Accrued income taxes		68		—		199			—			267
Other accrued expenses		267		15		500			—			782

		1,887		16		3,823			(1,702	)		4,024

LONG-TERM DEBT		6,136		647		2			—			6,785


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,195		4		3,336			—			5,535
Asset retirement obligation		1,086		—		1,517			—			2,603
Other		546		250		836			(1,000	)		632

		3,827		254		5,689			(1,000	)		8,770


COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY		27,903		1,428		19,299			(20,727	)		27,903

	$	39,753	$	2,345	$	28,813		$	(23,429	)	$	47,482

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 2010


					All Other
					Subsidiaries
	Apache		Apache		of Apache			Reclassifications
	Corporation		Finance Canada		Corporation			& Eliminations			Consolidated
					(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6	$	—	$	128		$	—		$	134
Receivables, net of allowance		691		—		1,443			—			2,134
Inventories		55		—		509			—			564
Drilling advances		10		2		247			—			259
Prepaid assets and other		3,313		—		(2,924	)		—			389

		4,075		2		(597	)		—			3,480

PROPERTY AND EQUIPMENT, NET		11,314		—		26,837			—			38,151


OTHER ASSETS:
Intercompany receivable, net		4,695		—		(3,149	)		(1,546	)		—
Equity in affiliates		16,649		1,275		98			(18,022	)		—
Goodwill, net		—		—		1,032			—			1,032
Deferred charges and other		178		1,003		581			(1,000	)		762

	$	36,911	$	2,280	$	24,802		$	(20,568	)	$	43,425

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	480	$	2	$	1,843		$	(1,546	)	$	779
Accrued exploration and development		274		—		1,093			—			1,367
Current debt		16		—		30			—			46
Current asset retirement obligation		317		—		90			—			407
Derivative instruments		153		—		41			—			194
Accrued income taxes		42		—		(40	)		—			2
Other accrued expenses		358		3		368			—			729

		1,640		5		3,425			(1,546	)		3,524

LONG-TERM DEBT		7,447		647		1			—			8,095


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,803		5		2,441			—			4,249
Asset retirement obligation		1,001		—		1,464			—			2,465
Other		643		250		822			(1,000	)		715

		3,447		255		4,727			(1,000	)		7,429

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY		24,377		1,373		16,649			(18,022	)		24,377

	$	36,911	$	2,280	$	24,802		$	(20,568	)	$	43,425

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

Apache Corporation, a Delaware corporation formed in 1954, together with its subsidiaries (collectively, Apache or the Company) is one of the world’s largest independent oil and gas companies, with operations in the United States (U.S.), Canada, Egypt, the United Kingdom (U.K.) North Sea, Australia and Argentina.

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 Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year.

Financial Overview

Apache’s steady commitment to building a portfolio of high-quality core assets with a diversity of geologic and geographic risk, product mix and reserve life drove our financial performance in the third quarter of 2011. Record third-quarter 2011 production and higher prices relative to the prior-year quarter delivered earnings of $983 million, or $2.50 per diluted common share, for the quarter, an increase of 28 percent from $765 million in the third quarter of 2010. Earnings for the first nine months of 2011 rose $1 billion from the comparable 2010 period to $3.3 billion, or $8.49 per diluted common share. Adjusted earnings for the quarter and first nine months of 2011, which exclude the impact of the U.K. tax rate increase and foreign currency benefits, were $1.2 billion and $3.5 billion, or $2.95 and $8.89 per diluted common share, respectively. For the comparable 2010 periods, adjusted earnings were $797 million and $2.3 billion, or $2.20 and $6.75 per diluted common share. Adjusted earnings is not a financial measure prepared in accordance with generally accepted accounting principles in the United States (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 “Results of Operations — Non-GAAP Measures — Adjusted Earnings” below.

Continued volatility in the commodity price environment reinforces the importance of our balanced portfolio approach. Our third-quarter results reflected the benefit of our product balance, as crude oil and liquids combined represented 50 percent of our third-quarter production but provided 78 percent of our $4.3 billion third-quarter oil and gas revenues. Crude oil drove 92 percent of this combined crude and liquids production and 96 percent of the related revenues. Dated Brent and sweet crude from the Gulf of Mexico continue to be priced at a significant premium to West Texas Intermediate (WTI)-based prices. As a result of our geographic balance, we are receiving these premium prices on approximately 75 percent of our crude oil production. The advantage of our geographic balance is also reflected in our 2011 natural gas revenues. Over one-third of our natural gas is produced outside of North America, where third-quarter prices averaged 33 percent higher than the comparable period in 2010.

We remain committed to our objective of maintaining a conservative capital structure and are on target to keep 2011 exploration and development capital spending within estimated operating cash flows. Consistent with prior quarters, we routinely review capital budgets and region allocations through a disciplined process of assessing internally-generated drilling prospects and opportunities for tactical land acquisitions, occasionally entering new venture areas that could enhance our portfolio. We also remain well-positioned to take advantage of potential acquisition opportunities that may materialize. Specifically, we exited the quarter with $586 million of cash and a debt-to-capitalization ratio of 20.5 percent, down from 25.0 percent at year-end 2010. In addition, as of September 30, 2011, we had access to $3.3 billion of available committed borrowing capacity.

Key financial measures of our performance for the third quarter and first nine months of 2011 are summarized below:

	•		Average third-quarter 2011 production of 752 thousand barrels of oil equivalent per day (Mboe/d) set a new record for the Company and represents an increase of 13 percent from third-quarter 2010;

	•		Net cash provided by operating activities totaled $2.4 billion for the third quarter of 2011, up 43 percent from $1.7 billion in the prior-year period, and totaled $7.2 billion for the 2011 nine-month period compared to $4.8 billion in 2010;

	•		Oil and gas capital expenditures totaled $6.1 billion in the first nine months of 2011, in line with the current $8.0 billion budgeted for the full year;

	•		Third-quarter 2011 oil and gas production revenues increased 41 percent from the prior-year quarter to $4.3 billion, while year-to-date 2011 oil and gas production revenues increased 44 percent to $12.5 billion from the comparable prior-year period;

	•		Pre-tax margin in the third quarter of 2011 was $30.26 per barrel of oil equivalent (boe), up 39 percent from the comparable 2010 period. Pre-tax margin year-to-date 2011 was $30.27 per boe, up 33 percent from the comparable 2010 period. Pre-tax margin is calculated as income before income taxes divided by boe; and

	•		Annualized after-tax return on average capital employed during the third quarter and first nine months of 2011 was 12 percent and 13 percent, respectively.

Please refer to “Results of Operations” below for a more detailed discussion of revenue and cost components.

Operating Highlights

Apache has a significant producing asset base as well as large undeveloped acreage positions, which provide capacity for continued growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. We also continue to advance several multi-year development projects. Our cash flows enable us to optimize both endeavors. Notable operating highlights for the third quarter of 2011 include:

United States

•

The Company’s deepwater region was recently awarded its first Apache-operated exploration permit located in the Atwater Valley blocks 76 and 120. The lease was acquired by Mariner in early 2010. During the quarter the Company was also awarded deepwater exploration permits in the Green Canyon block 861 and South Timbalier block 318.

Canada

•

In October Apache and its partners in the Kitimat liquefied natural gas (LNG) project announced that the National Energy Board granted the project a 20-year export license to ship LNG from Canada to international markets. This export approval represents a major milestone for Kitimat LNG and its partners. In addition, the Company progressed with the front-end engineering and design (FEED) study and continued efforts to secure firm sales commitments and required permits necessary to make a final investment decision on the LNG project in 2012.

Egypt

•

During the quarter the Company announced the results from two new wells in Egypt’s Western Desert that tested in aggregate over 15,000 barrels of oil per day (b/d) and 1.5 million cubic feet of natural gas per day (MMcf/d). These wells signal continued drilling success in the Faghur basin and on concessions acquired from BP in 2010. In 2011 Apache has drilled 13 exploration wells in the Faghur basin, resulting in 11 new field discoveries. We have also drilled 11 successful wells in the Abu Gharadig field. The Company is continuing to assess opportunities to leverage existing processing and transportation infrastructure to maximize efficiency at the BP-acquired Abu Gharadig field complex and across the Faghur basin.

Australia

	•		In the third quarter of 2011 Apache announced that the Company and its partners will proceed with the Chevron-operated Wheatstone LNG hub (Wheatstone) in Western Australia. The first phase of the project will comprise two LNG processing trains with a combined capacity of approximately 8.9 million tons per annum (mtpa), a domestic gas plant and associated infrastructure. Apache has a 13-percent interest in the project and expects to invest approximately $4 billion over five years for the field and LNG facility development. Apache will supply gas to Wheatstone from its Julimar and Brunello complex, which was approved for development by the Australian government in September 2011.

	•		In the third quarter of 2011 Apache and its partners also signed long-term agreements with Tokyo Electric Power Company (TEPCO) and Kyushu Electric Power Company, Inc. (Kyushu Electric) for the delivery of LNG from Wheatstone. Under the agreements, Apache and its partners agreed to supply TEPCO and Kyushu Electric with a combined 3.8 mtpa of LNG for up to 20 years. Through its 13-percent share in Wheatstone, Apache will supply approximately 0.55 mtpa annually to TEPCO and Kyushu Electric from its natural gas produced from the Julimar and Brunello complex.

	•		In the third quarter of 2011 Apache announced that it will proceed with development of the offshore Balnaves oil field in Western Australia through a leased floating production storage and offloading (FPSO) vessel. The project is expected to deliver initial production of 30,000 b/d in 2014. Apache has a 65-percent working interest in the project.

North Sea

•

On September 21, Apache announced an agreement to acquire Exxon Mobil Corporation’s Mobil North Sea LLC assets for $1.75 billion. The acquired assets include operated interests in the Beryl field and related properties, infrastructure, and exploration acreage. The fields have current net production of approximately 19,000 b/d and 58 MMcf/d. At year-end 2010, estimated proved reserves totaled 68 million barrels of oil equivalent. The transaction is projected to close by year-end 2011.

•

On April 8, 2011, BP Exploration Operating Company Limited (BP Exploration) sent a letter to Apache North Sea Limited alleging the potential for capacity constraints or increased tariffs relating to the Shippers Pipeline Liquids Transportation and Processing Agreement, dated January 11, 2003, between BP Exploration and Apache North Sea Limited. Apache North Sea Limited disagrees with the characterizations in the letter and will contest them vigorously; however, because this matter is unresolved, resolution of this matter, through litigation or otherwise, and/or forced renegotiation or modification of our existing contract with BP Exploration could, in the future, adversely affect our production and revenues from the Forties Field in the North Sea.

Argentina

•

During the third quarter of 2011 Apache continued to progress on several exploration wells in the Neuquén and Cuyo basins, including completion of the first horizontal shale gas well drilled and completed in South America. We also continued an active Gas Plus drilling program, completing five wells in the Neuquén basin with a combined gross rate of 23.4 MMcf/d and 1 thousand barrels of oil per day (Mb/d). During the third quarter, the average Gas Plus volume sold by Apache was 77.4 MMcf/d at an average price of $4.97 per thousand feet of natural gas (Mcf).

Other International

•

In the third quarter of 2011 we entered into a farm-in agreement with TAG Oil Ltd. (TAG) to explore and potentially develop oil and natural gas resources in the East Coast basin of New Zealand. TAG’s exploration permits comprise in excess of 1.7 million acres of onshore oil and gas opportunities. Apache has agreed to conduct a multi-phased program over the next four years, with seismic operations starting in 2011 and drilling commencing in 2012. Apache will earn a 50-percent interest in the permits upon completion of the program.

Results of Operations

Oil and Gas Revenues


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2011				2010				2011				2010
	$		%		$		%		$		%		$		%
	Value		Contribution		Value		Contribution		Value		Contribution		Value		Contribution
	($ in millions)
Total Oil Revenues:
United States	$	1,040		33%	$	663		29%	$	3,008		32%	$	1,861		29%
Canada		105		3%		88		4%		355		4%		279		4%

North America		1,145		36%		751		33%		3,363		36%		2,140		33%

Egypt		1,054		33%		697		30%		3,149		34%		2,004		31%
Australia		411		12%		391		17%		1,167		12%		985		15%
North Sea		542		17%		406		18%		1,535		16%		1,211		19%
Argentina		60		2%		52		2%		170		2%		152		2%

International		2,067		64%		1,546		67%		6,021		64%		4,352		67%

Total⁽¹⁾	$	3,212		100%	$	2,297		100%	$	9,384		100%	$	6,492		100%


Total Gas Revenues:
United States	$	399		43%	$	346		50%	$	1,185		43%	$	1,026		50%
Canada		256		28%		136		20%		792		29%		425		21%

North America		655		71%		482		70%		1,977		72%		1,451		71%

Egypt		159		17%		125		18%		464		17%		365		18%
Australia		50		5%		40		6%		136		5%		123		6%
North Sea		5		1%		4		1%		14		1%		11		1%
Argentina		57		6%		33		5%		147		5%		95		4%

International		271		29%		202		30%		761		28%		594		29%

Total⁽²⁾	$	926		100%	$	684		100%	$	2,738		100%	$	2,045		100%


Natural Gas Liquids (NGL)
Revenues:
United States	$	109		75%	$	52		78%	$	292		74%	$	128		74%
Canada		27		19%		7		11%		76		19%		19		11%

North America		136		94%		59		89%		368		93%		147		85%

Egypt		1		1%		—		—		2		1%		—		—
Argentina		7		5%		7		11%		23		6%		25		15%

International		8		6%		7		11%		25		7%		25		15%

Total	$	144		100%	$	66		100%	$	393		100%	$	172		100%


Total Oil and Gas Revenues:
United States	$	1,548		36%	$	1,061		35%	$	4,485		36%	$	3,015		35%
Canada		388		9%		231		7%		1,223		10%		723		8%

North America		1,936		45%		1,292		42%		5,708		46%		3,738		43%

Egypt		1,214		28%		822		27%		3,615		29%		2,369		27%
Australia		461		11%		431		14%		1,303		10%		1,108		13%
North Sea		547		13%		410		14%		1,549		12%		1,222		14%
Argentina		124		3%		92		3%		340		3%		272		3%

International		2,346		55%		1,755		58%		6,807		54%		4,971		57%

Total	$	4,282		100%	$	3,047		100%	$	12,515		100%	$	8,709		100%


⁽¹⁾		Financial derivative hedging activities and the North Sea fixed-price sales contract decreased oil revenues $82 million and $301 million for the 2011 third quarter and nine-month period, respectively, and $6 million and $33 million for the comparative 2010 periods.

⁽²⁾		Financial derivative hedging activities increased natural gas revenues $65 million and $190 million for the 2011 third quarter and nine-month period, respectively, and $59 million and $137 million for the comparative 2010 periods.

Production


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
						Increase							Increase
	2011			2010		(Decrease)			2011		2010		(Decrease)
Oil Volume — b/d:
United States		120,353			97,824		23	%		117,135		92,069		27	%
Canada		13,027			13,868		(6)	%		14,040		14,252		(1)	%

North America		133,380			111,692		19	%		131,175		106,321		23	%

Egypt		103,289			99,818		3	%		103,913		96,387		8	%
Australia		39,400			56,876		(31)	%		38,248		48,324		(21)	%
North Sea		57,838			58,764		(2)	%		54,097		58,254		(7)	%
Argentina		9,461			9,645		(2)	%		9,577		9,812		(2)	%

International		209,988			225,103		(7)	%		205,835		212,777		(3)	%

Total⁽¹⁾		343,368			336,795		2	%		337,010		319,098		6	%


Natural Gas Volume — Mcf/d:
United States		857,993			736,523		16	%		865,474		694,646		25	%
Canada		619,897			334,945		85	%		633,031		329,443		92	%

North America		1,477,890			1,071,468		38	%		1,498,505		1,024,089		46	%

Egypt		376,259			380,598		(1)	%		368,898		377,051		(2)	%
Australia		187,852			197,090		(5)	%		183,470		202,473		(9)	%
North Sea		2,497			2,372		5	%		2,257		2,483		(9)	%
Argentina		223,929			202,381		11	%		209,206		180,219		16	%

International		790,537			782,441		1	%		763,831		762,226		1	%

Total⁽²⁾		2,268,427			1,853,909		22	%		2,262,336		1,786,315		27	%


Natural Gas Liquids (NGL) Volume — b/d:
United States		21,919			16,499		33	%		21,001		11,776		78	%
Canada		6,120			2,134		187	%		6,220		1,956		218	%

North America		28,039			18,633		50	%		27,221		13,732		98	%

Egypt		(4	)		—	NM				66		—	NM
North Sea		14			—	NM				5		—	NM
Argentina		3,008			3,047		(1)	%		3,024		3,151		(4)	%

International		3,018			3,047		(1)	%		3,095		3,151		(2)	%

Total		31,057			21,680		43	%		30,316		16,883		80	%


BOE per day⁽³⁾
United States		285,271			237,076		20	%		282,381		219,619		29	%
Canada		122,463			71,827		70	%		125,765		71,115		77	%

North America		407,734			308,903		32	%		408,146		290,734		40	%

Egypt		165,995			163,251		2	%		165,461		159,228		4	%
Australia		70,708			89,724		(21)	%		68,826		82,070		(16)	%
North Sea		58,269			59,159		(2)	%		54,478		58,668		(7)	%
Argentina		49,790			46,423		7	%		47,471		43,000		10	%

International		344,762			358,557		(4)	%		336,236		342,966		(2)	%

Total		752,496			667,460		13	%		744,382		633,700		17	%


⁽¹⁾		Approximately 28 and 29 percent of worldwide oil production was subject to financial derivative hedges for the third quarter and nine-month period of 2011, respectively, and 11 percent for the comparative 2010 periods.

⁽²⁾		Approximately 15 and 16 percent of worldwide natural gas production was subject to financial derivative hedges for the third quarter and nine-month period of 2011, respectively, and 23 and 24 percent for the comparative 2010 periods.

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

Pricing


	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
					Increase							Increase
	2011		2010		(Decrease)			2011		2010		(Decrease)
Average Oil Price — Per barrel:
United States	$	93.86	$	73.67		27	%	$	94.05	$	74.05		27	%
Canada		88.34		69.01		28	%		92.77		71.76		29	%
North America		93.32		73.09		28	%		93.91		73.74		27	%
Egypt		110.96		75.91		46	%		111.02		76.15		46	%
Australia		113.40		74.80		52	%		111.78		74.66		50	%
North Sea		101.85		75.25		35	%		103.90		76.13		36	%
Argentina		69.27		57.31		21	%		65.08		56.84		14	%
International		107.03		74.66		43	%		107.15		74.91		43	%
Total⁽¹⁾		101.71		74.14		37	%		102.00		74.52		37	%

Average Natural Gas Price — Per Mcf:
United States	$	5.06	$	5.10		(1)	%	$	5.02	$	5.41		(7)	%
Canada		4.49		4.42		2	%		4.58		4.72		(3)	%
North America		4.82		4.89		(1)	%		4.83		5.19		(7)	%
Egypt		4.60		3.57		29	%		4.61		3.55		30	%
Australia		2.88		2.20		31	%		2.71		2.21		23	%
North Sea		21.43		16.54		30	%		22.87		17.35		32	%
Argentina		2.74		1.79		53	%		2.57		1.93		33	%
International		3.71		2.80		33	%		3.65		2.86		28	%
Total⁽²⁾		4.44		4.01		11	%		4.43		4.19		6	%

Average NGL Price — Per barrel:
United States	$	54.36	$	34.11		59	%	$	51.03	$	39.66		29	%
Canada		46.93		34.18		37	%		44.47		36.58		22	%
North America		52.74		34.12		55	%		49.53		39.22		26	%
Egypt		33.62		—	NM				66.37		—	NM
North Sea		65.45		—	NM				65.45		—	NM
Argentina		26.45		26.39		0	%		28.20		28.98		(3)	%
International		26.62		26.39		1	%		29.06		28.98		0	%
Total		50.20		33.03		52	%		47.44		37.31		27	%


⁽¹⁾		Reflects a per-barrel decrease of $2.58 and $3.27 from derivative activities and the North Sea fixed-price sales contract for the 2011 third quarter and nine-month period, respectively, and a decrease of $.20 and $.37 from derivative activities for the comparative 2010 periods.

⁽²⁾		Reflects a per-Mcf increase of $.31 from derivative activities for the 2011 third quarter and nine-month period, and an increase of $.35 and $.28 from derivative activities for the comparative 2010 periods.

Third-Quarter 2011 compared to Third-Quarter 2010

Crude Oil RevenuesCrude oil revenues for the third quarter of 2011 totaled $3.2 billion, $915 million higher than the comparative 2010 quarter, primarily the result of a 37-percent increase in average realized prices. Crude oil accounted for 75 percent of oil and gas production revenues and 46 percent of worldwide production in the third quarter of 2011. Higher realized prices added $854 million to the increase in revenues between the periods, while higher production volumes contributed an additional $61 million.

Crude oil prices realized in the third quarter of 2011 averaged $101.71 per barrel, compared with $74.14 per barrel in the comparative prior-year quarter. Our international regions’ crude oil realizations averaged $107.03 per barrel, an increase of 43 percent compared with third-quarter 2010 realizations of $74.66 per barrel. Our Egypt, Australia and North Sea regions, which comprise over 58 percent of our worldwide oil production, continue to benefit from wide Dated Brent premiums to U.S. WTI-based prices, with third-quarter 2011 oil realizations averaging $108.81 per barrel compared with third-quarter 2010 realizations of $75.44 per barrel.

Worldwide production increased 7 Mb/d from the third quarter of 2010 to 343 Mb/d in the third quarter of 2011, primarily a result of a 23 Mb/d increase in U.S. production on acquisitions and increased drilling activity. The Permian region was up 12 Mb/d on properties added from the BP acquisition and the Mariner merger and on increased drilling activity. The Gulf of Mexico (GOM) onshore and offshore regions added 6 Mb/d, reflecting properties acquired in the Mariner merger; however, natural decline negatively impacted results, as new drilling continues to be impacted by the slow pace of permitting in the GOM. Egypt’s gross oil production increased 16 percent from increased infrastructure capacity, a successful drilling and recompletion program, and volumes acquired in the BP acquisition. Egypt’s net production, however, was up only three percent as higher oil prices impact our cost recovery volumes. Australia’s production decreased 17 Mb/d as a result of natural decline.

Natural Gas RevenuesNatural gas revenues for the third quarter of 2011 totaled $926 million, up 36 percent from the third quarter of 2010. A 22-percent increase in average production added $170 million to natural gas revenues, while an 11-percent rise in average realized prices contributed an additional $73 million. Natural gas accounted for 22 percent of our oil and gas production revenues and 50 percent of our equivalent production in the third quarter of 2011. All of our international regions, which comprise approximately one-third of total gas production, benefited from higher realized prices.

Worldwide production grew 415 MMcf/d between the periods on production increases in Canada, the U.S., and Argentina. Daily production in Canada increased 85 percent, up 285 MMcf/d on additional volumes from properties acquired from BP and an active drilling and completion program. U.S. daily production increased 121 MMcf/d, primarily a result of acquisition activity in 2010. Permian region production rose 64 MMcf/d on incremental volumes from properties added from the BP acquisition and the Mariner merger and on increased drilling activity. The GOM onshore and offshore regions added 53 MMcf/d from properties acquired in the Mariner merger, offset by natural decline, as new drilling continues to be impacted by the slow pace of permitting in the GOM. Argentina’s production was up 22 MMcf/d from recompletions and new drilling, primarily associated with the country’s Gas Plus program. Egypt’s gross production was up 89 MMcf/d on a successful drilling program and production from properties added in the BP acquisition. Net production was down one percent, as higher commodity prices impacted our cost recovery volumes. Australia’s daily gas production fell 9 MMcf/d as customer maintenance activities resulted in lower takes under existing contractual arrangements.

Year-to-Date 2011 compared to Year-to-Date 2010

Crude Oil RevenuesCrude oil revenues for the first nine months of 2011 totaled $9.4 billion, nearly $2.9 billion higher than the comparative 2010 period, the result of a 37-percent increase in average realized prices and a six-percent increase in worldwide production. Crude oil accounted for 75 percent of oil and gas production revenues and 45 percent of worldwide production, compared with 75 percent and 50 percent, respectively, in the 2010 period. Higher realized prices added $2.4 billion to the increase in revenues, while higher production volumes contributed an additional $499 million.

Crude oil prices realized in the first nine months of 2011 averaged $102.00 per barrel, compared with $74.52 per barrel in the comparative prior-year period. Our international regions’ crude oil realizations averaged $107.15 per barrel, an increase of 43 percent compared with 2010-period realizations of $74.91 per barrel. Our Egypt, Australia and North Sea regions, which comprise approximately 58 percent of our worldwide oil production, continue to benefit from wide Dated Brent premiums to U.S. WTI-based prices, with oil realizations averaging $109.21 per barrel compared with realizations of $75.79 per barrel in the 2010 period.

Worldwide production increased 18 Mb/d from the prior-year period to 337 Mb/d in the first nine months of 2011, driven by increased production in the U.S. and Egypt. The 25 Mb/d increase in U.S. oil production is primarily a result of 2010 acquisitions and increased drilling activity. The Permian region was up 13 Mb/d on properties added from the BP acquisition and the Mariner merger, offset by natural decline and weather-related shut-ins. The GOM onshore and offshore regions added nine Mb/d reflecting properties acquired in the Devon acquisition and the Mariner merger; however, natural decline negatively impacted results, as new drilling has been impacted by the slow pace of permitting in the GOM. Egypt’s gross oil production increased 19 percent, while net production was up eight percent, as higher oil prices impacted our cost recovery volumes. The production increase was a result of additional capacity provided by the Kalabsha oil processing facility, production from properties added in the BP acquisition and an active drilling program. Australia saw production decrease 10 Mb/d as a result of repairs to the Van Gogh FPSO vessel, natural decline and tropical cyclones in the first quarter of 2011. Production decreased 4 Mb/d in the North Sea on natural decline, planned maintenance and downtime related to a shut-in intra-field pipeline. An existing pipeline was converted to oil service for temporary use until the permanent replacement line was completed in the third quarter of 2011.

Natural Gas RevenuesNatural gas revenues for the first nine months of 2011 totaled $2.7 billion, up 34 percent from the comparative 2010 period. A 27-percent increase in average production added $576 million to natural gas revenues, while a six-percent increase in average realized prices contributed an additional $117 million. Natural gas accounted for 22 percent of our oil and gas production revenues and 51 percent of our equivalent production, compared to 23 and 47 percent, respectively, for the 2010 period. All of our international regions, which comprise approximately one-third of total gas production, benefited from higher realized prices.

Worldwide production grew 476 MMcf/d between the periods on production increases in Canada, the U.S., and Argentina. Daily production in Canada almost doubled, rising 304 MMcf/d on additional volumes from properties acquired from BP and an active drilling and completion program. U.S. daily production increased 171 MMcf/d, primarily as a result of acquisition activity in 2010. Permian region production rose 70 MMcf/d on incremental volumes from properties added from the BP acquisition and the Mariner merger and on increased drilling activity. Frigid weather in the region during the first quarter of 2011 tempered production gains. The GOM onshore and offshore regions added 85 MMcf/d from properties acquired in the Devon acquisition and the Mariner merger, offset by natural decline, as new drilling has been impacted by the slow pace of permitting in the GOM. Argentina’s production was up 29 MMcf/d from new drilling and recompletions. Australia’s daily gas production fell 19 MMcf/d on downtime from tropical cyclones and customer maintenance activities resulting in lower takes under our existing contractual arrangements. Egypt’s gross production was up ten percent on a successful drilling program, additional gas throughput at the Obaiyed Gas Plant and production from properties added in the BP acquisition. Net production was down two percent, as higher prices impacted our cost recovery volumes.

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								For the Nine Months Ended
	September 30,								September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
	(In millions)				(Per boe)				(In millions)				(Per boe)
Depreciation, depletion and amortization:
Oil and gas property	$	993	$	731	$	14.36	$	11.90	$	2,823	$	1,994	$	13.90	$	11.52
Other assets		72		56		1.04		0.90		207		161		1.02		0.93
Asset retirement obligation accretion		39		25		0.57		0.40		114		74		0.56		0.43
Lease operating costs		661		507		9.54		8.25		1,946		1,393		9.57		8.05
Gathering and transportation costs		72		43		1.02		0.70		221		126		1.09		0.73
Taxes other than income		244		158		3.53		2.58		663		522		3.26		3.02
General and administrative expense		112		89		1.61		1.45		327		260		1.61		1.50
Merger, acquisitions & transition		4		8		0.05		0.13		15		16		0.07		0.09
Financing costs, net		37		59		0.54		0.97		123		174		0.60		1.01


Total	$	2,234	$	1,676	$	32.26	$	27.28	$	6,439	$	4,720	$	31.68	$	27.28

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 2011 and 2010:


	For the		For the Nine
	Quarter		Months
	Ended		Ended
	September 30		September 30
	(In millions)		(In millions)
2010 DD&A	$	731	$	1,994
Volume change		75		293
Rate change		167		490
Other		20		46

2011 DD&A	$	993	$	2,823

For the third quarter of 2011 oil and gas property DD&A expense of $993 million increased $262 million on an absolute dollar basis from the comparable prior-year period: $167 million on rate, $75 million from higher volumes and $20 million associated with new venture seismic activity in countries where Apache has no established presence. The Company’s oil and gas property DD&A rate increased $2.46 to $14.36 per boe, reflecting acquisition and drilling costs that exceed our historical basis.

For the first nine months of 2011 oil and gas property DD&A expense of $2.8 billion increased $829 million on an absolute dollar basis from the comparable prior-year period: $490 million on rate, $293 million from higher volumes and $46 million associated with new venture seismic activity in countries where Apache has no established presence. The Company’s oil and gas property DD&A rate increased $2.38 to $13.90 per boe, reflecting acquisition and drilling costs that exceed our historical basis.

Lease Operating Expenses (LOE)LOE increased $154 million, or 30 percent, and $553 million, or 40 percent, on an absolute dollar basis for the quarter and nine-month period ended September 30, 2011, compared to the comparable periods of 2010. On a per-unit basis, LOE increased 16 percent to $9.54 per boe for the third quarter of 2011, as compared to the same prior-year period, and 19 percent to $9.57 per boe for the first nine months of 2011, as compared to the prior-year nine-month period. The following table identifies changes in Apache’s LOE rate between the third quarters and nine-month periods of 2010 and 2011.


For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	Per boe				Per boe
2010 LOE	$	8.25		2010 LOE	$	8.05
Acquisitions⁽¹⁾		(0.16	)	Acquisitions⁽¹⁾		0.13
FX impact		0.31		FX impact		0.32
Chemicals, power and fuel		0.25		Workover costs		0.24
Labor and overhead		0.16		Labor and overhead		0.22
Workover costs		0.14		Chemicals, power and fuel		0.22
Non-operated costs		0.14		Transportation		0.11
Other		0.07		Repairs and maintenance		0.08
Decreased production, excluding acquisitions		0.38		Other		0.17
				Decreased production, excluding acquisitions		0.03


2011 LOE	$	9.54		2011 LOE	$	9.57


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

Gathering and TransportationGathering and transportation costs were up $29 million and $95 million in the third quarter and first nine months of 2011, respectively. On a per-unit basis, gathering and transportation costs of $1.02 and $1.09 for the third quarter and first nine months of 2011 were up 46 percent and 49 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				For the Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(In millions)				(In millions)
Canada	$	39	$	18	$	125	$	50
U.S.		17		11		47		32
Egypt		7		6		25		21
North Sea		7		7		19		19
Argentina		2		1		5		4


Total Gathering and Transportation	$	72	$	43	$	221	$	126

For the three- and nine-month periods ended September 30, 2011, Canada’s expense increased $21 million and $75 million, respectively, from a combination of an increase in gas volumes, higher average rates and foreign exchange impacts. Average per-unit costs were directly influenced by Apache’s increased production in Canada’s Horn River basin and properties acquired during 2010, where the associated gathering, processing and transportation contracts have higher average rates than Apache’s legacy properties. The increases in the U.S. are directly related to increased volumes. Egypt’s costs were up on a higher number of oil sales cargoes and higher vessel freight costs.

Taxes Other than IncomeTaxes other than income totaled $244 million and $663 million for the third quarter and first nine months of 2011, an increase of $86 million and $141 million, respectively, from the comparative prior-year periods. The following table presents a comparison of these expenses:


	For the Quarter Ended				For the Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(In millions)				(In millions)
U.K. PRT	$	149	$	94	$	386	$	346
Severance taxes		54		33		159		93
Ad valorem taxes		25		19		78		54
Canadian taxes		3		3		12		4
Other		13		9		28		25


Total Taxes other than Income	$	244	$	158	$	663	$	522

The North Sea Petroleum Revenue Tax (PRT) is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties and Nelson fields in the U.K. North Sea. U.K. PRT increased $55 million and $40 million for the third quarter and first nine months of 2011, respectively, over the comparable 2010 periods as a result of 56-percent and 12-percent respective increases in net receipts, primarily driven by higher revenues. Prior-year property acquisitions and higher realized oil and gas prices resulted in increases to severance and ad valorem tax expense. Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. Ad valorem taxes are assessed on U.S. and Canadian property values and sales.

General and Administrative ExpensesGeneral and administrative expenses (G&A) for the third quarter and first nine months of 2011 were $23 million and $67 million higher than the comparative prior-year periods on an absolute basis, driven by increases in insurance costs and various other corporate expenses resulting from the 2010 acquisitions. Per-unit G&A increased $.16 and $.11 to an average of $1.61 in both the quarter and nine-month periods, with the impact of higher production partially offsetting the impact of higher costs.

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


	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In millions)						(In millions)
Interest expense	$	109		$	86		$	326		$	237
Amortization of deferred loan costs		1			7			4			10
Capitalized interest		(69	)		(29	)		(193	)		(64	)
Interest income		(4	)		(5	)		(14	)		(9	)


Financing costs, net	$	37		$	59		$	123		$	174

Net financing costs were down $22 million and $51 million in the third quarter and first nine months of 2011, respectively, from the comparative prior-year periods. The decrease is primarily related to increases in capitalized interest, the result of additional unproved balances from the BP acquisitions and the Mariner merger. This decrease is partially offset by higher interest expense associated with $2.5 billion of debt issued in the second half of 2010.

Provision for Income TaxesThe Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which Apache operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

The 2011 third-quarter provision for income taxes increased $533 million to $1.1 billion on a 57-percent increase in income before income taxes and a 52-percent effective income tax rate, up from an effective rate of 42 percent in the third-quarter 2010 as a result of the U.K. tax rate increase. The provision for income taxes for the first nine months of 2011 increased $1.2 billion to $2.8 billion on a 56-percent increase in income before income taxes and a 45-percent effective income tax rate compared to an effective rate of 41 percent in the first nine months of 2010.

Non-GAAP Measures

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

Adjusted Earnings

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


	For the Quarter					For the Nine Months
	Ended September 30,					Ended September 30,
	2011			2010		2011			2010
	(In millions, except per share data)
Income Attributable to Common Stock (GAAP)	$	983		$	765	$	3,338		$	2,330

Adjustments:
U.K. tax rate increase		274			—		218			—
Foreign currency fluctuation impact on deferred tax expense		(99	)		27		(68	)		2
Merger, acquisitions & transition, net of tax		2			5		9			10

Adjusted Earnings (Non-GAAP)	$	1,160		$	797	$	3,497		$	2,342


Net Income per Common Share — Diluted (GAAP)	$	2.50		$	2.12	$	8.49		$	6.72

Adjustments:
U.K. tax rate increase		.69			—		.55			—
Foreign currency fluctuation impact on deferred tax expense		(.25	)		.07		(.17	)		—
Merger, acquisitions & transition, net of tax		.01			.01		.02			.03

Adjusted Earnings Per Share — Diluted (Non-GAAP)	$	2.95		$	2.20	$	8.89		$	6.75

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. Apache’s 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, but these historically have not been as volatile or as impactive as 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. Our business, as with other extractive industries, is a depleting one in which each unit produced must be replaced or the Company and its reserves, a critical source of future liquidity, will shrink. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities and our ability to acquire additional reserves at reasonable costs.

Apache’s primary uses of cash are for exploration, development and acquisition of oil and gas properties, costs necessary to maintain ongoing operations, repayment of principal and interest on outstanding debt and payment of dividends. We fund our exploration and development activities primarily through operating cash flows.

We may also elect to utilize available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets to meet our capital requirements. We believe these sources, combined with operating cash flows, will be adequate to fund our operations, capital spending, the repayment of debt and any amounts that may be paid in connection with contingencies.

See Part II, Item 1A, “Risk Factors” of this Form 10-Q and Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors Related to Our Business and Operations,” in Apache’s Amended Annual Report on Form 10-K/A for its 2010 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,
	2011		2010
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	7,171	$	4,800
Fixed-rate borrowings		—		1,484
Proceeds from issuance of common stock		—		2,258
Proceeds from issuance of mandatory convertible preferred stock		—		1,227
Sale of oil and gas properties		202		—
Common and treasury stock activity		51		33
Other		28		23

		7,452		9,825


Uses of Cash and Cash Equivalents:
Capital expenditures⁽¹⁾	$	5,230	$	3,369
Oil and gas acquisitions		509		3,550
Deposit related to acquisition of BP properties		—		3,500
Commercial paper, credit facility and bank note repayments, net		940		37
Dividends		230		152
Other		91		54

		7,000		10,662


Increase (decrease) in cash and cash equivalents	$	452	$	(837	)


		⁽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 ActivitiesCash 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 2011 totaled $7.2 billion, up $2.4 billion from the first nine months of 2010. The increase reflects the impact of higher oil and gas revenues (up $3.8 billion), with higher commodity prices contributing $2.6 billion, and a 17-percent increase in daily equivalent production adding another $1.2 billion. This increase was partially offset by higher income tax payments in the first nine months of 2011 as compared to the 2010 period.

For a detailed discussion of commodity prices, production, costs and expenses, see “Results of Operations” below. 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 PropertiesIn the first nine months of 2011 Apache completed the sale of certain properties in Canada and the U.S. for $202 million. While we intend to divest additional non-strategic assets, given strong oil prices and higher than expected cash flows, we intend to sell fewer assets than originally planned at year-end 2010.

Capital ExpendituresWe fund exploration and development (E&D) activities primarily through operating cash flows and budget capital expenditures based on projected cash flows. The Company remains determined to not outspend operating cash flows, and we review our capital budget accordingly on a quarterly basis. In response to higher realized commodity prices, in the second quarter of 2011, we reassessed our capital expenditure budget for 2011 and raised our plan from $7.5 billion to $8.0 billion.


	For the Nine Months Ended
	September 30,
	2011		2010
	(In millions)
E&D Costs:
United States	$	1,976	$	1,039
Canada		609		593

North America		2,585		1,632


Egypt		674		510
Australia		445		401
North Sea		618		437
Argentina		245		167
Chile		1		20
Other International		48		—

International		2,031		1,535

Worldwide E&D Costs		4,616		3,167


Gathering Transmission and Processing Facilities (GTP):
United States		9		—
Canada		113		107
Egypt		74		111
Australia		255		102
Argentina		7		2

Total GTP Costs		458		322

Asset Retirement Costs		288		198

Capitalized Interest		193		64


Capital Expenditures, excluding acquisitions		5,555		3,751

Acquisitions — Oil and Gas Properties		493		3,550

Asset Retirement Costs — Acquired		75		245


Total Capital Expenditures	$	6,123	$	7,546

Worldwide E&D expenditures for the first nine months of 2011 totaled $4.6 billion, or 46 percent above spending in the first nine months of 2010. E&D spending in North America, which was up 58 percent as compared to the first nine months of 2010, totaled 56 percent of worldwide E&D spending. U.S. E&D expenditures were up 90 percent on increased activity in the Permian region, where we continue to aggressively pursue opportunities on our Mariner-acquired Deadwood acreage. Current period activity also includes expenditures on Mariner-acquired deepwater properties for ongoing field development activities at Mandy, Wideberth and Lucius. Our Central region’s active horizontal drilling program in the Granite Wash and Cherokee plays further contributed to our increase in expenditures. E&D spending in Canada increased three percent in the first nine months of 2011 to $609 million on an active drilling program targeting several liquids-rich gas opportunities, as well as an active completion program at Horn River.

E&D expenditures outside of North America increased 32 percent over first nine-month 2010 levels to $2.0 billion. E&D spending in the North Sea was up $181 million over the comparable period on the Forties field drilling program and the construction of the Forties Alpha satellite platform. Egypt expenditures were up $164 million, or 32 percent, in the first nine months of 2011 on continued drilling activity across all major basins, and Argentina was $78 million higher on additional drilling and development activity.

We invested $458 million in GTP in the first nine months of 2011 compared to $322 million in the comparative prior-year period. GTP expenditures in Australia were for construction activity at the Devil Creek and Macedon gas plants. Australia has also incurred costs related to the FEED study and purchases of long-lead time items for the Wheatstone LNG project. Activity in Canada was centered in the Horn River basin, with expenditures for gathering systems and a gas processing plant. GTP expenditures in Egypt primarily comprised final stages of construction on the Kalabsha oil processing facility.

During the first nine months of 2011 we closed on $493 million of oil and gas property acquisitions. In addition, we have agreed to purchase Exxon Mobil’s North Sea assets for $1.75 billion, which is projected to close by year-end 2011.

Repayment of Commercial Paper and Lines of CreditDuring the first nine months of 2011 Apache repaid $940 million on commercial paper and money market lines of credit that were outstanding at December 31, 2010.

DividendsFor the nine-month periods ended September 30, 2011 and 2010, the Company paid $173 million and $152 million, respectively, in dividends on its common stock. The Company also made dividend payments of $57 million on its Series D Preferred Stock in the first nine months of 2011. Dividends of $13 million were accrued on the Series D Preferred Stock in the third quarter of 2010 and paid in November 2010.

Liquidity

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


	September 30,		December 31,
	2011		2010
	(In millions of dollars, except as indicated)
Cash and cash equivalents	$	586	$	134
Total debt		7,202		8,141
Shareholders’ equity		27,903		24,377
Available committed borrowing capacity		3,300		2,387
Floating-rate debt/total debt		.2%		11.8%
Percent of total debt-to-capitalization		20.5%		25.0%

Cash and Cash EquivalentsWe had $586 million in cash and cash equivalents as of September 30, 2011, compared to $134 million at December 31, 2010. Approximately $548 million of the cash was held by foreign subsidiaries, with the remaining balance held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly-liquid investment grade securities with maturities of three months or less at the time of purchase.

DebtAs of September 30, 2011, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $7.2 billion. Current debt included $400 million 6.25-percent notes due within the next 12 months and $17 million borrowed under uncommitted overdraft lines in Argentina.

Available Committed Borrowing CapacityAs of September 30, 2011, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $2.3 billion matures in May 2013 and $1.0 billion matures in August 2016. These consist of a $1.5 billion facility, a $1.0 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. There was $3.3 billion of available borrowing capacity under the unsecured credit facilities at September 30, 2011.

On August 16, 2011, Apache entered into a $1.0 billion five-year syndicated revolving credit facility. The credit facility is subject to covenants, events of default and representations and warranties that are substantially similar to those in Apache’s other revolving credit facilities. It may be used for acquisitions and for general corporate purposes or to support the Company’s commercial paper program. Loans under the facility will bear interest at a base rate, as defined in the credit agreement, or at LIBOR plus a margin determined by the Company’s senior long-term debt rating.

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

The Company was in compliance with the terms of all credit facilities as of September 30, 2011.

Percent of Total Debt to CapitalizationThe Company’s September 30, 2011 debt-to-capitalization ratio was 20.5 percent, down from 25.0 percent at December 31, 2010.

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 dramatically since the first nine months of 2010, rising 37 percent to $102.00 per barrel in the first nine months of 2011 from $74.52 per barrel in the first nine months of 2010. Our average natural gas price realizations have also risen slightly, increasing six percent to $4.43 per Mcf in the 2011 nine-month period from $4.19 per Mcf in the prior-year period.

We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. For the third quarter and first nine months of 2011, our natural gas production was subject to financial derivative hedges of approximately 15 and 16 percent, respectively, and our crude oil production was subject to financial derivative hedges of approximately 28 and 29 percent, respectively.

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, 2011, the Company had open natural gas derivative hedges in an asset position with a fair value of $373 million. A 10-percent increase in natural gas prices would reduce the fair value by approximately $59 million, while a 10-percent decrease in prices would increase the fair value by approximately $58 million. The Company also had open crude oil derivatives in a liability position with a fair value of $49 million. A 10-percent increase in oil prices would increase the liability by approximately $179 million, while a 10-percent decrease in prices would move the derivatives to an asset position of $119 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2011. 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 99.8 percent of the Company’s debt. At September 30, 2011, total debt included $17 million of floating-rate debt. As a result, Apache’s annual interest costs will fluctuate based on short-term interest rates on less than one percent of our total debt outstanding at September 30, 2011. The impact on cash flow of a 10-percent change in the floating interest rate based on debt balances at September 30, 2011, would be approximately $59,000 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 the majority of our gas production is sold under fixed-price Australian dollar contracts. Approximately half of our costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil and gas prices and costs, such as equipment rentals and services, are generally denominated in Canadian dollars but heavily influenced by U.S. markets. Our North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars, but are converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, Egyptian pounds and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other,” or, as is the case when we remeasure our foreign tax liabilities, as a component of the Company’s provision for income taxes on the statement of consolidated operations in Item 1 of this Form 10-Q. A 10-percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, Egyptian pound and Argentine peso as of September 30, 2011, would result in a cumulative foreign currency net loss or gain, respectively, of approximately $119 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, 2010, 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,” “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 Mariner and the BP properties;

	•		increased scrutiny from regulatory agencies due to the BP 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;

	•		the significant transaction and acquisition costs related to the Mariner merger and BP property acquisitions;

	•		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;

	•		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 Apache’s Amended Annual Report on Form 10-K/A for its 2010 fiscal year, other risks and uncertainties in our third-quarter 2011 earnings release, and other filings that we make with the SEC.

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, 2011, 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 Apache’s Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010 (filed with the SEC on April 7, 2011) and Part I, Item 1 of this Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2011 for a description of material legal proceedings.

ITEM 1A.		RISK FACTORS

		During the quarter ending September 30, 2011, there were no material changes from the risk factors as previously disclosed in Apache’s Amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2010.

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

		None

ITEM 3.		DEFAULTS UPON SENIOR SECURITIES

		None

ITEM 4.		[REMOVED AND RESERVED]

ITEM 5.		OTHER INFORMATION

		None

ITEM 6. EXHIBITS


*10.1	—	Amendment to Apache Corporation 401(k) Savings Plan, dated August 31, 2011, effective September 1, 2011.

*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 8, 2011	/s/ THOMAS P. CHAMBERS
	Thomas P. Chambers
	Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Dated: November 8, 2011	/s/ REBECCA A. HOYT
	Rebecca A. Hoyt
	Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)

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