Apache 10-Q 2008 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the Quarterly Period Ended September 30, 2008

OR

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

For the Transition Period from                    to                    

Commission File Number 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	41-0747868
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Suite 100, One Post Oak Central
2000 Post Oak Boulevard, Houston, TX	77056-4400
(Address of principal executive offices)	(Zip Code)

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

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 September 30, 2008 334,670,227

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
	ITEM 1 — FINANCIAL STATEMENTS
	ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4 — CONTROLS AND PROCEDURES
PART II — OTHER INFORMATION
	ITEM 1. LEGAL PROCEEDINGS
	ITEM 1A. RISK FACTORS
	ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	ITEM 5. OTHER INFORMATION
	ITEM 6. EXHIBITS
SIGNATURES
EXHIBIT 10.1
EXHIBIT 10.2
EXHIBIT 10.3
EXHIBIT 10.4
EXHIBIT 10.5
EXHIBIT 10.6
EXHIBIT 10.7
EXHIBIT 10.8
EXHIBIT 10.9
EXHIBIT 12.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1

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,
	2008			2007		2008		2007
	(In thousands, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,368,882		$	2,498,594	$	10,450,949	$	6,965,692
Other		(3,998	)		6,364		1,867		14,685
		3,364,884			2,504,958		10,452,816		6,980,377
OPERATING EXPENSES:
Depreciation, depletion and amortization		600,887			600,796		1,849,044		1,722,816
Asset retirement obligation accretion		24,970			24,436		77,146		72,634
Lease operating expenses		488,166			409,528		1,389,542		1,198,302
Gathering and transportation		42,375			34,887		123,118		100,585
Taxes other than income		304,280			139,461		845,406		393,222
General and administrative		57,561			61,405		218,856		200,065
Financing costs, net		33,291			60,367		116,594		165,788
		1,551,530			1,330,880		4,619,706		3,853,412
INCOME BEFORE INCOME TAXES:		1,813,354			1,174,078		5,833,110		3,126,965
Current income tax provision		305,735			200,878		1,495,641		684,458
Deferred income tax provision		316,794			359,852		679,902		702,672
NET INCOME:		1,190,825			613,348		3,657,567		1,739,835
Preferred stock dividends		1,420			1,420		4,260		4,260
INCOME ATTRIBUTABLE TO COMMON STOCK:	$	1,189,405		$	611,928	$	3,653,307	$	1,735,575
NET INCOME PER COMMON SHARE:
Basic	$	3.55		$	1.84	$	10.93	$	5.23
Diluted	$	3.52		$	1.83	$	10.84	$	5.19

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

1

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

	For the Nine Months Ended
	September 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	3,657,567		$	1,739,835
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,849,044			1,722,816
Asset retirement obligation accretion		77,146			72,634
Provision for deferred income taxes		679,902			702,672
Unrealized loss on derivatives		35,586			—
Other		(11,231	)		39,502
Changes in operating assets and liabilities:
(Increase) decrease in receivables		251,920			(30,595	)
(Increase) decrease in drilling advances and other		27,891			(36,324	)
(Increase) decrease in inventories		(7,729	)		30,621
(Increase) decrease in deferred charges and other		(200,038	)		(53,464	)
Increase (decrease) in accounts payable		71,188			(12,799	)
Increase (decrease) in accrued expenses		(367,553	)		(231,327	)
Increase (decrease) in deferred credits and noncurrent liabilities		(35,125	)		(66,099	)
Net cash provided by operating activities		6,028,568			3,877,472
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,062,975	)		(3,405,682	)
Acquisition of U.S. Permian Basin properties		—			(1,004,581	)
Additions to gas gathering, transmission and processing facilities		(420,850	)		(301,226	)
Restricted cash		(13,844	)		—
Proceeds from sale of oil and gas properties		306,701			11,074
Other, net		(42,509	)		(131,780	)
Net cash used in investing activities		(4,233,477	)		(4,832,195	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and money market borrowings, net		(169,042	)		(947,989	)
Fixed-rate debt borrowings		—			1,992,027
Payments on fixed-rate debt		(353	)		(3,000	)
Dividends paid		(187,735	)		(153,421	)
Common stock activity		31,207			22,707
Treasury stock activity, net		4,171			12,474
Cost of debt and equity transactions		(1,224	)		(18,000	)
Other		46,666			20,823
Net cash provided by (used in) financing activities		(276,310	)		925,621
NET INCREASE IN CASH AND CASH EQUIVALENTS		1,518,781			(29,102	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		125,823			140,524
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,644,604		$	111,422
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	137,106		$	124,913
Income taxes paid, net of refunds		1,512,864			604,862

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

2

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)

	September 30,			December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,644,604		$	125,823
Receivables, net of allowance		1,680,031			1,936,977
Inventories		479,723			461,211
Drilling advances		83,444			112,840
Derivative instruments		12,929			20,889
Prepaid assets and other		271,561			94,511
		4,172,292			2,752,251
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full cost accounting:
Proved properties		38,673,437			34,645,710
Unproved properties and properties under development, not being amortized		1,698,471			1,439,726
Gas gathering, transmission and processing facilities		2,627,304			2,206,453
Other		441,339			416,149
		43,440,551			38,708,038
Less: Accumulated depreciation, depletion and amortization		(15,321,733	)		(13,476,445	)
		28,118,818			25,231,593
OTHER ASSETS:
Restricted cash		13,844			—
Goodwill, net		189,252			189,252
Deferred charges and other		498,226			461,555
	$	32,992,432		$	28,634,651

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

3

APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)

	September 30,			December 31,
	2008			2007
	(In thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	702,143		$	617,937
Accrued operating expense		110,036			112,453
Accrued exploration and development		787,129			600,165
Accrued compensation and benefits		129,998			172,542
Accrued interest		73,175			78,187
Accrued income taxes		137,157			73,184
Current debt		140,514			215,074
Asset retirement obligation		359,975			309,777
Derivative instruments		264,309			286,226
United Kingdom Petroleum Revenue Tax		153,805			117,028
Other		58,065			82,443
		2,916,306			2,665,016
LONG-TERM DEBT		3,917,327			4,011,605
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		4,512,418			3,924,983
Asset retirement obligation		1,462,309			1,556,909
Derivative instruments		681,782			381,791
Other		739,184			716,368
		7,395,693			6,580,051
COMMITMENTS AND CONTINGENCIES (Note 6)
SHAREHOLDERS’ EQUITY:
Preferred stock, no par value, 5,000,000 shares authorized — Series B, 5.68% Cumulative, $100 million aggregate liquidation value, 100,000 shares issued and outstanding		98,387			98,387
Common stock, $0.625 par, 430,000,000 shares authorized, 342,738,124 and 341,322,088 shares issued, respectively		214,211			213,326
Paid-in capital		4,445,511			4,367,149
Retained earnings		14,927,178			11,457,592
Treasury stock, at cost, 8,067,897 and 8,394,945 shares, respectively		(228,981	)		(238,264	)
Accumulated other comprehensive loss		(693,200	)		(520,211	)
		18,763,106			15,377,979
	$	32,992,432		$	28,634,651

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

4

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

																	Accumulated
				Series B													Other			Total
	Comprehensive			Preferred		Common		Paid-In			Retained			Treasury			Comprehensive			Shareholders’
	Income			Stock		Stock		Capital			Earnings			Stock			Income (Loss)			Equity
	(In thousands)
BALANCE AT DECEMBER 31, 2006				$	98,387	$	212,365	$	4,269,795		$	8,898,577		$	(256,739	)	$	(31,332	)	$	13,191,053
Comprehensive income (loss):
Net income	$	1,739,835			—		—		—			1,739,835			—			—			1,739,835
Commodity hedges, net of income tax expense of $82,848		(145,509	)		—		—		—			—			—			(145,509	)		(145,509	)
Comprehensive income	$	1,594,326
Dividends:
Preferred					—		—		—			(4,260	)		—			—			(4,260	)
Common ($.45 per share)					—		—		—			(149,433	)		—			—			(149,433	)
Common shares issued					—		834		38,154			—			—			—			38,988
Treasury shares issued, net					—		—		972			—			16,321			—			17,293
Compensation expense					—		—		34,571			—			—			—			34,571
FIN 48 Adoption					—		—		—			(48,502	)		—			—			(48,502	)
Other					—		—		(1,483	)		241			—			—			(1,242	)
BALANCE AT SEPTEMBER 30, 2007				$	98,387	$	213,199	$	4,342,009		$	10,436,458		$	(240,418	)	$	(176,841	)	$	14,672,794
BALANCE AT DECEMBER 31, 2007				$	98,387	$	213,326	$	4,367,149		$	11,457,592		$	(238,264	)	$	(520,211	)	$	15,377,979
Comprehensive income (loss):
Net income	$	3,657,567			—		—		—			3,657,567			—			—			3,657,567
Commodity hedges, net of income tax benefit of $89,376		(172,989	)		—		—		—			—			—			(172,989	)		(172,989	)
Comprehensive income	$	3,484,578
Dividends:
Preferred					—		—		—			(4,260	)		—			—			(4,260	)
Common ($.55 per share)					—		—		—			(183,735	)		—			—			(183,735	)
Common shares issued					—		885		36,109			—			—			—			36,994
Treasury shares issued, net					—		—		247			—			9,283			—			9,530
Compensation expense					—		—		65,645			—			—			—			65,645
FIN 48					—		—		(23,770	)					—			—			(23,770	)
Other					—		—		131			14			—			—			145
BALANCE AT SEPTEMBER 30, 2008				$	98,387	$	214,211	$	4,445,511		$	14,927,178		$	(228,981	)	$	(693,200	)	$	18,763,106

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

5

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), and reflect all adjustments which 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 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. These financial statements should be read in conjunction with the financial statements and the summary of significant accounting policies and notes included in the Company’s most recent annual report on Form 10-K.

Reclassifications

     Certain prior-period amounts have been reclassified to conform with current-year presentations.

1. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

     Cash Flow HedgesWe periodically use derivative instruments in connection with anticipated crude oil and natural gas sales to mitigate the variability of cash flows associated with commodity price fluctuations. While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices. We account for derivative instruments and hedging activities in accordance with Statement of Financial Accounting Standards (SFAS) 133 and typically elect to designate our commodity derivatives instruments as cash flow hedges. No new hedges were entered into during the third quarter of 2008.

     As of September 30, 2008, we had entered into the following crude oil derivative instruments:

	Fixed-Price Swaps				Call Options				Collars
			Weighted				Weighted				Weighted		Weighted
Production			Average				Average				Average		Average
Period	Mbbls		Fixed Price(1)		Mbbls		Strike Price(1)		Mbbls		Floor Price(1)		Ceiling Price(1)
2008		1,104	$	69.21		—	$	—		3,450	$	65.51	$	81.43
2009		368		67.95		—		—		9,321		63.39		80.14
2010		2,018		70.87		368		129.50		6,016		62.11		77.44
2011		3,285		71.16		1,095		134.17		4,377		65.83		84.41
2012		2,926		71.34		364		138.00		1,456		66.88		85.52
2013		1,086		71.34		—		—		—		—		—

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

     As of September 30, 2008, we had entered into the following natural gas derivative instruments:

Put Options					Collars
			Weighted								Weighted		Weighted
Production	MMBtu		Average		Production		MMBtu		GJ		Average		Average
Period	(in 000’s)		Strike Price(1)		Period		(in 000’s)		(in 000’s)		Floor Price(1)		Ceiling Price(1)
2008		1,840	$	8.75		2008		23,460		—	$	7.27	$	10.31
2009		—		—		2008		—		8,280		6.22		9.74
2010		—		—		2009		18,250		—		7.35		10.19
2011		—		—		2009		—		29,200		6.13		9.53
2012		—		—		2010		1,350		—		7.17		10.58

⁽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 against a combination of indices, including NYMEX Henry Hub, Panhandle Eastern Pipe Line and Houston Ship Channel. The Canadian natural gas prices represent a weighted average of AECO Index prices. The Canadian gas collars are entered into on a per gigajoule (GJ) basis, are converted to U.S. dollars utilizing a September 30, 2008 exchange rate, and are settled against the AECO Index.

6

     Receivables/Payables Related to Crude Oil and Natural Gas Derivative InstrumentsThe fair market value of the Company’s derivative assets and liabilities, including derivatives no longer qualifying for hedge accounting, are as follows:

	September 30,		December 31,
	2008		2007
	(In millions)
Current asset	$	13	$	21
Long-term asset		—		7
Current liability		264		286
Long-term liability		682		382

     Commodity Derivative Activity in Accumulated Other Comprehensive Income (OCI)Based on market prices as of September 30, 2008, the Company’s net unrealized loss in accumulated OCI for commodity derivatives designated as cash flow hedges totaled $901 million ($585 million after tax). Gains and losses on these hedges will be realized in future earnings contemporaneously with the related sales of natural gas and crude oil production applicable to specific hedges, which will occur through mid-2013. A reconciliation of the components of accumulated OCI in the Statement of Consolidated Shareholders’ Equity related to Apache’s cash flow hedges is presented in the table below:

	Before tax			After tax
	(In millions)
Unrealized loss on derivatives at December 31, 2007	$	(639	)	$	(412	)
Realized amounts reclassified into earnings		516			334
Unrealized amounts reclassified into earnings		36			23
Net change in derivative fair value		(814	)		(530	)
Unrealized loss on derivatives at September 30, 2008	$	(901	)	$	(585	)

2. DEBT

  Credit Facilities

     As of September 30, 2008, the Company had committed revolving credit facilities totaling $2.3 billion. The facilities consist of a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. There were no outstanding loans under these facilities as of September 30, 2008.

     During March and April 2008, the Company amended its $1.5 billion U.S. five-year revolving credit facility to (a) extend the maturity date one year to May 28, 2013 and (b) remove certain restrictions on our Australian entities including their ability to incur liens and issue guarantees. The Company also amended its $450 million U.S. credit facility, $150 million Australian credit facility and $150 million Canadian credit facility to (a) extend the maturity date one year to May 12, 2013, (b) remove certain restrictions on our Australian entities including their ability to incur liens and issue guarantees, and (c) specific to the Australian credit facility, give the Company the option of increasing the size of the facility up to a maximum amount of $400 million from the current limit of $300 million by adding commitments from new or existing lenders. In April 2008, the Company increased the Australian credit facility by $50 million to $200 million.

7

Subsequent Events

     On October 1, 2008, the Company issued $400 million principal amount, $398 million net of discount, of senior unsecured 6.0-percent notes maturing September 15, 2013, and $400 million principal amount, $398 million net of discount, of senior unsecured 6.9-percent notes maturing September 15, 2018. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The proceeds are presently invested in U.S. Treasury Notes and will be used for general corporate purposes.

  Financing Costs, Net

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

	For the Quarter Ended						For the Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands)
Interest expense	$	66,055		$	82,939		$	201,690		$	230,487
Amortization of deferred loan costs		818			875			2,498			2,421
Capitalized interest		(24,032	)		(18,880	)		(68,419	)		(56,554	)
Interest income		(9,550	)		(4,567	)		(19,175	)		(10,566	)
Financing costs, net	$	33,291		$	60,367		$	116,594		$	165,788

3. INCOME TAXES

     The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes, settlements with taxing authorities and other infrequent or unusual items are recognized as discrete items in the quarter in which they occur.

     Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.

     During the third quarter of 2008, the Company was in Administrative Appeals with the United States Internal Revenue Service (IRS) regarding the 2002 through 2005 tax years and under IRS audit for the 2006 tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

     During the third quarter of 2008, the Company recorded a $22 million reduction in income taxes following completion of an income tax audit. This reduced tax contingency reserves established in accordance with Financial Accounting Standards Board Interpretation No. 48 (FIN 48), “Accounting for Uncertainty of Income Taxes — an Interpretation of SFAS No. 109.”

  Subsequent Event

     During the fourth quarter of 2008, the Company received notification from the Appeals Division of the Internal Revenue Service that the appeals process for the years 2002 and 2003 has been completed. As a result of the completion of this process, we expect a reduction in our deferred income taxes and FIN 48 tax reserves in the fourth quarter of 2008.

8

4. CAPITAL STOCK

  Net Income per Common Share

     A reconciliation of the components of basic and diluted net income per common share is presented in the table below:

	For the Quarter Ended September 30,
	2008						2007
			Weighted						Weighted
			Average						Average
			Common						Common
			Shares						Shares
	Income		Outstanding		Per Share		Income		Outstanding		Per Share
	(In thousands, except per share amounts)
Basic:
Income attributable to common stock	$	1,189,405		334,825	$	3.55	$	611,928		332,668	$	1.84
Effect of Dilutive Securities:
Stock options and other		—		3,069				—		2,449
Diluted:
Income attributable to common stock, including assumed conversions	$	1,189,405		337,894	$	3.52	$	611,928		335,117	$	1.83

	For the Nine Months Ended September 30,
	2008						2007
			Weighted						Weighted
			Average						Average
			Common						Common
			Shares						Shares
	Income		Outstanding		Per Share		Income		Outstanding		Per Share
	(In thousands, except per share amounts)
Basic:
Income attributable to common stock	$	3,653,307		334,145	$	10.93	$	1,735,575		331,903	$	5.23
Effect of Dilutive Securities:
Stock options and other		—		3,006				—		2,183
Diluted:
Income attributable to common stock, including assumed conversions	$	3,653,307		337,151	$	10.84	$	1,735,575		334,086	$	5.19

     The diluted earnings per share calculations above exclude 357,884 and 4,000 shares of common stock that were anti-dilutive at September 30, 2008 and September 30, 2007, respectively.

  Common and Preferred Stock Dividends

     During the third quarter of 2008 and 2007, Apache paid $50 million in dividends on its common stock. For the nine-month periods ended September 30, 2008 and 2007, the Company paid $183 million and $149 million, respectively. Dividends paid during the 2008 nine-month period included a special cash dividend of 10 cents per common share, paid March 18, 2008. In addition, for the three-month and nine-month periods ended September 30, 2008 and 2007, Apache paid a total of $1.4 million and $4.3 million, respectively, in dividends on its Series B Preferred Stock.

9

  Stock-Based Compensation

     2005 Share Appreciation PlanOn May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan that provided incentives for employees to double Apache’s share price to $108 by the end of 2008, with an interim goal of $81 to be achieved by the end of 2007. To achieve the trigger price, the Company’s stock price had to close at or above the stated threshold for 10 days out of any 30 consecutive trading days by the end of the stated period.

     On June 14, 2007, Apache’s share price exceeded the interim $81 threshold for the required 10-day period. As such, Apache will issue approximately one million shares of its common stock, after minimum tax withholding requirements, in four equal annual installments. The first and second installments have already been issued. Subsequent installments will be issued in 2009 and 2010 to eligible employees remaining with the Company during that period.

     On February 29, 2008, Apache’s share price exceeded the $108 threshold for the required 10-day period. As such, Apache will issue approximately two million shares of its common stock, after minimum tax withholding requirements, in four equal annual installments. The first installment was issued in March 2008. Subsequent installments will be issued in 2009, 2010 and 2011 to eligible employees remaining with the Company during that period.

     2008 Share Appreciation ProgramOn May 7, 2008, the Stock Option Plan Committee of the Company’s Board of Directors, pursuant to the Company’s 2007 Omnibus Equity Compensation Plan, approved the 2008 Share Appreciation Program (the “Program”) that provides incentives for employees to double Apache’s share price to $216 by the end of 2012, with an interim goal of $162 to be achieved by the end of 2010. To achieve the payout, the Company’s stock price must close at or above the stated threshold for 10 out of any 30 consecutive trading days before the end of the stated period. Under the Program, if the first threshold is achieved, approximately 1.1 million shares would be awarded at an intrinsic cost of approximately $180 million. Achieving the second threshold would result in awards of approximately 1.7 million shares at an intrinsic cost of approximately $359 million. Shares issued to employees would be reduced by the required minimum tax withholding. Awards under the Program are payable in five equal annual installments, beginning on a date not more than 30 days after a threshold is attained for the required measurement period and on the four succeeding anniversaries of the attainment date. Over 90 percent of the value would benefit non-executive employees.

     Current accounting practices dictate that, regardless of whether these thresholds are ultimately achieved, the Company will recognize, over time, the fair value cost determined at the grant date based on numerous assumptions, including an estimate of the likelihood that Apache’s stock price will achieve these thresholds and the expected forfeiture rate. As a result, the Company will recognize expense and capitalized costs of approximately $193 million over the expected service life of the Program.

     The weighted-average fair value, based on a Monte Carlo Simulation Model, was $84.32 per share, determined by using expected volatility of 27.35 percent, an expected dividend yield of 0.52 percent, and a risk free interest rate of 3.03 percent.

     On May 7, 2008, the Stock Option Plan Committee of Apache’s Board of Directors awarded its Chief Executive Officer 250,000 restricted stock units, 50,000 of which will vest on July 1, 2009. The remaining 200,000 shares will vest ratably on the first business day of the years 2010, 2011, 2012 and 2013. Upon vesting, the Company will issue one share of the Company’s common stock as settlement for each restricted stock unit. Thirty thousand of the shares vesting each year will not be eligible for sale by the executive until such time as he retires or otherwise terminates employment with the Company. This award was made under the terms of the Company’s 2007 Omnibus Equity Compensation Plan.

     In August 2008, the Company established, pursuant to the Company’s 2007 Omnibus Equity Compensation Plan, the Non-Employee Directors’ Restricted Stock Units Program (the “RSU Program”). Each non-employee director was awarded 1,500 restricted stock units on August 14, 2008 under the RSU Program, with half of the restricted stock units vesting thirty days after the grant, and the other half vesting on the one-year anniversary date of the grant. Each year, all non-employee directors will be eligible to receive grants of restricted stock units comparable in value to the 2008 grant. Non-employee directors are required to choose, at the time of each award, whether such award will vest as 100 percent common stock or a combination of 40 percent cash and 60 percent common stock.

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5. ASSET RETIREMENT OBLIGATIONS

     The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine months ended September 30, 2008:

	2008
	(In thousands)
Asset retirement obligation at December 31, 2007	$	1,866,686
Liabilities incurred		267,308
Liabilities settled		(471,923	)
Accretion expense		77,146
Revisions in estimated liabilities		83,067
Asset retirement obligation at September 30, 2008	$	1,822,284
Current portion	$	359,975
Long-term portion		1,462,309

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

     Liabilities settled primarily relate to individual properties plugged and abandoned during the period. Most of the current year abandonment activity was in the Gulf of Mexico, a portion of which relates to the continued abandonment of platforms destroyed in 2005 during Hurricanes Katrina and Rita.

     During the third quarter, four of the Company’s operated platforms and two non-operated platforms were destroyed as a result of Hurricane Ike. Upon completing an initial assessment of hurricane related damages, the Company increased the discounted ARO liability on the affected properties by $83 million. The revision reflects the increased costs and acceleration in expected timing to abandon the toppled or destroyed platforms.

6. COMMITMENTS AND CONTINGENCIES

Legal Matters

     GrynbergAs more fully described in Note 9 of the financial statements in our annual report on Form 10-K for our 2007 fiscal year, in 2003, Jack J. Grynberg added Apache to lawsuits he began filing in 1997 against other natural gas producers, gatherers, and pipelines claiming that the defendants have underpaid royalty to the federal government and Indian tribes by mismeasurement of the volume and heating content of natural gas and are responsible for acts of others who mismeasured natural gas. The claims against Apache were dismissed, though Mr. Grynberg has appealed the dismissal. No material changes in this matter have occurred since the filing of our most recent annual report on Form 10-K.

     Argentine Environmental ClaimsIn connection with the Pioneer acquisition in 2006, the Company acquired a subsidiary of Pioneer in Argentina (PNRA) that is involved in various administrative proceedings with environmental authorities in the Neuquén Province relating to permits for and discharges from operations in that province. In addition, PNRA was named in a suit initiated against oil companies operating in the Neuquén basin 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. All of these matters are more fully described in Note 9 of the financial statements in our annual report on Form 10-K for our 2007 fiscal year. No material change in the status of these matters has occurred since the filing of our most recent annual report on Form 10-K.

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     Louisiana RestorationAs more fully described in Note 9 of the financial statements in our annual report on Form 10-K for our 2007 fiscal year, numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages for contamination and cleanup. No material change in the status of these matters has occurred since the filing of our most recent annual report on Form 10-K.

     Hurricane Related LitigationAs more fully described in Note 9 of the financial statements in our annual report on Form 10-K for our 2007 fiscal year, in a case styledNed Comer, et al vs. Murphy Oil USA, Inc., et al,Case No: 1:05-cv-00436; U.S.D.C.,United States District Court, Southern District of Mississippi,Mississippi property owners allege that hurricanes’ meteorological effects increased in frequency and intensity due to global warming, and there will be continued future damage from increasing intensity of storms and sea level rises. They claim this was caused by the various defendants (oil and gas companies, electric and coal companies, and chemical manufacturers). No material change in the status of this matter has occurred since the filing of our most recent annual report on Form 10-K.

     Australia Gas Pipeline Force MajeureAs more fully described in Item 2 of this quarterly report on Form 10-Q, Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas to customers under various long-term contracts. The subsidiaries and their joint venture participants have declared force majeure under those contracts. Although no litigation has been filed other than pre-action discovery proceedings by a single customer, a few customers have threatened to file suit challenging the declaration of force majeure under their contracts. Contract prices under their contracts are significantly below current spot prices for natural gas in Australia. If there were to be a successful challenge of the declaration of force majeure, approximately 90 percent of the natural gas volumes were sold by Company subsidiaries under long-term contracts that have liquidated damages provisions. Contractual liquidated damages under the long-term contracts with such provisions would not be expected to exceed $200 million AUD. No assurance can be given that customers would not assert claims in excess of contractual liquidated damages. While an adverse judgment against Company subsidiaries is possible if litigation is filed, Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims. Exposure related to such claims is not currently determinable. Company subsidiaries believe that the event was a force majeure. In the event it is determined that the pipeline explosion was not a force majeure, Company subsidiaries believe that liquidated damages should be the extent of the damages under the long-term contracts with such provisions.

     By November 13, 2008, the Senate Economics Committee of the Parliament of Australia is expected to release its findings from public hearings to determine the economic impact of the gas shortage following the explosion on Varanus Island and the government’s response. The report will consist in part of losses alleged by some parties who have long-term contracts with Company subsidiaries (as described above), but also losses alleged by third parties who do not have contracts with Company subsidiaries (but who may have purchased gas that was re-sold by customers or who may have paid more for energy following the explosion or who lost wages or sales due to the inability to obtain energy or the increased price of energy). A timber industry group, whose members do not have a contract with Company subsidiaries, has announced that it intends to seek compensation for its members and their subcontractors from Company subsidiaries for $20 million AUD in losses allegedly incurred as a result of the gas supply shortage following the explosion. InJohnson Tiles Pty Ltd v. Esso Australia Pty Ltd[2003] VSC 27 (Supreme Court of Victoria, Gillard J presiding), which concerned a 1998 explosion at an Esso natural gas processing plant at Longford in East Gippsland, Victoria, the Court held that Esso was not liable for $1.3 billion AUD of pure economic losses suffered by claimants that had no contract with Esso, but was liable to such claimants for reasonably foreseeable property damage which Esso settled for $32.5 million plus costs. In reaching this decision the Court held that third-party claimants should have protected themselves from pure economic losses, through the purchase of insurance or the installation of adequate backup measures, in case of an interruption in their gas supply from Esso. While an adverse judgment against Company subsidiaries is possible if litigation is filed, Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims. Exposure related to any such potential claims is not currently determinable.

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

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

     Other MattersThe Company is involved in other litigation and is subject to government and regulatory controls in the normal course of business. The Company has an accrued liability of approximately $14 million for other legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. It is management’s opinion that the loss for any such other litigation matters and claims that are reasonably possible to occur will not have a material adverse affect on the Company’s financial position or results of operations.

Environmental Matters

     As of September 30, 2008, the Company had an undiscounted reserve for environmental remediation of approximately $25 million. The Company is not aware of any environmental claims existing as of September 30, 2008, which have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or that past non-compliance with environmental laws will not be discovered on the Company’s properties.

Other Commitments

     In January 2008, Apache, BP plc and Chevron Corporation entered into a contract with Wild Well Control, Inc., to decommission certain downed platforms and related well facilities located offshore Louisiana in the Gulf of Mexico for a fixed fee of $750 million. Apache’s portion is 37.5 percent, or $281 million, which is included as part of the Company’s accrued ARO. We have spent $63 million of the $281 million as of September 30, 2008.

     Subsequent to the end of the third quarter, we extended the term of a drilling rig currently in use in our Australian drilling program representing a commitment of $328 million over a two-year period.

7. FAIR VALUE

  Fair Value Measurements

     The Company adopted SFAS No. 157, “Fair Value Measurements,” as of the beginning of 2008. SFAS No. 157 defines fair value and establishes disclosure requirements for assets and liabilities presented at fair value on the consolidated balance sheet. Fair value is the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants. A liability is quantified at the price it would take to transfer the liability to a new obligor, not at the amount that would be paid to settle the liability with the creditor.

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     To better quantify fair value, SFAS No. 157 establishes a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. Level 1 inputs consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs which are significant and unobservable, and have the lowest priority.

     The following table presents the Company’s material assets and liabilities measured at fair value for each hierarchy level as of September 30, 2008:

	As of September 30, 2008
			Fair Value Measurements Using
			Quoted Price				Significant
			in Active		Significant		Unobservable
	Total Fair		Markets		Other Inputs		Inputs
	Value		(Level 1)		(Level 2)		(Level 3)
	(In millions)
Assets:
Crude Oil and Natural Gas Options	$	13	$	—	$	13	$	—
Liabilities:
Oil and Gas Collars	$	604	$	—	$	604	$	—
Fixed-Price Oil Swaps		342		—		342		—

     Derivative instruments are valued using forward commodity price curves provided by reputable third-party brokers. The fair value of derivative instruments are not actively quoted in the open market, and are valued using Level 2 inputs.

8. RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

     In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities.” The statement amends SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008. We are currently evaluating the provisions of SFAS No. 161 and assessing the impact, if any, it may have on the Company.

     In December 2007, the FASB issued a revision to SFAS No. 141 “Business Combinations” (SFAS No. 141 (R)). The revision broadens the definition of a business combination to include all transactions or other events in which control of one or more businesses is obtained. Further, the statement establishes principles and requirements for how an acquirer recognizes assets acquired, liabilities assumed and any non-controlling interests acquired. SFAS No. 141 (R) is effective for business combination transactions for which the acquisition date is on or after the beginning of the first reporting period beginning on or after December 15, 2008. Early adoption is prohibited. Apache is currently evaluating the provisions of SFAS No. 141 (R) and assessing the impact, if any, it may have on the Company.

     Also in December 2007, the FASB issued SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51 “Consolidated Financial Statements.” SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary, sometimes called a minority interest, is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Additionally, the amounts of consolidated net income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the income statement. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. We are currently evaluating the provisions of SFAS No. 160 and assessing the impact, if any, it may have on the Company.

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9. BUSINESS SEGMENT INFORMATION

     Apache has producing operations in six countries: the United States (Gulf Coast and Central regions), Canada, Egypt, Australia, offshore the United Kingdom (U.K.) in the North Sea, and Argentina. Early in the second quarter of 2008, we finalized contracts for two exploration blocks in Chile (reflected under “Other International”). Financial information by country is presented below:

	United								U.K.				Other
	States		Canada		Egypt		Australia		North Sea		Argentina		International		Total
							(In thousands)
For the Quarter Ended September 30, 2008
Oil and Gas Production Revenues	$	1,311,052	$	462,470	$	778,124	$	76,817	$	642,563	$	97,856	$	—	$	3,368,882
Operating Income(1)	$	734,907	$	245,126	$	606,142	$	20,297	$	286,704	$	15,028	$	—	$	1,908,204
Other Income (Expense)
Other																(3,998	)
General and administrative																(57,561	)
Financing costs, net																(33,291	)
Income Before Income Taxes															$	1,813,354
For the Nine Months Ended September 30, 2008
Oil and Gas Production Revenues	$	4,345,687	$	1,384,790	$	2,328,440	$	328,415	$	1,787,367	$	276,250	$	—	$	10,450,949
Operating Income(1)	$	2,587,714	$	721,435	$	1,870,362	$	134,398	$	806,239	$	46,545	$	—	$	6,166,693
Other Income (Expense)
Other																1,867
General and administrative																(218,856	)
Financing costs, net																(116,594	)
Income Before Income Taxes															$	5,833,110
Total Assets	$	13,689,943	$	7,824,649	$	4,481,858	$	2,443,667	$	2,736,426	$	1,792,951	$	22,938	$	32,992,432
For the Quarter Ended September 30, 2007
Oil and Gas Production Revenues	$	1,101,328	$	330,804	$	516,536	$	138,016	$	331,827	$	80,083	$	—	$	2,498,594
Operating Income(1)	$	563,395	$	107,753	$	391,307	$	61,236	$	152,708	$	13,087	$	—	$	1,289,486
Other Income (Expense)
Other																6,364
General and administrative																(61,405	)
Financing costs, net																(60,367	)
Income Before Income Taxes															$	1,174,078
For the Nine Months Ended September 30, 2007
Oil and Gas Production Revenues	$	3,023,617	$	1,009,517	$	1,382,778	$	383,820	$	942,334	$	223,626	$	—	$	6,965,692
Operating Income(1)	$	1,457,952	$	388,366	$	1,014,256	$	163,819	$	419,470	$	34,270	$	—	$	3,478,133
Other Income (Expense)
Other																14,685
General and administrative																(200,065	)
Financing costs, net																(165,788	)
Income Before Income Taxes															$	3,126,965
Total Assets	$	12,121,829	$	7,087,271	$	3,085,358	$	1,649,165	$	2,144,419	$	1,551,516	$	11,360	$	27,650,918

⁽¹⁾ Operating Income 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.

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10. SUPPLEMENTAL GUARANTOR INFORMATION

     Apache Finance Pty Ltd. (Apache Finance Australia) and Apache Finance Canada Corporation (Apache Finance Canada) are subsidiaries of Apache that have issued publicly traded securities, and the following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.

     Each of the Companies presented in the condensed consolidating financial statements 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.

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 30, 2008

											All Other
							Apache		Apache		Subsidiaries
	Apache			Apache			Finance		Finance		of Apache			Reclassifications
	Corporation			North America			Australia		Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,290,323		$	—		$	—	$	—	$	2,086,279		$	(7,720	)	$	3,368,882
Equity in net income (loss) of affiliates		842,215			36,760			27,015		124,596		(3,705	)		(1,026,881	)		—
Other		(51,534	)		(24,263	)		24,263		14,701		33,757			(922	)		(3,998	)
		2,081,004			12,497			51,278		139,297		2,116,331			(1,035,523	)		3,364,884
OPERATING EXPENSES:
Depreciation, depletion and amortization		257,091			—			—		—		343,796			—			600,887
Asset retirement obligation accretion		16,174			—			—		—		8,796			—			24,970
Lease operating expenses		229,018			—			—		—		259,148			—			488,166
Gathering and transportation costs		11,928			—			—		—		38,167			(7,720	)		42,375
Taxes other than income		57,863			—			—		—		246,417			—			304,280
General and administrative		43,661			—			—		—		14,822			(922	)		57,561
Financing costs, net		32,780			(2,777	)		4,523		14,152		(15,387	)		—			33,291
		648,515			(2,777	)		4,523		14,152		895,759			(8,642	)		1,551,530
INCOME (LOSS) BEFORE INCOME TAXES		1,432,489			15,274			46,755		125,145		1,220,572			(1,026,881	)		1,813,354
Provision (benefit) for income taxes		241,664			(7,628	)		9,995		141		378,357			—			622,529
NET INCOME		1,190,825			22,902			36,760		125,004		842,215			(1,026,881	)		1,190,825
Preferred stock dividends		1,420			—			—		—		—			—			1,420
INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,189,405		$	22,902		$	36,760	$	125,004	$	842,215		$	(1,026,881	)	$	1,189,405

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 30, 2007

											All Other
					Apache			Apache			Subsidiaries
	Apache		Apache		Finance			Finance			of Apache			Reclassifications
	Corporation		North America		Australia			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,086,882	$	—	$	—		$	—		$	1,430,813		$	(19,101	)	$	2,498,594
Equity in net income (loss) of affiliates		317,145		15,825		18,700			(11,167	)		(12,570	)		(327,933	)		—
Other		7,711		—		(51	)		409			2,907			(4,612	)		6,364
		1,411,738		15,825		18,649			(10,758	)		1,421,150			(351,646	)		2,504,958
OPERATING EXPENSES:
Depreciation, depletion and amortization		277,702		—		—			—			323,094			—			600,796
Asset retirement obligation accretion		17,768		—		—			—			6,668			—			24,436
Lease operating expenses		181,334		—		—			—			228,194			—			409,528
Gathering and transportation costs		16,241		—		—			—			37,747			(19,101	)		34,887
Taxes other than income		48,520		—		—			—			90,941			—			139,461
General and administrative		49,262		—		—			—			16,754			(4,611	)		61,405
Financing costs, net		46,894		—		4,514			14,112			(5,153	)		—			60,367
		637,721		—		4,514			14,112			698,245			(23,712	)		1,330,880
INCOME (LOSS) BEFORE INCOME TAXES		774,017		15,825		14,135			(24,870	)		722,905			(327,934	)		1,174,078
Provision (benefit) for income taxes		160,669		—		(1,690	)		(4,008	)		405,759			—			560,730
NET INCOME		613,348		15,825		15,825			(20,862	)		317,146			(327,934	)		613,348
Preferred stock dividends		1,420		—		—			—			—			—			1,420
INCOME ATTRIBUTABLE TO COMMON STOCK	$	611,928	$	15,825	$	15,825		$	(20,862	)	$	317,146		$	(327,934	)	$	611,928

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APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2008

											All Other
							Apache		Apache		Subsidiaries
	Apache			Apache			Finance		Finance		of Apache			Reclassifications
	Corporation			North America			Australia		Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,267,293		$	—		$	—	$	—	$	6,230,045		$	(46,389	)	$	10,450,949
Equity in net income (loss) of affiliates		2,267,847			51,205			51,760		307,270		(4,893	)		(2,673,189	)		—
Other		(41,679	)		(16,880	)		16,804		44,024		2,365			(2,767	)		1,867
		6,493,461			34,325			68,564		351,294		6,227,517			(2,722,345	)		10,452,816
OPERATING EXPENSES:
Depreciation, depletion and amortization		845,486			—			—		—		1,003,558			—			1,849,044
Asset retirement obligation accretion		50,882			—			—		—		26,264			—			77,146
Lease operating expenses		644,344			—			—		—		745,198			—			1,389,542
Gathering and transportation costs		32,904			—			—		—		136,603			(46,389	)		123,118
Taxes other than income		173,689			—			—		—		671,717			—			845,406
General and administrative		176,373			—			—		—		45,250			(2,767	)		218,856
Financing costs, net		102,882			(8,272	)		13,518		42,378		(33,912	)		—			116,594
		2,026,560			(8,272	)		13,518		42,378		2,594,678			(49,156	)		4,619,706
INCOME (LOSS) BEFORE INCOME TAXES		4,466,901			42,597			55,046		308,916		3,632,839			(2,673,189	)		5,833,110
Provision (benefit) for income taxes		809,334			(3,056	)		3,841		432		1,364,992			—			2,175,543
NET INCOME		3,657,567			45,653			51,205		308,484		2,267,847			(2,673,189	)		3,657,567
Preferred stock dividends		4,260			—			—		—		—			—			4,260
INCOME ATTRIBUTABLE TO COMMON STOCK	$	3,653,307		$	45,653		$	51,205	$	308,484	$	2,267,847		$	(2,673,189	)	$	3,653,307

19

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2007

											All Other
					Apache			Apache			Subsidiaries
	Apache		Apache		Finance			Finance			of Apache			Reclassifications
	Corporation		North America		Australia			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,977,123	$	—	$	—		$	—		$	4,082,417		$	(93,848	)	$	6,965,692
Equity in net income (loss) of affiliates		904,001		22,568		31,714			24,370			(39,099	)		(943,554	)		—
Other		21,533		—		(117	)		—			(3,964	)		(2,767	)		14,685
		3,902,657		22,568		31,597			24,370			4,039,354			(1,040,169	)		6,980,377
OPERATING EXPENSES:
Depreciation, depletion and amortization		775,454		—		—			—			947,362			—			1,722,816
Asset retirement obligation accretion		52,948		—		—			—			19,686			—			72,634
Lease operating expenses		573,525		—		—			—			624,777			—			1,198,302
Gathering and transportation costs		42,741		—		—			—			151,692			(93,848	)		100,585
Taxes other than income		130,705		—		—			—			262,517			—			393,222
General and administrative		162,650		—		—			—			40,182			(2,767	)		200,065
Financing costs, net		134,469		—		13,540			42,336			(24,557	)		—			165,788
		1,872,492		—		13,540			42,336			2,021,659			(96,615	)		3,853,412
INCOME (LOSS) BEFORE INCOME TAXES		2,030,165		22,568		18,057			(17,966	)		2,017,695			(943,554	)		3,126,965
Provision (benefit) for income taxes		290,330		—		(4,511	)		(12,383	)		1,113,694			—			1,387,130
NET INCOME		1,739,835		22,568		22,568			(5,583	)		904,001			(943,554	)		1,739,835
Preferred stock dividends		4,260		—		—			—			—			—			4,260
INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,735,575	$	22,568	$	22,568		$	(5,583	)	$	904,001		$	(943,554	)	$	1,735,575

20

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2008

													All Other
							Apache			Apache			Subsidiaries
	Apache			Apache			Finance			Finance			of Apache			Reclassifications
	Corporation			North America			Australia			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,548,120		$	(12,424	)	$	(11,967	)	$	(26,375	)	$	3,531,214		$	—		$	6,028,568
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,663,706	)		—			—			—			(2,399,269	)		—			(4,062,975	)
Additions to gas gathering, transmission and processing facilities		—			—			—			—			(420,850	)		—			(420,850	)
Restricted cash		(13,844	)		—			—			—			—			—			(13,844	)
Proceeds from sale of oil & gas properties		206,748			—			—			—			99,953			—			306,701
Investment in subsidiaries, net		(230,924	)		(12,975	)		—			—			—			243,899			—
Other, net		(34,814	)		—			—			—			(7,695	)		—			(42,509	)
NET CASH USED IN INVESTING ACTIVITIES		(1,736,539	)		(12,975	)		—			—			(2,727,861	)		243,899			(4,233,477	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and money market borrowings, net		(138,511	)		—			65			56			(30,652	)		—			(169,042	)
Payments on fixed-rate debt		—			—			—			—			(353	)		—			(353	)
Dividends paid		(187,735	)		4,940			(1,073	)		(2,130	)		143,313			(145,050	)		(187,735	)
Common stock activity		31,207			—			—			—			—			—			31,207
Treasury stock activity, net		4,171			19,975			12,975			26,699			39,200			(98,849	)		4,171
Cost of debt and equity transactions		(1,224	)		—			—			—			—			—			(1,224	)
Other		44,115			—			—			—			2,551			—			46,666
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(247,977	)		24,915			11,967			24,625			154,059			(243,899	)		(276,310	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		563,604			(484	)		—			(1,750	)		957,411			—			1,518,781
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		3,626			484			1			1,751			119,961			—			125,823
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	567,230		$	—		$	1		$	1		$	1,077,372		$	—		$	1,644,604

21

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 30, 2007

													All Other
							Apache			Apache			Subsidiaries
	Apache			Apache			Finance			Finance			of Apache			Reclassifications
	Corporation			North America			Australia			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,692,991		$	—		$	(12,758	)	$	(1,021,084	)	$	2,218,323		$	—		$	3,877,472
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,486,331	)		—			—			—			(1,919,351	)		—			(3,405,682	)
Acquisition of Anadarko properties		(1,004,581	)		—			—			—			—			—			(1,004,581	)
Additions to gas gathering, transmission and processing facilities		—			—			—			—			(301,226	)		—			(301,226	)
Restricted cash
Proceeds from sale of oil & gas properties		4,623			—			—			—			6,451			—			11,074
Investment in subsidiaries, net		(1,061,800	)		(12,525	)		—			—			(1,034,017	)		2,108,342			—
Other, net		(51,011	)		—			—			—			(80,769	)		—			(131,780	)
NET CASH USED IN INVESTING ACTIVITIES		(3,599,100	)		(12,525	)		—			—			(3,328,912	)		2,108,342			(4,832,195	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and money market borrowings, net		3,409,588			—			233			(2,426	)		85,982			(37,380	)		3,455,997
Payments on fixed-rate debt		(2,388,100	)		—			—			—			(26,859	)		—			(2,414,959	)
Dividends paid		(153,421	)		—			—			—			—			—			(153,421	)
Common stock activity		22,707			12,525			12,525			1,023,510			1,022,402			(2,070,962	)		22,707
Treasury stock activity, net		12,474			—			—			—			—			—			12,474
Cost of debt and equity transactions		(18,000	)		—			—			—			—			—			(18,000	)
Other		20,823			—			—			—			—			—			20,823
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		906,071			12,525			12,758			1,021,084			1,081,525			(2,108,342	)		925,621
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(38	)		—			—			—			(29,064	)		—			(29,102	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		4,148			—			1			1			136,374			—			140,524
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4,110		$	—		$	1		$	1		$	107,310		$	—		$	111,422

22

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of September 30, 2008

											All Other
						Apache			Apache		Subsidiaries
	Apache		Apache			Finance			Finance		of Apache			Reclassifications
	Corporation		North America			Australia			Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	567,230	$	—		$	1		$	1	$	1,077,273		$	—		$	1,644,504
Receivables, net of allowance		608,053		—			—			2,373		1,069,605			—			1,680,031
Inventories		42,246		—			—			—		437,477			—			479,723
Drilling advances and others		262,010		—			—			—		105,925			—			367,934
Short-term investments		—		—			—			—		100			—			100
		1,479,538		—			1			2,374		2,690,379			—			4,172,292
PROPERTY AND EQUIPMENT, NET		12,907,731		—			—			—		15,211,087			—			28,118,818
OTHER ASSETS:
Intercompany receivable, net		1,225,943		—			—			—		—			(1,225,943	)		—
Restricted cash		13,844		—			—			—		—			—			13,844
Goodwill, net		—		—			—			—		189,252			—			189,252
Equity in affiliates		12,821,112		484,889			692,281			2,003,426		(183,136	)		(15,818,572	)		—
Deferred charges and other		221,345		—			—			1,003,431		273,450			(1,000,000	)		498,226
		14,282,244		484,889			692,281			3,006,857		279,566			(18,044,515	)		701,322
	$	28,669,513	$	484,889		$	692,282		$	3,009,231	$	18,181,032		$	(18,044,515	)	$	32,992,432
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term debt	$	—	$	—		$	99,955		$	—	$	40,559		$	—		$	140,514
Accounts payable		475,010		—			—			—		227,133			—			702,143
Other accrued expenses		1,194,450		4,493			158,959			311,786		1,629,903			(1,225,943	)		2,073,648
		1,669,460		4,493			258,914			311,786		1,897,595			(1,225,943	)		2,916,305
LONG-TERM DEBT		3,264,410		—			—			647,052		5,866			—			3,917,327
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,013,286		(3,056	)		(34,641	)		4,394		2,532,435			—			4,512,418
Advances from gas purchasers		—		—			—			—		—			—			—
Asset retirement obligation		856,111		—			—			—		606,198			—			1,462,309
Derivative instruments		600,693		16,880			(16,880	)		—		81,089			—			681,782
Other		1,502,447		—			—			—		236,737			(1,000,000	)		739,184
		4,972,537		13,824			(51,521	)		4,394		3,456,459			(1,000,000	)		7,395,693
COMMITMENTS AND CONTINGENCIES:
SHAREHOLDERS’ EQUITY		18,763,106		466,572			484,889			2,045,999		12,821,112			(15,818,572	)		18,763,106
	$	28,669,513	$	484,889		$	692,282		$	3,009,231	$	18,181,032		$	(18,044,515	)	$	32,992,432

23

APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2007

											All Other
					Apache			Apache			Subsidiaries
	Apache		Apache		Finance			Finance			of Apache			Reclassifications
	Corporation		North America		Australia			Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,626	$	—	$	1		$	1,751		$	120,445		$	—		$	125,823
Receivables, net of allowance		883,022		—		—			—			1,053,955			—			1,936,977
Inventories		25,445		—		—			—			435,766			—			461,211
Drilling advances and others		140,335		—		—			—			87,905			—			228,240
Short-term investments
		1,052,428		—		1			1,751			1,698,071			—			2,752,251
PROPERTY AND EQUIPMENT, NET		11,858,362		—		—			—			13,373,231			—			25,231,593
OTHER ASSETS:
InterCompany receivable, net		1,080,893		—		(170,000	)		(253,268	)		(657,625	)		—			—
Restricted cash
Goodwill, net		—		—		—			—			189,252			—			189,252
Equity in affiliates		10,512,679		451,161		670,908			2,137,603			(168,977	)		(13,603,374	)		—
Deferred charges and other		211,399		—		—			1,003,668			246,488			(1,000,000	)		461,555
	$	24,715,761	$	451,161	$	500,909		$	2,889,754		$	14,680,440		$	(14,603,374	)	$	28,634,651
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term debt	$	139,100	$	—	$	—		$	—		$	75,974		$	—		$	215,074
Accounts payable		414,733		—		—			—			203,204			—			617,937
Other accrued expenses		1,170,670		—		(12,994	)		39,438			634,891			—			1,832,005
		1,724,503		—		(12,994	)		39,438			914,069			—			2,665,016
LONG-TERM DEBT		3,263,820		—		99,890			646,996			899			—			4,011,605
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,582,346		—		(37,148	)		5,630			2,374,155			—			3,924,983
Advances from gas purchasers		12,004		—		—			—			—			—			12,004
Asset retirement obligation		962,287		—		—			—			594,622			—			1,556,909
Derivative instruments		346,408		—		—			—			35,383			—			381,791
Other		1,446,414		—		—			9,317			248,633			(1,000,000	)		704,364
		4,349,459		—		(37,148	)		14,947			3,252,793			(1,000,000	)		6,580,051
COMMITMENTS AND CONTINGENCIES:
SHAREHOLDERS’ EQUITY		15,377,979		451,161		451,161			2,188,373			10,512,679			(13,603,374	)		15,377,979
	$	24,715,761	$	451,161	$	500,909		$	2,889,754		$	14,680,440		$	(14,603,374	)	$	28,634,651

24

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

     This discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with our consolidated financial statements as of September 30, 2008, and the period then ended and accompanying notes included under Part I, Item 1, of this Quarterly Report on Form 10-Q, as well as our consolidated financial statements as of December 31, 2007, and the year then ended, and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations, both of which are contained in our Annual Report on Form 10-K for the year ended December 31, 2007.

     Apache Corporation (Apache) is an independent energy company whose principal business includes exploration, development and production of crude oil, natural gas and natural gas liquids. We operate in six countries: the United States, Canada, Egypt, Australia, offshore the United Kingdom in the North Sea and Argentina. Early in the second quarter of 2008, we finalized contracts for two exploration blocks in Chile.

     Third-quarter 2008 earnings were Apache’s second highest on record, surpassed only by earnings in the second quarter of 2008. Our 2008 earnings through September totaled $10.84 per diluted common share, $2.45 ahead of 2007 full-year earnings. Crude oil and natural gas prices remained strong through July but began weakening in August and September. Since the end of the third quarter, we have seen further price reduction with the perception of future demand being altered by turmoil in the financial markets and diminished economic outlook. Third-quarter production was impacted by four named storms in the Gulf of Mexico (discussed below) and production remaining shut-in because of the June 3, 2008 pipeline explosion and fire at the Varanus Island gas processing and transportation hub offshore Western Australia operated by subsidiaries of the Company.

Third Quarter 2008 compared to Third Quarter 2007

     Apache earned $1.2 billion, or $3.52 per diluted common share, in the third quarter of 2008, nearly double the $612 million ($1.83 per share) earned in the same quarter of 2007. Cash flow from operating activities totaled $2.3 billion, compared to $1.4 billion last year, an increase of 60 percent. The 2008 third-quarter effective tax rate and earnings were impacted by a $114 million non-cash tax benefit, primarily deferred taxes, related to the strengthening U.S. dollar. The 2007 third-quarter effective tax rate and earnings were impacted by a $114 million non-cash tax charge, primarily deferred taxes, related to the weakening U.S. dollar.

     Oil and gas production revenues totaled $3.4 billion, 35 percent higher than the 2007 comparable quarter, on substantially higher price realizations. Crude oil realizations averaged $101.04 a barrel, 43 percent above 2007 third-quarter prices, while natural gas realizations averaged $7.43 per thousand cubic feet (Mcf), up 49 percent. While these quarterly price realizations were substantially above year-ago prices, they were down from our second-quarter 2008 record price realizations and will fall further if recent market price trends continue throughout the fourth quarter of 2008. This quarter’s pre-tax margin was the second highest in our history, up 70 percent from the 2007 third quarter. For a more detailed discussion of our revenue and cost components, please refer to Results of Operations in this Item 2.

Pre-tax Margins
	For the Quarter Ended September 30,
	2008		2007
	(In thousands, except margin)
Income before Income Taxes	$	1,813,354	$	1,174,078
Barrels of oil equivalent produced		46,982		51,650
Pre-tax margin per boe produced	$	38.60	$	22.73

Year-to-Date 2008 compared to Year-to-Date 2007

     Apache earned a record $3.7 billion, or $10.84 per diluted common share, for the nine-month period ending September 30, 2008, more than double the $1.7 billion, or $5.19 per share, earned in the same period last year. Cash flow from operating activities totaled $6.0 billion for the nine-month period, compared to $3.9 billion last year, an increase of 55 percent. The 2008 period effective tax rate and earnings were impacted by a $127 million non-cash tax benefit, primarily on deferred taxes, related to the strengthening U.S. dollar. The 2007 period effective tax rate and earnings were impacted by a $182 million non-cash deferred tax charge related to the weakening U.S. dollar, partially offset by a $17 million Canadian tax rate reduction benefit.

25

     The Company generated $10.5 billion of oil and gas production revenues, surpassing 2007 full-year revenues and 50 percent higher than the 2007 nine-month period. Crude oil realizations averaged $100.17 a barrel, 57 percent above 2007 year-to-date prices, while natural gas realizations averaged $7.30 per Mcf, up 39 percent. Apache’s pre-tax margin for the period was nearly double the 2007 period margin. For a more detailed discussion of our revenue and cost components, please refer to Results of Operations in this Item 2.

Pre-tax Margins
	For the Nine Months Ended
	September 30,
	2008		2007
	(In thousands, except margin)
Income before Income Taxes	$	5,833,110	$	3,126,965
Barrels of oil equivalent produced		147,922		151,985
Pre-tax margin per boe produced	$	39.43	$	20.57

Third Quarter 2008 Operating Highlights

U.S. Gulf Coast

     During the third quarter of 2008, four named storms struck the Gulf of Mexico, impacting the Company’s U.S. Gulf Coast operations. Three of these storms, Hurricane Dolly, Tropical Storm Edouard and Hurricane Gustav, required only temporary curtailment of production and caused minor damage to the Company’s production platforms. Even though the other storm, Hurricane Ike, caused widespread damage to both onshore and offshore production and transportation facilities, the majority of the Company’s 459 offshore operated platforms escaped with minor damage. Three Company-operated and two non-operated platforms were toppled. One other platform was destroyed by fire and will not be repaired. Another four operated platforms sustained major damage that will require significant repair. All were minor producers and had no significant reserves. Additionally, third-party pipelines and processing facilities, on which the Company relies to transport and process the crude oil and natural gas it produces, were damaged. Restoration of full production is dependent on numerous factors, most of which are beyond the Company’s control. The majority of the production should be restored by the end of 2008. The impact on operations and results follows:

     Production — Substantially all of Apache’s net production shut-in during the third quarter occurred late in September and averaged approximately 112 million cubic feet per day (MMcf/d) of natural gas and 17,900 barrels per day of oil (b/d). As of early November 2008, the Gulf Coast region was producing a net 283 MMcf/d of natural gas and 42,000 b/d of oil.

     Financial Results — The impact of the hurricanes on the Company’s third-quarter 2008 financial results included $262 million of lower crude oil and natural gas revenues. As of the end of the quarter, the Company had not incurred any meaningful capital or repair expenditures. During the fourth quarter, Apache expects repair costs to range from $60 million to $80 million, in line with the Company’s estimated insurance coverage deductibles.

     Assessment of Damage — The Company is continuing its assessment of damage caused by Hurricane Ike and is unable to estimate the ultimate costs of abandonment and repair at this time. Four operated production platforms were destroyed and four were severely damaged during Hurricane Ike. Prior to Hurricane Ike, aggregate net production from destroyed and damaged platforms was approximately 1,400 b/d of oil and 9 MMcf/d of gas. Additionally, two non-operated structures at Eugene Island 330 were destroyed. All but approximately 1,100 barrels of oil equivalent (boe) per day of production will ultimately be restored.

     Insurance Coverage — The Company carries property damage insurance for windstorm in the Gulf of Mexico of $250 million, subject to a $100 million deductible, per event. The deductible will be prorated based on the Company’s working interest in the damaged properties. The $250 million in coverage is provided through Oil Insurance Ltd (OIL) and will be prorated down if total claims received by the insurer for a single event exceed $750 million. The Company carries another $150 million in aggregate for the policy year, purchased in the commercial market. As of early November, OIL has indicated that losses for Hurricane Ike could exceed their aggregate limit. The total impact will not be known until all claims are filed.

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Egypt

     During the third quarter, several notable wells were drilled in Egypt. The East Bahariya and East Beni Suef concession wells tested at 1,145 b/d and 930 b/d, respectively. These two discoveries potentially add to our inventory of water-flood projects. In the Khalda Offset concession, a gas-condensate wildcat discovery tested 11 MMcf/d of gas and 5,027 b/d of condensate. The Heqet-2 well, located in the Greater Khalda area of Egypt’s Western Desert, tested 2,100 b/d from a previously untested Jurassic Safa formation at a depth of 14,430–14,450 feet. We also announced that the Umbarka-174 well tested 4,300 b/d in the main Alem el Bueib (AEB) field in the north central portion of the Greater Khalda area.

     Subsequent to the end of the third quarter, we announced the WKAL-C-1X discovery on the West Kalabsha concession. The well tested 4,746 b/d and 4.4 MMcf/d of gas in the Jurassic Safa formation. The WKAL-C-1X discovery had similar characteristics to the Heqet-2 well and represents the westernmost oil ever discovered in Egypt, confirming our exploration model for this area of the Faghur Basin.

Australia

     Varanus Island — On June 3, 2008, subsidiaries of the Company reported a gas pipeline explosion and fire at the Varanus Island gas processing and transportation hub offshore Western Australia, which shut-in production at the John Brookes field and Harriet Joint Venture. The Island’s operations account for approximately 195 million cubic feet (MMcf) of natural gas and 5,400 barrels of oil per day (net to Apache subsidiaries). On August 5, 2008, partial production was reestablished from the John Brookes field. By the end of the quarter, the field was producing at the full capacity of the John Brookes facility. Production from the Harriet Joint Venture remains shut-in, awaiting facility repairs. The John Brookes field accounted for approximately 60 percent and 25 percent of the island’s pre-incident natural gas and oil production, respectively. Production from the Harriet Joint Venture, which accounted for the remaining 40 percent and 75 percent of the island’s pre-incident natural gas and oil production, respectively, is currently projected to be restored in the fourth quarter. The Harriet Joint Venture facilities are located adjacent to the pipeline explosion and will require significant repairs to restore production. Company subsidiaries operate the facilities and own a 68.5 percent interest in the Harriet Joint Venture and a 55 percent interest in the John Brookes field. Company subsidiaries maintain replacement cost insurance, subject to a deductible of approximately $7 million, with adequate limits to cover fully their share of the estimated cost of restoring the Varanus Island facilities.

     Drilling Results — During the third quarter of 2008, four wells reached total depth. Three of the wells found commercial quantities of hydrocarbons. The Lee-4 intersected four pay zones in the North Rankin, Brigadier, Mungaroo “A” and Mungaroo “B” formations and is currently being completed as a future gas producer. The Simpson-9 and Simpson-10 oil wells have been perforated and are waiting on repairs to the Harriet Joint Venture facilities to commence production.

North Sea

     Drilling successes and improved platform operating efficiencies enabled the region’s third-quarter 2008 production to reach 61,305 boe per day, the region’s best daily production average since the second quarter of 2006.

Argentina

     We completed our 2,500 square kilometer three dimensional seismic shoot in the Tierra del Fuego province and have identified over 100 potential features to drill in the future.

Chile

     During the third quarter of 2008, we commenced a seismic program on the two exploration blocks we acquired early in the second quarter of 2008.

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Results of Operations

  Revenues

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2008				2007				2008				2007
Revenues (in thousands):
Oil	$	2,253,270	67	%	$	1,627,467	65	%	$	6,979,894	67	%	$	4,261,017	61	%
Natural gas		1,057,040	31	%		819,351	33	%		3,290,342	31	%		2,568,847	37	%
Natural gas liquids		58,572	2	%		51,776	2	%		180,713	2	%		135,828	2	%
Total	$	3,368,882	100	%	$	2,498,594	100	%	$	10,450,949	100	%	$	6,965,692	100	%

     Effect of cash flow hedges included in oil and gas revenues were as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In millions)
Increase (decrease) in crude oil revenues	$	(168	)	$	(40	)	$	(472	)	$	(30	)
Increase (decrease) in natural gas revenues		(19	)		35			(29	)		42
Total increase (decrease) in oil and gas revenues	$	(187	)	$	(5	)	$	(501	)	$	12
Percentage of oil and gas revenues		5	%		*			5	%		*

* Less than one percent

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  Production and Pricing

     The table below presents oil and gas production revenues, production and average prices realized from sales of natural gas, oil and natural gas liquids.

	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
					Increase							Increase
	2008		2007		(Decrease)			2008		2007		(Decrease)
Oil Volume — Barrels per day:
United States		80,284		97,025		(17.25	)%		93,622		87,660		6.80	%
Canada		16,655		18,451		(9.73	)%		17,247		18,838		(8.45	)%
Egypt		64,803		60,395		7.30	%		64,082		60,219		6.41	%
Australia		7,083		14,685		(51.77	)%		8,286		14,308		(42.09	)%
North Sea		60,856		48,888		24.48	%		58,740		52,572		11.73	%
Argentina		12,729		11,708		8.72	%		12,342		11,266		9.55	%
Total(1)		242,410		251,152		(3.48	)%		254,319		244,863		3.86	%
Average Oil price — Per barrel:
United States	$	93.69	$	67.70		38.39	%	$	91.48	$	61.75		48.15	%
Canada		111.81		73.95		51.20	%		108.10		63.74		69.60	%
Egypt		105.60		74.04		42.63	%		110.01		66.50		65.43	%
Australia		99.66		76.65		30.02	%		111.86		73.30		52.61	%
North Sea		113.56		73.18		55.18	%		110.08		65.21		68.81	%
Argentina		50.95		49.70		2.52	%		48.76		45.52		7.12	%
Total (2)		101.04		70.43		43.46	%		100.17		63.74		57.15	%
Natural Gas Volume — Mcf per day:
United States		635,891		763,693		(16.73	)%		712,529		768,520		(7.29	)%
Canada		349,000		386,659		(9.74	)%		355,834		386,312		(7.89	)%
Egypt		287,231		241,919		18.73	%		254,786		239,951		6.18	%
Australia		54,726		194,520		(71.87	)%		124,888		195,242		(36.03	)%
North Sea		2,697		1,721		56.71	%		2,604		1,851		40.68	%
Argentina		217,091		196,168		10.67	%		193,257		203,524		(5.04	)%
Total (3)		1,546,636		1,784,680		(13.34	)%		1,643,898		1,795,400		(8.44	)%
Average Natural Gas price — Per Mcf:
United States	$	9.96	$	6.59		51.14	%	$	9.64	$	6.95		38.71	%
Canada		8.70		5.54		57.04	%		8.63		6.25		38.08	%
Egypt		5.62		4.72		19.07	%		5.68		4.42		28.51	%
Australia		2.36		1.93		22.28	%		2.18		1.83		19.13	%
North Sea		27.17		16.98		60.01	%		21.88		12.80		70.94	%
Argentina		1.41		0.93		51.61	%		1.53		1.03		48.54	%
Total(4)		7.43		4.99		48.70	%		7.30		5.24		39.31	%
Natural Gas Liquids (NGL)
Volume — Barrels per day:
United States		5,450		7,766		(29.82	)%		6,636		7,677		(13.56	)%
Canada		2,034		2,253		(9.72	)%		2,046		2,199		(6.96	)%
Argentina		3,005		2,794		7.55	%		2,877		2,749		4.66	%
Total		10,489		12,813		(18.14	)%		11,559		12,625		(8.44	)%
Average NGL Price — Per barrel:
United States	$	72.82	$	47.18		54.35	%	$	64.49	$	41.64		54.88	%
Canada		63.77		40.39		57.89	%		58.62		37.05		58.22	%
Argentina		36.63		37.74		(2.94	)%		38.81		35.07		10.66	%
Total		60.70		43.92		38.21	%		57.06		39.41		44.79	%

(1)	Approximately 20 percent and 19 percent of oil production was subject to financial derivative hedges for the third quarter and nine-month period of 2008, respectively; 20 percent and 18 percent for the 2007 third quarter and nine-month period, respectively.
(2)	Reflects a per barrel reduction of $7.54 and $6.77 for the 2008 third quarter and nine-month period, respectively; a decrease of $1.71 and $.44 for the 2007 third quarter and nine-month period, respectively.
(3)	Approximately 22 percent and 20 percent of natural gas production was subject to financial derivative hedges for the third quarter and nine-month period of 2008, respectively; 20 percent and 18 percent for the 2007 third quarter and nine-month period, respectively.
(4)	Reflects a per Mcf reduction of $.13 and $.06 for the 2008 third quarter and nine-month period, respectively, an increase of $.21 and $.09 the 2007 third quarter and nine-month period, respectively.

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Third Quarter 2008 compared to Third Quarter 2007

     Crude Oil RevenuesThird-quarter 2008 crude oil revenues increased $626 million on a 43 percent increase in average realized price. Production was three percent lower.

     U.S. oil revenues were $88 million higher, driven by a 38 percent increase in realized crude oil prices. Revenue growth was restricted by the 17,900 b/d of estimated production shut-in from tropical storm and hurricane activity in the Gulf Coast region. Gulf Coast region production was 28 percent lower on a comparable basis, but would have been up three percent absent storm-related downtime. Production gains in the Gulf Coast region from drilling and recompletion activities were largely offset by natural decline and non-hurricane downtime. Central region production was down two percent following property divestitures.

     Egyptian crude oil revenues increased $218 million on a 43 percent increase in price realizations and a seven percent increase in production. Price realizations averaged $105.60 per barrel, up $31.56 from 2007. Oil production in Egypt increased 4,408 b/d as new discoveries and recompletion and workover activities combined to more than offset the impact that higher commodity prices have on cost recovery volumes. Production gains were made in several concessions, most notably from new wells in East Baharyia, Matruh and Umbarka, and successful recompletions in Matruh and El Diyur.

     North Sea crude oil revenues rose $307 million, nearly double last year’s third-quarter amount. Production was 24 percent higher primarily because of timing of annual maintenance and successful drilling and workover programs. Oil realizations increased 55 percent, averaging $113.56 per barrel.

     Canadian oil revenues rose $46 million on a 51 percent increase in price realizations. Prices increased $37.86 to $111.81 per barrel. Production was down 10 percent on natural decline and property divestitures, which more than offset gains from drilling and recompletion activities.

     Argentina’s crude oil revenues increased 11 percent, or $6 million from last year, on a nine percent increase in production and a three percent increase in realized prices. New wells in Tierra del Fuego area and successful recompletions in the El Santigueño field drove production gains. Price restrictions in Argentina limited oil price realizations and our ability to sell production at prevailing world prices.

     Australian oil revenues fell $39 million compared to the third quarter of 2007, primarily because production was 52 percent lower than the prior-year quarter. Output was severely impacted by the June 3, 2008, pipeline explosion and fire at Varanus Island which shut-in all production from the John Brookes and Harriet Joint Venture. In the month prior to the explosion, the fields were producing at an average net rate of 1,348 and 4,049 b/d, respectively. On August 5, 2008, partial production was restored at the John Brookes field, and in September, the field averaged 1,144 b/d. Production from the John Brookes field was fully restored in early October 2008. The Harriet Joint Venture remains shut-in awaiting repairs, and production is expected to come back online in the fourth quarter of 2008.

     Natural Gas RevenuesThird-quarter natural gas revenues increased $238 million driven by a 49 percent increase in realized prices. Worldwide production was down 13 percent. All core gas producing regions, with the exception of Australia, realized higher natural gas revenues.

     U.S. natural gas revenues increased $119 million as natural gas price realizations averaged $9.96, up $3.37 per Mcf from the prior-year period. Gulf Coast daily production was 29 percent lower on natural decline and approximately 112 MMcf/d of estimated production shut-in from tropical storms and hurricane activity in the Gulf Coast region, which more than offset gains from drilling and recompletion activity. Central region production was up two percent on acquired properties and drilling and recompletion activity, which more than offset natural decline and downtime.

     Egyptian gas revenues were $43 million higher than the comparable 2007 quarter. A 19 percent increase in both price realizations and production led to stronger revenues. Production was higher at the Khalda concession where the prior year’s quarter was negatively impacted by non-recurring gas plant shut-ins at Obayied and Salam. Production also rose with new wells at our Northeast Abu Gharadig Concession.

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     Canadian gas revenues increased $82 million, or 42 percent, led by stronger prices. Third-quarter natural gas realizations averaged $8.70 per Mcf, 57 percent higher than the prior year. Natural decline and property divestitures lowered production by 10 percent.

     Argentina’s natural gas revenues increased $11 million, or 67 percent, over last year on a 52 percent increase in realized price and an 11 percent rise in production. A successful drilling and workover program in the Neuquén Basin more than offset export and pipeline restrictions at Tierra del Fuego.

     Third-quarter 2008 Australian gas revenues fell $23 million from prior year, with production down 72 percent. As discussed above, the John Brookes and Harriet Joint Venture were shut-in following the pipeline explosion and fire at Varanus Island. In the month prior to the explosion, the fields were producing at an average net rate of 116,310 Mcf/d and 78,796 Mcf/d, respectively. On August 5, 2008, partial production was restored at the John Brookes field, and in September, the field averaged a net 107,286 Mcf/d. Production was fully restored in early October 2008. The Harriet Joint Venture remains shut-in awaiting repairs, and production is expected to come back online in the fourth quarter of 2008.

Year-to-Date 2008 compared to Year-to-Date 2007

     Crude Oil RevenuesYear-to-date crude oil revenues increased $2.7 billion on a 57 percent increase in average realized price and a four percent increase in daily production.

     U.S. oil revenues were $869 million higher, driven by a 48 percent increase in realized crude oil prices and a seven percent increase in daily production. Production increased six percent in the Gulf Coast region and seven percent in the Central region. Gulf Coast region production gains were associated with drilling and recompletion activity. Production shut-in because of the hurricanes averaged an estimated 6,000 b/d. Central region production was up from Permian Basin properties acquired at the end of March 2007. Prices in the U.S. averaged $91.48 per barrel in 2008 compared to $61.75 in 2007.

     Egypt’s crude oil revenues increased $838 million on a 65 percent increase in realized price and a six percent increase in daily crude oil production. Egypt’s 2008 price realizations were up $43.51 to $110.01 per barrel. Oil production in Egypt increased 3,863 b/d as new discoveries and recompletion and workover activities combined to more than offset the impact that higher commodity prices have on cost recovery volumes. Production rose on new wells at East Bahariya and development drilling at Umbarka.

     North Sea oil revenues increased $836 million, 89 percent higher than last year’s nine-month period. Revenue gains were driven by a 69 percent increase in realized price and a 12 percent increase in production. Oil price realizations averaged $110.08, up $44.87 per barrel. Production was higher with gains from new wells and workover activity more than offsetting natural decline.

     Canada’s oil revenues increased $183 million. Realized prices were up 70 percent and averaged $108.10 per barrel. Daily production declined eight percent on divested properties and natural decline in various fields, which more than offset drilling and recompletion activity.

     Argentina’s crude oil revenues increased $25 million with production up 10 percent and realized prices up seven percent. Higher production was related to successful drilling, workover and recompletion activities, particularly at Tierra del Fuego. Price restrictions in Argentina limited our oil price realizations and our ability to sell production at prevailing world prices.

     Australia’s oil revenues fell $32 million in the first nine months of 2008 compared to 2007. Production fell 6,022 b/d, a decline of 42 percent, on the Varanus Island pipeline explosion and fire previously mentioned.

     Natural Gas RevenuesYear-to-date natural gas revenues increased $721 million, driven by a 39 percent increase in realized natural gas prices. Worldwide production was down eight percent from 2007. All core gas producing regions saw higher natural gas revenues.

     U.S. natural gas revenues increased $423 million. Natural gas prices averaged $9.64, up $2.69 per Mcf. Production declined seven percent. Central region daily production was up four percent on drilling and recompletion activities and incremental volumes from Permian Basin properties acquired at the end of March 2007.

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Gulf Coast daily production was 14 percent lower on natural decline as well as downtime related to the hurricanes, which more than offset gains from drilling and recompletion activities.

     Canada’s natural gas revenues increased $182 million on a 38 percent increase in realized natural gas prices. Gas price realizations climbed $2.38 to $8.63 per Mcf. Natural gas production decreased eight percent because of natural decline in various areas and property divestitures.

     Egyptian gas revenues rose $107 million over last year’s amount on a six percent rise in production and a 29 percent increase in price realizations. Production from new discoveries and recompletion activities more than offset the reduction in cost recovery barrels associated with higher commodity prices. The production growth came from new wells and less relative downtime at Northeast Abu Gharadig and recompletion activities at Matruh.

     Argentina’s natural gas revenues increased $23 million, driven by a 49 percent increase in realized price. Production was down five percent, negatively impacted by gas re-injections at Tierra del Fuego related to gas export and pipeline restrictions.

     Australia’s natural gas revenues were down $23 million year-over-year, with sales impacted by a 36 percent drop in production related to the Varanus Island pipeline explosion and fire previously discussed.

Costs

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

	For the Quarter Ended September 30,								For the Nine Months Ended September 30,
	2008		2007		2008		2007		2008		2007		2008		2007
	(In millions)				(Per boe)				(In millions)				(Per boe)
Depreciation, depletion and amortization (DD&A):
Oil and gas property	$	560	$	565	$	11.93	$	10.94	$	1,734	$	1,619	$	11.72	$	10.65
Other assets		41		36		.86		.70		115		104		.78		.68
Total DD&A		601		601						1,849		1,723
Asset retirement obligation accretion		25		24		.53		.47		77		73		.52		.48
Lease operating costs		488		410		10.39		7.93		1,390		1,198		9.39		7.88
Gathering and transportation costs		43		35		.90		.67		123		100		.83		.66
Taxes other than income		304		140		6.48		2.70		846		393		5.72		2.59
General and administrative expense		58		61		1.22		1.19		219		200		1.48		1.32
Financing costs, net		33		60		.71		1.17		116		166		.79		1.09
Total	$	1,552	$	1,331	$	33.02	$	25.77	$	4,620	$	3,853	$	31.23	$	25.35

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Third Quarter 2008 compared to Third Quarter 2007

     Depreciation, Depletion and Amortization (DD&A)The following table details the changes in depletion of oil and gas properties between the three-month periods ended September 30, 2008 and 2007.

	For the Quarter
	Ended
	September 30,
	(In millions)
2007 depletion	$	565
Volume change		(65	)
Rate change		60
2008 depletion	$	560

     Full-cost depletion expense of $560 million decreased $5 million on an absolute dollar basis; $65 million on lower volumes, partially offset by a $60 million rate increase. The Company’s full-cost depletion rate increased $.99 to $11.93 per boe. The increase in rate reflects drilling and finding costs that continue to exceed our historical cost basis. The higher industry-wide costs, which also impact estimates of future development costs, have been driven by increased demand for drilling services, a consequence of recent higher oil and gas prices.

     Lease Operating Expenses (LOE)LOE increased 19 percent on an absolute dollar basis. On a per unit basis LOE was up 31 percent, or $2.46 per boe, with $1.17 of the increase associated with production shut-in at Varanus Island and in our Gulf Coast region because of the hurricanes.

     Factors impacting our LOE rate follow:

• Overall production declines resulted in an increase of $.95, with the impact from a combined 22 percent production decrease in the U.S., Canada and Australia partially offset by production growth in Egypt, the North Sea and Argentina. Individually, the chief contributors were production shut-in at Varanus Island, $.50; and production shut-in because of the hurricanes, $.67.

• Non-recurring repairs and maintenance, primarily in the U.S. and to Australia’s Varanus Island facility, increased LOE by $.50. These costs do not include any repairs for 2008 hurricane damage, which will commence in the fourth quarter of 2008.

• Increased workover activity, primarily in the U.S. and Egypt, added $.38.

• Increased labor costs and usage of materials, primarily in the U.S., Egypt, and Argentina, added $.11.

• Higher relative power rates and usage tacked on another $.27.

The remaining increase is caused by other minor variances, including increased gas buybacks and lower stock-based compensation.

     Gathering and TransportationGathering and transportation costs totaled $43 million, up $8 million. The following table presents gathering and transportation costs paid by Apache to third-party carriers for each of the periods presented.

	For the Quarter Ended
	September 30,
	2008		2007
	(In millions)
U.S.	$	12	$	10
Canada		16		15
North Sea		8		6
Egypt		6		3
Argentina		1		1
Total Gathering and Transportation	$	43	$	35

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     Higher transportation tariffs drove the increase in the U.S. Egypt was up on an increase in export volumes, while the North Sea increased on higher transportation tariffs and volumes.

     Taxes other than IncomeTaxes other than income increased $164 million from the corresponding prior-year period on higher product prices. A detail of these taxes follows:

	For the Quarter Ended
	September 30,
	2008		2007
	(In millions)
Ad Valorem taxes	$	16	$	15
Severance taxes		48		37
U.K. PRT		228		73
Canadian taxes		4		6
Other		8		9
Total Taxes other than Income	$	304	$	140

     North Sea Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the United Kingdom (U.K.) North Sea. U.K. PRT was $155 million more than the 2007 period on a 208 percent increase in net profits, primarily driven by a significant increase in revenues. Severance taxes are incurred primarily on onshore properties in the U.S. and certain properties in Australia and Argentina. The increase in severance taxes resulted from higher taxable revenues in the U.S., consistent with the higher realized oil and natural gas prices. Ad valorem taxes are assessed on U.S. and Canadian properties. The $1 million increase resulted from higher taxable valuations associated with higher oil and natural gas prices.

     General and Administrative Expenses (G&A)G&A expenses were $3 million lower. On a boe basis, G&A averaged $1.22, up $.03 per boe, with the impact from lower costs more than offset by reduced volumes. The decreased volumes added $.11 per boe to the rate, while costs reduced the rate $.08. Stock-based compensation was down because of a lower stock price, which impacts the Company’s Stock Appreciation Rights (SARs) value. This lower value offset higher incentive-based compensation and additional stock-based expense associated with new grants, reducing the 2008 rate $.15 per boe on a comparable basis. Higher legal fees along with other miscellaneous costs added $.07.

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

	For the Quarter Ended
	September 30,
	2008			2007
	(In millions)
Interest expense	$	66		$	83
Amortization of deferred loan costs		1			1
Capitalized interest		(24	)		(19	)
Interest income		(10	)		(5	)
Financing costs, net	$	33		$	60

     Interest expense decreased $17 million on lower average debt balances, which decreased 21 percent. Capitalized interest was up primarily because of higher expenditures associated with long-term construction projects that are under development. Interest income increased because of higher average cash balances.

     Provision for Income TaxesDuring interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. There were no significant changes in statutory tax rates in the major jurisdictions in which the Company operates during the third quarter of 2008 or 2007.

     The provision for income taxes increased $62 million to $623 million, 11 percent higher than the prior-year period taxes, as income before taxes increased 54 percent on significantly higher oil and gas production revenues. The effective income tax rate in the third quarter of 2008 was 34.3 percent compared to 47.8 percent in the third quarter of 2007. In the third quarter of 2008, Apache recorded a $114 million non-cash tax benefit, primarily on deferred taxes, related to the effect of the strengthening U.S. dollar on re-measurement of our foreign tax liabilities, compared to $114 million of additional tax expense from currency fluctuations during the third quarter of 2007.

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Year-to-Date 2008 compared to Year-to-Date 2007

     Depreciation, Depletion and AmortizationThe following table details the changes in depletion of oil and gas properties between the nine-month periods ended September 30, 2008 and 2007.

	For the Nine
	Months Ended
	September 30,
	(In millions)
2007 depletion	$	1,619
Volume change		(52	)
Rate change		167
2008 depletion	$	1,734

     Full-cost depletion expense increased $115 million, $167 million on rate offset by $52 million on lower volumes. The Company’s full-cost depletion rate increased $1.07 to $11.72 per boe. The increase in rate reflects drilling and finding costs that continue to exceed our historical cost basis. The higher industry-wide costs, which also impact estimates of future development costs, have been driven by increased demand for drilling services, a consequence of recent higher oil and gas prices.

     Lease Operating ExpensesLOE increased 16 percent on an absolute dollar basis. On a per unit basis LOE was up 19 percent, or $1.51 per boe, with $.44 of the increase associated with production shut-in at Varanus Island and in our Gulf Coast region because of the hurricanes.

     Factors impacting our LOE rate follow:

• Higher operating costs in all regions, including increased power costs in the U.S. and Egypt and increased labor costs in our North American regions, drove the rate up $.44.

• Increased workover activity, primarily in the U.S. and Egypt, resulted in an increase of $.39.

• Overall production declines resulted in an increase of $.26, with the impact from a combined 7 percent production decline in the U.S., Canada, Australia and Argentina partially offset by increased production in Egypt and the North Sea. The main contributors were production shut-in at Varanus Island, $.23; and production shut-in because of the hurricanes, $.21.

• The weakening U.S. dollar added $.17 to the rate. Over the past 12 months, the U.S. dollar weakened against the Australian and Canadian dollars and strengthened against the British Pound. Beginning in late September 2008 and continuing into October 2008, the U.S. dollar strengthened substantially against major currencies.

     These increases were partially offset by other minor variances, including a decrease in non-recurring repairs and maintenance.

     Gathering and TransportationGathering and transportation costs totaled $123 million, up $23 million. The following table presents gathering and transportation costs paid by Apache to third-party carriers for each of the periods presented.

	For the Nine Months Ended
	September 30,
	2008		2007
	(In millions)
U.S.	$	33	$	29
Canada		49		39
North Sea		23		19
Egypt		15		11
Argentina		3		2
Total Gathering and Transportation	$	123	$	100

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     The increase in Canada resulted primarily from the impact of higher transportation tariffs and foreign exchange rates. North Sea costs were up on increased volumes and higher transportation tariffs, while the U.S. costs were up on higher volumes and transportation tariffs.

     Taxes other than IncomeTaxes other than income totaled $846 million, an increase of $453 million on higher product prices. A detail of these taxes follows:

	For the Nine Months Ended
	September 30,
	2008		2007
	(In millions)
Ad Valorem taxes	$	55	$	40
Severance taxes		141		104
U.K. PRT		613		215
Canadian taxes		13		16
Other		24		18
Total Taxes other than Income	$	846	$	393

     U.K. PRT was $398 million more than the 2007 period on a 178 percent increase in net profits, primarily driven by higher oil revenues. The increase in severance taxes resulted from higher taxable revenues in the U.S., consistent with the higher realized oil and natural gas prices. The $15 million increase in ad valorem taxes resulted from higher taxable valuations associated with increases in oil and natural gas prices and the acquisition of Permian Basin properties late in the first quarter of 2007.

     General and Administrative ExpensesG&A was $19 million higher. On a boe basis, G&A averaged $1.48, up $.16 per boe with the impact of a combination of increased costs and lower volumes. The higher costs added $.12 to the rate, while decreased volumes added an additional $.04 per boe. The cost increase was related to higher employee incentive-based bonuses, insurance and legal fees.

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

	For the Nine Months Ended
	September 30,
	2008			2007
	(In millions)
Interest expense	$	201		$	230
Amortization of deferred loan costs		2			2
Capitalized interest		(68	)		(56	)
Interest income		(19	)		(10	)
Financing costs, net	$	116		$	166

     Interest expense was down $29 million on lower average debt, which decreased $658 million. Capitalized interest was up primarily because of higher expenditures associated with long-term construction projects that are under development.

     Provision for Income TaxesThere were no significant changes in statutory tax rates in the major jurisdictions in which the Company operates during the first nine months of 2008 or 2007.

     The provision for income taxes increased $788 million from 2007 to $2.2 billion, as income before taxes increased 87 percent on significantly higher oil and gas production revenues. The effective income tax rate for the first nine months of 2008 was 37.3 percent compared to 44.4 percent for the first nine months of 2007. The 2008 rate was lower because of a $127 million non-cash tax benefit, primarily on deferred taxes, related to the effect of the strengthening U.S. dollar on re-measurement of our foreign tax liabilities. The 2007 period included a $182 million non-cash tax charge, primarily on deferred taxes, from currency fluctuations.

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Capital Resources and Liquidity

  Sources and Uses of Cash

     The following table presents the sources and uses of our cash and cash equivalents for the nine-month periods ended September 30, 2008 and 2007. The table presents capital expenditures on a cash basis; therefore, the amounts differ from capital expenditures referred to elsewhere in this document, which include accruals.

	For the Nine Months Ended
	September 30,
	2008		2007
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	6,029	$	3,877
Sales of property and equipment		307		11
Fixed-rate debt borrowings		—		1,992
Common stock issuances		31		23
Other		50		33
		6,417		5,936
Uses of Cash and Cash Equivalents:
Oil and gas property		3,907		3,406
Acquisitions		156		1,005
Gas gathering, transmission and processing facilities		421		301
Restricted cash		14		—
Net commercial paper and money market repayments		169		948
Payments of fixed-rate debt		—		3
Dividends		188		153
Cost of debt and equity transactions		1		18
Other		42		131
		4,898		5,965
Increase (decrease) in Cash and Cash Equivalents	$	1,519	$	(29	)

     Net Cash Provided by Operating ActivitiesApache’s net cash provided by operating activities for the first nine months of 2008 totaled $6.0 billion, up $2.2 billion from the same period in 2007. For a detailed discussion of commodity prices, production, costs and expenses, refer to the “Results of Operations” of this Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     Historically, fluctuations in commodity prices have been the primary reason for the Company’s short-term changes in cash flow from operating activities. Sales volume changes have also impacted cash flow in the short-term but have not been as volatile as commodity prices. Apache’s long-term cash flow from operating activities is dependent on commodity prices, reserve replacement and the level of costs and expenses required for continued operations.

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     Capital ExpendituresCapital expenditures totaled $5.0 billion for the first nine months of 2008, compared to $4.8 billion for the comparable period last year. The following table presents a summary of the Company’s capital expenditures.

	For the Nine Months Ended
	September 30,
	2008		2007
	(In millions)
Exploration and Development:
United States	$	1,606	$	1,401
Canada		526		467
Egypt		624		435
Australia		662		366
North Sea		369		412
Argentina		235		186
Chile		11		—
		4,033		3,267
Acquisitions — Oil and Gas Properties		156		1,028
Asset Retirement Costs		350		155
Capitalized Interest		69		57
Gathering Transmission and Processing Facilities		406		299
Total Capital Expenditures	$	5,014	$	4,806

     Exploration and development (E&D) expenditures were $4.0 billion, up $766 million, or 23 percent, from the 2007 comparable period. The U.S. accounted for 40 percent of total E&D activity in the first nine months of 2008, down from 43 percent in the prior-year comparable period. Expenditures in the U.S. were up $205 million on higher drilling activity and less investment in platforms and production facilities located in the Gulf of Mexico. Canada accounted for 13 percent of worldwide E&D expenditures down from 14 percent in 2007. Canada’s E&D expenditures were up $59 million on increased drilling activity. Australia’s E&D expenditures totaled $662 million, nearly double 2007 spending. Australia’s portion of 2008 activity jumped to 16 percent from 11 percent in the comparable 2007 period. Australia’s higher expenditures related to increased exploration activity, development drilling on our Van Gogh property, and infrastructure spending on our Pyrenees project. Egypt spent $189 million more in the 2008 period on higher levels of drilling activity. North Sea E&D expenditures were down $43 million driven mainly by lower drilling activity.

     DividendsCommon stock dividends paid during the first nine months of 2008 rose to $183 million from $149 million in 2007, driven by a special cash dividend of 10 cents per common share paid on March 18, 2008. During the first nine months of 2008 and 2007, Apache paid $4.3 million in dividends on its Series B Preferred Stock issued in August 1998.

Liquidity

	September 30,			December 31,
	2008			2007
Millions of dollars except as indicated
Cash		1,645			126
Restricted cash		14			—
Total debt		4,058			4,227
Shareholders’ equity		18,763			15,378
Available committed borrowing capacity		2,300			2,115
Floating-rate debt/total debt		1	%		5	%
Percent of total debt to capitalization		18	%		22	%

     Cash and Cash EquivalentsWe had $1.6 billion in cash and cash equivalents at September 30, 2008, compared with $126 million at December 31, 2007. Nearly two-thirds of this cash is in our foreign subsidiaries ($570 million was in U.S.) and is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities, with maturities of three months or less at the time of purchase. We intend to use cash from our international subsidiaries to fund international projects.

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     Most of our cash is invested in obligations of the U.S. Government. Thus far, our liquidity and financial position have not been affected by recent events in the credit markets. We believe that losses from non-performance are unlikely to occur; however, we are not able to predict sudden changes in the creditworthiness of the financial institutions with which we do business.

     Restricted CashThe Company classifies cash balances as restricted cash when it is restricted as to withdrawal or usage. As of September 30, 2008, the Company had approximately $14 million of property divestiture proceeds classified as restricted cash and held in escrow available for use in a like-kind exchange under Section 1031 of the U.S. federal income tax code. The Company seeks to use these funds to acquire noncurrent assets. Accordingly, the restricted cash is classified as long-term on our consolidated balance sheet.

     DerivativesOur commodity derivative instruments are designated as cash flow hedges in accordance with SFAS 133. Under SFAS 133, unrealized gains and losses related to changes in fair value of cash flow hedges are deferred in other comprehensive income. Earnings and cash flows are not impacted until the derivatives are settled (when we either pay cash to, or receive cash from, our counterparties), which occurs contemporaneously with the hedged production. At settlement, if commodity prices exceed the fixed or ceiling price in our derivative instruments, our cash flows provided by the hedged production will be lower than if we had no derivative instruments. As of September 30, 2008, we had a net liability of $933 million, which represented the fair value of our unrealized commodity derivative instruments as of that date, $85 million of which relates to positions settling in the last three months of 2008. These unsettled positions, combined with the $517 million of derivative liabilities settled during the first nine months of the year, would reduce 2008 projected revenues by roughly four percent, assuming no change in quarter-end prices. The remaining liability would reduce projected future revenues over the periods 2009 through mid-2013 by two percent in 2009, 2010 and 2011, and less than one percent in 2012 and 2013. We expect future settlements of these liabilities to be funded by proceeds from the sale of the underlying production.

     Debt and Credit FacilitiesIn February 2008, the Company requested amendments to its existing $1.5 billion U.S. five-year revolving credit facility to (a) extend the maturity date one year to May 28, 2013 and (b) remove certain restrictions on our Australian entities including their ability to incur liens and issue guarantees. The Company also requested amendments to its $450 million U.S. credit facility, $150 million Australian credit facility and $150 million Canadian credit facility to (a) extend the maturity date one year to May 12, 2013, (b) remove certain restrictions on our Australian entities including their ability to incur liens and issue guarantees, and (c) specific to the Australian credit facility, give the Company the option of increasing the size of the facility up to a maximum amount of $400 million from the current limit of $300 million by adding commitments from new or existing lenders.

     Lenders approved the amendments removing certain restrictions on our Australian entities, including their ability to incur liens and issue guarantees, as well as the amendment allowing the Company to increase the size of Australian credit facility to a maximum of $400 million. The lenders also extended the maturity date on all of the credit facilities except for $50 million of the $1.5 billion U.S. credit facility and $40 million of the $450 million U.S. credit facility. In April 2008, the Company increased the Australian credit facility by $50 million to $200 million, half of the maximum amount, and as of April 30, lenders had extended the maturity dates on all of the credit facilities.

     The Company has available a $1.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates.

     As of September 30, 2008, Apache had no commercial paper outstanding. Our weighted-average interest rate for commercial paper was 3.85 percent and 5.45 percent for the first nine months of 2008 and 2007, respectively. 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 had available borrowing capacity under our total credit facilities of approximately $2.3 billion at September 30, 2008.

     As of September 30, 2008, current debt includes $100 million of notes due March 2009 and $41 million borrowed under uncommitted overdraft lines in Argentina.

     The Company was in compliance with the terms of all credit facilities as of September 30, 2008.

     Subsequent EventsOn October 1, 2008, the Company issued $400 million principal amount, $398 million net of discount, of senior unsecured 6.0-percent notes maturing September 15, 2013, and $400 million principal amount, $398 million net of discount, of senior unsecured 6.9-percent notes maturing September 15, 2018. The notes are

39

redeemable, as a whole or in part, at Apache’s options, subject to a make-whole premium. The proceeds will be used for general corporate purposes.

     Pricing TrendsFor the first nine months of the year, the Company’s average realized prices have been substantially higher than the previous year’s prices. In fact, prices continued a general upward trend until July of this year, at which time prices began to decline significantly. While our third-quarter realizations were higher than those for the same quarter last year, they were lower than our record realizations in the second quarter of 2008. Crude oil trades in a global market; consequently, prices for all types and grades of crude oil generally move in the same direction. Natural gas has a limited global transportation system and, therefore, is subject to local supply and demand conditions. Approximately two-thirds of our natural gas is sold in the North American market, which tracks New York Merchantile Exchange (NYMEX) prices, while the remaining is sold under fixed-price contracts in regulated markets. Following is a table of the published monthly average NYMEX prices in 2008:

	October		September		August		July
Crude Oil	$	76.77	$	104.41	$	116.73	$	134.42
Natural Gas	$	6.73	$	7.50	$	8.30	$	11.20

     While we are presently in a strong financial position, continued lower prices would negatively impact our future oil and gas production revenues, earnings and liquidity. Commodity prices are volatile and future prices cannot be accurately predicted. Apache’s investment decisions are based on longer-term commodity prices. For these reasons, we have historically based our capital expenditure budget on projected cash flows, modifying initial budgets in the event of significant changes in commodity prices. For the remainder of 2008, we expect some downward adjustments to our capital plans. Given the recent commodity price levels, our initial 2009 budgeted expenditures are likely to be substantially less than projected 2008 levels. We also believe that certain service costs will be reduced, but historically there has been a lag between a precipitous drop in commodity prices and the underlying service costs necessary to find, develop and produce oil and natural gas.

     Canadian RoyaltiesThe government of the Province of Alberta proposed increases to the royalty rates on oil and natural gas production beginning in 2009. The proposed changes are likely to be enacted and since they are price dependent, they could adversely impact future earnings and cash flows. As a result, we may limit our Alberta capital spending to shallow drilling activity, while reallocating remaining budgeted capital to other areas.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

     We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. Apache may use future contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from the Company’s price risk management activities that qualify for hedge treatment are generally recognized in oil and gas production revenues when the associated production occurs. Apache does not generally hold or issue derivative instruments for trading purposes.

     For the first nine months of 2008, approximately 20 percent of our natural gas production and 19 percent of our crude oil production for the nine-month period was subjected to financial derivative hedges. Hedges in place for the remainder of 2008 are expected to cover similar percentages of production.

     On September 30, 2008, the Company had open natural gas derivative hedges in an asset position with a fair value of $40 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $27 million, while a 10 percent decrease in prices would increase the fair value by approximately $31 million. The Company also had open oil derivatives in a liability position with a fair value of $973 million. A 10 percent increase in oil prices would decrease the fair value by approximately $316 million, while a 10 percent decrease in prices would increase the fair value by approximately $311 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2008. See Note 1 — Derivative Instruments and Hedging Activity of the Notes to consolidated financial statements in this quarterly report Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.

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Interest Rate Risk

     The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 99 percent of the Company’s debt. At September 30, 2008, total debt included $41 million of floating-rate debt. As a result, Apache’s annual interest costs in 2008 will fluctuate based on short-term interest rates on what is presently approximately one percent of our total debt outstanding at September 30, 2008. The impact on cash flow of a 10 percent change in the floating interest rate would be approximately $0.2 million per quarter on September 30, 2008.

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 the gas production is sold under fixed-price Australian dollar contracts. Approximately half of the costs incurred for Australian operations are paid in U.S. dollars. In Canada, the majority of oil and gas production is sold under Canadian dollar contracts. The majority of the costs incurred are paid in Canadian dollars. The North Sea production is sold under U.S. dollar contracts and the majority of costs incurred are paid in U.K. pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars but converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, Egyptian pounds and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.

     Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other,” or, as is the case when we re-measure our foreign tax liabilities, as a component of the Company’s provision for income tax expense on the Statement of Consolidated Operations.

Forward-Looking Statements and Risk

     Certain statements in this quarterly report on Form 10-Q, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.

     There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and costs overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although Apache may make use of futures contracts, swaps, options and fixed-price physical contracts to mitigate risk, fluctuations in oil and natural gas prices or a prolonged continuation of low prices, may adversely affect the Company’s financial position, results of operations and cash flows.

ITEM 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

     G. Steven Farris, the Company’s President, Chief Executive Officer and Chief Operating Officer, and Roger B. Plank, the Company’s Executive Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2008, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and communicated to our management, including our chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure.

41

     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 actions, 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.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Please refer to Part I, Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2007 (filed with the SEC on February 29, 2008) for a description of material legal proceedings.

ITEM 1A. RISK FACTORS

During the quarter ending September 30, 2008, there were no material changes from the risk factors as previously disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS

†*10.1	—	Apache Corporation 1995 Stock Option Plan, as amended and restated August 14, 2008.
†*10.2	—	Apache Corporation 1996 Performance Stock Option Plan, as amended and restated August 14, 2008
†*10.3	—	Apache Corporation 1998 Stock Option Plan, as amended and restated August 14, 2008.
†*10.4	—	Apache Corporation 2000 Stock Option Plan, as amended and restated August 14, 2008.
†*10.5	—	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated August 14, 2008.
†*10.6	—	Apache Corporation 2005 Stock Option Plan, as amended and restated August 14, 2008.
†*10.7	—	Apache Corporation 2005 Share Appreciation Plan, as amended and restated August 14, 2008.
†*10.8	—	Apache Corporation Executive Restricted Stock Plan, as amended and restated August 14, 2008.
†*10.9	—	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications.
*12.1	—	Statement of computation of ratio of earnings to fixed charges and combined fixed charges and preferred stock dividends.
*31.1	—	Certification of Chief Executive Officer.
*31.2	—	Certification of Chief Financial Officer.
*32.1	—	Certification of Chief Executive Officer and Chief Financial Officer.

†	Management contracts or compensation plans or arrangements.
*	Filed herewith

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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 10, 2008	/s/ ROGER B. PLANK
	Roger B. Plank
	Executive Vice President and Chief Financial Officer
Dated: November 10, 2008	/s/ REBECCA A. HOYT
	Rebecca A. Hoyt
	Vice President and Controller
	(Chief Accounting Officer)

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