UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 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
(State or other jurisdiction of incorporation or organization) 41-0747868
(I.R.S. Employer Identification No.)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices)

Registrant’s telephone number, including area code (713) 296-6000

Securities registered pursuant to Section 12(b) of the Act:

	Name of Each Exchange
Title of Each Class	On Which Registered
Common Stock, $0.625 par value	New York Stock Exchange,
	Chicago Stock Exchange and
	NASDAQ National Market
Preferred Stock Purchase Rights	New York Stock Exchange and
	Chicago Stock Exchange
Apache Finance Canada Corporation	New York Stock Exchange
7.75% Notes Due 2029
Irrevocably and Unconditionally
Guaranteed by Apache Corporation

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.625 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ  No o

Indicate by check mark if the registrant is not required to file reports pursuant to section 13 or Section 15(d) of the Act.  Yes o     No þ

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

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. (Check one):

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

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2008	$	46,488,719,719
Number of shares of registrant’s common stock outstanding as of January 31, 2009		334,753,638

DOCUMENTS INCORPORATED BY REFERENCE

Portions of registrant’s proxy statement relating to registrant’s 2009 annual meeting of stockholders have been incorporated by reference in parts II and III hereof.

TABLE OF CONTENTS

PART I
	ITEMS 1 AND 2. BUSINESS AND PROPERTIES
	ITEM 1A. RISK FACTORS
	ITEM 1B. UNRESOLVED SEC STAFF COMMENTS
	ITEM 3. LEGAL PROCEEDINGS
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
	ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
	ITEM 6. SELECTED FINANCIAL DATA
	ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	ITEM 9A. CONTROLS AND PROCEDURES
	ITEM 9B. OTHER INFORMATION
PART III
	ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	ITEM 11. EXECUTIVE COMPENSATION
	ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
	ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
	ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
	ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
SIGNATURES
REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
STATEMENT OF CONSOLIDATED OPERATIONS
STATEMENT OF CONSOLIDATED CASH FLOWS
CONSOLIDATED BALANCE SHEET
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EX-10.17
EX-10.19
EX-10.20
EX-10.21
EX-10.22
EX-10.23
EX-10.24
EX-10.25
EX-10.35
EX-10.36
EX-10.37
EX-10.38
EX-10.39
EX-10.44
EX-12.1
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1

PART I

ITEMS 1 AND 2.   BUSINESS AND PROPERTIES

General

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. In North America, our exploration and production interests are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin and the Western Sedimentary basin of Canada. Outside of North America, we have exploration and production interests onshore Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea), and onshore Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego. Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since 2004. On May 23, 2008, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of our Board of Directors, other documents related to Apache’s corporate governance (including our Code of Business Conduct and Governance Principles), and documents Apache files with the Securities and Exchange Commission (SEC), including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. Included in our annual and quarterly reports are the certifications of our principal executive officer and our principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. You may also request printed copies of our committee charters or other governance documents free of charge by writing to our corporate secretary at the address on the cover of this report. Our reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov. From time to time, we also post announcements, updates and investor information on our website in addition to copies of all recent press releases.

We hold interests in many of our United States (U.S.), Canadian, and other international properties through subsidiaries, including Apache Canada Ltd., DEK Energy Company (DEKALB), Apache Energy Limited (AEL), Apache North America, Inc., and Apache Overseas, Inc. Properties which we refer in this document may be held by those subsidiaries. We treat all operations as one line of business. References to “Apache” or the “Company” include Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.

Growth Strategy

Apache’s mission is to grow a profitable upstream oil and gas company for the long-term benefit of our shareholders. Our strategy includes building a balanced portfolio of assets, maintaining financial flexibility, and maximizing earnings and cash flows by controlling costs.

We have a portfolio of core areas that provide long-term growth opportunities through organic drilling supplemented by strategic acquisitions. Two decades ago, recognizing that the United States was a mature oil and gas province, we launched an international exploration component to our portfolio approach. Our international locations provide additional diversity of geologic and geographic risk as well as exposure to larger reserve targets, which fuel production and reserve growth. We have exploration and production operations in six countries, comprising seven regions: the Gulf Coast and Central regions in the United States, Canada, Egypt, the North Sea, Australia and Argentina. We have exploration interests in Chile located adjacent to our Argentine operations in Tierra del Fuego. We have achieved a critical mass in each of our producing regions that support sustainable, lower-risk, repeatable drilling opportunities. This enables us to pursue higher-risk, higher-reward exploration primarily in our international regions, particularly our growth areas of Australia, Canada and Egypt. Our acreage positions, which include 39 million gross acres across the globe, also bring ample growth opportunities.

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In 2008, we drilled or participated in 1,418 gross wells with an overall 93 percent success rate; 90 percent were developmental and 10 percent were exploratory. We carefully spread our risk among our regions. For instance, no single region contributed more than 23 percent of our production or reserves in 2008. Our multiple geological locations also provide us a mixture in reserve life, which translates into balance in the timing of returns on our investments. Reserve life (estimated reserves divided by annual production) in our regions ranges from as short as seven years to as long as 27 years.

In addition, our goal is to balance our mix of hydrocarbons, which provides some measure of protection against price deterioration in a given product while retaining upside potential through a significant increase in either commodity price. In 2008, crude oil and liquids provided 50 percent of our production and 68 percent of our revenue. We were well-positioned to realize the benefit of higher oil prices, which significantly outpaced natural gas price increases for much of the year, despite falling 70 percent from their June 2008 peak. Our year-end estimated proved reserves were balanced at 55 percent natural gas and 45 percent crude oil and liquids.

Preserving financial flexibility and a strong balance sheet are also key to our overall business philosophy. We ended 2008 with a debt-to-capitalization ratio of 23 percent, after current year capital investments of $6.3 billion, excluding asset retirement costs. We also had over $1.5 billion of cash and short-term investments. In tightening credit markets, we believe Apache’s single-A debt ratings provide a competitive advantage in accessing capital. Our 2008 return on capital employed and return on equity of four percent and five percent, respectively, was negatively impacted by a non-cash write-down (discussed in Item 7 of this Form 10-K).

Another critical component of our overall strategy is maximization of earnings and cash flow. Both are significantly impacted by commodity prices, which fluctuate and are primarily influenced by factors beyond our control, including worldwide supply and demand, political stability and governmental actions and regulations. For example, demand for energy, once thought to be insatiable, waned, driving prices down. Prices began the year strong and soared to unprecedented levels in mid-2008, only to fall rapidly by year-end, as the financial markets and ultimately the world’s economies stalled.

We also strive to control costs of both adding and producing reserves. Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems underscore high cash flows and motivate appropriate risk taking to reach or exceed targeted hurdle rates of return. Results are measured monthly, reviewed with management quarterly and utilized to determine annual performance awards. We monitor capital allocations, at least quarterly, through a disciplined and focused process of analyzing current economic conditions in each of our regions, internally generated drilling prospects, opportunities for tactical acquisitions or, occasionally, new core areas which could enhance our portfolio. We also periodically evaluate our properties to determine whether sales of certain assets could provide opportunities to redeploy our capital resources to rebalance our portfolio and enhance prospective returns.

The global economic slowdown and decline in oil and gas prices create a difficult operating environment for 2009. In preparation, we have substantially reduced our capital budget for 2009 in an effort to keep our expenditures in line with our cash flow. In 2009, we plan to invest $3.5 to $4.0 billion on capital expenditures, which is 50 percent less than in 2008. Our plan includes investments for drilling and recompleting wells, development projects, waterflood projects, equipment upgrades, production enhancement projects and seismic acquisition. Also included is $300 million for gathering, transmission and processing (GTP) assets and $500 million for plugging and abandonment work, of which $250 million is for damage caused by Hurricanes Katrina, Rita and Ike. As is our custom, we will review and revise our capital expenditure estimates throughout the year based on changing industry conditions and results-to-date. Additionally, we plan to step up our search for opportunities to acquire oil and gas properties where we believe we can add value and earn adequate rates of return.

During our 54 years in business and throughout the cycles of our industry, these strategies have underpinned our ability to deliver long-term production growth, increase proved reserves at a reasonable economic cost and achieve competitive investment rates of return for the benefit of our shareholders. We increased reserves 22 out of 23 years and increased production 28 out of the past 30 years, a testament to our longevity. While the business environment in 2009 is likely to be challenging, we believe we are in a strong financial position and are well-positioned to take advantage of what could be some of the most attractive acquisition opportunities in years.

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Region Overviews

We currently have exploration and production interests in six countries, divided into seven operating regions: the United States (Gulf Coast and Central regions), Canada, Egypt, Australia, offshore the United Kingdom in the North Sea and Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego, which we acquired in the second quarter of 2008.

The following table sets out a brief comparative summary of certain key 2008 data for each of our operating areas. Additional data and discussion is provided in Item 7 of this Form 10-K.

										Percentage			2008		2008 Gross
			Percentage					12/31/08		of Total			Gross		New
			of Total			2008		Estimated		Estimated			New		Productive
	2008		2008			Production		Proved		Proved			Wells		Wells
	Production		Production			Revenue		Reserves		Reserves			Drilled		Drilled
	(In MMboe)					(In millions)		(In MMboe)
Region/Country:
Gulf Coast		43.1		22	%		3,076		334.8		14	%		116		90
Central		33.4		17			2,007		602.8		25			415		404
Total U.S.		76.5		39			5,083		937.6		39			531		494
Canada		28.6		15			1,651		523.0		22			484		471
Total North America		105.1		54			6,734		1,460.6		61			1,015		965
Egypt		40.5		21			2,739		342.9		14			260		236
Australia		10.5		5			372		285.5		12			46		34
North Sea		22.0		11			2,103		188.8		8			14		12
Argentina		17.5		9			380		122.8		5			83		72
Total International		90.5		46			5,594		940.0		39			403		354
Total		195.6		100	%		12,328		2,400.6		100	%		1,418		1,319

United States

In the U.S., the Gulf Coast region historically generates high returns on invested capital and cash flow significantly in excess of its exploration and development spending. Occasional acquisitions have played an important role, as steep decline rates mean offshore reserves are generally shorter-lived and difficult to replace on a cost-effective basis through drilling alone. The Central region brings the balance of long-lived reserves and consistent drilling results to the portfolio. Apache’s future growth in the U.S. is more likely to be achieved through a combination of drilling and acquisitions than through drilling activity alone.

Gulf Coast Region  The region comprises our interests in and along the Gulf of Mexico, in the areas on and offshore Louisiana and Texas. In waters less than 1,200 feet deep in the Gulf of Mexico, Apache is the largest producer and, since 2004, has been the largest held-by-production acreage holder. In 2008, the region contributed approximately 22 percent of our production and approximately 25 percent of our revenues and, at year-end, held approximately 14 percent of our estimated proved reserves.

The region had a productive year even though a considerable amount of effort was expended on evacuations and repair related to Hurricanes Gustav and Ike. We drilled 116 wells, 90 of which were completed as producers, and performed 358 workover and recompletions. In June 2008, we had a key discovery at the Geauxpher prospect located on Garden Banks Block 462 in deepwater Gulf of Mexico. Apache generated the prospect and has a 40 percent working interest. Mariner Energy, Inc. is the designated operator of the block with a 60 percent working interest. A delineation well was drilled in December 2008, extending the productive reservoir limits. We project the initial discovery to be online in the second quarter of 2009. Additional potential on the block is expected to be tested by further drilling. At Ewing Banks 826, we completed four wells during the first half of 2008 and increased

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production to 6,315 b/d from 700 b/d at the beginning of the year. We own a 100 percent working interest in the field. In addition, significant progress was achieved toward wrapping up remaining abandonments associated with Hurricanes Katrina and Rita in 2005 and repairing damage and restoring shut-in production attributable to Hurricanes Gustav and Ike in 2008.

Central Region  The Central region includes assets in East Texas, the Permian basin of West Texas and New Mexico and the Anadarko basin of western Oklahoma and the Texas Panhandle, where the Company got its start over 50 years ago. At year-end 2008, the Central region accounted for approximately 25 percent of our estimated proved reserves, the largest concentration in the Company. During 2008, we participated in drilling 415 wells in the Central region, 404 of which were completed as producers. Apache also performed 1,210 workovers and recompletions in the region during the year.

Marketing  In general, most of our U.S. gas is sold at either monthly or daily market prices. Our natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, integrated major oil and gas companies and marketers. Approximately two percent of our 2008 U.S. natural gas production was sold under physical long-term fixed-price contracts, all of which expired in 2008. See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk Commodity Risk” in this Form 10-K.

Apache primarily markets its U.S. crude oil to integrated major oil companies, purchasers, transporters and refiners. The objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at market prevailing prices.

We manage our credit risk by selling our oil and gas to diverse counterparties and monitoring our exposure on a daily basis.

Canada

In our Canadian region, we have 4.9 million net acres across the provinces of British Columbia, Alberta and Saskatchewan, which provide a significant inventory of both low-risk development drilling opportunities in and around a number of Apache fields and higher-risk, higher-reward exploration opportunities. In 2008, we drilled 484 wells in Canada, with 471 completed as producers. Three percent of the wells drilled during the year were exploration wells, half of which were productive. We performed 531 workover and recompletion projects. The region comprises approximately 22 percent of our estimated proved reserves, the second largest concentration in the Company.

In 2009, we will continue our pursuit of the emerging shale-gas play in northeast British Columbia, where we have over 217,000 highly prospective net acres. Apache completed seven horizontal wells at the Ootla shale-gas play in the Horn River Basin during 2008. The last completed well utilized a 10-stage fracture stimulation. Apache plans to continue to develop the optimum strategy for Ootla well completions in 2009. In addition, we plan to drill exploratory wells to test other emerging plays in both Alberta and northeast British Columbia during 2009.

We will also continue to target shallow gas, including coal bed methane (CBM), in the Provost, North Grant Land and Nevis areas. As a result of these efforts, we believe Apache has emerged as one of Canada’s largest producers of CBM. We are also utilizing horizontal well technology to develop waterflood and enhanced oil recovery projects in the Midale field located in southeast Saskatchewan, and the Zama and House Mountain fields located in Alberta. Intermediate depth gas development drilling continues in the Kaybob, West 5 and South Grant Land areas of central and southern Alberta.

Marketing  Our Canadian natural gas marketing activities focus on sales to LDCs, utilities, end-users, integrated major oil companies, supply aggregators and marketers. Our composite client portfolio is diverse with the intent of reducing the concentration of credit risk in our portfolio. Improved North American natural gas pipeline connectivity over the years has led to a closer correlation between Canadian and U.S. natural gas prices. To diversify our market exposure and optimize pricing differences in the U.S. and Canada, we transport natural gas via our firm transportation contracts to California, the Chicago area, and eastern Canada. We sell the majority of our Canadian

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production on a monthly basis, either into the first- of-the-month market or the daily market. In 2008, approximately two percent of our gas sales were subject to long-term fixed-price contracts with the latest expiration in 2011.

Our Canadian crude oil is primarily sold to refiners, integrated major oil companies and marketers. To increase the market value of our condensate and heavier crudes, our condensate is generally either used or sold for blending purposes. We sell our oil and natural gas liquids (NGLs) on crude oil postings, which are market-reflective prices that depend on worldwide crude oil prices and are adjusted for transportation and quality. In order to reach more purchasers and diversify our market, we transport crude oil on 12 pipelines to the major trading hubs within Alberta and Saskatchewan.

Egypt

Egypt holds our largest acreage position with more than 11 million gross acres, following relinquishments in January 2009, in 23 separate concessions (19 producing concessions) that provide a sizable resource in the Cretaceous Upper Bahariya formations and outstanding exploration potential in deeper intervals from Lower Cretaceous to Jurassic. In addition to being the largest acreage holder in Egypt, we believe that Apache is the largest producer of liquid hydrocarbons and natural gas in the Western Desert and the third largest in all of Egypt. In 2008, our Egypt region contributed 22 percent of Apache’s production revenue, 21 percent of total production, and 14 percent of total estimated proved reserves. The Company reports all estimated proved reserves held under production sharing agreements utilizing the economic interest method, which excludes the host country’s share of reserves. In 2008, Apache had an active drilling program in Egypt, completing 236 of 260 wells, a 91 percent success rate, and conducted 701 workovers and recompletions. Historically, our growth in Egypt has been driven by drilling; we are the most active driller in Egypt.

In the Khalda concession two additional Salam gas processing trains, three and four, and an associated Apache pipeline compression project on the Western Desert Northern Gas Pipeline are forecasted to add additional net production of 100 MMcf/d and 5,000 b/d when fully operational in the second quarter of 2009. The third processing train commenced operations on December 4, 2008. Commissioning with first gas from the fourth processing train is projected to commence during the first quarter of 2009.

In Egypt, our operations are conducted pursuant to production sharing contracts under which the contractor partner pays all operating and capital expenditure costs for exploration and development. A percentage of the production, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs. In general, the balance of the production is allocated between the contractor partners and Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Development leases within concessions generally have a 25-year life with extensions possible for additional commercial discoveries or on a negotiated basis.

Marketing  Our gas production is sold to EGPC under an industry-pricing formula, a sliding scale based on Dated-Brent crude oil with a minimum of $1.50 per MMbtu and a maximum of $2.65 per MMbtu, which corresponds to a Dated-Brent price of $21.00 per barrel. Generally, the industry-pricing formula applies to all new gas discovered and produced. In exchange for extension of the Khalda Concession lease in July 2004, Apache agreed to accept the industry-pricing formula on a majority of gas sold but retained the previous gas-price formula (without a price cap) until 2013 for up to 100 MMcf/d gross.

Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is sold directly to EGPC or other third parties. Oil sales are made either directly into the Egyptian oil pipeline grid, exported or sold at one of two terminals on the northern coast of Egypt or sold to non-governmental third parties including the Middle East Oil Refinery located in northern Egypt. Oil production that is presently sold to EGPC is sold on a spot basis at the monthly EGPC quoted price (indexed to Brent). In 2008, we sold 34 cargoes (approximately 10.1 million barrels) of Western Desert crude oil from the El Hamra terminal located on the northern coast of Egypt into the export market. These export cargoes were sold to EGPC at market prices above our domestic sales. Additionally, Apache sold Qarun quality oil (approximately 7.6 million barrels) at the Sidi Kerir terminal, also located on the northern coast of Egypt. This Qarun oil was sold at prevailing market prices into the domestic market to non-governmental purchasers (three million barrels) or exported to buyers in the Mediterranean markets (11

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cargoes for approximately 4.6 million barrels). We expect sales to the export market from both the Khalda and Qarun areas in the Western Desert to continue in 2009.

Australia

Overview — In Australia, our exploration activity is focused in the offshore Carnarvon, Gippsland and Browse basins, where Apache holds 5.2 million net acres in 34 exploration permits, 11 production licenses and five retention leases.

Production operations are concentrated in the Carnarvon and Exmouth basins, the location of Apache’s 11 production licenses, all of which are Apache operated. In 2008, the region generated $372 million of production revenues from the sale of 10.5 MMboe, approximately five percent of our total production. Australia held 12 percent of our year-end estimated proved reserves. During the year, the region participated in drilling 46 wells, which generated 25 productive oil wells and nine productive gas wells.

Our growth strategy includes development in the Carnarvon basin and in areas adjacent to this core area. As of the end of 2008, our Van Gogh and Pyrenees projects in the Exmouth basin were under active development. We had also initiated a development project related to our 2008 Halyard discovery (discussed below) and began appraising our large Julimar discovery (also discussed below). We completed planned development drilling at our Reindeer field.

Van Gogh is Apache-operated, while Pyrenees is operated by BHP Billiton. Van Gogh development drilling and sub-sea production equipment installation is well underway, with first oil production slated for mid-2009 through a floating production storage and offloading tanker. Additional development drilling is planned in 2009 prior to the start of production. Pyrenees development drilling is expected to commence in 2009 with first oil production expected in the first half of 2010. Production from each field is estimated at 20,000 b/d net to Apache.

In April 2008, we drilled the Halyard-1 well, which tested 68 MMcf/d of gas and was completed as a producer. The Halyard field is expected to be tied-in to the nearby East Spar gas facilities once a market for the gas is under contract. Apache holds a 55 percent interest in the field. Additional appraisal in 2009 is necessary on the Julimar gas discovery before proceeding with a development plan. Based on current geological mapping, we believe that Julimar could be a multi-Tcf discovery. Apache owns a 65 percent interest in and operates the Julimar-Brunello complex.

During the fourth quarter of 2008, Apache completed a three-well development drilling campaign at the Reindeer field. On January 6, 2009, we secured a 154 Bcf, 7-year gas sales contract that allowed us to reinstate our Reindeer development, which was suspended at the end of 2008 program because of a delay in gas sales contract negotiations. Negotiations were delayed by the onset of the global economic crisis and the resulting drop in metal prices. The gas will be supplied through a new 65-mile offshore pipeline and a new onshore gas processing facility at Devil Creek. This sales contract is discussed in more detail below under “Subsequent Events.” Construction of pipeline and processing infrastructure is scheduled to commence in 2009 with first production anticipated in 2011. Apache owns a 55-percent interest in the field.

We are currently evaluating the results of wells drilled in 2008 and seismic information to assess the future potential in the Gippsland basin. All six wells drilled in 2008 were either dry or non-commercial.

Varanus Island — On June 3, 2008, subsidiaries of the Company reported a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia, which shut-in production from the John Brookes field and Harriet Joint Venture. When fully operational, the Island’s operations process approximately 195 MMcf/d and 5,400 b/d, net to Apache subsidiaries. On August 5, 2008, partial production was reestablished from the John Brookes field and by year-end was at greater than 80 percent pre-incident levels. The Harriet Joint Venture gas facilities are located adjacent to the pipeline explosion and required more significant repairs to restore operation. A portion of the gas production from the Harriet Joint Venture was restored in December 2008 and is projected to be fully restored in the first half of 2009. Harriet Joint Venture oil production is projected to be fully restored in the first quarter of 2009. 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 accounted for the remaining 40 percent and 75 percent of the island’s pre-incident natural gas and oil production,

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respectively. 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.

During 2009, our Australian region plans to focus on its major field development projects and, to a lesser extent, its exploration and appraisal activities.

Marketing  As of December 31, 2008, Apache had a total of 18 active gas contracts in Australia with expiration dates ranging from March 2010 to July 2030. Generally, natural gas is sold in Western Australia under long-term, fixed-price contracts, many of which contain price escalation clauses based on the Australian consumer price index.

We continue to export all of our crude oil production into international markets at prices indexed to Asian benchmark crude oil prices, which typically track at or above New York Mercantile Exchange (NYMEX) oil prices.

North Sea

Apache entered the North Sea in 2003 upon acquiring an approximate 97 percent working interest in the Forties field (Forties). Our drilling program and continued improvements in plant efficiencies led to an 11 percent increase in 2008 production. We expect to increase our North Sea production in 2009 relative to 2008. We also have several targeted facilities projects planned for 2009 to further improve the efficiency of our operations in the North Sea.

In 2008, the North Sea region produced 21.9 MMboe, approximately 11 percent of our total production, generating slightly more than $2.1 billion of revenue and accounting for approximately eight percent of our year-end estimated proved reserves. In 2008, we invested $459 million in the North Sea on drilling and recompleting wells and facility enhancement programs. We drilled 14 wells in the North Sea during 2008, 12 of which were producers. We completed and commissioned a number of key projects in the North Sea region during 2008, including replacing the key import header on the Charlie platform that services the field export system, high-pressure gas-lift compression projects on the Alpha and Delta platforms, a large produced water reinjection system on the Charlie platform and replacement of the infield pipeline between the Bravo and Charlie platforms. Investments in facility upgrades and integrity-related projects over the past five years have continually increased the efficiency of our operations.

Drilling successes and improved platform operating efficiencies led to fourth-quarter 2008 production of 61,740 b/d. During 2008, production averaged 59,494 b/d. The 2008 annual maintenance shut down on the Charlie platform impacted the field by 1,330 b/d, which was an improvement compared to 2,270 b/d impact in 2007. The new import header on the Charlie platform enabled the platform to be shut in for planned maintenance activities without impacting production export operations from the other field platforms.

Marketing  In 2008, we entered into two new term contracts for the physical sale of Forties crude at prevailing market prices. These term sales are composed of base-market indices, adjusted for the quality difference between the Forties crude and Brent, with a premium to reflect the higher market value for term arrangements. In addition to the term sales, Apache sold 11 spot cargoes of approximately 600,000 barrels each and received value at or above the prevailing market prices.

Argentina

Argentina became our latest core area following two significant acquisitions in 2006 that substantially increased our presence in the country. In the second quarter of 2006, we completed our purchase of Pioneer’s operations in Argentina for $675 million, with estimated proved reserves of 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas. In the third quarter of 2006, we acquired additional interests in (and now operate) seven concessions in Tierra del Fuego (TdF) from Pan American for $429 million. With the addition of Mendoza CCyB Block 17B in 2008, our oil and gas assets are located in the Neuquén, Austral and Cuyo basins of Argentina. While Argentina presents unique challenges with evolving governmental regulations, we are optimistic about our ability to find additional hydrocarbons with the drill bit and to grow our reserves and production over the long-term.

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In 2008, our Argentina region continued its broad drilling and recompletion programs. The region drilled 83 wells, 72 of which were productive. We produced 17.5 MMboe in 2008, which accounted for nine percent of Apache’s total production. Argentina holds approximately five percent of our total estimated proved reserves.

In December 2008, the Mendoza Province granted Apache an exploration permit for CCyB Block 17B in the Cuyo basin, increasing our Argentine acreage by 34 percent. The block is adjacent to and along a trend of existing producing fields.

We also completed a nearly 2,500 square kilometer three-dimensional (3-D) seismic mega shoot in Tierra del Fuego. which aided in the identification of prospects and increased Apache’s ability to drill productive wells. In the Austral Basin of Tierra del Fuego, Apache made discoveries on operated blocks in which we own a 70 percent working interest, including the San Sebastian area, where Apache successfully drilled three kilometers from the shore to test a new separate oil structure in the San Sebastian field. Apache also discovered a new field, Sección Veintinueve, and a field extension to the Sara Norte field. Apache believes that the new 3-D seismic survey will continue to generate an inventory of drilling prospects.

On the mainland, we continued our drilling and recompletion campaigns in our established gas areas in the Neuquén basin. We drilled 11 new wells in our Estacion Fernandez Oro field, 10 new wells in our Guanaco field including a new deeper gas pool and 9 new wells in our Ranquil Co field, with a success rate of 100 percent. Apache plans to continue drilling in each of these fields in 2009. We also drilled a successful exploratory well on our Collon Cura exploration lease, fulfilling our license obligations.

Marketing  In 2008, 52 percent of our natural gas portfolio was regulated based upon certain market segments. We realized an average price of $.92 per Mcf on sales to regulated market segments in 2008. The remaining free market volumes were sold either on a monthly or daily basis or under term contracts, some of which extend through 2009. The average price received for free market volumes during the fourth quarter 2008 was $2.28 per Mcf, versus a fourth-quarter 2007 price of $2.32, a decrease of two percent primarily because of lower spot price sales in Tierra del Fuego.

Taxes on exported oil effectively limits prices buyers are willing to pay for domestic sales. Domestic oil prices are currently based on $42 per barrel, plus quality adjustments, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, the price cap applies, but Apache retains the value-added tax collected from buyers, effectively increasing realized prices by 21 percent. In 2008, we received an average price of $49.46 per barrel for crude oil.

Chile

In November 2007, Apache was awarded exploration rights on two blocks comprising one million net acres in Tierra del Fuego, following a bid round. This acreage is adjacent to our 552,000 net acres on the Argentine side of the island of Tierra del Fuego, and the additional acreage represents a natural extension of our expanding exploration and production operations. In 2008, Apache finalized the contracts with the Chilean government in July and shot a 3-D seismic survey. In 2009, we plan to process and interpret this seismic data in order to validate prospects and identify initial drilling locations.

Major Customers

In 2008, purchases by Shell accounted for 17 percent of the company’s oil and gas production revenues.

Subsequent Events

Australian Gas Sales Contract  On January 6, 2009, Apache signed a contract to supply natural gas from its Reindeer field to CITIC Pacific’s Sino Iron project in Western Australia. Apache and its joint venture partner agreed to supply 154 billion cubic feet of gas over seven years, beginning in the second half of 2011. Apache owns a 55-percent interest in the field.

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The gas will be supplied through a new, 65-mile offshore pipeline and a new onshore sales gas processing facility at Devil Creek, about 28 miles southwest of Dampier, with capacity to process 210 MMcf/d. Apache plans to sell additional production from the Reindeer field to other domestic customers in Western Australia.

The contract price for the first three years is a fixed price adjusted periodically for changes in the Australian consumer price index. Beginning in the fourth year, the price is indexed to international oil prices. At an oil price of $50 per barrel, Apache’s net share of the revenue over the seven years of the contract would be approximately $700 million.

The gas sales agreement will not take effect unless Apache and its joint venture partner sign contracts for engineering and procurement of the gas plant and pipeline by mid-March 2009 (or a later date if agreed by all parties).

Management Changes  On January 15, 2009, Raymond Plank retired as Chairman of the Board, a director, and an employee of Apache. Mr. Plank founded Apache in 1954 and had served as an officer of the Company since 1954 (President and/or Chief Executive Officer from 1954 to 2002 and Chairman of the Board since 1979). He had been a director of the Company since 1954. G. Steven Farris, Apache’s president, chief executive officer and chief operating officer since 2002, succeeded Mr. Plank as chairman.

Also on January 15, 2009, Apache and Mr. Plank entered into an amendment and restatement of his employment agreement dated December 5, 1990, pursuant to which he agreed to provide consulting services to the Company for the remainder of his life.

On February 12, 2009, Mr. Farris formed an office of the chief executive with three key executives reporting to him. Messrs. Roger B. Plank, John A. Crum and Rodney J. Eichler were appointed to new positions effective as of February 12, 2009. Mr. Roger Plank now serves as president, Mr. Crum serves as co-chief operating officer and president — North America, and Mr. Eichler serves as co-chief operating officer and president — International. Although Messrs. Roger Plank, Crum and Eichler have separate functional responsibilities, they have joint and equal roles in the daily decision-making and direction of Apache. Mr. Farris continues to serve as chairman and chief executive officer of Apache and has resigned from his positions of president and chief operating officer of Apache effective February 12, 2009. Mr. Farris continues to serve as Apache’s principal executive officer and, in his new role as president, Mr. Roger Plank continues to serve as Apache’s principal financial officer.

Canadian Gas Pipeline Contract  On February 10, 2009, Apache’s wholly-owned subsidiary, Apache Canada Ltd entered into an agreement with TransCanada Pipelines Limited (TCPL) pursuant to which TCPL will construct and install a gas pipeline from northeastern British Columbia to the existing NOVA pipeline system located in the Ekwan area of Alberta. Apache Canada intends to ship gas produced from the Ootla basin on the new pipeline.

The construction, operation and transportation rates of the new pipeline are subject to regulatory approval. We expect to receive authority to construct the pipeline, and construction is expected to be complete on or before April 1, 2011. Upon completion of the pipeline, Apache Canada will have a ship-or-pay commitment to ship 100 MMBtu/d for either a four-year period or a ten-year period, depending on the rate structure determined and approved by the regulatory agency. Apache Canada has the right to terminate the agreement before October 1, 2009. If Apache Canada elects to terminate the agreement or TCPL terminates for reasons set forth in the agreement, Apache Canada must reimburse TCPL for certain costs and expenses up to CDN $90 million plus certain taxes.

Drilling Statistics

Worldwide, in 2008, we participated in drilling 1,418 gross wells, with 1,319 (93 percent) completed as producers. We also performed more than 2,800 workovers and recompletions during the year. Historically, our drilling activities in the U.S. have generally concentrated on exploitation and extension of existing, producing fields rather than exploration. As a general matter, our operations outside of the U.S. focus on a mix of exploration and exploitation wells. In addition to our completed wells, at year-end several wells had not yet reached completion: 91 in the U.S. (56.3 net); 10 in Canada (9.7 net); 36 in Egypt (33.5 net); 2 in Australia (1.6 net); 2 in the North Sea (1.9 net); and 9 in Argentina (8.7 net).

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The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:

	Net Exploratory						Net Development						Total Net Wells
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
2008
United States		4.5		6.6		11.1		334.8		25.3		360.1		339.3		31.9		371.2
Canada		3.9		5.0		8.9		328.0		10.1		338.1		331.9		15.1		347.0
Egypt		18.7		11.5		30.2		193.2		5.8		199.0		211.9		17.3		229.2
Australia		6.4		9.0		15.4		12.5		—		12.5		18.9		9.0		27.9
North Sea		—		—		—		11.7		—		11.7		11.7		—		11.7
Argentina		7.5		2.0		9.5		54.4		6.2		60.6		61.9		8.2		70.1
Total		41.0		34.1		75.1		934.6		47.4		982.0		975.6		81.5		1,057.1
2007
United States		3.0		3.1		6.1		264.9		16.5		281.4		267.9		19.6		287.5
Canada		9.5		15.5		25.0		206.0		35.4		241.4		215.5		50.9		266.4
Egypt		10.7		13.0		23.7		144.3		14.8		159.1		155.0		27.8		182.8
Australia		3.8		7.2		11.0		2.7		—		2.7		6.5		7.2		13.7
North Sea		—		2.5		2.5		4.9		6.8		11.7		4.9		9.3		14.2
Argentina		2.0		—		2.0		80.8		2.0		82.8		82.8		2.0		84.8
Total		29.0		41.3		70.3		703.6		75.5		779.1		732.6		116.8		849.4
2006
United States		2.9		2.7		5.6		266.4		15.3		281.7		269.3		18.0		287.3
Canada		34.3		6.4		40.7		577.3		114.8		692.1		611.6		121.2		732.8
Egypt		11.8		8.9		20.7		122.7		10.4		133.1		134.5		19.4		153.9
Australia		1.2		9.3		10.5		1.0		1.3		2.3		2.2		10.6		12.8
North Sea		—		1.0		1.0		3.9		—		3.9		3.9		1.0		4.9
Argentina		9.3		5.3		14.6		60.8		2.0		62.8		70.1		7.3		77.4
Other International		—		—		—		1.5		—		1.5		1.5		—		1.5
Total		59.5		33.6		93.1		1,033.6		143.8		1,177.4		1,093.1		177.5		1,270.6

Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2008, is set forth below:

	Gas				Oil				Total
	Gross		Net		Gross		Net		Gross		Net
Gulf Coast		835		675		885		640		1,720		1,315
Central		3,415		1,765		7,650		5,215		11,065		6,980
Canada		8,200		7,260		2,250		990		10,450		8,250
Egypt		42		42		618		589		660		631
Australia		10		6		37		22		47		28
North Sea		—		—		65		63		65		63
Argentina		395		363		580		503		975		866
Total		12,897		10,111		12,085		8,022		24,982		18,133

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Production, Pricing and Lease Operating Cost Data

The following table describes, for each of the last three fiscal years, oil, NGLs and gas production, average lease operating expenses per boe (including severance and other taxes and transportation costs) and average sales prices for each of the countries where we have operations:

							Average Lease
	Production						Operating Cost per		Average Sales Price
Year Ended December 31,	Oil		NGLs		Gas		Boe		Oil		NGLs		Gas
	(Mbbls)		(Mbbls)		(MMcf)		(Per bbl)				(Per bbl)		(Per Mcf)
2008
United States		32,866		2,191		248,835	$	14.67	$	83.70	$	58.62	$	8.86
Canada		6,278		760		129,099		14.27		93.53		49.33		7.94
Egypt		24,431		—		96,518		6.47		91.37		—		5.25
Australia		3,019		—		45,019		10.87		91.78		—		2.10
North Sea		21,775		—		965		41.70		95.76		—		18.78
Argentina		4,542		1,056		71,609		6.58		49.46		37.83		1.61
Total		92,911		4,007		592,045	$	15.02	$	87.80	$	51.38	$	6.70
2007
United States		33,127		2,811		280,903	$	11.99	$	66.48	$	45.24	$	7.04
Canada		6,846		820		141,697		12.74		68.29		40.55		6.30
Egypt		22,168		—		87,883		5.16		72.51		—		4.60
Australia		5,029		—		71,149		6.15		79.79		—		1.89
North Sea		19,576		—		705		28.21		70.93		—		15.03
Argentina		4,175		1,022		73,330		4.81		45.99		37.78		1.17
Total		90,921		4,653		655,667	$	11.35	$	68.84	$	42.78	$	5.34
2006
United States		24,394		2,915		243,442	$	11.13	$	54.22	$	38.44	$	6.54
Canada		7,561		798		147,579		10.58		59.90		35.40		6.09
Egypt		20,648		—		79,424		4.68		63.60		—		4.42
Australia		4,341		—		67,933		4.95		68.25		—		1.65
North Sea		21,368		—		752		28.23		63.04		—		10.64
Argentina		2,503		561		40,878		4.47		42.79		36.64		.97
Other International		1,156		—		—		4.77		62.73		—		—
Total		81,971		4,274		580,008	$	10.92	$	59.92	$	37.70	$	5.17

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Gross and Net Undeveloped and Developed Acreage

The following table sets out our gross and net acreage position in each country where we have operations:

	Undeveloped Acreage				Developed Acreage
	Gross Acres		Net Acres		Gross Acres		Net Acres
United States		2,158,979		1,365,722		2,904,849		1,797,004
Canada		3,138,067		2,225,462		3,325,289		2,652,939
Egypt		13,969,530		8,488,721		1,316,195		1,211,734
Australia		6,877,670		4,857,730		572,170		352,830
North Sea		319,929		241,450		41,019		39,952
Argentina		3,070,000		2,791,000		259,000		194,000
Chile		1,203,137		1,034,436		—		—
Total Company		30,737,312		21,004,521		8,418,522		6,248,459

As of December 31, 2008, we had 4,933,430, 3,270,055 and 8,474,094 net acres scheduled to expire by December 31, 2009, 2010 and 2011, respectively, if production is not established or we take no other action to extend the terms. Approximately two million net acres (four million gross acres) of the 2009 expiration total expired in Egypt in January 2009. We plan to continue the terms of many of these licenses and concession areas through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.

Estimated Proved Reserves and Future Net Cash Flows

As of December 31, 2008, Apache had total estimated proved reserves of 1,081 MMbbls of crude oil, condensate and NGLs and 7.9 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 2.4 billion barrels of oil equivalent or 14.4 Tcf of natural gas. As a result of prices in effect at the end of 2008, we experienced significant negative revisions to our reserves, causing 2008 to be the first year in the last 23 in which reserves did not grow.

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company reports all estimated proved reserves held under production sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. Reserve estimates are considered proved if economical productivity is supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program in the reservoir provides support for the engineering analysis on which the project or program is based. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.

Apache emphasizes that its reported reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed throughout the year and revised either upward or downward, as warranted by additional performance data.

Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of Apache’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues and ultimate recoverable reserves. Reserves are reviewed internally with senior management and presented to Apache’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable.

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The estimate of reserves disclosed in this Annual Report on Form 10-K are prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, we engage Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. We selected the properties for review by Ryder Scott. These properties represented all material fields, approximately 90 percent of international properties and over 80 percent of each country’s reserve value for new wells drilled during the year. During 2008, 2007 and 2006, Ryder Scott’s review covered 82, 77 and 75 percent of the Company’s worldwide estimated reserves value, respectively.

Ryder Scott opined that the overall proved reserves for the reviewed properties as estimated by the Company are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles and conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. Ryder Scott has informed the Company that the tests and procedures used during its reserves audit conform to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information approved by the Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities. A reserve audit is not the same as a financial audit and is less rigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on his or her own.

The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2008, 2007 and 2006, changes in estimated proved reserves during the last three years and estimates of future net cash flows and discounted future net cash flows from estimated proved reserves are contained in Note 13 — Supplemental Oil and Gas Disclosures of Item 15 in this Form 10-K. These estimated future net cash flows are based on prices on the last day of the year and are calculated in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities.” Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10.

In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting” (Modernization). The Modernization disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements become effective for Apache’s Annual Report on Form 10-K for the year ended December 31, 2009.

Employees

On December 31, 2008, we had 3,639 employees.

Offices

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2008, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2013. For information regarding the Company’s obligations under its office leases, see the table in Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity and Note 9 — Commitments and Contingencies of Item 15 in this Form 10-K.

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Title to Interests

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, and other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

ITEM 1A.   RISK FACTORS

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future.

Our profitability and the carrying value of our properties is highly dependent on the prices of crude oil, natural gas and natural gas liquids, which have historically been very volatile

Our estimated proved reserves, revenues, profitability, operating cash flows and future rate of growth are highly dependent on the prices of crude oil, natural gas and NGLs, which are affected by numerous factors beyond our control. These prices have historically been very volatile and are likely to remain volatile in the future. A significant and extended downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow and could result in a reduction in the carrying value of our oil and gas properties and the amounts of our estimated proved oil and gas reserves. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices adversely affects our financial position.

Under the full-cost method of accounting as allowed by the SEC, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. The Company recorded a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of the ceiling test limitations. If oil and gas prices deteriorate from the Company’s year-end realized prices, it is likely that additional write-downs will occur in 2009.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels could also be considered by the rating agencies. Apache’s senior unsecured long-term debt is currently rated A3 by Moody’s, A- by Standard & Poor’s and A by Fitch. Apache’s short-term debt rating for its commercial paper program is currently P-2 by Moody’s, A-2 by Standard & Poor’s and F1 by Fitch. The outlook is stable from Moody’s and Standard & Poor’s and negative from Fitch. A ratings downgrade could adversely impact our ability to access debt markets in

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the future, increase the cost of future debt and potentially require the Company to post letters of credit in certain circumstances.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition

Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatile oil, natural gas and NGLs prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors, suppliers and customers ability to continue operations, and ultimately, adversely impact our results of operations, liquidity and financial condition.

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks

To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

•  our production falls short of the hedged volumes;

•  there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

•  the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or

•  a sudden unexpected event materially impacts oil and natural gas prices.

The credit risk of financial institutions could adversely affect us

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Continued deterioration in the credit markets may continue to impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage

A sizeable portion of our acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to

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change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

Our ability to sell natural gas and/or receive market prices for our gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

Acquisitions or discoveries of additional reserves are needed to avoid a material decline in reserves and production

The production rate from oil and gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery reserves, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.

We may not realize an adequate return on wells that we drill

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

•  unexpected drilling conditions;

•  pressure or irregularities in formations;

•  equipment failures or accidents;

•  fires, explosions, blowouts and surface cratering;

•  marine risks such as capsizing, collisions and hurricanes;

•  other adverse weather conditions; and

•  increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.

Future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves

Although we perform a review of properties that we acquire that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual

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property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and associated costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.

Our North American operations are subject to governmental risks that may impact our operations

Our North American operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection laws and regulations. New political developments, laws and regulations may adversely impact our results on operations.

International operations have uncertain political, economic and other risks

Our operations outside North America are based primarily in Egypt, Australia, the United Kingdom and Argentina. On a barrel equivalent basis, approximately 46 percent of our 2008 production was outside North America and approximately 39 percent of our estimated proved oil and gas reserves on December 31, 2008 were located outside North America. As a result, a significant portion of our production and resources are subject to increased political and economic risks and other factors including, but not limited to:

•  general strikes and civil unrest;

•  the risk of war, acts of terrorism, expropriation, forced renegotiation or modification of existing contracts;

•  import and export regulations;

•  taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;

•  price control;

•  transportation regulations and tariffs;

•  constrained natural gas markets dependent on demand in a single or limited geographical area;

•  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;

•  laws and policies of the United States affecting foreign trade, including trade sanctions;

•  the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;

•  the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

•  difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world in which we operate have a history of political and economic instability. This instability could result in new

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governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our assets. This could adversely affect our interests and our future profitability.

The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

Material differences between the estimated and actual timing of critical events may affect the completion and commencement of production from development projects

We are involved in several large development projects whose completion may be delayed beyond our anticipated completion dates. Our projects may be delayed by project approvals from joint venture partners; timely issuances of permits and licenses by governmental agencies; weather conditions; manufacturing and delivery schedules of critical equipment; and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect our large development projects and our ability to participate in large scale development projects in the future.

Our operations are sensitive to currency rate fluctuations

Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar with the Canadian dollar, the Australian dollar and the British Pound. Our financial statements, presented in U.S. dollars, are affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operation, particularly through the weakening of the U.S. dollar relative to other currencies.

Weather and climate may have a significant adverse impact on our revenues and productivity

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico or cyclones offshore Australia, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather, and not all such effects can be predicted, eliminated or insured against.

We may incur significant costs related to environmental matters

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse affect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

We face strong industry competition that may have a significant negative impact on our result of operations

Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties and

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reserves, equipment and labor required to explore, develop and operate those properties and marketing of oil and natural gas production. Crude oil and natural gas prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geo-physicists, engineers and other specialists. These competitive pressures may have a significant negative impact on our results of operations.

Our insurance policies do not cover all risks

Exploration for and production of oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.

ITEM 1B.   UNRESOLVED SEC STAFF COMMENTS

As of December 31, 2008, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

ITEM 3.   LEGAL PROCEEDINGS

See the information set forth in Note 9 — Commitments and Contingencies of Item 15 of this Form 10-K which is incorporated herein by reference.

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

No matters were submitted to a vote of our security holders during the most recently ended fiscal quarter.

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PART II

ITEM 5.   MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

During 2008, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock Exchanges and the NASDAQ National Market under the symbol “APA.” The table below provides certain information regarding our common stock for 2008 and 2007. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per-share prices and quarterly dividends shown below have been rounded to the indicated decimal place.

	2008								2007
	Price Range				Dividends Per Share				Price Range				Dividends Per Share
	High		Low		Declared		Paid		High		Low		Declared		Paid
First Quarter	$	122.34	$	84.52	$	.25	$	.15	$	73.44	$	63.01	$	.15	$	.15
Second Quarter		149.23		117.65		.15		.25		87.82		70.53		.15		.15
Third Quarter		145.00		94.82		.15		.15		91.25		73.41		.15		.15
Fourth Quarter		103.17		57.11		.15		.15		109.32		87.44		.15		.15

The closing price of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 30, 2009 (last trading day of the month), was $75.00 per share. As of January 31, 2009, there were 334,753,638 shares of our common stock outstanding held by approximately 6,000 stockholders of record and approximately 448,000 beneficial owners.

We have paid cash dividends on our common stock for 44 consecutive years through December 31, 2008. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements and other relevant factors.

In 1995, under our stockholder rights plan, each of our common stockholders received a dividend of one preferred stock purchase right (a “right”) for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and a two-for-one stock split) that the stockholder owned. These rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the rights were reset to one right per share of common stock, and the expiration was extended to January 31, 2016. Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights, which trade automatically with our shares of common stock. For a description of the rights, please refer to Note 7 — Capital Stock of Item 15 in this Form 10-K.

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2009 annual meeting of stockholders, which is incorporated herein by reference.

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The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2003 through December 31, 2008.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Apache Corporation, S&P 500 Index
and the Dow Jones US Exploration & Production Index

* $100 invested on 12/31/03 in stock including reinvestment of dividends.
Fiscal year ending December 31.

	2003		2004		2005		2006		2007		2008
Apache Corporation	$	100.00	$	125.41	$	170.91	$	166.97	$	272.02	$	189.80
S & P’s Composite 500 Stock Index		100.00		110.88		116.33		134.70		142.10		89.53
DJ US Expl & Prod Index		100.00		141.87		234.54		247.14		355.06		212.61

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ITEM 6.   SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2008, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements of Item 15 in this Form 10-K. As discussed in more detail under Item 15, the 2008 numbers in the following table reflect a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of ceiling test limitations.

	As of or for the Year Ended December 31,
	2008		2007		2006		2005		2004
	(In thousands, except per share amounts)
Income Statement Data
Total revenues	$	12,389,750	$	9,999,752	$	8,309,131	$	7,584,244	$	5,332,577
Income (loss) attributable to common stock		706,274		2,806,678		2,546,771		2,618,050		1,663,074
Net income (loss) per common share:
Basic		2.11		8.45		7.72		7.96		5.10
Diluted		2.09		8.39		7.64		7.84		5.03
Cash dividends declared per common share		.70		.60		.50		.36		.28
Balance Sheet Data
Total assets	$	29,186,485	$	28,634,651	$	24,308,175	$	19,271,796	$	15,502,480
Long-term debt		4,808,975		4,011,605		2,019,831		2,191,954		2,588,390
Shareholders’ equity		16,508,721		15,377,979		13,191,053		10,541,215		8,204,421
Common shares outstanding		334,710		332,927		330,737		330,121		327,458

For a discussion of significant acquisitions and divestitures, see Note 2 — Significant Acquisitions and Divestitures of Item 15 in this Form 10-K.

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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. In North America, our exploration and production operations are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin and the Western Sedimentary basin of Canada. Outside of North America, we have exploration and production operations onshore Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea), and onshore Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Item 8 of this Form 10-K, and the Risk Factors information, which are set forth in Item 1A of this Form 10-K.

Overview

Apache’s 2008 results were significantly impacted by several events:

•  A drop in demand related to the slowing global economy caused fourth-quarter oil and gas prices to drop sharply.

•  Two major uncontrollable events curtailed our production:

•  hurricanes in the Gulf of Mexico, and

•  an explosion on a pipeline that transports all of our gas production in Australia.

•  A non-cash write-down of the carrying value of our U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties, necessitated by low commodity prices in effect at year-end (discussed below).

Crude Oil and Natural Gas Prices

The oil and gas industry as a whole experienced a year of extremes during 2008. Crude oil and natural gas prices climbed precipitously in the first half of the year, only to pull back in the third quarter before collapsing in the fourth quarter. Apache monthly average realized prices during the summer reached $118.38 per barrel and $9.12 per thousand cubic feet (Mcf). Our December average realized prices were $36.45 per barrel and $4.75 per Mcf. February 2009 indices indicate that prices are trending below December’s averages as the global economy and demand continue to weaken.

Crude Oil and Natural Gas Production

Apache’s 2008 consolidated production declined five percent from 2007 on a barrel of oil equivalent (boe) basis. Our production would have increased over 2007 levels had it not been for the impact of the following:

•  U.S. production was affected by wells shut-in because of, and damage caused by, Hurricanes Gustav and Ike. While we plan to restore nearly all of the production during the second quarter of 2009, the timing in many instances is pipeline dependent and, therefore, beyond our control. See Operating Highlights in this Item 7.

•  In June 2008, a pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia disrupted gas and oil sales, reducing 2008 production. We plan to have all of the volumes restored in the first half of 2009. See Operating Highlights in this Item 7.

Earnings and Cash Flow

From an earnings perspective, we had our historical best and worst quarters ever, just one quarter apart. The fourth-quarter price collapse and associated $3.6 billion non-cash after-tax write-down nearly eliminated 2008 nine-month earnings that totaled $3.7 billion dollars or $10.84 per common diluted share. The write-down reduced earnings for the year to $706 million, or $2.09 per share.

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Record commodity prices in the first half of 2008 drove record cash provided by operating activities of $7.1 billion and record oil and gas revenues of $12.4 billion, both of which were unaffected by the write-down. They were, however, affected by falling commodity prices, most notably in the fourth quarter of 2008. Key financial indicators for each quarter and the year of 2008 are noted below:

	2008 Key Financial Indicators, by Quarter
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter			Full Year
	(In thousands, except realized price)
Oil and Gas Revenues	$	3,177,949	$	3,904,118	$	3,368,882	$	1,876,890		$	12,327,839
Average Realized Oil Price	$	89.25	$	110.32	$	101.04	$	50.69		$	87.80
Average Realized Gas Price	$	6.42	$	8.09	$	7.43	$	4.76		$	6.70
Income Attributable to Common Stock	$	1,020,093	$	1,443,809	$	1,189,405	$	*(2,947,033	)	$	*706,274
Cash from operating activities	$	1,808,404	$	1,929,509	$	2,290,655	$	1,036,776		$	7,065,344

* Includes a $3.6 billion (after-tax) non-cash write-down in the carrying value of oil and gas properties.

Operating and Drilling Costs

Costs were a challenge for Apache and our industry in 2008 and are expected to remain so in 2009. Drilling, service and acquisition costs, which have increased steadily since the industry’s last downturn in 2001, reached unprecedented levels in 2008. Also, in the U.S., activity to repair damage caused by Gulf of Mexico hurricanes over the last few years has contributed to increased demand and costs. Even though we have seen a sharp drop in commodity prices, costs have fallen less rapidly pressuring operating margins. We believe costs will ultimately adjust to the current oil and gas price environment, but until they do, our operating margins and drilling costs will continue to be pressured.

Financial Position and 2009

We believe we are well positioned to take advantage of opportunities that will invariably present themselves in the current business environment. We enter 2009 with a debt-to-capitalization ratio of 23 percent, after consideration of the non-cash write-down. We had over $1.5 billion in cash and short-term investments and $2.3 billion availability on our lines of credit at the close of the year. In a tightening credit market, we believe Apache’s single-A debt ratings will provide a competitive advantage in accessing capital. Our 2008 return on capital employed and return on equity were four percent and five percent, respectively, after taking into effect the $5.3 million non-cash write-down.

In 2009, we are projecting production growth driven by multi-year projects coming on-line during the year (discussed below in Operational Highlights). We plan to hold our capital expenditures, currently planned at 50 percent below 2008 spending levels, in line with our operating cash flows. We will continue to monitor capital spending closely based on actual and projected cash flow estimates and intend to scale back spending further should commodity prices remain at current levels or fall further.

For an in-depth discussion of Apache’s long-term growth strategy, please refer to Part 1, Items 1 and 2. Business and Properties of this Form 10-K.

Full-Cost Accounting and 2008 Write-down in Net Oil and Gas Property Assets

The Company follows the full-cost method of accounting as allowed by the Securities and Exchange Commission (SEC). Under the full-cost method of accounting, a ceiling test must be performed each quarter, for each country. The test establishes a limit (ceiling), on the carrying value of proved oil and gas properties. This carrying value (net book value and the related deferred income taxes) may not exceed the ceiling. The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, excluding future

25

expected cash outflows associated with settling asset retirement obligations accrued on the balance sheet. The estimate of after-tax future net cash flows is discounted at 10 percent per annum and calculated using both commodity prices and costs in effect at the end of the period, held flat for the life of the properties, except where future oil and gas sales are covered by physical contract terms or by derivative instruments that qualify, and are accounted for, as cash flow hedges. If capitalized costs (carrying value) exceed this limit, the excess is charged to expense and reflected as additional Depletion, Depreciation and Amortization (DD&A) during the period.

In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting,” which will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new rule becomes effective for the quarter ended December 31, 2009. See Note 1— Summary of Significant Accounting Policies in this Form 10-K.

Despite record realized prices and record revenues for 2008, the low oil and gas prices in effect at the end of the year resulted in an aggregate $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties. If oil and gas prices fall below year-end levels, additional write-downs of oil and gas properties may occur. See Note 1 — Summary of Significant Accounting Policies in this Form 10-K.

Operating Highlights

We made considerable operational progress during the year, which we believe adds to our platform for long-term profitable growth in spite of hurricanes in the Gulf of Mexico and a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia. Key operational highlights include:

U.S. Gulf Coast

Gulf Coast focused on an active drilling program and restoring production impacted by the 2005 and 2008 hurricanes. In addition to drilling wells, the region also performed 358 workover and recompletion operations during 2008. Significant events affecting Gulf Coast operations include:

Development Projects

•  At Ewing Banks 826, we completed four wells during the first half of 2008 and increased production to 6,315 b/d, up from 700 b/d at the beginning of the year. We own a 100 percent working interest in the field.

Exploration Projects

•  In June 2008, we had a key discovery at the Geauxpher prospect located on Garden Banks Block 462 in deepwater Gulf of Mexico. Apache generated the prospect and has a 40-percent working interest. Mariner Energy, Inc. is the designated operator of the block with a 60-percent working interest. A delineation well was drilled in December 2008, extending the productive reservoir limits. We forecast the initial discovery to be online in the second quarter of 2009. Additional potential on the block is expected to be tested by further drilling.

Hurricanes

•  During the third quarter of 2008, Hurricanes Gustav and Ike damaged onshore and offshore production and transportation facilities in our Gulf Coast region. Although most of our offshore operated platforms escaped with minor damage, we did lose four Apache-operated and two non-operated platforms. Our ability to transport and process our crude oil and natural gas production was also impacted by damages to third-party pipelines and processing facilities. The impact of the hurricanes on 2008 operations and results follows:

Production — Wells shut-in as a result of the hurricanes reduced 2008 production by an estimated 54.6 MMcf/d and 6,941 b/d. A substantial part of Apache’s net production shut-in by the storm was restored by the end of 2008, with only 7,700 b/d and 83 MMcf/d remaining offline. While we plan to restore nearly all of the production by mid-year 2009, the timing in many instances is beyond our control since we

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are awaiting repairs to third-party pipelines and facilities. All but approximately 1,100 boe per day of production will ultimately be restored.

Financial Results — The impact of the hurricanes on our 2008 financial results was an estimated $410 million of lower crude oil and natural gas revenues. We also incurred approximately $75 million of expenditures for repair, redevelopment and abandonment of properties damaged by the hurricanes. The Company anticipates an additional $170 to $190 million of costs, most of which are likely to occur in 2009. A majority of these costs will be recovered through insurance, as discussed below.

Insurance Coverage — The Company carries property damage insurance through Oil Insurance Limited (OIL) for windstorm damage in the Gulf of Mexico of $250 million after reaching a $100 million deductible per event. The deductible will be scaled down based on the Company’s working interest in the damaged properties and is anticipated to be $80 million. The $250 million in coverage will be prorated downward if total claims received by OIL for Hurricane Ike exceed their aggregate limit per event of $750 million. In December 2008, OIL indicated that losses for Hurricane Ike will likely exceed the aggregate limit by an amount that would cause insurance payments to be 80 percent of amounts claimed; however, the final percentage will not be known until all claims have been submitted to OIL. In addition, Apache has $150 million of property damage and business interruption insurance through the London market subject to a $350 million deductible that can be met with property damage and qualifying business interruption losses.

Egypt

In Egypt, we had a steady stream of significant discoveries during the year across basins and plays, completing 236 of 260 wells for a 91-percent success rate. The region also conducted 701 workovers and recompletions and made significant progress on the completion of several major growth projects that will underpin future production growth. Notable successes during the year include:

Development Projects

•  In the Khalda concession, two additional Salam gas processing trains, trains three and four, and an associated Apache pipeline compression project on the Western Desert Northern Gas Pipeline are forecasted to add additional net production of 100 MMcf/d and 5,000 b/d when fully operational in the second quarter of 2009. The third processing train commenced operation on December 4, 2008. Commissioning with first gas from the fourth processing train is projected to commence during the first quarter of 2009.

•  We drilled 203 waterflood wells across several concessions during 2008, increasing gross oil production from these waterflood projects 55 percent or 27,000 b/d when compared to 2007 production levels. Also, we believe that several discoveries (discussed below) in a new area called the Heba Ridge, which is adjacent to the Asala Ridge waterflood area in the East Bahariya concession, will add significantly to our inventory of waterflood projects in the concession.

Exploration Discoveries

•  During 2008, Apache announced that the Hydra-1X exploration well in Egypt’s Western Desert test-flowed 76.6 MMcf/d and 2,813 b/d from the Deep Jurassic and overlying AEB-6 formations. The Hydra 4X well appraised this discovery. Apache has a 100-percent contractor interest in the Shushan “C” concession and is in the process of negotiating a Gas Sales Agreement with the Egyptian General Petroleum Corporation (EGPC) and, when completed, will file to establish a development lease.

•  On July 30, 2008, Apache announced that the Heqet-2 well in the Greater Khalda area in Egypt’s Western Desert tested 2,100 b/d from the Jurassic Safa formation at a depth of 14,700 feet. We also announced that the Umbarka-174 well tested 4,300 b/d in the main AEB field in the north central portion of the Greater Khalda area. Both wells are currently producing, and development of these fields continues. In October 2008, we announced the WKAL-C-1X discovery on the West Kalabsha concession. The well tested 4,746 b/d and 4.4 MMcf/d in the Jurassic Safa formation. The WKAL-C-1X discovery represents the westernmost oil ever

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discovered in Egypt, confirming our exploration model for this area of the Faghur Basin. Apache has a 100 percent contractor interest in both the Khalda and West Kalabsha concessions.

•  During 2008, several new oil fields were discovered in the Bahariya formation in the East Bahariya concession. The EBAH-C-1X oil discovery identified a new area called the Heba Ridge. The initial discovery and three additional development wells were drilled in the EBAH-C field during 2008 and all were producing at year-end. A total of 40 wells are planned to fully develop the EBAH-C field. Three additional exploration discoveries in the East Bahariya concession found Bahariya oil pay in separate fields. The initial wells are expected to commence production during early 2009. Each of these discoveries will add significantly to our inventory of water-flood projects in the concession.

•  Also in 2008, the Phiops-1X exploration well on the Kalabsha development lease in the Khalda area encountered a potential 374 foot oil column with 173 feet of logged pay in a secondary objective, the Cretaceous Alam El Bueib formation. The well will be tested in early 2009 and is expected to provide a significant oil reserve addition.

•  In early 2009, we formally announced three new December 2008 field discoveries in Egypt’s Western Desert that tested an aggregate 80 MMcf/d and 5,909 b/d. The Sultan-3X located on the Khalda Offset Concession test-flowed 5,021 b/d and 11 MMcf/d from three commingled intervals in the Safa formation. The two other discoveries, the Adam-1X and the Maggie-1X, discovered new gas-condensate fields on the Matruh development lease north of the Sultan discovery. Apache has a 100-percent contractor interest in both of the concessions. We anticipate completion of Sultan-3X as an oil well prior to the end of first-quarter 2009, and completion of Adam-1X and Maggie-1X by year-end 2009.

Australia

In Australia, we had two notable discoveries, the Halyard-1 and Brulimar-1 as well as continued appraisal success at Julimar and Bambra. We also progressed on several major long lead-time development growth projects, including the Van Gogh and Pyrenees developments. In the Julimar-Brunello area on Australia’s Northwest Shelf, we drilled three successful appraisal wells that will allow us to pursue a development strategy after completing our assessment of commercial options. Also, our subsidiaries made considerable progress in restoring operations at the Varanus Island gas processing and transportation hub, which sustained damage from a gas pipeline explosion in June 2008. Lastly, on January 6, 2009, we secured a 154 Bcf, seven-year gas sales contract that enabled us to reinstate our Reindeer development program. These discoveries and developments are discussed in more detail below.

Development and Appraisal Projects

•  We have several large development projects underway in Australia. The Van Gogh and Pyrenees developments remain on schedule to deliver first production in 2009 and 2010, respectively, each with projected net rates of 20,000 b/d. Our Reindeer development program was reinstated following signing of a gas-supply contract (discussed below) and is scheduled to deliver approximately 60 MMcf/d net to Apache in late 2011. Construction of pipeline and processing infrastructure is scheduled to commence in 2009.

•  On January 6, 2009, the Company announced that it had signed a contract to supply natural gas from the Reindeer field to CITIC Pacific’s Sino Iron project in Western Australia. The terms call for Apache and its joint venture partner to supply 154 billion cubic feet of gas over seven years beginning in the second half of 2011. Apache owns a 55 percent interest in the field. The gas will be supplied through a new 65-mile offshore pipeline and a new onshore sales gas processing facility at Devil Creek.

•  Appraisal of the Julimar-Brunello area on Australia’s Northwest Shelf progressed with three appraisal wells. In January 2008, we announced the Brulimar-1 discovery, which encountered 113 feet of net pay in the Upper Triassic Mungaroo sandstone. In April, we announced the Julimar Southeast-1 discovery, which logged 195 feet of net pay across five intervals of the Triassic Mungaroo sandstone. In May, we announced the Julimar Northwest-1 discovery, which logged 43 feet of net pay in the J-17 Triassic Mungaroo sandstone. We have now drilled seven discoveries in the complex. We plan to complete our appraisal program by mid-

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year and pursue a development strategy in the second half of 2009 after completing our assessment of commercial options. The Julimar development will not require funding until we determine which market is best suited for the asset. Apache is evaluating LNG options as well as domestic-market options for Julimar gas. Apache owns a 65 percent interest in and operates the Julimar-Brunello complex.

Exploration Discoveries

•  In April, we announced the Halyard-1 discovery on Australia’s WA-13-L block, which test-flowed 68 MMcf/d. We are currently in the development design phase that includes consideration of a sub-sea gathering line from Halyard to an existing pipeline at our East Spar field, 10 miles to the southeast, from which the gas can be transported to Varanus Island for processing. Using our existing infrastructure would accelerate development of the field and first sales. Apache obtained governmental approval for the Halyard Field development during the third quarter of 2008, and we are working toward first production in 2010. Apache has a 55 percent interest in and operates the block.

•  We are currently evaluating the results of wells drilled in 2008 and seismic information to assess the future potential in the Gippsland basin. All six wells drilled in 2008 were either dry or non-commercial.

Varanus Island

•  On June 3, 2008, subsidiaries of the Company reported a gas pipeline explosion 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. When fully operational, the Island’s operations process approximately 195 MMcf/d and 5,400 b/d, net to Apache subsidiaries. On August 5, 2008, partial production was reestablished from the John Brookes field, and by year-end was at greater than 80 percent pre-incident levels. The Harriet Joint Venture gas facilities are located adjacent to the pipeline explosion and required more significant repairs to restore operation. A portion of our gas production from the Harriet Joint Venture was restored in December 2008 and is projected to be fully restored in the first half of 2009. Harriet Joint Venture oil production is projected to be fully restored in the first quarter of 2009. 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 accounted for the remaining 40 percent and 75 percent of the island’s pre-incident natural gas and oil production, respectively. 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.

Canada

During 2008, the Canadian region had an active development drilling program and commenced pursuit of an emerging shale-gas play in northeast British Columbia. Notable activities during the year include:

Exploration Projects

•  During 2008, the Company completed a total of seven horizontal wells in the Ootla shale-gas play, located in northeast British Columbia. December gross production averaged 2.5 MMcf/d. Current plans for the Ootla development in 2009 include drilling 31 gross horizontal wells and construction of compression and gathering infrastructure required to take the additional production to existing processing facilities. Based on information obtained from these wells, Apache expects to achieve significant improvements in both production rate and reserves per well. Apache has a 50 percent interest and operates approximately one-half of its 400,000 gross acreage position in the play.

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Development Projects

•  Apache continues to target shallow gas, including coal bed methane (CBM), in areas such as Nevis, North Grant Lands and Provost. Intermediate-depth drilling continued in the Kaybob, West 5 and South Grant Land areas of central and southern Alberta.

North Sea

Throughout 2008, the North Sea region invested in drilling and recompleting wells and facility enhancement programs. Key activities include:

Development Projects

•  During 2008, we completed 12 new development wells in the Forties field, which flowed at a combined rate of 18,900 b/d.

•  Investments in facility upgrades and integrity-related projects over the past five years have significantly reduced platform downtime. Coupled with production from new wells, these improved platform operating efficiencies enabled the region’s fourth-quarter 2008 production to reach an average 61,740 b/d. Annual production averaged 59,494 b/d, an 11 percent increase from 2007.

Argentina

During 2008, the Argentina region pursued active drilling and recompletion programs. In total, the region drilled 83 wells, 72 of which were productive. Significant activities include:

Development Projects

•  Apache drilled 30 new wells in the Neuquén basin, with a success rate of 100 percent, and continued to exploit two new plays with an aggressive drilling and recompletion campaign.

Exploration Projects

•  In 2008, Apache completed a nearly 2,500 square kilometer 3-D seismic mega shoot in Tierra del Fuego. Twenty-nine wells were drilled in Tierra del Fuego, resulting in a number of new exploration discoveries and field extensions. Notable successes included the completion of the first phase appraisal campaign in the 2008 Sección Baños block and the successful appraisal of La Sara Norte. We also made exploration discoveries at Las Flechas, Sección Veintinueve, Camino Real and Perla.

•  In the Cuyo basin, Apache was awarded the 4,710 square kilometer CC&B-17 B block adjacent to and along a trend of existing producing fields, which increased our Argentine acreage portfolio by 34 percent.

Chile

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

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Results of Operations

Revenues

	Crude Oil			Natural Gas			NGL’s			Total
				(In thousands)
2006 Revenues	$	4,911,861		$	3,001,246		$	161,146		$	8,074,253
Volume increase (decrease)		616,179			404,311			16,214			1,036,704
Price increase (decrease)		827,725			34,111			21,680			883,516
Impact of hedges increase (decrease)		(96,640	)		64,149			—			(32,491	)
Increase (decrease) in 2007	$	1,347,264		$	502,571		$	37,894		$	1,887,729
2007 Revenues	$	6,259,125		$	3,503,817		$	199,040		$	9,961,982
Contribution to total revenues		63	%		35	%		2	%		100	%
Volume increase (decrease)		174,718			(426,055	)		(33,183	)		(284,520	)
Price increase (decrease)		2,174,202			894,818			40,025			3,109,045
Impact of hedges increase (decrease)		(450,802	)		(7,866	)		—			(458,668	)
Increase (decrease) in 2008	$	1,898,118		$	460,897		$	6,842		$	2,365,857
2008 Revenues	$	8,157,243		$	3,964,714		$	205,882		$	12,327,839
Contribution to total revenues		66	%		32	%		2	%		100	%

Oil and Natural Gas Prices

Crude Oil Prices — A substantial portion of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Apache’s oil realizations climbed precipitously in the first half of the year reaching a record $118.38 per barrel in June, before collapsing in the fourth quarter. Our realized oil price in December averaged nearly 70 percent lower than June’s peak, as demand for energy dropped following the onset of the global financial crisis. Apache manages a portion of its exposure to fluctuations in crude oil prices, primarily in North America, using financial instruments. In 2008, the 19 percent of our oil production that was subject to financial derivative hedges reduced revenues by $451 million, which comprised a $472 million loss in the first nine months and a $21 million gain in the fourth quarter of 2008. Refer to Note 3 — Hedging and Derivative Instruments for the year-end status of our derivatives.

While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a worldwide market. With the exception of Argentina, price movements for all types and grades of crude oil generally move in the same direction. In Argentina, we are currently selling our oil in the domestic market. The Argentine government previously imposed a sliding-scale tax on oil exports, which effectively limits prices buyers are wiling to pay. Domestic oil prices are currently based on a $42 per barrel price, subject to quality adjustments, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar price formulas exist, but producers retain value-added tax collected from buyers, effectively increasing price realizations by 21 percent.

Natural Gas Prices — Natural gas, which has a limited global transportation system, is subject to price variances stemming from local supply and demand conditions. The majority of our gas sales contracts are indexed to prevailing local market prices. Apache uses a variety of strategies to manage its exposure to fluctuations in natural gas prices, primarily in North America, including fixed-price contracts and derivatives. In 2008, the 20 percent of our gas production that was subject to financial derivative hedges reduced revenues by $8 million, which comprised a $29 million loss for the first nine months and a gain of $21 million in the fourth quarter of 2008. Refer to Note 3 — Hedging and Derivative Instruments for the year-end status of our derivatives.

Apache primarily sells natural gas into four markets:

1) North America, which has a common market and where most of our gas is sold on a monthly or daily basis at either monthly or daily market prices.

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2) Egypt, where the majority of our gas is sold to Egyptian General Petroleum Corporation (EGPC) under an industry pricing formula indexed to Dated-Brent crude oil with a maximum gas price of $2.65 per MMbtu. On up to 100 MMcf/d gross, there is no price cap for our gas under a legacy contract which expires in 2013.

3) Australia, which has a local market with mostly long-term fixed-price contracts that are periodically adjusted for changes in Australia’s consumer price index. Subsequent to year-end, however, Apache signed a contract on 85 bcf (net) that is indexed to oil prices following an initial period of fixed prices.

4) Argentina, where we receive low government-regulated pricing on a substantial portion of our production. The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors and industry category. During the year, we realized an average price of $.92 per Mcf on government regulated sales. The majority of the remaining volumes were sold at market-driven prices, which exceeded $2.00 per Mcf at year-end. Our average price for 2008 was $1.61 per Mcf.

For specific more information on marketing arrangements by country, please refer to Item 1 and 2, “Business and Properties” of this Form 10-K.

Production and Pricing

	For the Year Ended December 31,
			Increase					Increase
	2008		(Decrease)			2007		(Decrease)			2006
Oil Volume — Barrels per day:
United States		89,797		(1.06	)%		90,759		35.80	%		66,832
Canada		17,154		(8.54	)%		18,756		(9.46	)%		20,715
Egypt		66,753		9.91	%		60,735		7.36	%		56,570
Australia		8,249		(40.13	)%		13,778		15.86	%		11,892
North Sea		59,494		10.93	%		53,632		(8.39	)%		58,544
Argentina		12,409		8.47	%		11,440		66.84	%		6,857
China		—		NM			—		NM			3,167
Total(1)		253,856		1.91	%		249,100		10.92	%		224,577
Average Oil price — Per barrel:
United States	$	83.70		25.90	%	$	66.48		22.61	%	$	54.22
Canada		93.53		36.96	%		68.29		14.01	%		59.90
Egypt		91.37		26.01	%		72.51		14.01	%		63.60
Australia		91.78		15.03	%		79.79		16.91	%		68.25
North Sea		95.76		35.01	%		70.93		12.52	%		63.04
Argentina		49.46		7.55	%		45.99		7.48	%		42.79
China		—		NM			—		NM			62.73
Total(2)		87.80		27.54	%		68.84		14.89	%		59.92
Natural Gas Volume — Mcf per day:
United States		679,876		(11.66	)%		769,596		15.39	%		666,965
Canada		352,731		(9.14	)%		388,211		(3.99	)%		404,325
Egypt		263,711		9.52	%		240,777		10.65	%		217,601
Australia		123,003		(36.90	)%		194,928		4.73	%		186,119
North Sea		2,637		36.42	%		1,933		(6.21	)%		2,061
Argentina		195,651		(2.61	)%		200,903		79.39	%		111,994
Total(3)		1,617,609		(9.95	)%		1,796,348		13.04	%		1,589,065
Average Natural Gas price — Per Mcf:

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	For the Year Ended December 31,
			Increase					Increase
	2008		(Decrease)			2007		(Decrease)			2006
United States	$	8.86		25.85	%	$	7.04		7.65	%	$	6.54
Canada		7.94		26.03	%		6.30		3.45	%		6.09
Egypt		5.25		14.13	%		4.60		4.07	%		4.42
Australia		2.10		11.11	%		1.89		14.55	%		1.65
North Sea		18.78		24.95	%		15.03		41.26	%		10.64
Argentina		1.61		37.61	%		1.17		20.62	%		.97
Total(4)		6.70		25.47	%		5.34		3.29	%		5.17
Natural Gas Liquids (NGL) Volume — Barrels per day:
United States		5,986		(22.28	)%		7,702		(3.54	)%		7,985
Canada		2,076		(7.57	)%		2,246		2.70	%		2,187
Argentina		2,887		3.11	%		2,800		82.17	%		1,537
Total		10,949		(14.11	)%		12,748		8.87	%		11,709
Average NGL Price — Per barrel:
United States	$	58.62		29.58	%	$	45.24		17.38	%	$	38.54
Canada		49.33		21.65	%		40.55		14.55	%		35.40
Argentina		37.83		0.13	%		37.78		3.11	%		36.64
Total		51.38		20.10	%		42.78		13.47	%		37.70

(1)	Approximately 19 percent of 2008 oil production was subject to financial derivative hedges, compared to 17 percent in 2007 and nine percent in 2006.
(2)	Reflects per-barrel reductions of $4.85 in 2008, $1.06 in 2007 and $1.37 in 2006 from financial derivative hedging activities.
(3)	Approximately 20 percent of 2008 gas production was subject to financial derivative hedges, compared to 17 percent in 2007 and eight percent in 2006.
(4)	Reflects per-Mcf reduction of $.01 in 2008, increase of $.10 in 2007 and reduction of $.05 in 2006 from financial derivative hedging activities.

NM — Not Meaningful

Year 2008 Compared to Year 2007

Crude Oil Revenues

Apache’s 2008 consolidated crude oil revenues increased $1.9 billion on a 28 percent increase in average realized price and a two percent increase in daily production.

U.S. oil revenues were up $549 million, driven by a 26 percent increase in realized crude oil prices, more than offsetting one percent lower production. Prices in the U.S. averaged $83.70 per barrel in 2008, up 26 percent from 2007. Gulf Coast region oil was 2,700 b/d lower, reflecting the impact of hurricanes, which reduced the region’s 2008 production by 6,941 b/d. Central region production was up five percent resulting primarily from production increases on the Permian basin properties acquired at the end of March 2007 and new drilling and recompletion activity in 2008.

Egypt’s crude oil revenues increased $625 million on a 26 percent increase in realized price and a 10 percent increase in production. Price realizations averaged $91.37 per barrel, up from $72.51 per barrel in the prior year. Increases in oil production came from wells at El Diyur, Umbarka and East Bahariya, as well as higher cost recovery

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volumes related to accelerated capital spending on the Salam gas plant expansion. These increases more than offset lower condensate volumes at Khalda because of scheduled Obayed and Salam plant shutdowns.

North Sea oil revenues increased $697 million, a 50 percent increase over last year. Revenue gains were driven by a 35 percent increase in realized price and an 11 percent increase in production. Oil price realizations averaged $95.76, up $24.83 per barrel. Production was higher on a successful drilling and workover program and a reduction in platform downtime.

Canada’s oil revenues increased $120 million. Realized prices were up 37 percent and averaged $93.53 per barrel. Daily production declined nine percent on natural decline in various fields and divested properties, which more than offset drilling and recompletion activity.

Argentina’s crude oil revenues increased $33 million, with both production and realized prices up eight percent. Higher production was related to successful drilling, workover and recompletion activities, particularly in Tierra del Fuego. Realized prices increased on favorable quality adjustments received for oil which remains subject to price restrictions, as well as increased production from Tierra del Fuego, a tax favored area where producers retain the 21 percent value-added tax collected from buyers.

Australia’s 2008 oil revenues fell $124 million from 2007 on a 40 percent decline in production, which more than offset a 15 percent increase in realized prices. Nearly half of the production decline resulted from wells shut-in following a pipeline explosion on June 3, 2008 at the Varanus Island gas processing and transportation hub. The remaining decrease is related to a natural decline. Partial production from our John Brookes field, and the associated condensate yields, was brought back on-line in August, and by year-end the field was at 80 percent pre-incident levels. Harriet field oil production was mostly restored by year-end and should be fully restored in early 2009. Condensate yields associated with Harriet gas production, which recommenced in December 2008, are expected to be fully restored in the first half of 2009 when repairs to the Harriet Joint Venture facility are completed.

Natural Gas Revenues

Apache’s 2008 consolidated natural gas revenues increased $461 million, driven by a 25 percent increase in realized natural gas prices. Worldwide daily production was down 10 percent from 2007.

U.S. natural gas revenues increased $227 million on higher prices as production declined 12 percent. Natural gas prices averaged $8.86, up $1.82 per Mcf. Central region gas production was up three percent on drilling and recompletion activities and incremental volumes from Permian basin properties acquired at the end of March 2007. Gulf Coast daily production was 21 percent lower on downtime, natural decline and a delay in Apache’s drilling program related to the hurricanes.

Canada’s natural gas revenues rose $134 million on a 26 percent increase in realized natural gas prices. Gas price realizations climbed $1.64 to $7.94 per Mcf. Natural gas production decreased nine percent because of natural decline in various areas and property divestitures in early 2008.

Egyptian gas revenues were up $103 million over 2007 on a 14 percent increase in price realizations and a 10 percent rise in production. Production rose on successful recompletions at our Matruh concession, new wells brought online at the Northeast Abu Gharadig concession and higher cost recovery volumes associated with an increase in capital spending related to the Salam gas plant expansion.

Argentina’s natural gas revenues increased $30 million on a 38 percent increase in realized price, offset by a three percent decline in daily production. Gas production was negatively impacted by gas re-injections at Tierra del Fuego resulting from gas export and pipeline restrictions. Realized gas prices increased given the more favorable sales mix attained during the year. Relative to last year, we were able to deliver more volumes under higher priced industry contracts. We also benefited from a year over year increase in residential gas prices.

Australia’s natural gas revenues fell $40 million on a 37 percent drop in production. Volumes were impacted by production shut-in after an explosion on the pipeline that transports all of our gas production in Australia and resulting fire that damaged our processing facilities, as previously discussed. Following the incident, both the John Brookes and Harriet fields were shut-in for approximately two months. John Brookes was the first field to come back online, with volumes partially restored in August and ramping up in subsequent months. Harriet production

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came back online in December at reduced rates. At year-end, John Brookes produced 80 percent of pre-incident levels, while Harriet saw approximately one-third of its pre-incident volumes restored. Repairs are expected to be completed late in the first half of 2009.

Year 2007 Compared to Year 2006

Crude Oil Revenues

Apache’s 2007 consolidated crude oil revenues totaled $6.3 billion, $1.3 billion above 2006, with nearly equal contributions from an 11 percent rise in production and a 15 percent increase in our realized oil price. On the whole, production increased an average 24,523 b/d, driven by the U.S. which was up 23,927 b/d. Crude oil price realizations averaged $68.84 per barrel for the year, $83.00 in the fourth quarter alone.

U.S. oil revenues were up $879 million to $2.2 billion with $580 million, or two-thirds of the increase, attributable to a 36 percent increase in production. A 23 percent increase in realized prices added the remaining $299 million. Gulf Coast production climbed 48 percent to 53,842 b/d, mainly on production restored from hurricane-damaged properties, a full year of production from Gulf of Mexico properties acquired in June 2006 and successful drilling and recompletion activities. Central region production grew 21 percent to 36,917 b/d, with the addition of Permian basin properties acquired from Anadarko Petroleum Corporation (Anadarko) in March 2007 and successful drilling and recompletion activities.

In Egypt, crude oil revenues rose $294 million, to $1.6 billion, with increased production generating an additional $110 million of revenues. The balance of the increase in revenues, $184 million, came from a 14 percent increase in realized prices, which were up $8.91 to $72.51 per barrel. Daily production averaged 60,735 b/d, up seven percent. Production gains were associated with development drilling in the Khalda and Matruh concessions as well as the East Bahariya, Umbarka, El Diyur and North El Diyur concessions.

Australia’s crude oil revenues of $401 million increased 35 percent, or $105 million. Production was 16 percent higher generating $55 million of the increase. Production growth resulted from an additional interest acquired in the Legendre field, completion of West Cycad wells and increased liquids from the Bambra, Wonnich Deep, Doric and Lee gas wells. Australia’s price realizations rose 17 percent to $79.79 per barrel, the highest in the Company, generating an additional $50 million of revenue.

Argentina’s oil revenues increased $85 million to $192 million, with over 90 percent of the increase associated with 67 percent higher production. The year 2007 benefited from a full year of production from acquisitions made in 2006, as well as successful drilling, workover and recompletion activity during the year. Higher volumes added $77 million to revenues, with price increases adding $8 million. Argentina’s realized oil prices averaged $45.99 per barrel, up seven percent from the prior year.

North Sea oil revenues increased $41 million to $1.4 billion. Oil prices averaged $70.93 per barrel, up 13 percent, adding $168 million in revenues. Production averaged 53,632 b/d, down eight percent, reducing revenues by $127 million. Production increases on three of our platforms were more than offset by declines from wells at the Alpha and Echo platforms while drilling operations were suspended for facility upgrades.

Canada’s oil revenues increased $15 million to $467 million, with a 14 percent price increase mostly offset by a nine percent decline in production. Prices averaged $68.29 per barrel, up from $59.90 in 2006. Production dropped in 2007 primarily because of natural decline resulting from a 38 percent reduction in exploration and development capital invested in Canada compared to 2006.

China had no crude oil revenues in 2007 compared to $73 million in the prior year, a result of our August 2006 asset divestiture and exit from China.

Natural Gas Revenues

Apache’s natural gas revenues increased 17 percent, or $503 million, to $3.5 billion. Higher production contributed $405 million of the additional revenues. Gas production averaged 1,796 MMcf/d, up 13 percent from 2006. Natural gas prices increased $.17 to an average $5.34 per Mcf, generating an additional $98 million in revenue.

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U.S. natural gas revenues grew by $385 million to nearly $2 billion. U.S. production rose 15 percent, boosting revenues $264 million. Gulf Coast production increased 16 percent, boosted by final production restoration on hurricane-damaged properties, a full year of production from Gulf of Mexico properties acquired in June 2006 and successful drilling and recompletion activities. Central region production climbed 14 percent on successful drilling and recompletion activities and the addition of Permian basin properties acquired in March 2007. Higher natural gas prices, which averaged $7.04 per Mcf compared to $6.54 in 2006, added $121 million to revenues.

Gas revenues in Egypt were up $53 million, to $404 million, on an 11 percent increase in production and a four percent increase in price realizations. Production gains of 23 MMcf/d boosted the region’s average output to 241 MMcf/d, generating an additional $39 million in revenues. Production gains resulted from higher throughput and less downtime at the Obaiyed plant compared to 2006 and new wells in the North East Abu Gharadig (NEAG) concession. Higher prices added another $14 million.

Australia’s natural gas revenues increased $22 million to $134 million on higher price realizations and production gains. Price realizations improved 15 percent, adding $16 million to revenues. A five percent demand-driven rise in production generated another $6 million of revenues.

Argentina’s natural gas revenues more than doubled to $86 million, bolstered by a full year of production from 2006 property acquisitions, successful drilling and recompletion activities and a 21 percent increase in price realizations. Production grew 89 MMcf/d, or 79 percent, generating $38 million of new revenues. The price gain added another $8 million.

Canada’s natural gas revenues decreased $6 million to $892 million on a four percent decline in production. Production, which averaged 388 MMcf/d, was impacted by natural decline, which more than offset increases from drilling and recompletion activities. Our exploration and development capital investment in Canada was 38 percent lower than 2006. Lower production reduced revenues by $37 million. Natural gas prices rose $.21, to $6.30 per Mcf, increasing revenues $31 million.

Costs

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

	Year Ended December 31,						Year Ended December 31,
	2008		2007		2006		2008		2007		2006
	(In millions)						(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment Recurring	$	2,358	$	2,208	$	1,699	$	12.06	$	10.78	$	9.29
Additional		5,334		—		—		27.27		—		—
Other assets		158		140		118		.81		.68		.64
Asset retirement obligation accretion		101		96		89		.52		.47		.48
Lease operating expenses		1,909		1,653		1,323		9.76		8.07		7.23
Gathering and transportation		157		137		120		.80		.67		.66
Taxes other than income		985		598		598		5.03		2.92		3.27
General and administrative expenses		289		275		211		1.48		1.34		1.16
Financing costs, net		166		220		142		.85		1.07		.78
Total	$	11,457	$	5,327	$	4,300	$	58.58	$	26.00	$	23.51

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Year 2008 Compared to Year 2007

Depreciation, Depletion and Amortization

The following table details the changes in recurring depreciation, depletion and amortization (DD&A) of oil and gas properties between 2008 and 2007:

	Recurring DD&A
	(In millions)
2007	$	2,208
Volume change		(127	)
Rate change		277
2008	$	2,358

Recurring full-cost depletion expense increased $150 million, $277 million on rate partially offset by $127 million on lower volumes. Our full-cost depletion rate increased $1.28 to $12.06 per boe on drilling and finding costs that exceeded 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 higher oil and gas prices.

In addition, we recorded a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of our December 31, 2008 proved property balances in the U.S., U.K. North Sea, Canada and Argentina proved oil and gas properties. Under the full-cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices and costs in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. Write-downs required by these rules do not impact cash flow from operating activities. If oil and gas prices deteriorate from the Company’s year-end levels, additional write-downs may occur.

Lease Operating Expenses

Lease operating expenses (LOE) include several components: direct operating costs, repair and maintenance, and workover costs.

Direct operating costs generally trend with commodity price levels and are impacted by the type of commodity produced and the location of properties (i.e. offshore, onshore, remote locations, etc). Rising commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Other items such as labor, boats, helicopters and materials and supplies are indirectly impacted as high prices increase industry activity and demand and thus, costs. Oil, which contributed nearly half of our production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are higher on offshore properties and in areas with remote plants and facilities. All production in Australia and the North Sea and nearly 90 percent from the U.S. Gulf Coast region comes from offshore properties. Workovers accelerate production; hence, activity generally increases with higher commodity prices. Fluctuations in exchange rates impact the Company’s LOE, with a weakening U.S. dollar adding to per-unit costs and a strengthening U.S. dollar lowering per unit costs in our international regions.

LOE increased 15 percent on an absolute dollar basis. On a per-unit basis LOE was up 21 percent, or $1.69 per boe. The following discussion focuses on per-unit costs which we believe to be the most meaningful measure for analyzing LOE.

•  Higher operating costs in all regions, including increased power costs in the U.S. and Egypt along with increased labor costs in the North Sea and Argentina, drove the rate up $.33.

•  Increased workover activity, primarily in the U.S. and Egypt, resulted in an increase of $.29.

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•  Hurricane repairs in the U.S. contributed $.07 to increased cost.

•  Repairs related to the pipeline explosion at Varanus Island in Australia added $.03.

•  Non-recurring repairs and maintenance in Egypt, Australia, the North Sea and Argentina increased $.07.

•  Overall production declines resulted in an increase of $.45, with the impact from a combined 12 percent production decline in the U.S., Canada and Australia partially offset by increased production in Egypt, the North Sea and Argentina. The main contributors were decreased production in Australia, $.30, and production shut-in because of the hurricanes, $.29.

Gathering and Transportation

We generally sell oil and natural gas under two common types of agreements, both of which include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a lower relative price to reflect transportation costs to be incurred by the purchaser. In this case, we record sales at the netback price received from the purchaser. Alternatively, we sell oil or natural gas at a specific delivery point, pay our own transportation to a third-party carrier and receive a price with no transportation deduction. In this case we record the separate transportation cost as gathering and transportation costs.

In both the U.S. and Canada, we sell oil and natural gas under both types of arrangements. In the North Sea, we pay transportation to a third-party carrier. In Australia, oil and natural gas are sold under netback arrangements. In Egypt, our oil and natural gas production is primarily sold to EGPC under netback arrangements; however, we also export crude oil under both types of arrangements. In Argentina, we sell oil and natural gas under both types of arrangements.

The following table presents gathering and transportation costs we paid directly to third-party carriers for each of the periods presented:

	For the Year Ended
	December 31,
	2008		2007
	(In millions)
U.S.	$	39	$	38
Canada		64		54
North Sea		28		27
Egypt		21		15
Argentina		5		3
Total Gathering and Transportation	$	157	$	137
Total Gathering and Transportation per boe	$	.80	$	.67

These costs are primarily related to the portion of natural gas in our U.S. and Canadian operation sold under arrangements where we pay transportation directly to third parties North Sea crude oil sales and our Egyptian crude oil exports not sold under netback arrangements. The $20 million increase was driven primarily by higher transportation tariffs in Canada and an increase in Egyptian export volumes.

Taxes other than Income

Taxes other than income primarily comprises United Kingdom (U.K.) Petroleum Revenue Tax (PRT), severance taxes on properties onshore and in state or provincial waters in the U.S. and Australia and ad valorem taxes on properties in the U.S. and Canada. Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties field in the U.K. North Sea. We are subject to a variety of other taxes including U.S. franchise taxes, Australian Petroleum Resources Rent tax and various Canadian taxes including: Freehold

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Mineral tax, Saskatchewan Capital tax and Saskatchewan Resources Surtax. We also pay taxes on invoices and bank transactions in Argentina. The table below presents a comparison of these expenses:

	For the Year Ended
	December 31,
	2008		2007
	(In millions)
U.K. PRT	$	695	$	346
Severance taxes		168		142
Ad valorem taxes		71		56
Other taxes		51		54
Total Taxes other than Income	$	985	$	598
Total Taxes other than Income per boe	$	5.03	$	2.92

U.K. PRT was $349 million more than 2007 on a 98 percent increase in net profits, 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 in the first nine months of the year. The $15 million increase in ad valorem taxes resulted from higher taxable valuations associated with increases in oil and natural gas prices at the time the taxes were assessed and a full year of taxes on the Permian Basin properties acquired in the first quarter of 2007.

General and Administrative Expenses

General and administrative expenses (G&A) were $14 million higher. On a boe basis, G&A averaged $1.48, up $.14 per boe on a combination of increased costs and lower volumes, each of which added $.07 to the rate. The cost increase was driven by higher legal fees, especially in our international operations, increased incentive compensation expenses and miscellaneous higher costs in several departments, partially offset by a decrease in stock-based compensation expenses related to cash settled stock appreciation rights.

Financing Costs, Net

The major components of financing costs, net, include interest expense and capitalized interest. Net financing costs for 2008 decreased $54 million or $.22 per boe, on lower average outstanding debt balances. Interest expense was down $28 million on lower average debt. Capitalized interest was up primarily because of higher expenditures associated with long-term construction projects that are under development.

Provision for Income Taxes

There were no significant changes in statutory tax rates in the major jurisdictions in which the Company operates during 2008. In 2007 we saw a significant reduction to deferred income taxes resulting from Canadian tax rate reductions.

The provision for income taxes decreased $1.6 billion from 2007 to $220 million, as income before taxes decreased 80 percent as a result of the $5.3 billion in additional DD&A recorded in conjunction with the ceiling test write-down. The effective income tax rate for the year was 23.6 percent compared to 39.8 percent in 2007. The 2008 effective rate was impacted by the magnitude of the taxes related to the write-down, non-cash benefits related to the effect of the strengthening U.S. dollar on our foreign deferred tax liabilities and other net tax settlements. Excluding these items, the 2008 effective rate would have been comparable to the 2007 effective rate. The 2007 effective rate was impacted by a non-cash charge related to the effect of the weakening U.S. dollar on our foreign deferred tax liabilities. Partially offsetting this charge was an out of period benefit from Canadian federal tax rate reductions enacted in the second and fourth quarters of 2007.

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Year 2007 Compared to Year 2006

Depreciation, Depletion and Amortization

The following table details the changes in depreciation, depletion and amortization (DD&A) of oil and gas properties between 2007 and 2006:

	DD&A
	(In millions)
2006	$	1,699
Volume change		210
Rate change		299
2007	$	2,208

Full-cost DD&A expense totaled $2.2 billion, $509 million more than 2006. Production growth drove $210 million of the increase; the remainder is a consequence of higher costs. DD&A per boe averaged $10.78, $1.49 higher than 2006 as the costs to acquire, find and develop reserves continued to exceed our historical cost basis. Increasing costs also impact our estimates for future development of known reserves and estimates to abandon properties, both of which impact our full-cost depletion rate.

DD&A on other assets increased $22 million to $140 million with facilities coming online, in Canada, Egypt and the U.S. A full year of DD&A on assets acquired during 2006 in Argentina also contributed to the year-over-year increase.

Lease Operating Expenses

Lease operating expenses (LOE) increased 25 percent on an absolute dollar basis. On a per-unit basis LOE was up 12 percent, or $.84 per boe. Almost two-thirds of the increase was from additional workover activity ($.16), a weakening U.S. dollar ($.16), hurricane repair activity ($.15) and incentive-based compensation ($.07). The remaining increase is the result of the inflationary impact of higher commodity prices on all other operating costs, as described above.

The U.S. contributed $.47 to the $.84 per boe increase. Driving factors in the increase were additional hurricane repairs ($.15), more workover activity ($.13), acquired Permian basin oil properties which carry a higher rate than our historical average ($.05), incremental incentive-based compensation with Apache’s rising stock price ($.04) and the inflationary impact higher commodity prices have on operating costs ($.05). Over two-thirds of the increase in workover activity occurred on properties acquired in March 2007 in the Permian basin of West Texas.

Canada added $.30 per boe to the consolidated rate, $.09 of which was attributed to a decline in relative production. A weakening U.S. dollar negatively impacted the rate an additional $.09. The balance of the increase related to higher levels of workover activity ($.03), lease rentals ($.02), company labor ($.02) and generally higher costs.

The North Sea increased the consolidated rate $.09 per boe: the net impact of a $.10 per boe increase on a decline in production volumes and a reduction of $.01 on lower costs. The benefit of decreases in diesel fuel consumption ($.08) and lower turnaround expenses more than offset increases from the impact of the weakening U.S. dollar ($.05), higher standby and supply boat costs ($.01) and higher contract labor ($.01). We are seeing the benefits of several years of facility upgrades to reduce the operating costs, including completion of our power generation ring.

Australia increased the consolidated rate $.09 per boe over 2006. The increase was primarily a result of our acquisition of an additional interest in Legendre, an oil field which carries a higher cost per barrel than our existing blended Australian rate ($.06), and appreciation of the Australian dollar relative to the U.S. dollar ($.02).

Two Argentine acquisitions, in April and September 2006, lowered the 2007 consolidated rate $.13 per boe. The LOE rate on these properties was lower than our existing consolidated rate.

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Egypt had no impact on the consolidated rate. Our 2006 exit from China increased the 2007 consolidated rate $.04 per boe.

Gathering and transportation

Gathering and transportation costs totaled $137 million, up $17 million. The following table presents gathering and transportation costs paid by Apache to third-party carriers for each of the periods presented.

	For the Year Ended
	December 31,
	2007		2006
	(In millions)
U.S.	$	38	$	32
Canada		54		50
North Sea		27		26
Egypt		15		11
Argentina		3		1
Total Gathering and Transportation	$	137	$	120
Total Gathering and Transportation per boe	$	.67	$	.66

These costs are primarily related to the portion of natural gas in our U.S. and Canadian operation sold under arrangements where we pay transportation directly to third parties, and North Sea crude oil sales and our Egyptian crude oil exports not sold under netback arrangements. The $17 million increase was driven primarily by U.S. production growth, an increase in Egyptian crude exports not sold under netback arrangements and a full year of transportation costs paid to third parties in Argentina.

Taxes other than Income

Taxes other than income totaled $598 million for 2007 and 2006.

The table below presents a comparison of these expenses:

	For the Year Ended
	December 31,
	2007		2006
	(In millions)
U.K. PRT	$	346	$	394
Severance taxes		142		122
Ad Valorem taxes		56		44
Other taxes		54		38
Taxes other than Income	$	598	$	598
Taxes other than Income per boe	$	2.92	$	3.27

On a per-unit basis taxes other than income decreased $.35, or 12 percent, reflecting the 12 percent increase in equivalent production. The increase in severance taxes was driven by higher production and prices on U.S. and Australian properties burdened by such taxes. U.K. PRT was 12 percent below 2006, largely driven by lower comparable revenues on less production and slightly higher deductible costs. Deductible costs include capital expenditures, LOE, general and administrative expenses (G&A) and transportation tariffs. Ad valorem taxes increased $12 million. Oil and liquids were 47 percent of our production in both 2007 and 2006. A significant portion of our ad valorem taxes are reserve based and increase when prices rise. Other taxes increased with a full year of taxes on invoice and bank transactions in Argentina.

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General and Administrative Expenses

General and administrative expenses (G&A) were $64 million, or $.18 per boe, higher than 2006. Incentive-based compensation added $.12 per boe to the rate, a consequence of a strong stock price appreciation during the year, while insurance costs added $.11 per boe, a consequence of industry-wide premium increases after the 2005 hurricanes. These increases were partially offset by a decrease in rate stemming from higher production.

Financing Costs, Net

The major components of financing costs, net, include interest expense and capitalized interest. Net financing costs for 2007 increased $78 million or $.29 per boe, on higher average outstanding debt balances, which offset a slightly lower average interest rate.

Provision for Income Taxes

The 2007 provision for income taxes was $1.9 billion, $403 million above 2006 on both higher taxable income and a higher effective tax rate. Apache’s 2007 effective tax rate was 39.8 percent compared to 36.3 percent in 2006. The 2007 effective rate was impacted by a non-cash charge related to the effect of the weakening U.S. dollar on our foreign deferred tax liabilities. Partially offsetting this charge was an out of period benefit from Canadian federal tax rate reductions enacted in the second and fourth quarters of 2007. The 2006 effective tax rate was impacted by a charge related to retroactive application of a 10 percent increase in the oil and gas company supplemental tax enacted by the U.K., a benefit from a Canadian federal provincial tax rate reduction enacted in the second quarter of 2006 and a gain recognized on the sale of China. Foreign currency fluctuations had a negligible impact on the 2006 rate.

Acquisitions and Divestitures

2008 Activity

There was no major acquisition activity during 2008; however, the Company completed several divestiture transactions. On January 29, 2008, the Company completed the sale of its interest in Ship Shoal blocks 349 and 359 on the outer continental shelf of the Gulf of Mexico to W&T Offshore, Inc. for $116 million. On January 31, 2008, the Company completed the sale of non-strategic oil and gas properties in the Permian Basin of West Texas to Vanguard Permian, LLC for $78 million. On April 2, 2008, the Company completed the sale of non-strategic Canadian properties to Central Global Resources for $112 million. These divestitures are subject to normal post-closing adjustments.

2007 Activity

U.S. Gulf Coast Farm-in  On September 6, 2007, Apache entered into an Exploration Agreement with various EnerVest Partnerships (“EVP”) for an initial term of four years whereby Apache committed to spend $30 million in qualified expenditures to explore, drill, produce and market hydrocarbons from specified undeveloped formations across 400,000 net acres in Central and East Texas. As of December 31, 2008, Apache has fulfilled the $30 million commitment.

U.S. Permian Basin  On March 29, 2007, the Company closed its acquisition of controlling interest in 28 oil and gas fields in the Permian basin of West Texas from Anadarko for $1 billion. Apache estimates that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of year-end 2006. The Company funded the acquisition with debt. Apache and Anadarko entered into a joint-venture arrangement to effect the transaction. The Company entered into cash flow hedges for a portion of the crude oil and the natural gas production.

2006 Activity

U.S. Permian Basin  On January 5, 2007, the Company purchased Amerada Hess’s interest in eight fields located in the Permian basin of West Texas and New Mexico. The original purchase price was reduced from $404 million to $269 million because other interest owners exercised their preferential rights to purchase a number of the properties. The settlement price at closing of $239 million was adjusted for revenues and expenditures

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occurring between the effective date and the closing date of the acquisition. The acquired fields had estimated proved reserves of 27 MMbbls of liquid hydrocarbons and 27 Bcf of natural gas as of year-end 2005.

Argentina  On April 25, 2006, the Company acquired the operations of Pioneer Natural Resources (Pioneer) in Argentina for $675 million. The settlement price at closing, of $703 million, was adjusted for revenues and expenditures occurring between the effective date and closing date of the acquisition. The properties are located in the Neuquén, San Jorge and Austral basins of Argentina and had estimated net proved reserves of approximately 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas as of December 31, 2005. Eight gas processing plants (five operated and three non-operated), 112 miles of operated pipelines in the Neuquén basin and 2,200 square miles of three-dimensional (3-D) seismic data were also included in the transaction. Apache financed the purchase with cash on hand and commercial paper.

The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):

Proved property	$	501,938
Unproved property		189,500
Gas Plants		51,200
Working capital acquired, net		11,256
Asset retirement obligation		(13,635	)
Deferred income tax liability		(37,630	)
Cash consideration	$	702,629

On September 19, 2006, Apache acquired additional interests in (and now operates) seven concessions in the Tierra del Fuego Province from Pan American Fueguina S.R.L. (Pan American) for total consideration of $429 million. The settlement price at closing of $396 million was adjusted for normal closing items, including revenues and expenses between the effective date and the closing date of the acquisition. Apache financed the purchase with cash on hand and commercial paper.

The total cash consideration allocated below includes working capital balances purchased, asset retirement obligations assumed and an obligation to deliver specific gas volumes in the future. The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):

Proved property	$	289,916
Unproved property		132,000
Gas plants		12,722
Working capital acquired, net		8,929
Asset retirement obligation		(1,511	)
Assumed obligation		(46,000	)
Cash consideration	$	396,056

U.S. Gulf Coast  In June 2006, the Company acquired the remaining producing properties of BP plc (BP) on the Outer Continental Shelf of the Gulf of Mexico. The original purchase price was reduced from $1.3 billion for 18 producing fields to $845 million because other interest owners exercised their preferential rights to purchase five of the 18 fields. The purchase price consisted of $747 million of proved property, $42 million of unproved property and $56 million of facilities. The settlement price on the date of closing of $821 million was adjusted primarily for revenues and expenditures occurring between the April 1, 2006 effective date and the closing date of the acquisition. The acquired properties include 13 producing fields (nine of which are operated) with estimated proved reserves of 19.5 MMbbls of liquid hydrocarbons and 148 Bcf of natural gas. Apache financed the purchase with cash on hand and commercial paper.

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Divestitures  On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. Apache did not have any proved reserves booked for these properties.

On August 8, 2006, the Company completed the sale of its 24.5 percent interest in the Zhao Dong block, offshore the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking Apache’s exit from China. The effective date of the transaction was July 1, 2006. The Company recorded a gain of $174 million in the third quarter of 2006.

Capital Resources and Liquidity

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for each of the three years ended December 31. The table presents capital expenditures on a cash basis; therefore, the amounts differ from the amounts of capital expenditures, elsewhere in this document, which include accruals.

	Year Ended December 31,
	2008		2007			2006
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	7,065	$	5,677		$	4,313
Sales of property and equipment		308		67			678
Net commercial paper and bank loan borrowings		—		—			1,630
Project financing draw-downs		100		—			—
Fixed-rate debt borrowings		796		2,002			—
Common stock issuances		36		44			39
Other		39		26			36
		8,344		7,816			6,696
Uses of Cash and Cash Equivalents
Capital expenditures		5,823		4,802			4,140
Purchase of short-term investments		792		—			—
Acquisitions		150		1,005			2,164
Net commercial paper and bank loan repayments		200		1,425			—
Payments on debt		—		170			—
Repurchase of common stock		—		—			174
Dividends		239		205			154
Other		84		224			152
		7,288		7,831			6,784
Increase (decrease) in cash and cash equivalents	$	1,056	$	(15	)	$	(88	)

Net Cash Provided by Operating Activities  Net cash provided by operating activities (“operating cash flows”) is our primary source of capital and liquidity. Factors affecting changes in operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A and deferred income tax expense. Factors affecting our operating cash flows are discussed in the “Results of Operations” section of this report. Operating cash flows in 2008 increased from 2007.

Fixed-Rate Debt Issuances  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

44

proceeds are presently invested in U.S. Treasury Bills and will be used for general corporate purposes or, possibly, future acquisitions.

Project Financing Draw-downs  On December 5, 2008, one of the Company’s Australian subsidiaries entered into a secured revolving syndicated credit facility for the Van Gogh and Pyrenees oil developments. The facility provides for total commitments of $350 million with availability determined by a borrowing base formula. The borrowing base was set at $350 million and will be redetermined at completion and semi-annually thereafter. The facility is secured by certain assets associated with the Van Gogh and Pyrenees oil developments, including the shares of stock of the Company’s subsidiary holding the assets. The Company has agreed to guarantee the credit facility until completion occurs pursuant to terms of the facility, which is expected in 2010. The commitments under the facility will be reduced by scheduled increments every six months beginning June 30, 2010, with final maturity on March 31, 2014. Interest is based on LIBOR, which may be subject to change under certain market disruption conditions, plus a margin of 1.00 percent pre-completion and 1.75 percent post-completion. The pre-completion margin increases to 1.125 percent in the event the Company’s ratings are downgraded to BBB+ or below by at least two major rating agencies. As of December 31, 2008 there was $100 million outstanding under the facility.

Capital Expenditures  We fund exploration and development activities primarily through net cash provided by operating activities and budget capital expenditures based on projected operating cash flows. Our operating cash flows, both in the short- and long-term, is impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire or find high-margin reserves at competitive prices. For these reasons, management primarily relies on annual operating cash flow forecasts. Annual operating cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to these adjusted operating cash flow forecasts and market trends in drilling and acquisitions costs. Longer-term operating cash flows and capital spending projections are rarely used by management to operate the business.

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

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

	Year Ended December 31,
	2008		2007		2006
	(In thousands)
Exploration and Development:
United States	$	2,183,473	$	1,630,776	$	1,532,959
Canada		705,066		650,676		1,056,614
Egypt		852,802		605,115		454,892
Australia		879,680		516,054		179,892
North Sea		459,239		537,868		329,498
Argentina		317,490		287,047		115,570
Chile		27,457		—		—
China		—		—		12,288
		5,425,207		4,227,536		3,681,713
Acquisitions — Oil and gas properties		149,838		1,024,956		2,428,432
Asset Retirement Costs		513,891		439,368		390,612
Capitalized Interest		94,164		75,748		61,301
Gathering, Transmission and Processing Facilities		659,248		473,481		248,589
Total capital expenditures	$	6,842,348	$	6,241,089	$	6,810,647

Exploration and Development (E&D) — Increases in our 2008 operating cash flows, year-over-year, enabled us to invest larger amounts on E&D capital projects. We invested $5.4 billion on drilling, recompletions and

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platform and production support facilities in 2008, up 28 percent from 2007. Our 2007 E&D capital expenditures were $546 million above 2006.

Acquisitions — We completed $150 million of acquisitions in 2008 compared to $1 billion in 2007. Acquisition capital expenditures occur as attractive opportunities arise and, therefore, vary from year to year.

Asset Retirement Costs — In 2008, we recorded $514 million of additional asset retirement costs. The increase is primarily related to revisions of our cost estimates. Rising estimates for service costs and the high level of abandonment activities in the Gulf Coast region have accelerated some obligations. Continued worldwide drilling programs, acquisition activity and damage from Hurricane Ike also contributed to the increased abandonment costs.

Gathering, Transmission and Processing Facilities (GTP) — We invested $659 million in GTP facilities in 2008 compared to $473 million in 2007. In Egypt, we invested $571 million in gas processing facilities to alleviate capacity constraints, which are restricting production. We also invested $55 million in Australia on GTP projects currently in process. In Canada, we invested $29 million in processing plants.

2009 Outlook — In light of a collapse in commodity prices and uncertainties surrounding the worldwide financial crisis, we seek to keep capital spending in line with 2009 operating cash flows in order to preserve our strong balance sheet and financial flexibility. We will closely monitor commodity prices, service cost levels and predicted operating cash and will adjust our exploration and development budgets accordingly. While certain long-lead development projects are committed in 2009, the majority of our drilling and development projects are discretionary and subject to deferral or cancellation as conditions warrant. Because we revise our exploration and development capital budgets frequently throughout the year, projecting future expenditures is difficult at best. Our 2009 preliminary plan includes exploration and development capital of approximately $3.5 to $4.0 billion, including GTP. We generally do not project estimates for acquisitions because their occurrence and timing is unpredictable. Any acquisitions would be funded from operating cash flow, credit facilities, issuing new equity, or a combination thereof.

Repurchases of Common Stock  On April 19, 2006, the Company announced that its Board of Directors authorized the purchase of up to 15 million shares of the Company’s common stock, representing a market value of approximately $1 billion on the date of announcement. The Company may buy shares from time to time on the open market, in privately negotiated transactions, or a combination of both. The timing and amounts of any purchases will be at the discretion of Apache’s management. The Company initiated the purchase program on May 1, 2006, after the Company’s first-quarter 2006 earnings information was disseminated in the market. During 2006, the Company purchased 2,500,000 shares at an average price of $69.74 per share. No stock purchases were made in 2007 or 2008, and we currently have no plans to purchase any shares in 2009.

Dividends  The Company has paid cash dividends on its common stock for 44 consecutive years through 2008. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other relevant factors. Common dividends paid during 2008 rose 17 percent to $234 million, reflecting the special cash dividend of 10 cents per common share paid on March 18, 2008 and an increase in common shares outstanding. Common dividends paid during 2007 rose 34 percent to $199 million, reflecting the increase in common shares outstanding and an increase in the common stock dividend rate. The Company increased its quarterly cash dividend 50 percent, to 15 cents per share from 10 cents per share, effective with the November 2006 dividend payment.

During 2008 and 2007, Apache paid a total of $6 million in dividends each year on its Series B Preferred Stock issued in August 1998. See Note 7 — Capital Stock of Item 15 in this Form 10-K.

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Liquidity

	At December 31,
Millions of Dollars Except as Indicated	2008			2007			2006
Cash	$	1,181		$	126		$	141
Short-term investments		792			—			—
Restricted cash		14			—			—
Total debt		4,922			4,227			3,822
Shareholders’ equity		16,509			15,378			13,192
Available committed borrowing capacity		2,550			2,115			690
Floating-rate debt/total debt		2	%		5	%		43	%
Percent of total debt to capitalization		23	%		22	%		22	%

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. The banks with lending commitments to the Company have credit ratings of at least single-A (or equivalent) which in some cases is based on government support. There is no assurance that the financial condition of these banks will not deteriorate or that the government guarantee will be maintained. We closely monitor the ratings of the 27 banks in our bank group. Having a large bank group allows the Company to mitigate the impact of any bank’s failure to honor its lending commitment.

Cash and Cash Equivalents  We had $1.2 billion in cash and cash equivalents at December 31, 2008, compared with $126 million at December 31, 2007. The majority of this cash is in our foreign subsidiaries ($146 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.

Short-term Investments  The Company occasionally invests in highly-liquid, short-term investments in order to maximize our income on available cash balances. As needed, we may reduce such short-term investment balances to further supplement our operating cash flows. At December 31, 2008, we had $792 million invested in obligations of the U.S. Government with original maturities greater than three months but less than a year.

Restricted Cash  The Company classifies cash balances as restricted cash when it is restricted as to withdrawal or usage. As of December 31, 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 expected to use these funds to purchase noncurrent assets. Accordingly, the restricted cash was classified as long-term at year-end. Subsequent to year-end, the time limits pursuant to Section 1031 expired and the funds were transferred to cash.

Debt  At year-end 2008, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $4.9 billion. Current debt includes $100 million of Apache Finance Pty Limited 7.0-percent notes due March 2009 and $13 million borrowed under uncommitted overdraft lines in Argentina. We have no debt maturing in 2010 or 2011, $439 million maturing in 2012, $942 million maturing in 2013 and the remaining $3.4 billion maturing intermittently in years 2014 through 2096.

Debt-to-Capitalization Ratio  The Company’s debt-to-capitalization ratio as of December 31, 2008 was 23 percent.

Available Credit Facilities  The Company had available borrowing capacity under our total credit facilities of approximately $2.6 billion at December 31, 2008; $2.3 billion of unsecured revolving syndicated bank credit facilities and $250 million under one of the Company’s Australian subsidiaries secured revolving syndicated credit facility for the Van Gogh and Pyrenees oil developments, entered into in December 2008. The Company was in compliance with the terms of all credit facilities as of December 31, 2008.

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The $2.3 billion of unsecured revolving syndicated bank credit facilities mature in May 2013. Since there were no outstanding borrowings or commercial paper at year-end, the full $2.3 billion of unsecured credit facilities were available to the Company. These 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. The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to five percent of the Company’s consolidated assets, which approximated $1.5 billion as of December 31, 2008. There are no restrictions on incurring liens in countries other than U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group. Furthermore, our non-cash write-down of oil and gas properties in 2008 does not impact the availability of credit lines or result in non-compliance with any covenants.

There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes (MAC clauses). The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2008.

At the Company’s option, the interest rate for the facilities is based on (i) the greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent or (ii) the London Inter-bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $1.5 billion and the $450 million credit facilities (U.S. credit facilities) also allow the company to borrow under competitive auctions.

At December 31, 2008, the margin over LIBOR for committed loans was .19 percent on the $1.5 billion facility and .23 percent on the other three facilities. If the total amount of the loans borrowed under the $1.5 billion facility equals or exceeds 50 percent of the total facility commitments, then an additional .05 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of .06 percent on the total amount of the $1.5 billion facility and .07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating. The U.S. credit facilities are used to support Apache’s commercial paper program.

On December 5, 2008, one of the Company’s Australian subsidiaries entered into a secured revolving syndicated credit facility for the Van Gogh and Pyrenees oil developments. The facility provides for total commitments of $350 million with availability determined by a borrowing base formula. The borrowing base was set at $350 million and will be redetermined at project completion and semi-annually thereafter. The facility is secured by certain assets associated with the Van Gogh and Pyrenees oil developments, including the shares of stock of the Company’s subsidiary holding the assets. The Company has agreed to guarantee the credit facility until completion occurs pursuant to terms of the facility, which is expected in 2010. The commitments under the facility will be reduced by scheduled increments every six months beginning June 30, 2010, with final maturity on March 31, 2014. Interest is based on LIBOR, which may be subject to change under certain market disruption conditions, plus a margin of 1.00 percent pre-completion and 1.75 percent post-completion. The pre-completion margin increases to 1.125 percent in the event the Company’s ratings are downgraded to BBB+ or below by at least two major rating agencies. As of December 31, 2008, there is $100 million outstanding under the facility.

Commercial Paper Program  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 December 31, 2008, Apache had no commercial paper outstanding. Our weighted-average interest rate for commercial paper was 5.65 percent and 3.85 percent for 2008 and 2007, respectively. If the Company is unable to issue commercial paper

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following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100 percent backstop.

Credit Ratings  We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels could also be considered by the rating agencies. Apache’s senior unsecured long term debt is currently rated A3 by Moody’s, A- by Standard & Poor’s and A by Fitch. Apache’s short-term debt rating for its commercial paper program is currently P-2 by Moody’s, A-2 by Standard & Poor’s and F1 by Fitch. The outlook is stable from Moody’s and Standard & Poor’s and negative from Fitch. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and potentially require the Company to post letters of credit in certain circumstances. We cannot predict, nor can we assure, that we will not receive a ratings downgrade in the future.

Pricing Trends.  For 2008, the Company’s average realized prices were 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. Crude oil trades in 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 Mercantile 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:

	December		November		October		September		August		July
Crude Oil	$	42.04	$	57.44	$	76.77	$	104.41	$	116.73	$	134.42
Natural Gas	$	5.79	$	6.70	$	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. Given the recent commodity price levels, our initial 2009 budgeted expenditures is 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.

Contractual Obligations

We are subject to various financial obligations and commitments in the normal course of operations. These contractual obligations represent known future cash payments that we are required to make and relate primarily to long-term debt, operating leases, pipeline transportation commitments and international commitments. The Company expects to fund these contractual obligations with cash generated from operating activities.

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The following table summarizes the Company’s contractual obligations as of December 31, 2008. See Notes 5 — Debt and 9 — Commitments and Contingencies of Item 15 in this form 10-K for further information regarding these obligations.

	Note										2015 &
Contractual Obligations	Reference		Total		2009		2010-2012		2013-2014		Beyond
					(In thousands)
Debt		Note 5	$	4,921,573	$	112,598	$	438,852	$	957,065	$	3,413,058
Interest payments		Note 5		5,112,221		299,485		875,455		471,595		3,465,686
Drilling rig commitments		Note 9		889,874		516,180		372,594		1,100		—
Purchase obligations		Note 9		371,279		370,720		559		—		—
E&D commitments		Note 9		197,512		92,459		99,670		5,383		—
Firm transportation agreements		Note 9		223,153		26,541		81,234		55,496		59,882
Office and related equipment		Note 9		122,599		21,354		60,758		18,962		21,525
Oil and gas operations equipment		Note 9		472,980		77,122		125,676		59,304		210,878
Other				3,840		3,840		—		—		—
Total Contractual Obligations(a)(b)(c)(d)			$	12,315,031	$	1,520,299	$	2,054,798	$	1,568,905	$	7,171,029

(a)	This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1.9 billion. See Note 4 — Asset Retirement Obligation of Item 15 in this Form 10-K for further discussion.
(b)	This table does not include the Company’s $212 million asset for outstanding derivative instruments valued as of December 31, 2008. See Note 3 — Hedging and Derivative Instruments of Item 15 in this Form 10K for further discussion.
(c)	This table does not include the Company’s pension or postretirement benefit obligations. See Note 9 — Commitments and Contingencies of Item 15 in this Form 10-K for further discussion.
(d)	This table does not include the Company’s FIN 48 obligations. See Note 6 — Income Taxes of Item 15 in this Form 10-K for further discussion.

Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations, including approximately $27 million for environmental remediation and approximately $25 million for various legal liabilities. See Note 9 — Commitments and Contingencies of Item 15 in this Form 10-K for a detailed discussion of the Company’s environmental and legal contingencies.

The Company also accrued approximately $74 million as of December 31, 2008, for an insurance contingency because of our involvement with Oil Insurance Limited (OIL). Apache is a member of this insurance pool, which insures specific property, pollution liability and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay termination fees were we to elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential termination fee is calculated annually based on past losses, and the liability reflecting this potential charge has been accrued as required.

Subsequent Event  On February 10, 2009, Apache’s wholly-owned subsidiary, Apache Canada Ltd. entered into an agreement with TransCanada Pipelines Limited (TCPL) pursuant to which TCPL will construct and install a gas pipeline from northeastern British Columbia to the existing NOVA pipeline system located in the Ekwan area of Alberta. Apache Canada intends to ship gas produced from the Ootla basin on the new pipeline.

The construction, operation and transportation rates of the new pipeline are subject to regulatory approval. Authority to construct the pipeline is expected, and construction is anticipated to be complete on or before April 1, 2011. Upon completion of the pipeline, Apache Canada will have a ship-or-pay commitment of 100 MMBtu of gas

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for either a four-year period or a ten-year period depending on the rate structure determined and approved by the regulatory agency. Apache Canada has the right to terminate the agreement before October 1, 2009. If Apache Canada elects to terminate the agreement or TCPL terminates for reasons set forth in the agreement, Apache Canada must reimburse TCPL for certain costs and expenses up to approximately CDN $90 million plus certain taxes.

Off-Balance Sheet Arrangements

Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions.

Critical Accounting Policies and Estimates

Apache prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Apache identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of Apache’s financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of Apache’s most critical accounting policies:

Reserve Estimates  Our estimate of proved reserves is based on the quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. As such, our reserve engineers review and revise the Company’s reserve estimates at least annually.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Asset Retirement Obligation (ARO)  The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future, and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal,

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regulatory, environmental and political environments. 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.

Income Taxes  Our oil and gas exploration and production operations are currently located in six countries. As a result, we are subject to taxation on our income in numerous jurisdictions. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

The Company regularly assesses and, if required, establishes accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. Tax reserves have been established and include any related interest, despite the belief by the Company that certain tax positions have been fully documented in the Company’s tax returns. These reserves are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law and any new legislation. The Company believes that the reserves established are adequate in relation to the potential for any additional tax assessments.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates, foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile due to unpredictable events such as economical growth or retraction, weather and climate. Crude oil prices in 2008 began the year strong and increased rapidly to unprecedented levels in the summer, before decreasing to below first quarter 2008 prices by the end of the year. West Texas Intermediate (WTI), an industry benchmark crude oil, peaked above $147 per barrel in July before falling to nearly $40 at year-end as a result of decreased demand for energy as world economies slowed. Natural gas prices, especially in the U.S. where we have fewer long-term supply contracts, followed a similar path.

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

Apache historically only hedged long-term oil and gas prices related to a portion of its expected production associated with acquisitions; however, in 2007 and 2008, the Company’s Board of Directors authorized management to hedge a portion of production generated from the Company’s drilling program. Approximately 20 percent of our 2008 natural gas production and 19 percent of our crude oil production were subjected to financial derivative hedges.

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On December 31, 2008, the Company had open natural gas derivative hedges in an asset position with a fair value of $47 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $15 million, while a 10 percent decrease in prices would increase the fair value by approximately $18 million. The Company also had open oil derivatives in an asset position with a fair value of $165 million. A 10 percent increase in oil prices would decrease the asset by approximately $117 million, while a 10 percent decrease in prices would increase the asset by approximately $118 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2008. See Note 3 — Hedging and Derivative Instruments of Item 15 in this Form 10-K for notional volumes and terms associated with the Company’s derivative contracts.

Apache conducts its risk management activities for its commodities under the controls and governance of its risk management policy. The Risk Management Committee, comprising the President (principal financial officer), General Counsel, Treasurer and other key members of Apache’s management, approve and oversee these controls, which have been implemented by designated members of the treasury department. The treasury and accounting departments also provide separate checks and reviews on the results of hedging activities. Controls for our commodity risk management activities include limits on credit, limits on volume, segregation of duties, delegation of authority and a number of other policy and procedural controls.

Interest Rate Risk

On December 31, 2008, the Company’s debt with fixed interest rates represented approximately 98 percent of total debt. As a result, the interest expense on approximately two percent of Apache’s debt will fluctuate based on short-term interest rates. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $707,000.

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 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 British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars but 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

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2008 and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are

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reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

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

•  our commodity hedging arrangements;

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

•  production and reserve levels;

•  drilling risks;

•  economic and competitive conditions;

•  the availability of capital resources;

•  capital expenditure and other contractual obligations;

•  currency exchange rates;

•  weather conditions;

•  inflation rates;

•  the availability of goods and services;

•  legislative or regulatory changes;

•  terrorism;

•  occurrence of property acquisitions or divestitures;

•  the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and

•  other factors disclosed under Items 1 and 2 — “Business and Properties — Estimated Proved Reserves and Future Net Cash Flows,” Item 1A — “Risk Factors,” Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A — “Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this Form 10-K.

All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this item are presented on pages F-1 through F-55 of this Form 10-K and are incorporated herein by reference.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2008, 2007 and 2006, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein.

ITEM 9A.   CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

G. Steven Farris, the Company’s Chairman and Chief Executive Officer, in his capacity as principal executive officer, and Roger B. Plank, the Company’s President, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 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 the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in internal controls over financial reporting during the quarter ending December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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

Management’s Report on Internal Control Over Financial Reporting

The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to “Report of Management on Internal Control Over Financial Reporting,” included on Page F-1 in Item 15 of this Form 10-K.

The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated by reference to the “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting,” included on Page F-3 in Item 15 of this Form 10-K.

Changes in Internal Control Over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ending December 31, 2008, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

55

PART III

ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2009 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), which also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Management and Governance page of the Company’s website at www.apachecorp.com. Any stockholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within five business days and maintained for at least 12 months.

ITEM 11.   EXECUTIVE COMPENSATION

The information set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Non-Qualified Deferred Compensation Table,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements” and “Director Compensation Table” in the Proxy Statement is incorporated herein by reference.

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information set forth under the captions “Securities Ownership and Principal Holders” and “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information set forth under the captions “Certain Business Relationships and Transactions” and “Director Independence” in the Proxy Statement is incorporated herein by reference.

ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information set forth under the caption “Independent Registered Public Accountants” in the Proxy Statement is incorporated herein by reference.

PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a)   Documents included in this report:

56

1. Financial Statements

Report of management	F-1
Report of independent registered public accounting firm	F-2
Report of independent registered public accounting firm	F-3
Statement of consolidated operations for each of the three years in the period ended December 31, 2008	F-4
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2008	F-5
Consolidated balance sheet as of December 31, 2008 and 2007	F-6
Statement of consolidated shareholders’ equity for each of the three years in the period ended December 31, 2008	F-7
Notes to consolidated financial statements	F-8

2. Financial Statement Schedules

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.

3. Exhibits

Exhibit
No.				Description
	2	.1	—	Agreement and Plan of Merger among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996).
	2	.2	—	Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
	2	.3	—	Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
	3	.1	—	Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	3	.2	—	Bylaws of Registrant, as amended December 14, 2006 (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2006, SEC File No. 001-4300).
	4	.1	—	Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
	4	.2	—	Form of Certificate for Registrant’s 5.68% Cumulative Preferred Stock, Series B (incorporated by reference to Exhibit 4.2 to Amendment No. 2 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 001-4300).
	4	.3	—	Rights Agreement, dated January 31, 1996, between Registrant and Norwest Bank Minnesota, N.A., rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).

57

Exhibit
No.				Description
	4	.4	—	Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of December 31, 1996, between Apache Corporation, a Delaware corporation, and Wells Fargo Bank, N.A. (successor to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).
	4	.5	—	Senior Indenture, dated February 15, 1996, between Registrant and JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
	4	.6	—	First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
	4	.7	—	Form of Indenture among Apache Finance Pty Ltd, Registrant and The Chase Manhattan Bank, as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973).
	4	.8	—	Form of Indenture among Registrant, Apache Finance Canada Corporation and The Chase Manhattan Bank, as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).
	10	.1	—	Form of Amended and Restated Credit Agreement, dated as of May 9, 2006, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2006, SEC File No. 001-4300).
	10	.2	—	Form of Request for Approval of Extension of Maturity Date and Amendment, dated as of April 5, 2007, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300).
	10	.3	—	Form of Request Form of Request for Approval of Extension of Maturity Date and Amendment, dated as of February 18, 2008, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).
	10	.4	—	Form of Credit Agreement, dated as of May 12, 2005, among Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, J.P. Morgan Securities Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners, Bank of America, N.A. and Citibank, N.A., as U.S. Co-Syndication Agents, and Calyon New York Branch and Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
	10	.5	—	Form of Credit Agreement, dated as of May 12, 2005, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, RBC Capital Markets and BMO Nesbitt Burns, as Co-Lead Arrangers and Joint Bookrunners, Royal Bank of Canada, as Canadian Administrative Agent, Bank of Montreal and Union Bank of California, N.A., Canada Branch, as Canadian Co-Syndication Agents, and The Toronto-Dominion Bank and BNP Paribas (Canada), as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).

58

Exhibit
No.				Description
	10	.6	—	Form of Credit Agreement, dated as of May 12, 2005, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as Co-Lead Arrangers and Joint Bookrunners, Citisecurities Limited, as Australian Administrative Agent, Deutsche Bank AG, Sydney Branch, and JPMorgan Chase Bank, as Australian Co-Syndication Agents, and Bank of America, N.A., Sydney Branch, and UBS AG, Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
	10	.7	—	Form of Request for Approval of Extension of Maturity Date and Amendment, dated April 5, 2007, among Registrant, Apache Canada Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300).
	10	.8	—	Form of Request for Approval of Extension of Maturity Date and Amendment, dated February 18, 2008, among Registrant, Apache Canada Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).
	10	.9	—	Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt, dated April 6, 1981 (incorporated by reference to Exhibit 19(g) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1984, SEC File No. 1-547).
	10	.10	—	Amendment, dated July 10, 1989, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt (incorporated by reference to Exhibit 10(d)(4) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
	10	.11	—	Farmout Agreement, dated September 13, 1985 and relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10.1 to Phoenix’s Registration Statement on Form S-1, Registration No. 33-1069, filed October 23, 1985).
	10	.12	—	Amendment, dated March 30, 1989, to Farmout Agreement relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10(d)(5) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
	10	.13	—	Amendment, dated May 21, 1995, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Repsol Exploration Egypt S.A., Phoenix Resources Company of Egypt and Samsung Corporation (incorporated by reference to Exhibit 10.12 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1997, SEC File No. 001-4300).
	10	.14	—	Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area in Western Desert of Egypt, between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Phoenix Resources Company of Qarun and Apache Oil Egypt, Inc., dated May 17, 1993 (incorporated by reference to Exhibit 10(b) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1993, SEC File No. 1-547).

59

Exhibit
No.				Description
	10	.15	—	Agreement for Amending the Gas Pricing Provisions under the Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area, effective June 16, 1994 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300)
	†10	.16	—	Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
	*†10	.17	—	First Amendment to Apache Corporation Corporate Incentive Compensation Plan A, dated November 20, 2008, effective as of January 1, 2005.
	†10	.18	—	Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
	*†10	.19	—	First Amendment to Apache Corporation Corporate Incentive Compensation Plan B, dated November 20, 2008, effective as of January 1, 2005
	*†10	.20	—	Apache Corporation 401(k) Savings Plan, dated January 1, 2008
	*†10	.21	—	Amendment to Apache Corporation 401(k) Savings Plan, dated January 29, 2009, effective as of January 1, 2009, except as otherwise specified
	*†10	.22	—	Apache Corporation Money Purchase Retirement Plan, dated January 1, 2008
	*†10	.23	—	Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 29, 2009, effective as of January 1, 2009, except as otherwise specified
	*†10	.24	—	Non-Qualified Retirement/Savings Plan of Apache Corporation, amended and restated as of January 1, 2009
	*†10	.25	—	Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated November 19, 2008, effective as of May 2, 2007
	†10	.26	—	Apache Corporation 1995 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.27	—	Apache Corporation 2000 Share Appreciation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.28	—	Apache Corporation 1996 Performance Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.29	—	Apache Corporation 1998 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.30	—	Apache Corporation 2000 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.31	—	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.32	—	Apache Corporation 2005 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2008, Commission File No. 001-4300).
	†10	.33	—	Apache Corporation 2005 Share Appreciation Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, Commission File No. 001-4300).

60

Exhibit
No.				Description
	†10	.34	—	Apache Corporation 2008 Share Appreciation Program Specifications, pursuant to Apache Corporation 2007 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300)
	*†10	.35	—	Apache Corporation Income Continuance Plan, as amended and restated November 20, 2008, effective as of January 1, 2005
	*†10	.36	—	Apache Corporation Deferred Delivery Plan, as amended and restated November 19, 2008, effective as of January 1, 2009, except as otherwise specified
	*†10	.37	—	Apache Corporation Executive Restricted Stock Plan, as amended and restated November 19, 2008
	*†10	.38	—	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated November 20, 2008, effective as of January 1, 2009
	*†10	.39	—	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated November 20, 2008, effective as of January 1, 2009
	†10	.40	—	Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 8, 2007 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007, SEC File No. 001-4300).
	†10	.41	—	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, dated August 14, 2008, pursuant to Apache Corporation 2007 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.9 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.42	—	Restated Employment and Consulting Agreement, dated January 15, 2009, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated January 15, 2009, filed January 16, 2009, SEC File No. 001-4300).
	†10	.43	—	Amended and Restated Employment Agreement, dated December 20, 1990, between Registrant and John A. Kocur (incorporated by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1990, SEC File No. 001-4300)
	*†10	.44	—	Employment Agreement between Registrant and G. Steven Farris, dated June 6, 1988, and First Amendment, dated November 20, 2008, effective as of January 1, 2005
	†10	.45	—	Amended and Restated Conditional Stock Grant Agreement, dated September 15, 2005, effective January 1, 2005, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.06 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.46	—	Restricted Stock Unit Award Agreement, dated May 8, 2008, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008, SEC File No. 001-4300).
	†10	.47	—	Form of Restricted Stock Unit Award Agreement, dated February 12, 2009, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).
	10	.48	—	Amended and Restated Gas Purchase Agreement, effective July 1, 1998, by and among Registrant and MW Petroleum Corporation, as seller, and Producers Energy Marketing, LLC, as buyer (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated June 18, 1998, filed June 23, 1998, SEC File No. 001-4300).
	10	.49	—	Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
	*12	.1	—	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.

61

Exhibit
No.				Description
	14	.1	—	Code of Business Conduct (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	*21	.1	—	Subsidiaries of Registrant
	*23	.1	—	Consent of Ernst & Young LLP
	*23	.2	—	Consent of Ryder Scott Company L.P., Petroleum Consultants
	*24	.1	—	Power of Attorney (included as a part of the signature pages to this report)
	*31	.1	—	Certification of Principal Executive Officer
	*31	.2	—	Certification of Principal Financial Officer
	*32	.1	—	Certification of Principal Executive Officer and Principal Financial Officer

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

NOTE:  Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.

(b) See (a) 3. above.

(c) See (a) 2. above.

62

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

/s/  G. STEVEN FARRIS

G. Steven Farris

Chairman of the Board and Chief Executive Officer

Dated: February 27, 2009

POWER OF ATTORNEY

The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, P. Anthony Lannie and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/  G. STEVEN FARRIS G. Steven Farris	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 27, 2009
/s/  ROGER B. PLANK Roger B. Plank	President (principal financial officer)	February 27, 2009
/s/  REBECCA A. HOYT Rebecca A. Hoyt	Vice President and Controller (principal accounting officer)	February 27, 2009
/s/  FREDERICK M. BOHEN Frederick M. Bohen	Director	February 27, 2009
/s/  RANDOLPH M. FERLIC Randolph M. Ferlic	Director	February 27, 2009
/s/  EUGENE C. FIEDOREK Eugene C. Fiedorek	Director	February 27, 2009
/s/  A. D. FRAZIER, JR. A. D. Frazier, Jr.	Director	February 27, 2009
/s/  PATRICIA ALBJERG GRAHAM Patricia Albjerg Graham	Director	February 27, 2009

63

Name	Title	Date
/s/  JOHN A. KOCUR John A. Kocur	Director	February 27, 2009
/s/  GEORGE D. LAWRENCE George D. Lawrence	Director	February 27, 2009
/s/  F. H. MERELLI F. H. Merelli	Director	February 27, 2009
/s/  RODMAN D. PATTON Rodman D. Patton	Director	February 27, 2009
/s/  CHARLES J. PITMAN Charles J. Pitman	Director	February 27, 2009

64

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.

Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (Exchange Act). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program on internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2008.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Apache Corporation and subsidiaries, and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.

G. Steven Farris
Chairman of the Board and Chief Executive Officer
(principal executive officer)

Roger B. Plank
President
(principal financial officer)

Rebecca A. Hoyt
Vice President and Controller
(principal accounting officer)

Houston, Texas

February 27, 2009

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Corporation and subsidiaries at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As described in Note 1 to the consolidated financial statements, in 2007 the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apache Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009, expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Houston, Texas

February 27, 2009

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited Apache Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apache Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Apache Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008, and our report dated February 27, 2009, expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Houston, Texas

February 27, 2009

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

	For the Year Ended December 31,
	2008			2007		2006
	(In thousands, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	12,327,839		$	9,961,982	$	8,074,253
Gain on China divestiture		—			—		173,545
Other		61,911			37,770		61,333
		12,389,750			9,999,752		8,309,131
OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		2,516,437			2,347,791		1,816,359
Additional		5,333,821			—		—
Asset retirement obligation accretion		101,348			96,438		88,931
Lease operating expenses		1,909,625			1,652,855		1,322,562
Gathering and transportation		156,491			137,407		120,537
Taxes other than income		984,807			597,647		597,927
General and administrative		288,794			275,065		211,334
Financing costs, net		166,035			219,937		141,886
		11,457,358			5,327,140		4,299,536
INCOME BEFORE INCOME TAXES		932,392			4,672,612		4,009,595
Current income tax provision		1,456,382			970,728		705,687
Deferred income tax provision		(1,235,944	)		889,526		751,457
NET INCOME		711,954			2,812,358		2,552,451
Preferred stock dividends		5,680			5,680		5,680
INCOME ATTRIBUTABLE TO COMMON STOCK	$	706,274		$	2,806,678	$	2,546,771
NET INCOME PER COMMON SHARE:
Basic	$	2.11		$	8.45	$	7.72
Diluted	$	2.09		$	8.39	$	7.64

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

F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

	For the Year Ended December 31,
	2008			2007			2006
	(In thousands)
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	711,954		$	2,812,358		$	2,552,451
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		7,850,258			2,347,791			1,816,359
Provision (benefit) for deferred income taxes		(1,235,944	)		889,527			751,457
Asset retirement obligation accretion		101,348			96,438			88,931
Gain on sale of China operations		—			—			(173,545	)
Other		(50,596	)		48,966			32,380
Changes in operating assets and liabilities, net of effects of acquisitions:
(Increase) decrease in receivables		570,592			(261,962	)		(153,616	)
(Increase) decrease in inventories		(22,295	)		39,787			10,238
(Increase) decrease in drilling advances and other		28,846			(30,531	)		66,323
(Increase) decrease in deferred charges and other		(323,832	)		12,368			(126,869	)
(Increase) decrease in accounts payable		(70,979	)		(38,923	)		(136,663	)
(Increase) decrease in accrued expenses		(456,635	)		(169,087	)		(475,021	)
(Increase) decrease in deferred credits and noncurrent liabilities		(37,373	)		(69,299	)		60,481
NET CASH PROVIDED BY OPERATING ACTIVITIES		7,065,344			5,677,433			4,312,906
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(5,293,762	)		(4,322,469	)		(3,891,639	)
Acquisition of BP plc properties		—			—			(833,820	)
Acquisition of Pioneer’s Argentine operations		—			—			(704,809	)
Acquisition of Amerada Hess properties		—			—			(229,134	)
Acquisition of Pan American properties		—			—			(396,056	)
Acquisition of Anadarko properties		—			(1,004,593	)		—
Proceeds from China divestiture		—			—			264,081
Proceeds from sale of Egypt properties		—			—			409,203
Additions to gathering, transmission and processing facilities		(679,084	)		(479,874	)		(248,589	)
Restricted cash		(13,880	)		—			—
Proceeds from sales of oil and gas properties		307,974			67,483			4,740
Other, net		(64,226	)		(206,476	)		(149,559	)
NET CASH USED IN INVESTING ACTIVITIES		(5,742,978	)		(5,945,929	)		(5,775,582	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and bank loans, net		(99,803	)		(1,412,250	)		1,629,257
Fixed-rate debt borrowings		796,315			1,992,290			714
Payments on fixed-rate debt		(353	)		(173,000	)		(274	)
Dividends paid		(239,358	)		(204,753	)		(154,143	)
Common stock activity		31,513			29,682			31,963
Treasury stock activity, net		4,498			14,279			(166,907	)
Purchase of short-term investments		(791,999	)		—			—
Cost of debt and equity transactions		(7,050	)		(18,179	)		(2,061	)
Other		39,498			25,726			35,791
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(266,739	)		253,795			1,374,340
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,055,627			(14,701	)		(88,336	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		125,823			140,524			228,860
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	1,181,450		$	125,823		$	140,524
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	171,487		$	181,138		$	150,253
Income taxes paid, net of refunds		1,694,557			797,589			827,785

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

F-5

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31,
	2008			2007
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,181,450			125,823
Short-term investments		791,999			—
Receivables, net of allowance		1,356,979			1,936,977
Inventories		498,567			461,211
Drilling Advances		93,377			112,840
Derivative instruments		154,280			20,889
Prepaid taxes		303,203			21,077
Prepaid assets and other		71,119			73,434
		4,450,974			2,752,251
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full cost accounting:
Proved properties		40,639,281			34,645,710
Unproved properties and properties under development, not being amortized		1,300,347			1,439,726
Gathering, transmission and processing facilities		2,883,789			2,206,453
Other		452,989			416,149
		45,276,406			38,708,038
Less: Accumulated depreciation, depletion and amortization		(21,317,889	)		(13,476,445	)
		23,958,517			25,231,593
OTHER ASSETS:
Restricted cash		13,880			—
Goodwill, net		189,252			189,252
Deferred charges and other		573,862			461,555
	$	29,186,485		$	28,634,651
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	570,138		$	617,937
Accrued operating expense		168,531			112,453
Accrued exploration and development		964,859			600,165
Accrued compensation and benefits		111,907			172,542
Accrued interest		91,456			78,187
Accrued income taxes		48,028			73,184
Current debt		112,598			215,074
Asset retirement obligations		339,155			309,777
Derivative instruments		—			286,226
Other		208,556			199,471
		2,615,228			2,665,016
LONG-TERM DEBT		4,808,975			4,011,605
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		3,166,657			3,924,983
Asset retirement obligation		1,555,529			1,556,909
Derivative instruments		7,713			381,791
Other		523,662			716,368
		5,253,561			6,580,051
COMMITMENTS AND CONTINGENCIES (Note 9) 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, 342,754,114 and 341,322,088 shares issued, respectively		214,221			213,326
Paid-in capital		4,472,826			4,367,149
Retained earnings		11,929,827			11,457,592
Treasury stock, at cost, 8,044,050 and 8,394,945 shares, respectively		(228,304	)		(238,264	)
Accumulated other comprehensive loss		21,764			(520,211	)
		16,508,721			15,377,979
	$	29,186,485		$	28,634,651

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY

																	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, 2005				$	98,387	$	210,623	$	4,170,714		$	6,516,863		$	(89,764	)	$	(365,608	)	$	10,541,215
Comprehensive income (loss):
Net income	$	2,552,451			—		—		—			2,552,451			—			—			2,552,451
Post retirement, net of income tax benefit of $2,816		(6,116	)		—		—		—			—			—			(6,116	)		(6,116	)
Commodity hedges, net of income tax expense of $187,162		340,392			—		—		—			—			—			340,392			340,392
Comprehensive income	$	2,886,727
Cash dividends:
Preferred					—		—		—			(5,680	)		—			—			(5,680	)
Common ($.50 per share)					—		—		—			(165,059	)		—			—			(165,059	)
Common shares issued					—		1,742		54,917			—			—			—			56,659
Treasury shares purchased, net					—		—		1,968			—			(166,967	)		—			(164,999	)
Compensation expense					—		—		42,085			—			—						42,085
Other					—		—		111			2			(8	)		—			105
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	$	2,812,358			—		—		—			2,812,358			—			—			2,812,358
Post retirement, net of income tax expense of $4,896		6,333			—		—		—			—			—			6,333			6,333
Commodity hedges, net of income tax benefit of $272,865		(495,212	)		—		—		—			—			—			(495,212	)		(495,212	)
Comprehensive income	$	2,323,479
Cash dividends:
Preferred					—		—		—			(5,680	)		—			—			(5,680	)
Common ($.60 per share)					—		—		—			(199,401	)		—			—			(199,401	)
Common shares issued					—		961		48,144			—			—			—			49,105
Treasury shares purchased, net					—		—		1,834			—			18,475			—			20,309
Compensation expense					—		—		48,816			—			—			—			48,816
FIN 48 adoption					—		—		—			(48,502	)		—			—			(48,502	)
Other					—		—		(1,440	)		240			—			—			(1,200	)
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	$	711,954			—		—		—			711,954			—			—			711,954
Post retirement, net of income tax benefit of $7,495		(7,530	)		—		—		—			—			—			(7,530	)		(7,530	)
Commodity hedges, net of income tax expense of $301,157		549,505			—		—		—			—			—			549,505			549,505
Comprehensive income	$	1,253,929
Cash dividends:
Preferred					—		—		—			(5,680	)		—			—			(5,680	)
Common ($.70 per share)					—		—		—			(233,952	)		—			—			(233,952	)
Common shares issued					—		895		36,722			—			—			—			37,617
Treasury shares purchased, net					—		—		(442	)		—			9,960			—			9,518
Compensation expense					—		—		93,762			—			—			—			93,762
FIN 48					—		—		(23,663	)					—			—			(23,663	)
Other					—		—		(702	)		(87	)		—			—			(789	)
BALANCE AT DECEMBER 31, 2008				$	98,387	$	214,221	$	4,472,826		$	11,929,827		$	(228,304	)	$	21,764		$	16,508,721

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations  Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. The Company’s North American exploration and production activities are divided into two United States (U.S.) operating regions (Central and Gulf Coast) and a Canadian region. Approximately 61 percent of the Company’s proved reserves are located in North America. Outside of North America, Apache has exploration and production interests in Egypt, offshore Western Australia, offshore the United Kingdom in the North Sea (North Sea) and Argentina. In 2008, we finalized contracts for two exploration blocks in Chile.

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). Certain reclassifications have been made to prior periods to conform with the current presentations. Significant policies are discussed below.

Principles of Consolidation  The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company consolidates all investments in which the Company, either through direct or indirect ownership, has more than a 50 percent voting interest. In addition, Apache consolidates all variable interest entities where it is the primary beneficiary. The Company’s interest in oil and gas exploration and production ventures and partnerships are proportionately consolidated.

Use of Estimates  Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Apache evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and related present value estimates of future net cash flows there from (See Note 13 — Supplemental Oil and Gas Disclosure), asset retirement obligations, income taxes, valuation of derivative instruments and contingency obligations including legal and environmental risks and exposures.

Cash Equivalents  The Company considers all highly liquid short-term investments with a maturity of three months or less at time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. At December 31, 2008, we had $1.2 billion of cash and cash equivalents.

Marketable Securities  The Company accounts for investments in debt and equity securities in accordance with Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” Investments in debt securities classified as “held to maturity” are recorded at cost. At December 31, 2008, we had $792 million invested in obligations of the U.S. government with original maturities greater than three months but less than a year.

Allowance for Doubtful Accounts  The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. Many of Apache’s receivables are from joint interest owners on properties Apache operates. Thus, Apache may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s crude oil and natural gas receivables are collected within two months. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2008 and 2007, the Company had an allowance for doubtful accounts of $33 million and $23 million, respectively.

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache experienced a decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for oil and gas sales in the second half of 2008. Although the Company continues to collect on these receivables, albeit late, management does not believe there is an indication that the Company will not be able to collect the balance of our receivables from this customer.

Inventories  Inventories consist principally of tubular goods and equipment, stated at the lower of weighted-average cost or market, and oil produced but not sold, stated at the lower of cost or market.

Oil and Gas Property  The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, including salaries and benefits, but does not include any costs related to production, general corporate overhead or similar activities. Historically, total capitalized internal costs in any given year have not been material to total oil and gas costs capitalized in such year. Apache capitalized $236 million, $208 million and $146 million of these internal costs in 2008, 2007 and 2006, respectively. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized.

Costs Excluded  Oil and gas unevaluated properties and properties under development include costs that are excluded from costs being depreciated or amortized. These costs represent investments in unproved properties and major development projects in which the Company owns a direct interest. Apache excludes these costs on a country-by-country basis until proved reserves are found, until it is determined that the costs are impaired, or major development projects are placed in service. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. Also, geological and geophysical (G&G) costs not associated with specific properties are recorded to proved property. For international operations where a reserve base has not yet been established, impairments are charged to earnings and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan and political, economic and market conditions.

Ceiling Test  Under the full-cost method of accounting, a ceiling test is performed each quarter. The test establishes a limit (ceiling), on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet. The estimate of after-tax future net cash flows is calculated using a discount rate of 10 percent per annum and both costs and commodity prices in effect at the end of the period held flat for the life of production, except where future oil and gas sales are covered by physical contract terms or by derivative instruments that qualify, and are accounted for, as cash flow hedges. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional DD&A. See Note 13 — Supplemental Oil and Gas Disclosures (Unaudited) for a discussion on calculation of estimated future net cash flows.

The Company recorded a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of the ceiling test limitations, which is reflected as additional DD&A expense in the accompanying statement of consolidated operations. Approximately nine percent of our future oil and gas production is being hedged in 2009, three percent in 2010 and 2011, two percent in 2012 and less than one percent in 2013. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down would have been $5.9 billion ($4.0 billion net of tax). See Note 12 — Business Segment Information.

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

If oil and gas prices at the end of the first quarter are below year-end levels, additional write-downs of oil and gas properties are likely to occur.

Depreciation, Depletion and Amortization  DD&A of oil and gas properties is calculated quarterly, on a country-by-country basis, using the Units of Production Method (UOP). The UOP calculation, in simplest terms, multiplies the percentage of estimated proved reserves produced each quarter times the costs of those reserves. The result is to recognize expense at the same pace that the reservoirs are actually depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop reserves) and asset retirement costs which are not already included in oil and gas property, less related salvage value.

Gas gathering, transmission and processing facilities, buildings and equipment are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to 20 years. Accumulated depreciation for these assets totaled $870 million and $720 million at December 31, 2008 and 2007, respectively.

Asset Retirement Obligation  The initial estimated retirement obligation of properties is recognized as a liability, with an associated increase in properties and equipment for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

Capitalized Interest  Interest is capitalized on oil and gas investments in unproved properties and exploration and development activities that are in progress qualify for capitalized interest. Major construction projects also qualify for interest capitalization until the assets are ready for service. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of qualifying costs. For projects under construction that carry their own financing, interest is calculated using the interest rate related to the project financing. Interest and related costs are capitalized until each project is complete. Capitalized interest cannot exceed gross interest expense. As oil and gas costs excluded are transferred to unproved properties, any associated capitalized interest is also transferred. As major construction projects are completed, the associated capitalized interest is amortized over the useful life of the related asset. Capitalized interest totaled $94 million, $76 million and $61 million in 2008, 2007, and 2006 respectively.

Goodwill  Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to the implied fair value of the goodwill through a charge to expense. Goodwill totaled $189 million at December 31, 2008 and 2007, with approximately $103 million and $86 million recorded in Canada and Egypt, respectively. Each country was assessed as a reporting unit. No impairment of goodwill was recognized during 2008, 2007 or 2006.

Accounts Payable  Included in accounts payable at December 31, 2008 and 2007, are liabilities of approximately $164 million and $125 million, respectively, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts.

Commitments and Contingencies  Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revenue Recognition and Imbalances  Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to Apache will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Company’s recorded liability is generally reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures.

The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent, is available to the contractor partners to recover these operating and capital costs. The balance of the production is split among the contractor partners and Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis.

Apache markets its own U.S. natural gas production. As the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase gas (third-party gas) to fulfill its sales obligations and commitments. Both the costs and sales proceeds of this third-party gas are reported on a net basis in oil and gas production revenues. The costs of third-party gas netted against the related sales proceeds totaled $56 million, $123 million and $160 million, for 2008, 2007 and 2006, respectively.

Derivative Instruments and Hedging Activities  Apache periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

Apache accounts for its derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 establishes accounting and reporting standards requiring that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). SFAS No. 133 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from the Company’s oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period income as “Other” under Revenues and Other in the Statement of Consolidated Operations. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting under SFAS No. 133 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported as “Other” under Revenues and Other in the Statement of Consolidated Operations.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

General and Administrative Expense  General and administrative expenses are reported net of recoveries from owners in properties operated by Apache and net of amounts related to lease operating activities or capitalized pursuant to the full-cost method of accounting.

Income Taxes  We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

Earnings from Apache’s international operations are permanently reinvested; therefore, the Company does not recognize U.S. deferred taxes on the unremitted earnings of its international subsidiaries. If it becomes apparent that some or all of the unremitted earnings will be remitted, the Company will then recognize taxes on those earnings.

Foreign Currency Translation  The U.S. dollar has been determined to be the functional currency for each of Apache’s international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment and financing arrangements in each country. Foreign currency translation gains and losses arise when monetary assets and liabilities denominated in foreign currencies are remeasured to U.S. dollars at the exchange rate in effect at the end of each reporting period.

The Company accounts for foreign currency gains and losses in accordance with SFAS No. 52, “Foreign Currency Translation.” Foreign currency translation gains and losses related to deferred taxes are recorded as a component of provision for income taxes. The Company recorded a deferred tax benefit of $397 million in 2008, additional deferred tax expense of $228 million in 2007 and a deferred tax benefit of $5 million in 2006 (see Note 6 — Income Taxes). All other foreign currency translation gains and losses are reflected in “Other” under Revenues and Other in the Statement of Consolidated Operations. The Company’s other foreign currency gains and losses included in “Other” under Revenues and Other in the Statement of Consolidated Operations netted to a gain of $38 million in 2008, a $9 million gain in 2007 and a loss of $15 million in 2006.

Foreign currency gains and losses also arise when revenue and disbursement transactions denominated in a country’s local currency are converted to U.S. equivalent dollars based on the average exchange rates during the reporting period.

Insurance Coverage  The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

Earnings Per Share  The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury stock method, which could occur if options were exercised and restricted stock were fully vested.

Diluted EPS also includes the impact of unvested Share Appreciation Plans. For awards in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury stock method. For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in the diluted EPS is based on the number of shares, if any, using the treasury stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan.

Stock-Based Compensation  The Company accounts for stock-based compensation under the fair value recognition provisions of SFAS No. 123-R, “Accounting for Stock-Based Compensation,” as amended and revised.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company grants various types of stock-based awards including stock options, nonvested equity shares (restricted stock) and performance-based awards. In 2003 and 2004, the Company also granted cash-based stock appreciation rights. These plans and related accounting policies are defined and described more fully in Note 7 — Capital Stock. Stock compensation awards granted are valued on the date of grant and are expensed, net of estimated forfeitures, on a straight-line basis over the required service period.

Gathering, Transmission and Processing Facilities  The Company assesses the carrying amount of its gathering, transmission and processing facilities by testing the facilities annually and whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. If the carrying amount of these facilities is less than the sum of the undiscounted cash flows expected to result from their use and eventual disposition, an impairment loss is recorded through a charge to expense. Gathering, transmission and processing facilities totaled $2.9 billion and $2.2 billion at December 31, 2008 and 2007, respectively. No impairment of gathering, transmission and processing facilities was recognized during 2008, 2007 or 2006.

SFAS No. 123-R also requires that benefits of tax deductions in excess of recognized compensation cost be reported as financing cash flows rather than as operating cash flows. The Company classified $47 million, $30 million and $49 million as financing cash inflows in 2008, 2007 and 2006, respectively.

Treasury Stock  The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

Recently Issued Accounting Standards Not Yet Adopted  In December 2007, the Financial Accounting Standards Board (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. Apache has adopted SFAS No. 141 (R) as of January 1, 2009.

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. Apache adopted SFAS No. 160 as of January 1, 2009. Adoption of this standard did not have an effect on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” an amendment to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities to include 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. Apache adopted SFAS No. 161 as of January 1, 2009. Adoption of this standard did not have an effect on our financial position or results of operations.

In June 2008, the FASB issued FASB Staff Position (FSP) Emerging Issues Task Force (EITF) Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” FSP EITF No. 03-6-1 addresses whether instruments granted in share-based payment transactions should be considered participating securities for the purposes of applying the two-class method of calculating earnings per share (EPS) pursuant to FASB Statement No. 128, “Earnings Per Share.” This FSP concludes that unvested share-based payment awards that contain rights to receive nonforfeitable dividends or dividend equivalents are participating securities prior to vesting and, therefore, should be included in the earnings allocations in computing basic

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

EPS under the two-class method. This FSP is effective for financial statements issued beginning after December 15, 2008, with prior-period retrospective allocation. Apache has adopted FSP EITF Issue No. 03-6-1 as of January 1, 2009. Apache does not expect the effect of this FSP on its financial statements to be material.

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP provides additional guidance regarding the application of SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits — An Amendment of FASB Statements No. 87, 88, and 106,” which requires additional disclosures about plan assets of a defined benefit pension or other postretirement plan, including investment strategies, major categories of plan assets, concentrations of risk within plan assets, inputs and valuation techniques used to measure the fair value of plan assets and the effect of fair-value measurements using significant unobservable inputs on changes in plan assets for the period. FSP 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. We do not expect the adoption of this standard to have an effect on our financial position or results of operations.

In January 2009, the Securities and Exchange Commission (SEC) issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K and bringing full-cost accounting rules into alignment with the revised disclosure requirements. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The final rules are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009.

2.   SIGNIFICANT ACQUISITIONS AND DIVESTITURES

U.S. Permian Basin

On March 29, 2007, the Company closed its acquisition of controlling interest in 28 oil and gas fields in the Permian Basin of West Texas from Anadarko Petroleum Corporation (Anadarko) for $1 billion. Apache estimated that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of year-end 2006. The Company funded the acquisition with debt. Apache and Anadarko entered into a joint-venture arrangement to effect the transaction. The Company entered into cash flow hedges for a portion of the crude oil and the natural gas production.

U.S. Permian Basin

On January 5, 2006, the Company purchased Amerada Hess’s interest in eight fields located in the Permian basin of West Texas and New Mexico. The original purchase price was reduced from $404 million to $269 million because other interest owners exercised their preferential rights to purchase a number of the properties. The settlement price at closing of $239 million was adjusted for revenues and expenditures occurring between the effective date and the closing date of the acquisition. The acquired fields had estimated proved reserves of 27 MMbbls of liquid hydrocarbons and 27 Bcf of natural gas as of year-end 2005.

Argentina

On April 25, 2006, the Company acquired the operations of Pioneer Natural Resources (Pioneer) in Argentina for $675 million. The settlement price at closing, of $703 million, was adjusted for revenues and expenditures occurring between the effective date and closing date of the acquisition. The properties are located in the Neuquén, San Jorge and Austral basins of Argentina and had estimated net proved reserves of approximately 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas as of December 31, 2005. Eight gas processing plants (five operated and three non-operated), 112 miles of operated pipelines in the Neuquén basin and 2,200 square miles of three-dimensional (3-D) seismic data were also included in the transaction. Apache financed the purchase with cash on hand and commercial paper.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):

Proved property	$	501,938
Unproved property		189,500
Gas Plants		51,200
Working capital acquired, net		11,256
Asset retirement obligation		(13,635	)
Deferred income tax liability		(37,630	)
Cash consideration	$	702,629

On September 19, 2006, Apache acquired additional interests in (and now operates) seven concessions in the Tierra del Fuego Province from Pan American Fueguina S.R.L. (Pan American) for total consideration of $429 million. The settlement price at closing of $396 million was adjusted for normal closing items, including revenues and expenses between the effective date and the closing date of the acquisition. Apache financed the purchase with cash on hand and commercial paper.

The total cash consideration allocated below includes working capital balances purchased, asset retirement obligations assumed and an obligation to deliver specific gas volumes in the future. The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):

Proved property	$	289,916
Unproved property		132,000
Gas plants		12,722
Working capital acquired, net		8,929
Asset retirement obligation		(1,511	)
Assumed obligation		(46,000	)
Cash consideration	$	396,056

U.S. Gulf Coast

In June 2006, the Company acquired the remaining producing properties of BP plc (BP) on the Outer Continental Shelf of the Gulf of Mexico. The original purchase price was reduced from $1.3 billion for 18 producing fields to $845 million because other interest owners exercised their preferential rights to purchase five of the 18 fields. The purchase price consisted of $747 million of proved property, $42 million of unproved property and $56 million of facilities. The settlement price on the date of closing of $821 million was adjusted primarily for revenues and expenditures occurring between the April 1, 2006 effective date and the closing date of the acquisition. The acquired properties include 13 producing fields (nine of which are operated) with estimated proved reserves of 19.5 MMbbls of liquid hydrocarbons and 148 Bcf of natural gas. Apache financed the purchase with cash on hand and commercial paper.

Divestitures

On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. Apache did not have any proved reserves booked for these properties.

On August 8, 2006, the Company completed the sale of its 24.5 percent interest in the Zhao Dong block, offshore the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache’s exit from China. The effective date of the transaction was July 1, 2006. The Company recorded a gain of $174 million in the third quarter of 2006.

3.   HEDGING AND DERIVATIVE INSTRUMENTS

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

As of December 31, 2008, we had entered into the following crude oil derivative instruments:

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

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

As of December 31, 2008, we had entered into the following natural gas derivative instruments:

	Collars
					Weighted		Weighted
	MMBtu		GJ		Average		Average
Production Period	(in 000’s)		(in 000;s)		Floor Price(1)		Ceiling Price(1)
2009		18,250		—	$	7.35	$	10.19
2009		—		29,200		5.31		8.25
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 NYMEX Henry Hub. 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 December 31, 2008 exchange rate, and are settled against the AECO Index.

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

	December 31,		December 31,
	2008		2007
	(In millions)
Current asset	$	154	$	21
Long-term asset		65		7
Current liability		—		286
Long-term liability		7		382

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Commodity Derivative Activity in Accumulated Other Comprehensive Income (OCI)  Based on market prices as of December 31, 2008, the Company’s net unrealized gain in accumulated OCI for commodity derivatives designated as cash flow hedges totaled $212 million ($138 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. Of the $212 million estimated unrealized gain on derivatives at December 31, 2008, approximately $156 million ($102 million after tax) applies to the next 12 months; however, estimated and actual amounts are likely to vary materially as a result of changes in market conditions. 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		436			282
Net change in derivative fair value		415			268
Unrealized gain on derivatives at December 31, 2008	$	212		$	138

4.   ASSET RETIREMENT OBLIGATION

The following table is a reconciliation of the asset retirement obligation liability:

	2008			2007
	(In thousands)
Asset retirement obligation at beginning of year	$	1,866,686		$	1,747,566
Liabilities incurred		343,210			243,284
Liabilities settled		(587,246	)		(480,655	)
Accretion expense		101,348			96,438
Revisions in estimated liabilities		170,686			260,053
Asset retirement obligation at end of year		1,894,684			1,866,686
Less current portion		339,155			309,777
Asset retirement obligation, long-term	$	1,555,529		$	1,556,909

The majority of Apache’s asset retirement obligations (ARO) relate to plugging, abandonment and restoration of oil and gas properties. An abandonment liability is initially recorded in the period the related assets are placed in service, with an offsetting increase to properties and equipment. The liabilities incurred are recorded at fair value, and accretion expense is recognized over the life of the related assets, increasing the liability to its expected settlement value. Liabilities settled relate to individual properties plugged and abandoned or sold during the period and include the continued abandonment activity of platforms lost during Hurricanes Katrina, Rita and Ike. Revisions in estimated liabilities during the period primarily related to escalating retirement costs, changes in property lives and the expected timing of settling asset retirement obligations.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.   DEBT

	December 31,
	2008			2007
	(In millions)
Apache:
Money market lines of credit	$	—		$	4
Commercial paper		—			135
6.25% debentures due 2012		400			400
5.25% notes due 2013		500			500
6.0% notes due 2013		400			—
5.625% notes due 2017		500			500
6.9% notes due 2018		400			—
7.0% notes due 2018		150			150
7.625% notes due 2019		150			150
7.7% notes due 2026		100			100
7.95% notes due 2026		180			180
6.0% notes due 2037		1,000			1,000
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		4,080			3,419
Subsidiary and other obligations:
Argentina overdraft lines of credit		13			76
Apache PVG secured facility		100			—
Notes due in 2016 and 2017		1			1
Apache Finance Australia 7.0% notes due 2009		100			100
Apache Finance Canada 4.375% notes due 2015		350			350
Apache Finance Canada 7.75% notes due 2029		300			300
		864			827
Total debt		4,944			4,246
Less:
Unamortized discount		(22	)		(19	)
Current maturities		(113	)		(215	)
Total long-term debt	$	4,809		$	4,012

All of the Company’s debt, excluding the PVG secured facility, is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. The 6.25%, 5.25%, 5.625%, 6.9% and both 6.0% notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The remaining U.S. notes are not redeemable. Under certain conditions, the Company has the right to advance maturity on the 7.375% debentures and 7.625% debentures.

The Company has $22 million of debt discounts as of December 31, 2008, which will be charged to interest expense over the life of the related debt issuances; $1.1 million, $1.0 million and $714,000 was recognized in 2008, 2007 and 2006, respectively.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2008 and 2007, the Company had approximately $45 million and $33 million, respectively, of unamortized deferred loan costs associated with its various debt obligations. These costs are included in deferred charges and other in the accompanying consolidated balance sheet and are being charged to expense over the life of the related debt issuances.

The indentures for the notes described above place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens and its ability to enter into certain sale and leaseback transactions. Upon certain change in control, all of these debt instruments would be subject to mandatory repurchase, at the option of the holders. None of the indentures for the notes contain pre-payment obligations in the event of a decline in credit ratings.

Debt Issuances

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 Bills and will be used for general corporate purposes or, possible, future acquisitions when they mature.

Money Market and Overdraft Lines of Credit

The Company has certain uncommitted money market and overdraft lines of credit which are used from time to time for working capital purposes. As of December 31, 2008, $12.6 million was drawn on facilities in Argentina and nothing was drawn on U.S. facilities, compared with $76 million and $4 million in the prior year.

Commercial Paper Program

The Company has a $1.95 billion commercial paper program that enables Apache to borrow funds for up to 270 days at competitive interest rates. As of December 31, 2008, the Company had no outstanding commercial paper, compared to $135 million in the prior year. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2013.

Subsidiary Debt

The notes issued by Apache Finance Pty Limited (Apache Finance Australia) and Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache and, in the case of Apache Finance Pty Limited, by Apache North America, Inc., an indirect wholly-owned subsidiary of the Company. Under certain conditions related to changes in relevant tax laws, Apache Finance Pty Limited and Apache Finance Canada have the right to redeem the notes prior to maturity. The Apache Finance Canada 4.375% notes may be redeemed at the Company’s option subject to a make-whole premium (see Note 15 — Supplemental Guarantor Information).

Credit Facilities

The company has $2.3 billion of unsecured revolving syndicated bank credit facilities which mature in May 2013. Since there were no outstanding borrowings or commercial paper at year-end, the full $2.3 billion of unsecured credit facilities were available to the Company. These 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. The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end as any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics’ liens.

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company may incur liens on assets located in the U.S. and Canada of up to five percent of the Company’s consolidated assets, which approximated $1.5 billion as of December 31 , 2008. There are no restrictions on incurring liens in countries other than U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group. Furthermore, our non-cash write-down of oil and gas properties in 2008 does not impact the availability of credit lines or result in non-compliance with any covenants.

There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes (MAC clauses). The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2008. The Company’s debt-to-capitalization ratio as of December 31, 2008 was 23 percent.

At the Company’s option, the interest rate for the facilities is based on (i) the greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent or (ii) the London Inter-bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $1.5 billion and the $450 million credit facilities (U.S. credit facilities) also allow the company to borrow under competitive auctions.

At December 31, 2008, the margin over LIBOR for committed loans was .19 percent on the $1.5 billion facility and .23 percent on the other three facilities. If the total amount of the loans borrowed under the $1.5 billion facility equals or exceeds 50 percent of the total facility commitments, then an additional .05 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of .06 percent on the total amount of the $1.5 billion facility and .07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating. The U.S. credit facilities are used to support Apache’s commercial paper program.

On December 5, 2008, one of the Company’s Australian subsidiaries entered into a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The facility provides for total commitments of $350 million, with availability determined by a borrowing base formula. The borrowing base was set at $350 million and will be redetermined at project completion and semi-annually thereafter. The facility is secured by certain assets associated with the Van Gogh and Pyrenees oil developments, including the shares of stock of the Company’s subsidiary holding the assets. The Company has agreed to guarantee the credit facility until project completion occurs pursuant to terms of the facility, which is expected in 2010. The commitments under the facility will be reduced by scheduled increments every six months beginning June 30, 2010, with final maturity on March 31, 2014. Interest is based on LIBOR, which may be subject to change under certain market disruption conditions, plus a margin of 1.00 percent pre-completion and 1.75 percent post-completion. The pre-completion margin increases to 1.125 percent in the event the Company’s ratings are downgraded to BBB+ or below by at least two major rating agencies. As of December 31, 2008 there was $100 million outstanding under the facility.

Credit Ratings

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings, include debt levels, planned asset-purchases or sales and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels could also be considered by the rating agencies. Apache’s senior unsecured long-term debt is currently rated A3 by Moody’s, A- by Standard & Poor’s and A by Fitch. Apache’s short-term debt rating for its commercial paper program is currently

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

P-2 by Moody’s, A-2 by Standard & Poor’s and F1 by Fitch. The outlook is stable from Moody’s and Standard & Poor’s and negative from Fitch. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and potentially require the Company to post letters of credit in certain circumstances. We cannot predict, nor can we assure, that we will not receive a ratings downgrade in the future.

Aggregate Maturities of Debt

	(In millions)
2009	$	113
2010		—
2011		—
2012		439
2013		942
Thereafter	$	3,428

Financing Costs, Net

Financing costs are composed of the following:

	For the Year Ended December 31,
	2008			2007			2006
	(In thousands)
Interest expense	$	280,457		$	308,235		$	217,454
Amortization of deferred loan costs		3,689			3,310			2,048
Capitalized interest		(94,164	)		(75,748	)		(61,301	)
Interest Income		(23,947	)		(15,860	)		(16,315	)
Financing Costs	$	166,035		$	219,937		$	141,886

6.   INCOME TAXES

Income before income taxes is composed of the following:

	For the Year Ended December 31,
	2008			2007		2006
	(In thousands)
United States	$	(349,405	)	$	1,728,441	$	1,265,915
Foreign		1,281,797			2,944,171		2,743,680
Total	$	932,392		$	4,672,612	$	4,009,595

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2008			2007			2006
	(In thousands)
Current taxes:
Federal	$	127,801		$	133,140		$	65,068
State		1,613			5,162			4,069
Foreign		1,326,968			832,426			633,513
		1,456,382			970,728			702,650
Deferred taxes:
Federal		(413,731	)		435,276			369,301
State		3,014			(1,073	)		3,037
Foreign		(825,227	)		455,323			382,156
		(1,235,944	)		889,526			754,494
Total	$	220,438		$	1,860,254		$	1,457,144

A reconciliation of the tax on the Company’s income before income taxes and total tax expense is shown below:

	For the Year Ended December 31,
	2008			2007			2006
	(In thousands)
Income tax expense at U.S. statutory rate	$	326,337		$	1,635,414		$	1,403,358
State income tax, less federal benefit		3,008			2,658			24,191
Taxes related to foreign operations		437,396			127,614			131,370
Realized tax basis in investment		—			—			(4,387	)
Canadian tax rate reduction		—			(145,398	)		(161,073	)
United Kingdom tax rate increase		—			—			63,395
Current and deferred taxes related to currency fluctuations		(399,973	)		227,671			(4,891	)
Domestic manufacturing deduction		(7,312	)		(6,656	)		(2,644	)
Net change in tax contingencies		(139,590	)		—			—
Increase in valuation allowance		2,924			12,144			—
All other, net		2,352			6,807			7,825
	$	220,438		$	1,860,254		$	1,457,144

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The net deferred tax liability is comprised of the following:

	December 31,
	2008			2007
	(In thousands)
Deferred tax assets:
Deferred income	$	(18,327	)	$	(15,312	)
State net operating loss carryforwards		(14,420	)		(17,454	)
Foreign net operating loss carryforwards		(127,393	)		(27,275	)
Tax credits		(322,351	)		(285,493	)
Accrued expenses and liabilities		(80,684	)		(12,772	)
Other		(97,282	)		(94,673	)
Total deferred tax assets		(660,457	)		(452,979	)
Valuation allowance		15,068			12,144
Net deferred tax assets		(645,389	)		(440,835	)
Deferred tax liabilities:
Depreciation, depletion and amortization		3,577,990			4,152,354
Total deferred tax liabilities		3,577,990			4,152,354
Net deferred income tax liability	$	2,932,601		$	3,711,519

The Company has not recorded U.S. deferred income taxes on the undistributed earnings of its foreign subsidiaries as management intends to permanently reinvest such earnings. As of December 31, 2008, the undistributed earnings of the foreign subsidiaries amounted to approximately $14.3 billion. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits. Presently, limited foreign tax credits are available to reduce the U.S. taxes on such amounts if repatriated.

On December 31, 2008, the Company had state net operating loss carryforwards of $280 million and foreign net operating loss carryforwards of $4 million in Canada, $25 million in Argentina and $342 million in Australia. The Company also had $121 million of capital loss carryforwards in Canada. The state net operating losses will expire over the next 20 years if they are not otherwise utilized. The foreign net operating loss in Canada will begin to expire in 2014, the Argentina net operating loss will begin to expire in 2009, and the Australia net operating loss has an indefinite carryover period. The capital loss in Canada also has an indefinite carryover period.

The tax benefits of carryforwards are recorded as assets to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforwards is determined not to be “more likely than not,” a valuation allowance is provided to reduce the recorded tax benefits from such assets. The Company does not believe the utilization of the Canadian capital losses to be “more likely than not.” Accordingly, a valuation allowance was provided to reduce the tax benefit from this deferred tax asset.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache adopted the provisions of FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes” as of January 1, 2007. FIN 48 clarifies the accounting for income taxes by prescribing a minimum recognition threshold a tax position must meet before being recognized in the financial statements. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	Total
	(In thousands)
Balance at January 1, 2008	$	508,475
Additions based on tax positions related to the current year		—
Additions for tax positions of prior years		48,131
Reductions for tax positions of prior years		(335,334	)
Settlements		(6,037	)
Balance at December 31, 2008	$	213,235

Included in the balance at December 31, 2008, are $37 million of tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than penalties and interest, the disallowance of the shorter deductibility period would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The Company records interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2008, 2007 and 2006, the Company recorded approximately $42 million, $43 million and $26 million, respectively, in interest and penalties. The Company had approximately $42 million and $128 million for the payment of interest and penalties accrued as of December 31, 2008 and 2007, respectively.

During 2008, we settled tax audits in various jurisdictions. These settlements resulted in a $190 million reduction of previously recorded FIN 48 liabilities and associated interest.

The Company is in Administrative Appeals with the Internal Revenue Service (IRS) regarding the 2004 and 2005 tax years and under IRS Audit for the 2006 and 2007 tax years. Resolution of either of the above, which may occur in 2009, could result in a significant change to the balance of the FIN 48 reserve. However, the resolution of unagreed tax issues in the Company’s open tax years cannot be predicted with absolute certainty and differences between what has been recorded and the eventual outcomes may occur. Due to this uncertainty and the uncertain timing of the final resolution of the Appeals process and the 2006 and 2007 audits, an accurate estimate of the range of outcomes occurring during the next 12 months cannot be made at this time. Nevertheless, the Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. While during 2008, the Company settled tax audits in various jurisdictions, our uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. The Company’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction
United States	2004
Canada	2004
Egypt	1998
Australia	2001
United Kingdom	2003
Argentina	2002

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7.  CAPITAL STOCK

Common Stock Outstanding

	2008		2007		2006
Balance, beginning of year		332,927,143		330,737,425		330,121,230
Treasury shares issued (acquired), net		350,895		651,022		(2,170,144	)
Shares issued for:
Stock-based compensation plans		1,432,026		1,538,696		2,786,339
Balance, end of year		334,710,064		332,927,143		330,737,425

On April 19, 2006, the Company announced that its Board of Directors authorized the purchase of up to 15 million shares of the Company’s common stock, representing a market value of approximately $1 billion on the date of the announcement. The Company may buy shares from time to time on the open market, in privately negotiated transactions, or a combination of both. The timing and amounts of any purchases will be at the discretion of Apache’s management. The Company initiated the purchase program on May 1, 2006, after the Company’s first-quarter earnings information was disseminated in the market. During 2006, the Company purchased 2,500,000 shares at an average price of $69.74 per share. No stock purchases were made in 2007 or 2008. Currently, the Company has no plans to purchase additional shares.

Net Income Per Common Share

A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2008, 2007 and 2006 is presented in the table below. The income for 2008, reflects an after tax write-down for full-cost accounting of $3.6 billion.

	2008						2007						2006
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In thousands, except per share amounts)
Basic:
Income attributable to.. common stock	$	706,274		334,351	$	2.11	$	2,806,678		332,192	$	8.45	$	2,546,771		330,083	$	7.72
Effect of Dilutive Securities:
Stock options and others	$	—		2,840	$	—	$	—		2,404	$	—	$	—		3,128	$	—
Diluted:
Income attributable to common stock, including assumed conversions	$	706,274		337,191	$	2.09	$	2,806,678		334,596	$	8.39	$	2,546,771		333,211	$	7.64

The diluted earnings per share calculation excluded 673,801, 482,994 and 1.2 million average shares of common stock that were anti-dilutive for the years ended December 31, 2008, 2007 and 2006, respectively.

Common Stock Dividend

The Company paid common stock dividends of $.70, $.60 and $.45 per share in 2008, 2007 and 2006, respectively. The 2008 dividends include a special cash dividend of 10 cents per common share declared by the Company’s Board of Directors on February 15, 2008. The special dividend was paid on March 18, 2008, to stockholders of record on February 26, 2008.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, stock appreciation rights, restricted stock, and performance-based share appreciation plans. In May 2007, the Company’s shareholders

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approved the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), which is intended to provide eligible employees with equity-based incentives. The 2007 Plan provides for the granting of Incentive Stock Options, Non-Qualified Stock Options, Performance Awards, Restricted Stock, Restricted Stock Units, Stock Appreciation Rights, or any combination of the foregoing. All new grants will be issued from the 2007 Plan. The existing plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2007 Plan, including the 2005 Share Appreciation Plan, which remains in effect to issue shares for previously-attained stock appreciation goals.

For 2008, 2007 and 2006, stock-based compensation expensed was $52 million, $73 million and $35 million ($34 million, $47 million and $23 million after-tax), respectively. Costs related to the plans are capitalized or expensed based on the nature of the employee’s activities. A description of the Company’s stock-based compensation plans and related costs follows:

	2008		2007		2006
	(In millions)
Stock-based compensation expensed:
General and administrative	$	34	$	48	$	22
Lease operating expenses		18		25		13
Stock-based compensation capitalized		21		37		14
	$	73	$	110	$	49

Stock Options

As of December 31, 2008, officers and employees held options to purchase shares of the Company’s common stock under one or more of the employee stock option plans adopted in 1995, 1998, 2000, and 2005 (collectively, the Stock Option Plans), and under the 2007 Plan discussed above. New shares of Company stock will be issued for employee option exercises; however, under the 2000 Stock Option Plan, shares of treasury stock are used for employee option exercises to the extent treasury stock is held. Under the Stock Option Plans and the 2007 Plan, the exercise price of each option equals the closing price of Apache’s common stock on the date of grant. Options generally become exercisable ratably over a four-year period and expire 10 years after granted. All of these plans allow for accelerated vesting if there is a change in control (as defined in each plan). The 2007 Plan and all of the Stock Option Plans, except for the 2000 Stock Option Plan, were submitted to and approved by the Company’s stockholders.

On October 31, 1996, the Company also established the 1996 Performance Stock Option Plan (the Performance Plan) for substantially all full-time employees, excluding officers and certain other key employees. As of December 31, 2008, all options granted under the Performance Plan had been exercised or cancelled.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of stock options issued under the Stock Option Plans, the 2007 Plan and the Performance Plan is presented in the table and narrative below (shares in thousands):

	2008					2007					2006
				Weighted					Weighted					Weighted
				Average		Shares			Average		Shares			Average
	Shares			Exercise		Under			Exercise		Under			Exercise
	Under Option			Price		Option			Price		Option			Price
Outstanding, beginning of year		6,964		$	58.31		6,971		$	43.41	$	7,480		$	30.55
Granted		403			132.37		2,403			77.08		1,805			71.63
Exercised		(1,161	)		38.79		(1,976	)		27.54		(2,021	)		18.99
Forfeited or expired		(238	)		77.54		(434	)		63.04		(293	)		57.56
Outstanding, end of year(1)		5,968			66.34		6,964			58.31		6,971			43.41
Expected to vest(1)		2,716			80.82		3,773			71.38		3,024			59.50
Exercisable, end of year(1)		2,950			51.53		2,772			38.53		3,612			28.41
Available for grant, end of year		5,546					7,805					1,705
Weighted average fair value of options granted during the year	$	39.78				$	23.01				$	24.38

(1) As of December 31, 2008, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.8 years, 8.0 years and 5.5 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest and exercisable at year-end was $78 million, $8 million and $70 million, respectively.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on implied volatilities of traded options on the Company’s common stock, historical volatility of the Company’s common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

	2008			2007			2006
Expected volatility		27.93	%		24.60	%		27.79	%
Expected dividend yields		.53	%		.79	%		.57	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		3.04	%		4.51	%		4.98	%

The intrinsic value of options exercised during 2008 was approximately $100 million, and the Company realized an additional tax benefit of approximately $28 million for the amount of intrinsic value in excess of compensation cost recognized. As of December 31, 2008, the total compensation cost related to non-vested options not yet recognized was $56 million, which will be recognized over the remaining vesting period of the options.

Stock Appreciation Rights

In 2003 and 2004, the Company issued a total of 1,802,210 and 1,328,400, respectively, of stock appreciation rights (SARs) to non-executive employees in lieu of stock options. The SARs vest ratably over four years and will be settled in cash upon exercise throughout their 10-year life. The weighted-average exercise price was $42.68 and $28.78 for those issued in 2004 and 2003, respectively. The number of SARs outstanding and exercisable as of December 31, 2008 was 907,589. The Company records compensation expense on the vested SARs outstanding

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

based on the fair value of the SARs at the end of each period because SARs are cash-settled. As of year-end, the weighted-average fair value of SARs outstanding was $41.73 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2008, 404,685 SARs were exercised and approximately 1,325 were forfeited. The aggregate of cash payments made to settle SARs exercised in 2008 was $36 million.

Restricted Stock and Restricted Stock Units

The Company has restricted stock and restricted stock unit plans, including those awarded from the 2007 Plan, that are for all executive officers and certain other key employees. The plans have been approved by Apache’s Board of Directors. The Company awarded 806,396, 399,500 and 149,500 restricted stock units at a per share market price of $135.46, $77.31 and $71.52 in 2008, 2007 and 2006, respectively. The value of the stock issued was established by the market price on the date of grant and is being recorded as compensation expense ratably over the four-year vesting terms. During 2008, 2007 and 2006, $21.3 million ($13.7 million after tax), $8.2 million ($5.3 million after tax) and $6.1 million ($3.9 million after tax), respectively, was charged to expense as shares vested. In 2008 and 2007, $5.9 million and $1.0 million was capitalized, respectively. There were no amounts capitalized in 2006. As of December 31, 2008, there was $103 million of total unrecognized compensation cost related to approximately 1,163,372 unvested shares. The weighted-average remaining life of unvested shares is approximately 3.1 years.

				Weighted-Average
				Grant-Date
Restricted Stock	Shares			Fair Value
Non-vested at January 1, 2008		584,850		$	72.66
Granted		806,396			135.46
Vested		(189,250	)		70.45
Forfeited		(38,624	)		99.25
Non-vested at December 31, 2008		1,163,372		$	115.67

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.

Subsequent Event

The Company appointed Roger B. Plank to President, John A. Crum to Co-chief Operating Officer and President — North America, and Rodney J. Eichler to Co-chief Operating Officer and President — International effective February 12, 2009. On the same date, the Company awarded each of them 62,500 restricted stock units pursuant to Apache’s 2007 Omnibus Equity Compensation Plan. 12,500 of such restricted stock units will vest on each of April 1, 2010, February 12, 2011, February 12, 2012, February 11, 2013 and February 11, 2014. Upon

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

vesting, Apache will issue one share of Apache’s common stock as settlement for each restricted stock unit. 7,500 of the shares vesting each year for each recipient will be subject to the restriction that none of such 7,500 shares will be eligible for sale by the recipient until such time as he retires or otherwise terminates employment with Apache.

Share Appreciation Plans

The Company utilizes share appreciation plans from time to time to provide incentives for substantially all full-time employees and officers to increase Apache’s share price within a stated measurement period. To achieve the payout, the Company’s stock price must close at or above a stated threshold for 10 out of any 30 consecutive trading days before the end of the stated period. Awards under the plans are payable in equal annual installments as specified by each plan, beginning on a date not more than 30 days after a threshold is attained for the required measurement period and on succeeding anniversaries of the attainment date. Shares issued to employees would be reduced by the required minimum tax withholding. Shares of Apache common stock contingently issuable under the plans are excluded from the computation of income per common share until the stated goals are met as described below.

Since 2000, three share appreciation plans have been approved. A summary of these plans is as follows:

•  On May 7, 2008, the Stock Option Plan Committee of the Company’s Board of Directors, pursuant to the Company’s 2007 Omnibus Equity Compensation Plan, approved the 2008 Share Appreciation Program with a target to increase Apache’s share price to $216 by the end of 2012, with an interim goal of $162 to be achieved by the end of 2010. Any awards under the plan would be payable in five equal annual installments. As of December 31, 2008, neither share price threshold had been met.

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

•  In October 2000, the Company adopted the 2000 Share Appreciation Plan with goals to reach share price targets of $43.29, $51.95 and $77.92 prior to January 1, 2005. Any awards under the plan would be payable in three equal annual installments. The share price targets of $43.29 and $51.95 were met in 2004, and 3.2 million shares of common stock were issued to employees in equal installments in 2004, 2005 and 2006. The third share price target of $77.92 was not met and the related grants were cancelled as of December 31, 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of the number of shares contingently issuable as of December 31, 2008, 2007 and 2006 for each plan is presented in the table below:

	Shares Subject to
	Conditional Grants
	2008			2007			2006
	(In thousands)
2008 Share Appreciation Program
Outstanding, beginning of year	$	—		$	—		$	—
Granted		2,929			—			—
Issued		—			—			—
Forfeited or cancelled		(115	)		—			—
Outstanding, end of year(1)		2,814			—			—
Weighted-average fair value of conditional grants(2)	$	81.78		$	—		$	—
2005 Share Appreciation Plan
Outstanding, beginning of year	$	2,965		$	3,529		$	3,438
Granted		—			171			447
Issued		(805	)		(331	)		—
Forfeited or cancelled		(159	)		(404	)		(356	)
Outstanding, end of year(3)		2,001			2,965			3,529
Weighted-average fair value of conditional grants(4)	$	26.07		$	26.07		$	26.20
2000 Share Appreciation Plan
Outstanding, beginning of year	$	—		$	—		$	1,442
Granted		—			—			—
Issued		—			—			(1,398	)
Forfeited or cancelled		—			—			(44	)
Outstanding, end of year	$	—		$	—		$	—

(1)	Represents shares issuable upon vesting of $216 and $162 per share price goals of 1,685,430 shares and 1,128,320 shares in 2008.
(2)	The fair value of each Share Price Goal conditional grant is estimated as of the date of grant using a Monte Carlo simulation with the following weighted-average assumptions used for grants in 2008 (i) risk-free interest rate of 3.01 percent; (ii) expected volatility of 27.89 percent; and (iii) expected dividend yield of .53 percent.
(3)	Represents shares issuable upon vesting of $81 and $108 per share price goals of 581,045 shares and 1,420,177 shares, respectively, in 2008, 933,780 shares and 2,031,522 shares, respectively, in 2007 and 1,395,030 shares and 2,134,100 shares, respectively, in 2006.
(4)	The fair value of each Share Price Goal conditional grant is estimated as of the date of grant using a Monte Carlo simulation with the following weighted-average assumptions used for grants in 2007 and 2006, respectively: (i) risk-free interest rate of 3.95 and 3.93 percent; (ii) expected volatility of 28.02 and 28.17 percent; and (iii) expected dividend yield of .57 and .56 percent. No grants were made in 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Over the expected service life of each program, the Company will recognize total expense and capitalized costs of approximately $197 million through 2014 and $82 million through 2011 for the 2008 Share Appreciation Program and the 2005 Share Appreciation Plan, respectively. A summary of the amounts recognized as expense and capitalized costs for each plan are detailed in the table below:

	For the Year Ended December 31,
	2008		2007		2006
	(In millions)
2008 Share Appreciation Program
Compensation expense	$	15.2	$	—	$	—
Compensation expense, net of tax		9.8		—		—
Capitalized costs		8.3		—		—
2005 Share Appreciation Plan
Compensation expense	$	9.4	$	10.6	$	12.1
Compensation expense, net of tax		6.0		6.8		7.8
Capitalized costs		4.8		5.4		6.2
2000 Share Appreciation Plan
Compensation expense	$	—	$	—	$	1.1
Compensation expense, net of tax		—		—		0.7
Capitalized costs		—		—		0.6

Preferred Stock

The Company has five million shares of no par preferred stock authorized, of which 25,000 shares have been designated as Series A Junior Participating Preferred Stock (the Series A Preferred Stock) and 100,000 shares have been designated as the 5.68 percent Series B Cumulative Preferred Stock (the Series B Preferred Stock).

Series A Preferred Stock

In December 1995, the Company declared a dividend of one right (a Right) for each 2.31 shares (adjusted for subsequent stock dividends and a two-for-one stock split) of Apache common stock outstanding on January 31, 1996. Each full Right entitles the registered holder to purchase from the Company one ten-thousandth (1/10,000) of a share of Series A Preferred Stock at a price of $100 per one ten-thousandth of a share, subject to adjustment. The Rights are exercisable 10 calendar days following a public announcement that certain persons or groups have acquired 20 percent or more of the outstanding shares of Apache common stock or 10 business days following commencement of an offer for 30 percent or more of the outstanding shares of Apache’s outstanding common stock (flip in event); each Right will become exercisable for shares of Apache’s common stock at 50 percent of the then-market price of the common stock. If a 20 percent shareholder of Apache acquires Apache, by merger or otherwise, in a transaction where Apache does not survive or in which Apache’s common stock is changed or exchanged (flip over event), the Rights become exercisable for shares of the common stock of the Company acquiring Apache at 50 percent of the then-market price for Apache common stock. Any Rights that are or were beneficially owned by a person who has acquired 20 percent or more of the outstanding shares of Apache common stock and who engages in certain transactions or realizes the benefits of certain transactions with the Company will become void. If an offer to acquire all of the Company’s outstanding shares of common stock is determined to be fair by Apache’s board of directors, the transaction will not trigger a flip in event or a flip-over event. The Company may also redeem the Rights at $.01 per Right at any time until 10 business days after public announcement of a flip in event. These rights

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

were originally scheduled to expire on January 31, 2006. Effective as of that date, the Rights were reset to one right per share of common stock and the expiration was extended to January 31, 2016. Unless the Rights have been previously redeemed, all shares of Apache common stock issued by the Company after January 31, 1996 will include Rights. Unless and until the Rights become exercisable, they will be transferred with and only with the shares of Apache common stock.

Series B Preferred Stock

In August 1998, Apache issued 100,000 shares ($100 million) of Series B Preferred Stock in the form of one million depositary shares, each representing one-tenth (1/10) of a share of Series B Preferred Stock, for net proceeds of $98 million. The Series B Preferred Stock has no stated maturity, is not subject to a sinking fund and is not convertible into Apache common stock or any other securities of the Company. Apache has the option to redeem the Series B Preferred Stock at $1,000 per preferred share on or after August 25, 2008. Holders of the shares are entitled to receive cumulative cash dividends at an annual rate of $5.68 per depositary share when, and if, declared by Apache’s Board of Directors. During 2008, 2007 and 2006, the Company paid $5.7 million of dividends in its Series B Preferred Stock. In the event of a liquidation of the Company, the holders of the shares will be entitled to receive liquidating distributions in the amount of $1,000 per preferred share plus any accrued or unpaid dividends before any distributions are made on the Company’s common stock.

Comprehensive Income

Components of accumulated other comprehensive income (loss) consists of the following:

	For the Year Ended December 31,
	2008			2007			2006
				(In thousands)
Currency translation adjustment(1)	$	(108,750	)	$	(108,750	)	$	(108,750	)
Unrealized gain (loss) on derivatives (Note 3)		137,827			(411,678	)		83,534
Unfunded pension and post retirement benefit plan		(7,313	)		217			(6,116	)
Accumulated other comprehensive loss	$	21,764		$	(520,211	)	$	(31,332	)

(1) Prior to October 1, 2002, the Company’s Canadian subsidiaries’ functional currency was the Canadian dollar. Translation adjustments resulting from translating the Canadian subsidiaries’ financial statements into U.S. dollar equivalents were reported separately and accumulated in other comprehensive income (loss). Currency translation adjustments held in other comprehensive income on the balance sheet will remain there indefinitely unless there is a substantially complete liquidation of the Company’s Canadian operations.

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8.   FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2008 and 2007. See Note 3 — Hedging and Derivative Instruments for a discussion of the Company’s derivative instruments.

	2008				2007
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
	(In millions)
Long-term debt:
Apache
Money market lines of credit	$	—	$	—	$	4	$	4
Commercial paper		—		—		135		135
6.25% debentures due 2012		399		417		398		424
5.25% notes due 2013		499		502		499		512
6.0% notes due 2013		398		413		—		—
5.625% notes due 2017		500		496		500		508
6.9% notes due 2018		398		433		—		—
7.0% notes due 2018		149		162		149		167
7.625% notes due 2019		149		170		149		175
7.7% notes due 2026		100		114		100		115
7.95% notes due 2026		179		209		179		212
6.0% notes due 2037		993		963		993		993
7.375% debentures due 2047		148		167		148		171
7.625% debentures due 2096		149		167		149		174
Subsidiary and other obligations
Argentina overdraft lines of credit		13		13		76		76
Apache PVG secured facility		100		100		—		—
Notes due in 2016 and 2017		1		1		1		1
Apache Finance Australia 7.0% notes due 2009		100		100		100		103
Apache Finance Canada 4.375% notes due 2015		350		325		350		329
Apache Finance Canada 7.75% notes due 2029		297		340		297		353

The fair value of the notes and debentures is based upon an estimate provided to the Company by an independent investment banking firm. The carrying amount of the commercial paper and money market lines of credit approximated fair value because the interest rates are variable and reflective of market rates. The Company’s trade receivables, trade payables and short-term investments are by their very nature short-term. The carrying values included in the accompanying consolidated balance sheet approximate fair value at December 31, 2008 and 2007.

9.   COMMITMENTS AND CONTINGENCIES

Apache is party to various legal actions arising in the ordinary course of business including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $25 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position or results of operations after consideration of recorded accruals. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse affect on the Company’s financial position or results of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Legal Matters

Grynberg

In 1997, Jack J. Grynberg began filing lawsuits against other natural gas producers, gatherers, and pipelines claiming that the defendants have under paid royalty to the federal government and Indian tribes by mis-measurement of the volume and heating content of natural gas and are responsible for acts of others who mis-measured natural gas. In 2005, Grynberg filed suit against Apache making the same claims he had made previously against others in the industry. With the addition of Apache, there are more than 300 defendants to these actions. The Grynberg lawsuits were consolidated through a federal Multi-District Litigation (MDL) action located in Wyoming federal court for discovery and pre-trial purposes. Although Grynberg purports to be acting on behalf of the government, the federal government has declined to join in the cases. While an adverse judgment against Apache is possible, Apache does not believe the plaintiff’s claims have merit and plans to vigorously pursue its defenses against these claims. Exposure related to this lawsuit is not currently determinable. Apache and other defendants in the MDL filed motions to dismiss based upon Grynberg’s failure to prove statutory requirements for maintaining qui tam lawsuits. On October 20, 2006, the multi-district Judge ruled in favor of Apache and other defendants on these motions to dismiss, dismissing Grynberg’s lawsuits against Apache and others. Grynberg has appealed the ruling.

Argentine Environmental Claims

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

Louisiana Restoration

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

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Australia Gas Pipeline Force Majeure

The Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas to customers under various long-term contracts. Company subsidiaries believe that the event was a force majeure and as a result, the subsidiaries and their joint venture participants have declared force majeure under those contracts. 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. In the event it is determined that the pipeline explosion was not a force majeure, Company subsidiaries believe that liquidated damages should be the extent of the damages under those long-term contracts with such provisions. Approximately 90 percent of the natural gas volumes 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 and exposure related to such claims is not currently determinable. 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.

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

On October 10, 2008, the Australia National Offshore Petroleum Safety Authority (NOPSA) released a self-titled “Final Report” of the findings of its investigation into the pipeline explosion, prepared at the request of the Western Australian Department of Industry and Resources (DoIR). NOPSA concluded in its report that the evidence gathered to date indicates that the main causal factors in the incident were: (1) ineffective anti-corrosion coating at the beach crossing section of the 12” 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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

21 years validity, and an application for renewal of the license was submitted to DoIR by Company subsidiaries in December 2005 and remains pending.

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

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

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.

Apache manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to Apache’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In our estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on our financial condition. As of December 31, 2008, the Company had an undiscounted reserve for environmental remediation of approximately $27 million. Apache is not aware of any environmental claims existing as of December 31, 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 past non-compliance with environmental laws will not be discovered on the Company’s properties.

Retirement and Deferred Compensation Plans

Apache Corporation provides retirement benefits to its U.S. employees through the use of three types of plans: an IRC 401(k); a money purchase pension plan and a restorative non-qualified retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

compensation to the plan with the Company making matching contributions up to a maximum of six percent of each employee’s annual covered compensation. In addition, the Company annually contributes six percent of each participating employee’s compensation, as defined, to a money purchase retirement plan. The 401(k) plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement/savings plan that allows the deferral of up to 50 percent of each employee’s salary and that accepts employee contributions and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan and the non-qualified retirement/savings plan occurs at the rate of 20 percent for every full-year of employment. Upon a change in control of ownership, immediate and full vesting occurs.

Additionally, Apache Energy Limited, Apache Canada Ltd. and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Australia, Canada and the United Kingdom, respectively. Total annual cost under the retirement plans were $52 million, $59 million and $41 million for 2008, 2007 and 2006, respectively.

Apache also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations. The plan provides defined pension benefits based on years of service and final average salary. The plan is closed to newly hired employees.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Covered participants receive medical benefits up until the age of 65 provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2008 and 2007 and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans.

	2008						2007
	Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits
	(In thousands)
Change in Projected Benefit Obligation
Projected benefit obligation beginning of period	$	129,883		$	14,918		$	125,627		$	17,226
Service cost		5,554			1,484			7,255			1,552
Interest cost		6,705			977			6,508			978
Foreign currency exchange rate changes		(37,602	)		—			2,131			—
Amendments		—			—			—			—
Actuarial losses/(gains)		(1,619	)		166			(9,241	)		(4,770	)
Effect of curtailment and settlements		—			—			—			—
Benefits paid		(3,789	)		(284	)		(2,397	)		(180	)
Retiree contributions		—			138			—			112
Projected benefit obligation at end of year		99,132			17,399			129,883			14,918
Change in Plan Assets
Fair value of plan assets at beginning of period		122,233			—			112,821			—
Actual return on plan assets		(13,337	)		—			4,704			—
Foreign currency exchange rates		(32,309	)		—			1,881			—
Employer contributions		9,811			146			5,224			68
Benefits paid		(3,789	)		(284	)		(2,397	)		(180	)
Retiree contributions		—			138			—			112
Fair value of plan assets at end of year		82,609			—			122,233			—
Funded status at end of year		(16,523	)		(17,399	)		(7,650	)		(14,918	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(565	)		—			(363	)
Non current liability		(16,523	)		(16,834	)		(7,650	)		(14,555	)
		(16,523	)		(17,399	)		(7,650	)		(14,918	)
Pretax Amounts Recognized in Accumulated Other Comprehensive Income
Accumulated gain (loss)		(13,854	)		(246	)		1,049			(80	)
Prior service cost		—			—			—			—
Transition asset (obligation)		—			(353	)		—			(397	)
		(13,854	)		(599	)		1,049			(477	)
Weighted Average Assumptions used as of December 31
Discount rate		5.50	%		6.03	%		5.60	%		6.01	%
Salary increases		4.50	%		N/A			4.40	%		N/A
Expected return on assets		6.05	%		N/A			6.50	%		N/A
Healthcare cost trend
Initial		N/A			8.00	%		N/A			8.00	%
Ultimate in 2015		N/A			5.00	%		N/A			5.00	%

F-38

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2008 and 2007, the accumulated benefit obligation for the pension plan was $69 million and $91 million, respectively.

Apache’s defined benefit pension plan assets are held by a non-related Trustee who has been instructed to invest the assets in an equal blend of equity securities and low-risk debt securities. The Company believes this blend of investments will provide a reasonable rate of return and ensure that the benefits promised to members are provided.

The plan’s assets do not include any equity or debt securities of Apache. A breakout of previous allocations for plan asset holding and the target allocation for the Company’s plan assets are summarized below:

				Percentage of
				Plan Assets at
	Target Allocation			Year-End
	2008			2008			2007
Asset Category
Equity securities		50	%		45	%		50	%
Debt securities		50			51			50
Cash		—			4			—
Total		100	%		100	%		100	%

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2008, 2007 and 2006:

	2008						2007						2006
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
							(In thousands)
Components of Net Periodic Benefit Costs
Service cost	$	5,554		$	1,484		$	7,255		$	1,552		$	7,189		$	1,517
Interest cost		6,705			977			6,508			978			5,218			899
Expected return on assets		(7,479	)		—			(7,632	)		—			(5,750	)		—
Amortization of:
Transition obligation		—			44			—			44			—			44
Actuarial (gain)/loss		—			—			—			139			—			290
Net periodic benefit cost	$	4,780		$	2,505		$	6,131		$	2,713		$	6,657		$	2,750
Weighted Average Assumptions used to determine Net Periodic Benefit Costs for the Years ended December 31
Discount rate		5.60	%		6.01	%		5.10	%		5.77	%		4.70	%		5.50	%
Salary increases		4.40	%		N/A			4.10	%		N/A			3.80	%		N/A
Expected return on assets		6.50	%		N/A			6.50	%		N/A			5.75	%		N/A
Healthcare cost trend
— Initial		N/A			8.00	%		N/A			9.00	%		N/A			9.00	%
— Ultimate in 2014		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

F-39

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assumed health care cost trend rates effect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	Postretirement Benefits
	1% Increase		1% Decrease
	(In thousands)
Effect on service and interest cost components	$	316	$	(272	)
Effect on postretirement benefit obligation		1,873		(1,647	)

Apache expects to contribute approximately $12 million to its pension plan and $565,000 to its postretirement benefit plan in 2009. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension		Postretirement
	Benefits		Benefits
	(In thousands)
2009	$	1,454	$	565
2010		2,155		750
2011		3,761		936
2012		4,566		1,180
2013		3,190		1,447
Years 2014 — 2018		23,137		10,925

Contractual Obligations

At December 31, 2008, contractual obligations for drilling rigs, purchase obligations, E&D commitments, firm transportation agreements, and long-term operating leases ranging from one to 28 years, are as follows:

Net Minimum Commitments	Total		2009		2010-2012		2013-2014		2015 & Beyond
					(In thousands)
Drilling rig commitments	$	889,874	$	516,180	$	372,594	$	1,100	$	—
Purchase obligations		371,279		370,720		559		—		—
E&D commitments		197,512		92,459		99,670		5,383		—
Firm transportation agreements		223,153		26,541		81,234		55,496		59,882
Office and related equipment		122,599		21,354		60,758		18,962		21,525
Oil and gas operations equipment		472,980		77,122		125,676		59,304		210,878
Other		3,840		3,840		—		—		—
Total Minimum Commitments	$	2,281,237	$	1,108,216	$	740,491	$	140,245	$	292,285

•  Drilling rig commitments include dayrate and other contracts for use of drilling, completion and workover rigs.

•  Purchase obligations include contractual obligations to buy or build oil and gas plants and facilities.

•  E&D commitments generally consist of seismic and drilling work programs required to retain acreage, meet contractual obligations of international concessions, or to satisfy minimums associated with farm-in properties.

•  Firm transportation agreements relate to contractual obligations for capacity rights on third-party pipelines.

•  Office and related equipment leases include office and other buildings rentals and related equipment leases.

•  Oil and gas operations equipment includes floating production storage and offloading (FPSO’s), compressors, helicopters and boats.

F-40

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Included in the table above are leases for buildings, facilities and related equipment with varying expiration dates through 2035. Net rental expense was $38 million, $31 million and $23 million for 2008, 2007 and 2006, respectively.

Subsequent Event

On February 10, 2009, Apache’s wholly-owned subsidiary, Apache Canada Ltd. entered into an agreement with TransCanada Pipelines Limited (TCPL) pursuant to which TCPL will construct and install a gas pipeline from north eastern British Columbia to the existing NOVA pipeline system located in the Ekwan area of Alberta. Apache Canada intends to ship gas produced from the Ootla basin on the new pipeline.

The construction, operation and transportation rates of the new pipeline are subject to regulatory approval. Authority to construct the pipeline is expected, and construction is anticipated to be complete on or before April 1, 2011. Upon completion of the pipeline, Apache Canada will have a ship-or-pay commitment of 100 MMBtu of gas for either a four-year period or a ten-year period depending on the rate structure determined and approved by the regulatory agency. Apache Canada has the right to terminate the agreement before October 1, 2009. If Apache Canada elects to terminate the agreement or TCPL terminates for reasons set forth in the agreement, Apache Canada must reimburse TCPL for certain costs and expenses up to CDN $90 million plus certain taxes.

10.   FAIR VALUE

Fair Value Measurement

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.

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 December 31, 2008:

	As of December 31, 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	$	203	$	—	$	203	$	—
Fixed-Price Oil Swaps		16		—		16		—
Liabilities:
Crude Oil Swaps	$	7	$	—	$	7	$	—

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 markets and are valued using Level 2 inputs.

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11.   MAJOR CUSTOMERS

In 2008, purchases by Shell accounted for 17 percent of the Company’s oil and gas production revenues.

In 2007, purchases by Shell accounted for 12 percent of the Company’s oil and gas production revenues.

In 2006, purchases by BP accounted for 20 percent of the Company’s oil and gas production revenues.

Concentration of Credit Risk

We have experienced a decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC) for our Egyptian oil and gas sales in the second half of 2008. We continue to collect on these receivables, albeit late, and there is no indication that we will not be able to collect the balance of our receivables from this customer.

12.   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”).

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company divested its interest in China effective July 1, 2006. Apache is primarily in the business of crude oil and natural gas exploration and production. Financial information by country is presented below:

															Other
	United States		Canada			Egypt		Australia		North Sea		Argentina			International		Total
	(In thousands)
2008
Oil and gas production revenues	$	5,083,397	$	1,650,402		$	2,739,246	$	371,669	$	2,103,283	$	379,842		$	—	$	12,327,839
Operating Expenses:
Depreciation, depletion and amortization
Recurring		1,112,989		416,880			397,573		134,926		262,787		191,282			—		2,516,437
Additional		2,667,440		1,689,392			—		—		568,450		408,539			—		5,333,821
Asset retirement obligation accretion		66,189		14,173			—		5,921		13,215		1,850			—		101,348
Lease operating expenses		925,977		336,871			241,455		103,627		190,966		110,729			—		1,909,625
Gathering and transportation		39,739		62,848			20,896		—		28,382		4,626			—		156,491
Taxes other than income		211,251		42,662			8,306		10,719		695,443		16,426			—		984,807
Operating Income (Loss)(1)	$	59,812	$	(912,424	)	$	2,071,016	$	116,476	$	344,040	$	(353,610	)	$	—		1,325,310
Other Income (Expense):
Other																		61,911
General and administrative																		(288,794	)
Financing costs, net																		(166,035	)
Income Before Income Taxes																	$	932,392
Net Property and Equipment	$	10,685,505	$	4,500,040		$	3,615,126	$	2,393,894	$	1,536,202	$	1,200,294		$	27,456	$	23,958,517
Total Assets	$	11,975,654	$	5,846,269		$	4,967,603	$	2,626,588	$	2,287,225	$	1,445,864		$	37,282	$	29,186,485
Additions to Net Property and Equipment	$	2,748,241	$	871,521		$	1,452,089	$	937,875	$	478,987	$	363,018		$	27,457	$	6,879,188
2007
Oil and gas production revenues	$	4,306,108	$	1,392,856		$	2,011,796	$	535,699	$	1,399,201	$	316,322		$	—	$	9,961,982
Operating Expenses:
Depreciation, depletion and amortization		1,074,669		413,074			306,084		190,606		196,888		166,470			—		2,347,791
Asset retirement obligation accretion		70,006		9,144			—		3,684		12,511		1,093			—		96,438
Lease operating expenses		802,164		331,403			174,859		81,288		182,388		80,753			—		1,652,855
Gathering and transportation		38,086		54,412			15,242		—		26,647		3,020			—		137,407
Taxes other than income		166,798		42,598			7,887		22,497		346,500		11,367			—		597,647
Operating Income (Loss)(1)	$	2,154,385	$	542,225		$	1,507,724	$	237,624	$	634,267	$	53,619		$	—		5,129,844
Other Income (Expense):
Other																		37,770
General and administrative																		(275,065	)
Financing costs, net																		(219,937	)
Income Before Income Taxes																	$	4,672,612
Net Property and Equipment	$	11,919,013	$	5,834,792		$	2,560,609	$	1,590,431	$	1,889,651	$	1,437,097		$	—	$	25,231,593
Total Assets	$	12,195,552	$	7,289,118		$	3,360,494	$	1,884,443	$	2,229,502	$	1,664,462		$	11,080	$	28,634,651
Additions to Net Property and Equipment	$	2,912,541	$	836,547		$	1,059,793	$	603,174	$	541,761	$	344,818		$	—	$	6,298,634

(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.

F-43

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

													Other
	United States		Canada		Egypt		Australia		North Sea		Argentina		International		Total
	(In thousands)
2006
Oil and gas production revenues	$	3,027,227	$	1,379,626	$	1,664,103	$	408,453	$	1,355,139	$	167,195	$	72,510	$	8,074,253
Operating Expenses:
Depreciation, depletion and amortization		765,564		365,369		247,354		147,413		179,625		93,025		18,009		1,816,359
Asset retirement obligation accretion		65,357		8,506		—		2,527		11,808		733		—		88,931
Lease operating expenses		592,281		292,576		147,656		57,942		185,902		40,807		5,398		1,322,562
Gathering and transportation		31,810		50,461		10,995		—		26,387		763		121		120,537
Taxes other than income		143,689		32,999		—		19,524		394,487		2,559		4,669		597,927
Operating Income (Loss)(1)	$	1,428,526	$	629,715	$	1,258,098	$	181,047	$	556,930	$	29,308	$	44,313		4,127,937
Other Income (Expense):
Other																61,333
General and administrative																(211,334	)
Gain on China divestiture																173,545
Financing costs, net																(141,886	)
Income Before Income Taxes															$	4,009,595
Net Property and Equipment	$	10,139,918	$	5,411,726	$	1,806,901	$	1,184,180	$	1,544,778	$	1,258,749	$	—	$	21,346,252
Total Assets	$	11,486,070	$	5,821,685	$	2,423,655	$	1,322,501	$	1,839,150	$	1,404,382	$	10,732	$	24,308,175
Additions to Property and Equipment	$	3,159,613	$	1,250,355	$	569,316	$	218,345	$	335,055	$	1,311,804	$	11,794	$	6,856,282

(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.

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13.   SUPPLEMENTAL OIL AND GAS DISCLOSOURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.

															Other
	United States		Canada			Egypt		Australia		North Sea		Argentina			International		Total
	(In thousands)
2008
Oil and gas production revenues	$	5,083,397	$	1,650,402		$	2,739,246	$	371,669	$	2,103,283	$	379,842		$	—	$	12,327,839
Operating cost:
Depreciation, depletion and amortization Recurring(1)		1,081,027		410,047			397,573		133,126		260,831		187,918			—		2,470,522
Additional		2,667,440		1,689,392			—		—		568,450		408,539			—		5,333,821
Asset retirement obligation accretion		66,189		14,173			—		5,921		13,215		1,850			—		101,348
Lease operating expenses		925,977		336,871			241,455		103,627		190,966		110,729			—		1,909,625
Gathering and transportation		39,739		62,848			20,896		—		28,382		4,626			—		156,491
Production taxes(2)		201,590		33,643			—		10,719		695,443		—			—		941,395
Income tax		36,009		(215,536	)		998,075		35,483		172,998		(116,837	)		—		910,192
		5,017,971		2,331,438			1,657,999		288,876		1,930,285		596,825			—		11,823,394
Results of operations	$	65,426	$	(681,036	)	$	1,081,247	$	82,793	$	172,998	$	(216,983	)	$	—	$	504,445
Amortization rate per boe	$	14.08	$	13.11		$	8.48	$	11.26	$	11.89	$	10.49		$	—	$	12.06
2007
Oil and gas production revenues	$	4,306,108	$	1,392,856		$	2,011,796	$	535,699	$	1,399,201	$	316,322		$	—	$	9,961,982
Operating cost:
Depreciation, depletion and amortization(1)		1,048,213		400,630			306,084		189,208		196,054		163,557			—		2,303,746
Asset retirement obligation accretion		70,006		9,144			—		3,684		12,511		1,093			—		96,438
Lease Operating expenses		802,164		331,403			174,859		81,288		182,388		80,753			—		1,652,855
Gathering and transportation		38,086		54,412			15,242		—		26,647		3,020			—		137,407
Production taxes(2)		152,274		34,724			—		22,497		346,500		—			—		555,995
Income tax		779,355		168,763			727,493		81,267		317,551		23,765			—		2,098,194
		2,890,098		999,076			1,223,678		377,944		1,081,651		272,188			—		6,844,635
Results of Operations	$	1,416,010	$	393,780		$	788,118	$	157,755	$	317,550	$	44,134		$	—	$	3,117,347
Amortization rate per boe	$	12.62	$	11.81		$	7.15	$	10.36	$	9.96	$	9.17		$	—	$	10.78
2006
Oil and gas production revenues	$	3,027,227	$	1,379,626		$	1,664,103	$	408,453	$	1,355,139	$	167,195		$	72,510	$	8,074,253
Operating cost:
Depreciation, depletion and amortization(1)		742,981		355,446			247,354		146,406		178,682		91,562			17,991		1,780,422
Asset retirement obligation accretion		65,357		8,506			—		2,527		11,808		733			—		88,931
Lease Operating expenses		592,281		292,576			147,656		57,942		185,902		40,807			5,398		1,322,562
Gathering and transportation		31,810		50,461			10,995		—		26,387		763			121		120,537
Production taxes(2)		131,600		25,867			—		19,524		394,487		2,559			—		574,037
Income tax		519,435		208,583			603,887		61,898		278,937		10,770			16,170		1,699,680
		2,083,464		941,439			1,009,892		288,297		1,076,203		147,194			39,680		5,586,169
Results of Operations	$	943,763	$	438,187		$	654,211	$	120,156	$	278,936	$	20,001		$	32,830	$	2,488,084
Amortization rate per boe	$	10.90	$	9.97		$	6.23	$	8.48	$	8.31	$	9.08		$	15.56	$	9.29

(1)	This amount only reflects DD&A of capitalized costs of oil and gas proved properties and, therefore, does not agree with DD&A reflected on Note 11 — Business Segment Information.
(2)	This amount only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 11 — Business Segment Information.

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities

														Other
	United States		Canada		Egypt		Australia			North Sea		Argentina		International		Total
	(In thousands)
2008
Acquisitions:
Proved	$	69,642	$	4,938	$	—	$	(500	)	$	—	$	—	$	—	$	74,080
Unproved		75,437		—		—		—			—		—		—		75,437
Exploration		382,019		253,940		192,588		293,031			107,338		256,068		27,457		1,512,441
Development		2,200,910		580,406		667,860		588,539			364,421		98,074		—		4,500,210
Costs incurred(1)	$	2,728,008	$	839,284	$	860,448	$	881,070		$	471,759	$	354,142	$	27,457	$	6,162,168
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	20,267	$	12,313	$	7,646	$	8,636		$	703	$	23,988	$	—	$	73,553
Asset retirement costs		379,189		116,967		—		(6,746	)		11,817		12,664		—		513,891
2007
Acquisitions:
Proved	$	965,476	$	—	$	19,261	$	10,530		$	—	$	9,259	$	—	$	1,004,526
Unproved		—		24,474		—		20,511			507		—		—		45,492
Exploration		139,092		187,312		131,552		323,553			229,946		223,865		—		1,235,320
Development		1,762,740		593,926		480,384		231,394			309,448		97,025		—		3,474,917
Costs incurred(1)	$	2,867,308	$	805,712	$	631,197	$	585,988		$	539,901	$	330,149	$	—	$	5,760,255
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	20,577	$	13,106	$	6,821	$	6,447		$	1,526	$	20,980	$	—	$	69,457
Asset retirement costs		271,183		117,456		—		37,866			—		12,863		—		439,368
2006
Acquisitions:
Proved	$	1,246,748	$	5,859	$	—	$	23,981		$	—	$	800,673	$	—	$	2,077,261
Unproved		71,260		—		—		—			3,060		321,500		—		395,820
Exploration		102,711		212,700		84,404		127,246			110,465		76,503		2,028		716,057
Development		1,660,523		891,008		376,877		58,573			219,033		39,067		10,260		3,255,341
Costs incurred(1)	$	3,081,242	$	1,109,567	$	461,281	$	209,800		$	332,558	$	1,237,743	$	12,288	$	6,444,479
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interests	$	29,300	$	21,793	$	6,839	$	3,819		$	—	$	—	$	—	$	61,301
Asset retirement costs		348,057		25,301		—		2,108			—		15,146		—		390,612

Capitalized Costs

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s oil and gas production, exploration and development activities:

																			Other
	United States			Canada			Egypt			Australia			North Sea			Argentina			International		Total
	(In thousands)
2008
Proved properties	$	21,275,814		$	7,748,591		$	3,638,368		$	3,121,845		$	3,099,916		$	1,754,747		$	—	$	40,639,281
Unproved properties		381,258			312,616			231,169			110,348			15,724			221,775			27,457		1,300,347
		21,657,072			8,061,207			3,869,537			3,232,193			3,115,640			1,976,522			27,457		41,939,628
Accumulated DD&A		(11,136,475	)		(3,970,016	)		(1,826,379	)		(1,071,364	)		(1,588,885	)		(856,380	)		1,431		(20,448,068	)
	$	10,520,597		$	4,091,191		$	2,043,158		$	2,160,829		$	1,526,755		$	1,120,142		$	28,888	$	21,491,560
2007
Proved properties	$	18,819,680		$	7,009,747		$	2,834,325		$	2,148,882		$	2,610,429		$	1,222,215		$	432	$	34,645,710
Unproved properties		315,000			312,903			174,764			202,243			34,651			400,165			—		1,439,726
		19,134,680			7,322,650			3,009,089			2,351,125			2,645,080			1,622,380			432		36,085,436
Accumulated DD&A		(7,391,442	)		(1,906,208	)		(1,482,923	)		(952,907	)		(759,604	)		(263,992	)		999		(12,756,077	)
	$	11,743,238		$	5,416,442		$	1,526,166		$	1,398,218		$	1,885,476		$	1,358,388		$	1,431	$	23,329,359

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2008, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.

										2005
	Total		2008		2007		2006			and Prior
	(In thousands)
Property acquisition costs	$	862,314	$	225,796	$	223,915	$	270,590		$	142,013
Exploration and development		378,842		380,168		25,193		(39,420	)		12,901
Capitalized interest		59,191		35,910		7,875		6,187			9,219
Total	$	1,300,347	$	641,874	$	256,983	$	237,357		$	164,133

Oil and Gas Reserve Information

The estimate of reserves disclosed in this Annual Report on Form 10-K are prepared by the Company’s internal staff and the Company is responsible for the adequacy and accuracy of those estimates. However, we engage Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. We selected the properties for review by Ryder Scott. These properties represented all material fields, approximately 90 percent of international properties and over 80 percent of each country’s reserve value for new wells drilled during the year. During 2008, 2007 and 2006, Ryder Scott’s review covered 82, 77 and 75 percent of the Company’s worldwide estimated reserves value, respectively.

Ryder Scott opined that the overall proved reserves for the reviewed properties as estimated by the Company are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles and conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. Ryder Scott has informed the Company that the tests and procedures used during its reserves audit conform to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information approve by the Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used and (5) the reasonableness of the estimated reserve quantities. A reserve audit is not the same as a financial audit and is less rigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on his own.

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.

																																																Total
																																																(Thousands
	Crude Oil, Condensate and Natural Gas Liquids																								Natural Gas																							barrels
	(Thousands of barrels)																								(Millions of cubic feet)																							of
	United												North												United												North											oil
	States			Canada			Egypt			Australia			Sea			Argentina			China			Total			States			Canada			Egypt			Australia			Sea			Argentina			China		Total			equivalent)
Proved developed reserves:
December 31, 2005		313,580			87,012			59,197			22,550			189,385			1,573			3,393			676,690			1,711,060			1,799,102			605,687			649,972			7,475			2,594			—		4,775,890			1,472,672
December 31, 2006		343,743			102,417			58,366			20,197			178,364			25,378			—			728,464			1,840,105			1,591,157			664,818			584,236			6,840			438,391			—		5,125,547			1,582,722
December 31, 2007		394,960			94,090			74,315			19,948			186,706			24,535			—			794,554			1,923,750			1,605,675			818,509			536,131			6,304			442,058			—		5,332,427			1,683,292
December 31, 2008		363,516			85,038			93,103			39,758			168,925			26,752			—			777,092			1,866,988			1,594,782			1,010,102			713,290			5,585			487,980			—		5,678,727			1,723,547
Total proved reserves:
Balance December 31, 2005		461,568			170,197			90,893			51,322			195,262			1,661			5,007			975,910			2,566,187			2,366,592			1,080,357			824,817			7,475			2,594			—		6,848,022			2,117,248
Extensions, discoveries and other additions		12,354			18,430			18,535			23,517			21,777			3,422			3,386			101,421			253,707			248,549			151,086			46,860			118			36,986			—		737,306			224,305
Purchases of minerals in-place		53,853			643			—			—			—			28,351			—			82,847			195,552			1,500			—			—			—			484,707			—		681,759			196,473
Revisions of previous estimates		(2,009	)		63			31			24			—			147			(19	)		(1,763	)		(74,225	)		(102,922	)		3,965			4			—			1,858			—		(171,320	)		(30,317	)
Production		(27,308	)		(8,359	)		(20,648	)		(4,341	)		(21,369	)		(3,064	)		(1,156	)		(86,245	)		(243,441	)		(147,579	)		(79,424	)		(67,934	)		(753	)		(40,878	)		—		(580,009	)		(182,913	)
Sales of properties		(3,187	)		—			—			—			—			(724	)		(7,218	)		(11,129	)		(2,418	)		(421	)		—			—			—			—			—		(2,839	)		(11,602	)
Balance December 31, 2006		495,271			180,974			88,811			70,522			195,670			29,793			—			1,061,041			2,695,362			2,365,719			1,155,984			803,747			6,840			485,267			—		7,512,919			2,313,194
Extensions, discoveries and other additions		31,504			8,083			34,148			9,812			28,622			3,353			—			115,521			217,560			122,745			178,978			414,896			169			91,236			—		1,025,584			286,452
Purchases of minerals in-place		56,954			208			186			1,424			—			—			—			58,772			79,532			4,179			—			—			—			—			—		83,712			72,724
Revisions of previous estimates		5,546			(3,644	)		(6,369	)		—			—			138			—			(4,328	)		8,881			(15,889	)		(64,196	)		—			—			287			—		(70,917	)		(16,150	)
Production		(35,938	)		(7,666	)		(22,168	)		(5,029	)		(19,575	)		(5,198	)		—			(95,574	)		(280,902	)		(141,697	)		(87,883	)		(71,149	)		(705	)		(73,330	)		—		(655,667	)		(204,850	)
Sales of properties		(1,722	)		—			—			—			—			—			—			(1,722	)		(21,385	)		(1,529	)		—			—			—			—			—		(22,914	)		(5,541	)
Balance December 31, 2007		551,615			177,955			94,608			76,729			204,717			28,086			—			1,133,710			2,699,048			2,333,528			1,182,883			1,147,494			6,304			503,460			—		7,872,717			2,445,829
Extensions, discoveries and other additions		38,010			5,623			28,966			4,401			9,288			9,261			—			95,549			247,100			192,974			109,488			151,308			362			114,852			—		816,084			231,563
Purchases of minerals in-place		1,919			7			—			—			—			—			—			1,926			27,551			1,757			—			—			—			—			—		29,308			6,810
Revisions of previous estimates		(31,540	)		(18,787	)		15,264			(1,576	)		(4,315	)		30			—			(40,924	)		(175,834	)		(134,563	)		175,125			(238	)		(116	)		(330	)		—		(135,956	)		(63,583	)
Production		(35,057	)		(7,038	)		(24,432	)		(3,019	)		(21,775	)		(5,598	)		—			(96,919	)		(248,835	)		(129,100	)		(96,518	)		(45,019	)		(965	)		(71,608	)		—		(592,045	)		(195,593	)
Sales of properties		(10,183	)		(2,015	)		—			—			—			—			—			(12,198	)		(11,848	)		(61,235	)		—			—			—			—			—		(73,083	)		(24,378	)
Balance December 31, 2008		514,764			155,745			114,406			76,535			187,915			31,779			—			1,081,144			2,537,182			2,203,361			1,370,978			1,253,545			5,585			546,374			—		7,917,025			2,400,648

As of December 31, 2008, 2007 and 2006, on a barrel of equivalent basis 28, 31 and 32 percent of our estimated worldwide reserves, respectively, were classified as proved undeveloped. Approximately 24 percent of our year-end 2008 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 13, under “Future Net Cash Flows.”

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Future Net Cash Flows

Future cash inflows are based on year-end oil and gas prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.

	United
	States			Canada(1)			Egypt			Australia			North Sea			Argentina			Total
	(In thousands)
2008
Cash inflows	$	33,163,869		$	19,176,850		$	8,197,873		$	8,081,114		$	7,245,187		$	2,189,600		$	78,054,493
Production costs		(12,106,876	)		(10,816,837	)		(1,364,304	)		(2,484,538	)		(4,007,188	)		(815,453	)		(31,595,196	)
Development costs		(3,315,013	)		(2,038,896	)		(1,452,228	)		(1,704,401	)		(1,100,321	)		(180,926	)		(9,791,785	)
Income tax expense		(4,559,309	)		(3,685,399	)		(1,857,758	)		(893,348	)		(1,043,415	)		(270,928	)		(12,310,157	)
Net cash flows		13,182,671			2,635,718			3,523,583			2,998,827			1,094,263			922,293			24,357,355
10 percent discount rate		(6,660,164	)		(1,567,388	)		(1,168,561	)		(1,515,430	)		(230,793	)		(267,187	)		(11,409,523	)
Discounted future net cash flows(2)	$	6,522,507		$	1,068,330		$	2,355,022		$	1,483,397		$	863,470		$	655,106		$	12,947,832
2007
Cash inflows	$	65,709,496		$	30,593,185		$	13,218,300		$	11,109,570		$	18,804,621		$	2,196,765		$	141,631,937
Production costs		(14,756,624	)		(10,615,928	)		(1,441,370	)		(2,645,871	)		(10,712,341	)		(640,022	)		(40,812,156	)
Development costs		(3,570,210	)		(2,484,076	)		(1,332,022	)		(1,861,987	)		(872,754	)		(144,569	)		(10,265,618	)
Income tax expense		(15,112,020	)		(5,049,325	)		(3,988,962	)		(1,820,006	)		(3,586,735	)		(364,839	)		(29,921,887	)
Net cash flows		32,270,642			12,443,856			6,455,946			4,781,706			3,632,791			1,047,335			60,632,276
10 percent discount rate		(16,958,060	)		(6,987,602	)		(2,087,773	)		(2,218,830	)		(1,338,178	)		(294,095	)		(29,884,538	)
Discounted future net cash flows(2)	$	15,312,582		$	5,456,254		$	4,368,173		$	2,562,876		$	2,294,613		$	753,240		$	30,747,738
2006
Cash inflows	$	42,809,947		$	22,835,940		$	9,000,743		$	5,747,306		$	11,736,209		$	1,775,939		$	93,906,084
Production costs		(10,930,520	)		(7,602,015	)		(1,101,859	)		(1,804,495	)		(6,905,086	)		(427,363	)		(28,771,338	)
Development costs		(3,207,033	)		(1,888,896	)		(1,554,931	)		(985,414	)		(672,059	)		(190,508	)		(8,498,841	)
Income tax expense		(8,862,385	)		(5,049,325	)		(2,466,836	)		(883,814	)		(1,624,701	)		(298,424	)		(19,185,485	)
Net cash flows		19,810,009			8,295,704			3,877,117			2,073,583			2,534,363			859,644			37,450,420
10 percent discount rate		(9,910,108	)		(4,714,251	)		(1,404,781	)		(850,124	)		(923,183	)		(278,584	)		(18,081,031	)
Discounted future net cash flows(2)	$	9,899,901		$	3,581,453		$	2,472,336		$	1,223,459		$	1,611,180		$	581,060		$	19,369,389

1)	Prior to 2007, Canadian provincial tax credits were included in the estimated future net cash flows. Effective January 1, 2007, the Alberta government eliminated the Royalty Tax Credit program.
2)	Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $19.8 billion, $47.5 billion and $29.6 billion as of December 31, 2008, 2007 and 2006, respectively.

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the principal sources of change in the discounted future net cash flows:

	For the Year Ended December 31,
	2008			2007			2006
	(In thousands)
Sales, net of production costs	$	(9,725,306	)	$	(7,967,797	)	$	(6,192,148	)
Net change in prices and production costs		(25,450,706	)		15,869,295			(5,765,792	)
Discoveries and improved recovery, net of related costs		3,132,109			5,983,717			3,256,269
Change in future development costs		1,335,971			289,764			(665,840	)
Revision of quantities		214,797			(546,938	)		(439,936	)
Purchases of minerals in-place		1,675,599			1,842,457			2,161,922
Accretion of discount		4,692,752			2,956,636			3,592,933
Change in income taxes		7,820,734			(5,848,139	)		1,119,235
Sales of properties		(653,782	)		(83,336	)		(73,817	)
Change in production rates and other		(842,074	)		(1,117,310	)		(2,151,786	)
	$	(17,799,906	)	$	11,378,349		$	(5,158,960	)

14.  SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

	First		Second		Third		Fourth			Total
	(In thousands, except per share amounts)
2008
Revenues	$	3,187,741	$	3,900,191	$	3,364,884	$	1,936,934		$	12,389,750
Expenses, net		2,166,228		2,454,962		2,174,059		4,882,547			11,677,796
Net income	$	1,021,513	$	1,445,229	$	1,190,825	$	(2,945,613	)	$	711,954
Income attributable to common stock	$	1,020,093	$	1,443,809	$	1,189,405	$	(2,947,033	)	$	706,274
Net income per common share(1):
Basic	$	3.06	$	4.32	$	3.55	$	(8.80	)	$	2.11
Diluted	$	3.03	$	4.28	$	3.52	$	(8.80	)	$	2.09
2007
Revenues	$	2,002,875	$	2,472,544	$	2,504,958	$	3,019,375		$	9,999,752
Expenses, net		1,509,926		1,839,006		1,891,610		1,946,852			7,187,394
Net income	$	492,949	$	633,538	$	613,348	$	1,072,523		$	2,812,358
Income attributable to common stock	$	491,529	$	632,118	$	611,928	$	1,071,103		$	2,806,678
Net income per common share(1):
Basic	$	1.48	$	1.91	$	1.84	$	3.22		$	8.45
Diluted	$	1.47	$	1.89	$	1.83	$	3.19		$	8.39

(1) The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period. All potentially dilutive securities were included in each quarterly computation of diluted net income per common share, as none were antidilutive.

15.   SUPPLEMENTAL GUARANTOR INFORMATION

Prior to 2001, Apache Finance Australia was a finance subsidiary of Apache with no independent operations. In this capacity, it issued approximately $270 million of publicly traded notes that are fully and unconditionally

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

guaranteed by Apache and, beginning in 2001, Apache North America, Inc. In 2007, $170 million of these notes matured and were repaid. The guarantors of Apache Finance Australia have joint and several liabilities. Similarly, Apache Finance Canada was also a finance subsidiary of Apache and had issued approximately $300 million of publicly traded notes that were fully and unconditionally guaranteed by Apache. In 2008, Apache Finance Canada issued an additional $350 million in notes that were fully and unconditionally guaranteed by Apache.

Generally, the issuance of publicly traded securities would subject those subsidiaries to the reporting requirements of the Securities and Exchange Commission. Since these subsidiaries had no independent operations and qualified as “finance subsidiaries,” they were exempted from these requirements.

During 2001, Apache contributed stock of its Australian and Canadian operating subsidiaries to Apache Finance Australia and Apache Finance Canada, respectively. As a result of these contributions, they no longer qualify as finance subsidiaries. As allowed by the SEC rules, 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 is wholly owned and has been consolidated in Apache Corporation’s consolidated financial statements for all periods presented. As such, the condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto of which this note is an integral part.

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2008

												All Other
												Subsidiaries
	Apache			Apache			Apache		Apache			of Apache			Reclassifications
	Corporation			North America			Finance Australia		Finance Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,552,515		$	—		$	—	$	—		$	7,821,713		$	(46,389	)	$	12,327,839
Equity in net income (loss) of affiliates		525,829			71,228			67,820		(156,540	)		88,407			(596,744	)		—
Other		25,876			(30,643	)		30,542		58,832			(19,006	)		(3,690	)		61,911
		5,104,220			40,585			98,362		(97,708	)		7,891,114			(646,823	)		12,389,750
OPERATING EXPENSES:
Depreciation, depletion and amortization		3,276,414			—			—		—			4,573,844			—			7,850,258
Asset retirement obligation accretion		66,189			—			—		—			35,159			—			101,348
Lease operating expenses		821,150			—			—		—			1,088,475			—			1,909,625
Gathering and transportation		38,606			—			—		—			164,274			(46,389	)		156,491
Taxes other than income		169,061			—			—		—			815,746			—			984,807
General and administrative		223,468			—			—		—			69,016			(3,690	)		288,794
Financing costs, net		150,202			(11,050	)		18,046		(5,585	)		14,422			—			166,035
		4,745,090			(11,050	)		18,046		(5,585	)		6,760,936			(50,079	)		11,457,358
INCOME (LOSS) BEFORE INCOME TAXES		359,130			51,635			80,316		(92,123	)		1,130,178			(596,744	)		932,392
Provision (benefit) for income taxes		(352,823	)		(11,939	)		9,088		(28,236	)		604,348			—			220,438
NET INCOME		711,953			63,574			71,228		(63,887	)		525,830			(596,744	)		711,954
Preferred stock dividends		5,680			—			—		—			—			—			5,680
INCOME ATTRIBUTABLE TO COMMON STOCK	$	706,273		$	63,574		$	71,228	$	(63,887	)	$	525,830		$	(596,744	)	$	706,274

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended December 31, 2007

											All Other
											Subsidiaries
	Apache		Apache		Apache			Apache			of Apache			Reclassifications
	Corporation		North America		Finance Australia			Finance Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,243,362	$	—	$	—		$	—		$	5,827,276		$	(108,656	)	$	9,961,982
Equity in net income (loss) of affiliates		1,704,390		49,183		60,985			141,181			—			(1,955,739	)		—
Other		13,000		—		(259	)		(59,160	)		87,879			(3,690	)		37,770
		5,960,752		49,183		60,726			82,021			5,915,155			(2,068,085	)		9,999,752
OPERATING EXPENSES:
Depreciation, depletion and amortization		1,070,058		—		—			—			1,277,733			—			2,347,791
Asset retirement obligation accretion		70,005		—		—			—			26,433			—			96,438
Lease operating expenses		801,937		—		—			—			850,918			—			1,652,855
Gathering and transportation		38,084		—		—			—			207,979			(108,656	)		137,407
Taxes other than income		160,971		—		—			—			436,676			—			597,647
General and administrative		223,229		—		—			—			55,526			(3,690	)		275,065
Financing costs, net		237,892		—		18,076			(2,711	)		(33,320	)		—			219,937
		2,602,176		—		18,076			(2,711	)		2,821,945			(112,346	)		5,327,140
INCOME (LOSS) BEFORE INCOME TAXES		3,358,576		49,183		42,650			84,732			3,093,210			(1,955,739	)		4,672,612
Provision (benefit) for income taxes		546,218		—		(6,533	)		(16,511	)		1,337,080			—			1,860,254
NET INCOME		2,812,358		49,183		49,183			101,243			1,756,130			(1,955,739	)		2,812,358
Preferred stock dividends		5,680		—		—			—			—			—			5,680
INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,806,678	$	49,183	$	49,183		$	101,243		$	1,756,130		$	(1,955,739	)	$	2,806,678

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2006

											All Other
											Subsidiaries
	Apache		Apache		Apache			Apache			of Apache			Reclassifications
	Corporation		North America		Finance Australia			Finance Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,920,731	$	—	$	—		$	—		$	5,382,157		$	(228,635	)	$	8,074,253
Equity in net income (loss) of affiliates		1,795,327		33,997		41,733			277,944			(45,977	)		(2,103,024	)		—
Gain on China divestiture		—		—		—			—			173,545			—			173,545
Other		94,369		—		(63	)		—			(32,973	)		—			61,333
		4,810,427		33,997		41,670			277,944			5,476,752			(2,331,659	)		8,309,131
OPERATING EXPENSES:
Depreciation, depletion and amortization		752,930		—		—			—			1,063,429			—			1,816,359
Asset retirement obligation accretion		65,357		—		—			—			23,574			—			88,931
Lease operating expenses		587,089		—		—			—			964,108			(228,635	)		1,322,562
Gathering and transportation		31,618		—		—			—			88,919			—			120,537
Taxes other than income		135,257		—		—			—			462,669			—			597,927
General and administrative		161,625		—		—			—			49,709			—			211,334
Financing costs, net		118,429		—		18,003			56,444			(50,990	)		—			141,886
		1,852,306		—		18,003			56,444			2,601,418			(228,635	)		4,299,536
INCOME (LOSS) BEFORE INCOME TAXES		2,958,121		33,997		23,667			221,500			2,875,334			(2,103,024	)		4,009,595
Provision (benefit) for income taxes		405,670		—		(10,330	)		(18,203	)		1,080,007			—			1,457,144
NET INCOME		2,552,451		33,997		33,997			239,703			1,795,327			(2,103,024	)		2,552,451
Preferred stock dividends		5,680		—		—			—			—			—			5,680
INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,546,771	$	33,997	$	33,997		$	239,703		$	1,795,327		$	(2,103,024	)	$	2,546,771

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2008

													All Other
													Subsidiaries
	Apache			Apache			Apache			Apache			of Apache			Reclassifications
	Corporation			North America			Finance Australia			Finance Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,590,113		$	(1,038	)	$	(12,239	)	$	3,255		$	5,485,253		$	—		$	7,065,344
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,532,815	)		—			—			—			(3,760,947	)		—			(5,293,762	)
Acquisition of Anadarko properties					—			—			—						—			—
Additions to gathering, transmission and processing facilities		(321	)		—			—			—			(678,763	)		—			(679,084	)
Restricted cash		(13,880	)		—			—			—			—			—			(13,880	)
Proceeds from sales of oil and gas properties		206,047			—			—			—			101,927			—			307,974
Investment in and advances to subsidiaries, net		(198,164	)		(12,977	)		—			—			—			211,141			—
Other, net		384,782			—			—			—			(449,008	)		—			(64,226	)
NET CASH USED IN INVESTING ACTIVITIES		(1,154,351	)		(12,977	)		—			—			(4,786,791	)		211,141			(5,742,978	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and bank loan borrowings, net		(138,231	)		(6,872	)		(737	)		(2,202	)		153,117			(104,878	)		(99,803	)
Fixed-rate debt borrowings, net		796,315			—			—			—			—			—			796,315
Payments on fixed-rate debt		—			—			—			—			(353	)		—			(353	)
Dividends paid		(239,358	)		—			—			—			—			—			(239,358	)
Common stock activity		31,513			19,977			12,977			(1,090	)		74,399			(106,263	)		31,513
Treasury stock activity, net		4,498			—			—			—			—			—			4,498
Purchase of short-term investing		(791,999	)		—			—			—			—			—			(791,999	)
Cost of debt and equity transactions		(7,050	)		—			—			—			—			—			(7,050	)
Other		46,951			—			—			—			(7,453	)		—			39,498
NET CASH PROVIDED BY FINANCING ACTIVITIES		(297,361	)		13,105			12,240			(3,292	)		219,710			(211,141	)		(266,739	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		138,401			(910	)		1			(37	)		918,172			—			1,005,627
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 YEAR	$	142,027		$	(426	)	$	2		$	1,714		$	1,038,133		$	—		$	1,181,450

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2007

													All Other
													Subsidiaries
	Apache			Apache			Apache			Apache			of Apache			Reclassifications
	Corporation			North America			Finance Australia			Finance Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	3,536,130		$	—		$	(18,622	)	$	(990,754	)	$	3,150,679		$	—		$	5,677,433
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,748,063	)		—			—			—			(2,574,406	)		—			(4,322,469	)
Acquisition of Anadarko properties		(1,004,581	)		—			—			—			(12	)		—			(1,004,593	)
Additions to gathering, transmission and processing facilities		(1,062	)		—			—			—			(478,812	)		—			(479,874	)
Restricted cash
Proceeds from sales of oil and gas properties		4,623			—			—			—			62,860			—			67,483
Investment in and advances to subsidiaries, net		(1,123,148	)		(24,977	)		—			—			(1,181,454	)		2,329,579			—
Other, net		(71,752	)		—			—			—			(134,724	)		—			(206,476	)
NET CASH USED IN INVESTING ACTIVITIES		(3,943,983	)		(24,977	)		—			—			(4,306,548	)		2,329,579			5,945,929
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and bank loan borrowings, net		(1,431,714	)		—			163,645			(377	)		93,696			(237,500	)		(1,412,250	)
Fixed-rate debt borrowings, net		1,992,290			—			—			—			—			—			1,992,290
Payments on fixed-rate debt		—			—			(170,000	)		—			(3,000	)		—			(173,000	)
Dividends paid		(204,753	)		—			—			—			—			—			(204,753	)
Common stock activity		29,682			24,977			24,977			992,881			1,049,244			(2,092,079	)		29,682
Treasury stock activity, net		14,279			—			—			—			—			—			14,279
Cost of debt and equity transactions		(18,179	)		—			—			—			—			—			(18,179	)
Other		25,726			—			—			—			—			—			25,726
NET CASH PROVIDED BY FINANCING ACTIVITIES		407,331			24,977			18,622			992,504			1,139,940			(2,329,579	)		253,795
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(522	)		—			—			1,750			(15,929	)		—			(14,701	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		4,148			—			1			1			136,374			—			140,524
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	3,626		$	—		$	1		$	1,751		$	120,445		$	—		$	125,823

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2006

													All Other
													Subsidiaries
	Apache			Apache			Apache			Apache			of Apache			Reclassifications
	Corporation			North America			Finance Australia			Finance Canada			Corporation			& Eliminations			Consolidated
	(In thousands)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,508,882			—		$	(20,706	)	$	(21,372	)	$	2,846,102		$	—		$	4,312,906
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,834,732	)		—			—			—			(2,056,907	)		—			(3,891,639	)
Acquisition of BP p.l.c. properties		(833,820	)		—			—			—			—			—			(833,820	)
Acquisition of Pioneer’s Argentine operations		—			—			—			—			(704,809	)		—			(704,809	)
Acquisition of Amerada Hess properties		(229,134	)		—			—			—			—			—			(229,134	)
Acquisitions of Pan American Fueguina S.R.L. properties		—			—			—			—			(396,056	)		—			(396,056	)
Additions to gathering, transmission and processing facilities		(53,656	)		—			—			—			(194,933	)		—			(248,589	)
Proceeds from China divestiture		—			—			—			—			264,081			—			264,081
Proceeds from sales of Egyptian properties		—			—			—			—			409,203			—			409,203
Proceeds from sales of oil and gas properties		—			—			—			—			4,740			—			4,740
Investment in and advances to subsidiaries, net		6,270			(18,050	)		—			—			(41,333	)		53,113			—
Other, net		120,997			—			—			—			(270,556	)		—			(149,559	)
NET CASH USED IN INVESTING ACTIVITIES		(2,824,075	)		(18,050	)		—			—			(2,986,570	)		53,113			(5,775,582	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt borrowings		1,714,813			—			2,654			1,651			21,685			39,160			1,779,963
Payments on debt		(143,900	)		—			—			—			(6,366	)		—			(150,226	)
Dividends paid		(154,143	)		—			—			—			—			—			(154,143	)
Common stock activity		31,963			18,050			18,050			19,721			36,452			(92,273	)		31,963
Treasury stock activity, net		(166,907	)		—			—			—			—			—			(166,907	)
Cost of debt and equity transactions		(2,061	)		—			—			—			—			—			(2,061	)
Other		35,791			—			—			—			—			—			35,791
NET CASH PROVIDED BY FINANCING ACTIVITIES		1,315,556			18,050			20,704			21,372			51,771			(53,113	)		1,374,340
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		363			—			(2	)		—			(88,697	)		—			(88,336	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		3,785			—			2			1			225,072			—			228,860
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	4,148		$	—		$	—		$	1		$	136,375		$	—		$	140,524

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET
For the Year Ended December 31, 2008

											All Other
											Subsidiaries
	Apache		Apache			Apache			Apache		of Apache			Reclassifications
	Corporation		North America			Finance Australia			Finance Canada		Corporation			& Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	142,026	$	—		$	2		$	1,714	$	1,037,708		$	—		$	1,181,450
Marketable securities		—		—			—			—		—			—			—
Receivables, net of allowance		514,174		—			—			1,095		841,710			—			1,356,979
Inventories		59,106		—			—			—		439,461			—			498,567
Drilling advances and other		456,956		—			—			1,786		163,237			—			621,979
Short-term investments		791,899		—			—			—		100			—			791,999
		1,964,161		—			2			4,595		2,482,216			—			4,450,974
PROPERTY AND EQUIPMENT, NET		9,970,619		—			—			—		13,987,898			—			23,958,517
OTHER ASSETS:
Intercompany receivable, net		1,185,771		—			—			—		—			(1,185,771	)		—
Restricted cash		13,880		—			—			—		—			—			13,880
Goodwill, net		—		—			—			—		189,252			—			189,252
Equity in affiliates		12,919,395		510,620			714,092			1,556,673		(157,276	)		(15,543,504	)		—
Deferred charges and other		212,635		—			—			1,003,353		357,874			(1,000,000	)		573,862
	$	26,266,461	$	510,620		$	714,094		$	2,564,621	$	16,859,964		$	(17,729,275	)	$	29,186,485
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Short-term debt	$	—	$	—		$	99,977		$	—	$	12,621		$	—		$	112,598
Accounts payable		2,059,459		—			—			—		(1,489,321	)		—			570,138
Other accrued expenses		900,786		(10,097	)		165,432			290,587		1,771,555			(1,185,771	)		1,932,492
		2,960,245		(10,097	)		265,409			290,587		294,855			(1,185,771	)		2,615,228
LONG-TERM DEBT		4,061,005		—			—			647,071		100,899			—			4,808,975
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,599,539		—			(31,292	)		3,548		1,594,862			—			3,166,657
Advances from gas purchases		—		—			—			—		—			—			—
Asset retirement obligation		844,126		—			—			—		711,403			—			1,555,529
Derivative instruments		—		30,643			(30,643	)		—		7,713			—			7,713
Other		292,825		—			—			—		1,230,837			(1,000,000	)		523,662
		2,736,490		30,643			(61,935	)		3,548		3,544,815			(1,000,000	)		5,253,561
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		16,508,721		490,074			510,620			1,623,415		12,919,395			(15,543,504	)		16,508,721
	$	26,266,461	$	510,620		$	714,094		$	2,564,621	$	16,859,964		$	(17,729,275	)	$	29,186,485

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET
For the Year Ended December 31, 2007

											All Other
											Subsidiaries
	Apache		Apache		Apache			Apache			of Apache			Reclassifications
	Corporation		North America		Finance Australia			Finance 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 other		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		8,924,250		451,161		670,908			2,137,603			(168,977	)		(12,014,945	)		—
Deferred charges and other		211,399		—		—			1,003,668			246,488			(1,000,000	)		461,555
	$	23,127,332	$	451,161	$	500,909		$	2,889,754		$	14,680,440		$	(13,014,945	)	$	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 purchases		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	)		658,051
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		13,789,550		451,161		451,161			2,188,373			10,512,679			(12,014,945	)		15,377,979
	$	23,127,332	$	451,161	$	500,909		$	2,889,754		$	14,680,440		$	(13,014,945	)	$	28,634,651

F-59

Board of Directors

Frederick M. Bohen (3)(5)

Former Executive Vice President and

Chief Operating Officer,

The Rockefeller University

G. Steven Farris (1)

Chairman and Chief Executive Officer,

Apache Corporation

Randolph M. Ferlic, M.D. (1)(2)

Founder and Former President,

Surgical Services of the Great Plains, P.C.

Eugene C. Fiedorek (2)

Private Investor, Former Managing Director,

EnCap Investments L.C.

A.D. Frazier, Jr. (3)(5)

Chairman and Chief Executive Officer,

Danka Business Systems PLC

Patricia Albjerg Graham (4)

Charles Warren Professor of the

History of Education Emerita,

Harvard University

John A. Kocur (1)(3)(4)

Attorney at Law; Former Vice Chairman of the Board, Apache Corporation

George D. Lawrence (1)(3)

Private Investor; Former Chief Executive Officer,

The Phoenix Resource Companies, Inc.

F. H. Merelli (1)(2)

Chairman of the Board, Chief Executive Officer,

and President, Cimarex Energy Co.

Rodman D. Patton (2)

Former Managing Director,

Merrill Lynch Energy Group

Charles J. Pitman (4)

Former Regional President — Middle East/

Caspian/Egypt/India, BP Amoco plc;

(1)	Executive Committee
(2)	Audit Committee
(3)	Management Development and Compensation Committee
(4)	Corporate Governance and Nominating Committee
(5)	Stock Option Plan Committee

Officers

G. Steven Farris

Chairman and Chief Executive Officer

Roger B. Plank

President

John A. Crum

Co-Chief Operating Officer and President — North America

Rodney J. Eichler

Co-Chief Operating Officer and President — International

Michael S. Bahorich

Executive Vice President and Technology Officer

Floyd R. Price

Executive Vice President and Exploration Officer

Jon A. Jeppesen

Senior Vice President

P. Anthony Lannie

Senior Vice President and General Counsel

W. Kregg Olson

Senior Vice President — Corporate Reservoir Engineering

Sarah B. Teslik

Senior Vice President — Policy and Governance

Thomas P. Chambers

Vice President — Corporate Planning

John J. Christmann

Vice President — Business Development

Matthew W. Dundrea

Vice President and Treasurer

Robert J. Dye

Vice President — Investor Relations

Margie Harris

Vice President — Human Resources

Rebecca A. Hoyt

Vice President and Controller

Janine J. McArdle

Vice President — Oil and Gas Marketing

Jon W. Sauer

Vice President — Tax

Cheri L. Peper

Corporate Secretary

Shareholder Information

Stock Data

					Dividends
	Price Range				per Share
	High		Low		Declared		Paid
2008
First Quarter	$	122.34	$	84.52	$	.25	$	.15
Second Quarter		149.23		117.65		.15		.25
Third Quarter		145.00		94.82		.15		.15
Fourth Quarter		103.17		57.11		.15		.15
2007
First Quarter	$	73.44	$	63.01	$	.15	$	.15
Second Quarter		87.82		70.53		.15		.15
Third Quarter		91.25		73.41		.15		.15
Fourth Quarter		109.32		87.44		.15		.15

The Company has paid cash dividends on its common stock for 44 consecutive years through December 31, 2008. Future dividend payments will depend upon the Company’s level of earnings, financial requirements and other relevant factors.

Apache common stock is listed on the New York and Chicago stock exchanges and the NASDAQ National Market (symbol APA). At December 31, 2008, the Company’s shares of common stock outstanding were held by approximately 6,000 shareholders of record and 448,000 beneficial owners. Also listed on the New York Stock Exchange are:

•  Apache Finance Canada’s 7.75% notes, due 2029 (symbol APA29)

Corporate Offices

One Post Oak Central

2000 Post Oak Boulevard

Suite 100

Houston, Texas 77056-4400

(713) 296-6000

Independent Public Accountants

Ernst & Young LLP

Five Houston Center

1401 McKinney Street, Suite 1200

Houston, Texas 77010-2007

Stock Transfer Agent and Registrar

Wells Fargo Bank, N.A.

Attn: Shareowner Services

P.O. Box 64854

South St. Paul, Minnesota 55164-0854

(651) 450-4064 or (800) 468-9716

Communications concerning the transfer of shares, lost certificates, dividend checks, duplicate mailings or change of address should be directed to the stock transfer agent. Shareholders can access account information on the web site: www.shareowneronline.com

Dividend Reinvestment Plan

Shareholders of record may invest their dividends automatically in additional shares of Apache common stock at the market price. Participants may also invest up to an additional $25,000 in Apache shares each quarter through this service. All bank service fees and brokerage commissions on purchases are paid by Apache. A prospectus describing the terms of the Plan and an authorization form may be obtained from the Company’s stock transfer agent, Wells Fargo Bank, N.A.

Direct Registration

Shareholders of record may hold their shares of Apache common stock in book-entry form. This eliminates costs related to safekeeping or replacing paper stock certificates. In addition, shareholders of record may request electronic movement of book-entry shares between your account with the Company’s stock transfer agent and your broker. Stock certificates may be converted to book-entry shares at any time. Questions regarding this service may be directed to the Company’s stock transfer agent, Wells Fargo Bank, N.A.

Annual Meeting

Apache will hold its annual meeting of shareholders on Thursday, May 7, 2009, at 10:00 a.m. in the Ballroom, Hilton Houston Post Oak, 2001 Post Oak Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live; connect through the Apache web site: www.apachecorp.com

Stock Held in “Street Name”

The Company maintains a direct mailing list to ensure that shareholders with stock held in brokerage accounts receive information on a timely basis. Shareholders wanting to be added to this list should direct their requests to Apache’s Public and International Affairs Department, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400, by calling (713) 296-6157 or by registering on Apache’s web site: www.apachecorp.com

Form 10-K Request

Shareholders and other persons interested in obtaining, without cost, a copy of the Company’s Form 10-K filed with the Securities and Exchange Commission may do so by writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400.

Investor Relations

Shareholders, brokers, securities analysts or portfolio managers seeking information about the Company are welcome to contact Robert J. Dye, Vice President of Investor Relations, at (713) 296-6662.

Members of the news media and others seeking information about the Company should contact Apache’s Public and International Affairs Department at (713) 296-7276.

Web site: www.apachecorp.com

Exhibit Index

Exhibit
No.				Description
	2	.1	—	Agreement and Plan of Merger among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996).
	2	.2	—	Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
	2	.3	—	Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
	3	.1	—	Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	3	.2	—	Bylaws of Registrant, as amended December 14, 2006 (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2006, SEC File No. 001-4300).
	4	.1	—	Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
	4	.2	—	Form of Certificate for Registrant’s 5.68% Cumulative Preferred Stock, Series B (incorporated by reference to Exhibit 4.2 to Amendment No. 2 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 001-4300).
	4	.3	—	Rights Agreement, dated January 31, 1996, between Registrant and Norwest Bank Minnesota, N.A., rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit(a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).
	4	.4	—	Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of December 31, 1996, between Apache Corporation, a Delaware corporation, and Wells Fargo Bank, N.A. (successor to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).
	4	.5	—	Senior Indenture, dated February 15, 1996, between Registrant and JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
	4	.6	—	First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
	4	.7	—	Form of Indenture among Apache Finance Pty Ltd, Registrant and The Chase Manhattan Bank, as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973).
	4	.8	—	Form of Indenture among Registrant, Apache Finance Canada Corporation and The Chase Manhattan Bank, as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).
	10	.1	—	Form of Amended and Restated Credit Agreement, dated as of May 9, 2006, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2006, SEC File No. 001-4300).

Exhibit
No.				Description
	10	.2	—	Form of Request for Approval of Extension of Maturity Date and Amendment, dated as of April 5, 2007, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300).
	10	.3	—	Form of Request Form of Request for Approval of Extension of Maturity Date and Amendment, dated as of February 18, 2008, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).
	10	.4	—	Form of Credit Agreement, dated as of May 12, 2005, among Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, J.P. Morgan Securities Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners, Bank of America, N.A. and Citibank, N.A., as U.S. Co-Syndication Agents, and Calyon New York Branch and Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
	10	.5	—	Form of Credit Agreement, dated as of May 12, 2005, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, RBC Capital Markets and BMO Nesbitt Burns, as Co-Lead Arrangers and Joint Bookrunners, Royal Bank of Canada, as Canadian Administrative Agent, Bank of Montreal and Union Bank of California, N.A., Canada Branch, as Canadian Co-Syndication Agents, and The Toronto-Dominion Bank and BNP Paribas (Canada), as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
	10	.6	—	Form of Credit Agreement, dated as of May 12, 2005, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as Co-Lead Arrangers and Joint Bookrunners, Citisecurities Limited, as Australian Administrative Agent, Deutsche Bank AG, Sydney Branch, and JPMorgan Chase Bank, as Australian Co-Syndication Agents, and Bank of America, N.A., Sydney Branch, and UBS AG, Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
	10	.7	—	Form of Request for Approval of Extension of Maturity Date and Amendment, dated April 5, 2007, among Registrant, Apache Canada Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300).
	10	.8	—	Form of Request for Approval of Extension of Maturity Date and Amendment, dated February 18, 2008, among Registrant, Apache Canada Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).

Exhibit
No.				Description
	10	.9	—	Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt, dated April 6, 1981 (incorporated by reference to Exhibit 19(g) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1984, SEC File No. 1-547).
	10	.10	—	Amendment, dated July 10, 1989, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt (incorporated by reference to Exhibit 10(d)(4) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
	10	.11	—	Farmout Agreement, dated September 13, 1985 and relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10.1 to Phoenix’s Registration Statement on Form S-1, Registration No. 33-1069, filed October 23, 1985).
	10	.12	—	Amendment, dated March 30, 1989, to Farmout Agreement relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10(d)(5) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
	10	.13	—	Amendment, dated May 21, 1995, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Repsol Exploration Egypt S.A., Phoenix Resources Company of Egypt and Samsung Corporation (incorporated by reference to Exhibit 10.12 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1997, SEC File No. 001-4300).
	10	.14	—	Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area in Western Desert of Egypt, between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Phoenix Resources Company of Qarun and Apache Oil Egypt, Inc., dated May 17, 1993 (incorporated by reference to Exhibit 10(b) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1993, SEC File No. 1-547).
	10	.15	—	Agreement for Amending the Gas Pricing Provisions under the Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area, effective June 16, 1994 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.16	—	Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
	*†10	.17	—	First Amendment to Apache Corporation Corporate Incentive Compensation Plan A, dated November 20, 2008, effective as of January 1, 2005.
	†10	.18	—	Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
	*†10	.19	—	First Amendment to Apache Corporation Corporate Incentive Compensation Plan B, dated November 20, 2008, effective as of January 1, 2005.
	*†10	.20	—	Apache Corporation 401(k) Savings Plan, dated January 1, 2008.
	*†10	.21	—	Amendment to Apache Corporation 401(k) Savings Plan, dated January 29, 2009, effective as of January 1, 2009, except as otherwise specified.
	*†10	.22	—	Apache Corporation Money Purchase Retirement Plan, dated January 1, 2008.
	*†10	.23	—	Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 29, 2009, effective as of January 1, 2009, except as otherwise specified.
	*†10	.24	—	Non-Qualified Retirement/Savings Plan of Apache Corporation, amended and restated as of January 1, 2009.
	*†10	.25	—	Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated November 19, 2008, effective as of May 2, 2007.

Exhibit
No.				Description
	†10	.26	—	Apache Corporation 1995 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.27	—	Apache Corporation 2000 Share Appreciation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.28	—	Apache Corporation 1996 Performance Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.29	—	Apache Corporation 1998 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.30	—	Apache Corporation 2000 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.31	—	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.32	—	Apache Corporation 2005 Stock Option Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2008, Commission File No. 001-4300).
	†10	.33	—	Apache Corporation 2005 Share Appreciation Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, Commission File No. 001-4300).
	†10	.34	—	Apache Corporation 2008 Share Appreciation Program Specifications, pursuant to Apache Corporation 2007 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).
	*†10	.35	—	Apache Corporation Income Continuance Plan, as amended and restated November 20, 2008, effective as of January 1, 2005.
	*†10	.36	—	Apache Corporation Deferred Delivery Plan, as amended and restated November 19, 2008, effective as of January 1, 2009, except as otherwise specified.
	*†10	.37	—	Apache Corporation Executive Restricted Stock Plan, as amended and restated November 19, 2008.
	*†10	.38	—	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated November 20, 2008, effective as of January 1, 2009.
	*†10	.39	—	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated November 20, 2008, effective as of January 1, 2009.
	†10	.40	—	Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 8, 2007 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007, SEC File No. 001-4300).
	†10	.41	—	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, dated August 14, 2008, pursuant to Apache Corporation 2007 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.9 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).
	†10	.42	—	Restated Employment and Consulting Agreement, dated January 15, 2009, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated January 15, 2009, filed January 16, 2009, SEC File No. 001-4300).
	†10	.43	—	Amended and Restated Employment Agreement, dated December 20, 1990, between Registrant and John A. Kocur (incorporated by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1990, SEC File No. 001-4300).
	*†10	.44	—	Employment Agreement between Registrant and G. Steven Farris, dated June 6, 1988, and First Amendment, dated November 20, 2008, effective as of January 1, 2005.

Exhibit
No.				Description
	†10	.45	—	Amended and Restated Conditional Stock Grant Agreement, dated September 15, 2005, effective January 1, 2005, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.06 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.46	—	Restricted Stock Unit Award Agreement, dated May 8, 2008, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008, SEC File No. 001-4300).
	†10	.47	—	Form of Restricted Stock Unit Award Agreement, dated February 12, 2009, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).
	10	.48	—	Amended and Restated Gas Purchase Agreement, effective July 1, 1998, by and among Registrant and MW Petroleum Corporation, as seller, and Producers Energy Marketing, LLC, as buyer (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated June 18, 1998, filed June 23, 1998, SEC File No. 001-4300).
	10	.49	—	Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
	*12	.1	—	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.
	14	.1	—	Code of Business Conduct (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	*21	.1	—	Subsidiaries of Registrant
	*23	.1	—	Consent of Ernst & Young LLP
	*23	.2	—	Consent of Ryder Scott Company L.P., Petroleum Consultants
	*24	.1	—	Power of Attorney (included as a part of the signature pages to this report).
	*31	.1	—	Certification of Principal Executive Officer
	*31	.2	—	Certification of Principal Financial Officer
	*32	.1	—	Certification of Principal Executive Officer and Principal Financial Officer

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

NOTE:  Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.

(b) See (a) 3. above.

(c) See (a) 2. above.