Edgar Filing: APACHE CORP

e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
[X]		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005,
OR

[ ]		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

A Delaware Corporation IRS Employer No. 41-0747868

One Post Oak Central

2000 Post Oak Boulevard, Suite 100

Houston, Texas 77056-4400

Telephone Number (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 NASDAQ National Market
Preferred Stock Purchase Rights		New York Stock Exchange Chicago Stock Exchange
Apache Finance Canada Corporation 7.75% Notes Due 2029 Irrevocably and Unconditionally Guaranteed by Apache Corporation		New York Stock Exchange

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 of 1933. Yes [X] No [ ]

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 [ ] No [X]

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

Indicate by check mark 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. [ ]

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

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ]

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


Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2005	$	21,243,517,363
Number of shares of registrant’s common stock outstanding as of February 28, 2006		330,307,585

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of registrant’s proxy statement relating to registrant’s 2006 annual meeting of stockholders have been incorporated by reference into Part III hereof.

TABLE OF CONTENTS

DESCRIPTION


Item		Page

PART I

1.	BUSINESS		1
1A.	RISK FACTORS		13
1B.	UNRESOLVED STAFF COMMENTS		17
2.	PROPERTIES		1
3.	LEGAL PROCEEDINGS		17
4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		17
PART II

5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS		18
6.	SELECTED FINANCIAL DATA		19
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		19
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		48
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		51
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		51
9A.	CONTROLS AND PROCEDURES		51
9B.	OTHER INFORMATION		51
PART III

10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT		51
11.	EXECUTIVE COMPENSATION		52
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		52
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		52
14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES		52
PART IV

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K		53
Amendment to 401(k) Savings Plan
Executive Restricted Stock Plan
Computation of Ratios of Earnings to Fixed Charges
Subsidiaries of Registrant
Consent of Ernst & Young LLP
Consent of Ryder Scott Company L.P.
Certification of Chief Executive Officer
Certification of Chief Financial Officer
Certification of CEO & CFO

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Oil is quantified in terms of barrels (bbls); thousands of barrels (Mbbls) and millions of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural gas liquids are compared with natural gas in terms of million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Daily oil and gas production is expressed in terms of barrels of oil per day (b/d) and thousands or millions of cubic feet of gas per day (Mcf/d and MMcf/d, respectively) or millions of British thermal units per day (MMBtu/d). Gas sales volumes may be expressed in terms of one million British thermal units (MMBtu), which is approximately equal to one Mcf. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

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 in the North Sea (North Sea), offshore The People’s Republic of China (China), and onshore Argentina. 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 January 2004. On May 12, 2005, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our Chief Executive Officer’s certification of compliance with the NYSE standards. Through our website, http://www.apachecorp.com, you can access 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. Included in our annual and quarterly reports are the certifications of our chief executive officer and our chief financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as practicable after filing with the SEC. You may also request printed copies of our committee charters or other governance documents by writing to our corporate secretary at the address on the cover of this report.

We hold interests in many of our U.S., Canadian, and other International properties through operating subsidiaries, such as Apache Canada Ltd., DEK Energy Company (DEKALB), Apache Energy Limited (AEL), Apache International, Inc., and Apache Overseas, Inc. Properties referred to in this document may be held by those subsidiaries. We treat all operations as one line of business.

Our Growth Strategy

Apache’s strategy is built on a portfolio of assets that provide opportunities to grow through both grassroots drilling and acquisition activities. We now have six core areas — two in the United States, and in Canada, Egypt, the United Kingdom sector of the North Sea and Australia — encompassing 35 million acres. In each core area, our goal is to build critical mass that supports sustainable, lower-risk, repeatable drilling opportunities, balanced by higher-risk, higher-reward exploration. Our portfolio also is balanced in terms of gas vs. oil, geologic risk, reserve life and political risk.

Over the past five years, we have invested approximately $13.5 billion, with more than 70 percent of the total spent on exploration and development activities. During that five-year period, we have grown production by 75 percent and reserves by 95 percent. How we allocate our capital resources is reviewed quarterly, as we assess our portfolio of drilling opportunities, service costs and the market for producing assets.

When acquisition opportunities are identified, operational and technical teams participate in the evaluation process, enabling our personnel to move in quickly to execute exploitation activities (including workovers, re-completions and drilling) that will increase production and reserves, reduce costs per unit produced and enhance profitability. Over time, we build teams that have the technical knowledge and sense of urgency to maximize value. This knowledge of producing basins and our culture provide a platform for continued growth through strategic acquisitions and drilling.

More than a decade ago, we recognized that the United States is a mature oil and gas province and added an international exploration component to our portfolio strategy, which provides opportunities for larger reserve targets and a greater ability to grow production and reserves through drilling. Apache is one of the

leading acquirers of three-dimensional seismic data in the industry today. Our technology experts have developed strategies for cost-effective acquisition of 3-D seismic, enabling our technical teams to analyze the data and develop drilling prospects on an accelerated timetable.

Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems underscore high cash flow and rate-of-return targets, which are measured monthly, reviewed with senior management quarterly and utilized to determine annual performance rewards.

The effectiveness of our portfolio strategy is illustrated by 2005 financial and operational results: Record earnings, cash flow, production and year-end reserves even though Gulf of Mexico operations were curtailed significantly by two of the worst Gulf hurricanes in recorded history. Production interruptions in the Gulf were offset by growth in other regions.

In the United States, the Gulf Coast Region consistently delivers high returns on capital employed, as well as cash flow significantly in excess of our exploration and development spending. Acquisitions are part of the picture because, with steep decline rates, offshore reserves are generally short-lived and difficult to replace through drilling alone. The Central Region brings the balance of long-lived reserves and consistent drilling results in the Permian Basin of West Texas and New Mexico, the Anadarko Basin in western Oklahoma and East Texas. Apache’s future growth in the United States is more likely to be achieved in the U.S. through drilling and acquisitions, rather than through drilling activity alone.

In Canada, we have 7 million acres across British Columbia, Alberta, Saskatchewan and Northwest Territories. We have a multi-year inventory of low-risk drilling opportunities at Nevis, Hatton and on acreage acquired in the ExxonMobil farm-in agreements of 2004 and 2005. With acquisition and land costs rising in Canada, these farm-ins provide a way for Apache to earn acreage through drilling on 1,815 sections in Alberta with no upfront costs. ExxonMobil retains a carried interest in the fields. We also have opportunities to drill exploration targets with higher reserve potential in the Northwest Territories.

In Egypt’s Western Desert, Apache’s 10.7 million acres encompass a sizable resource play in the Cretaceous Upper Bahariya formations and outstanding exploration potential in deeper intervals from lower Cretaceous to Jurassic that are established producing trends. The Qasr gas/condensate field, discovered in 2003, is the largest field ever found by Apache with more than 2 trillion cubic feet of gas and 50 million barrels of estimated recoverable reserves.

In Australia, we have expanded our exploration program to the high-potential Perth, Exmouth and Gippsland basins while continuing to exploit our acreage position and control of key infrastructure in the Carnarvon Basin.

Apache entered the North Sea in 2003 with our acquisition of the Forties Field, the largest field ever discovered in the United Kingdom sector. Through drilling and extensive improvements to the production infrastructure, we virtually doubled production — and significantly reduced per-unit operating costs — from the second quarter of 2003, our first as operator, through the fourth quarter of 2005. We plan continued drilling activity at Forties as well as exploration drilling on blocks obtained in bid rounds.

We have maintained financial flexibility — at year-end, our debt-to-capitalization ratio was 17 percent — so we are in a solid position to conduct an active drilling program and, potentially, to acquire properties where we can add value and earn adequate rates of return.

Apache has increased reserves in each of the last 20 years and production in 26 of the last 27 years. We believe our portfolio of assets provides a platform for profitable growth through drilling and acquisitions across the cycles of our dynamic industry.

In 2006, we are planning another active year of drilling. We revise our capital expenditure estimates throughout the year based on industry conditions and results to date. Therefore, accurately projecting annual capital spending is difficult at best. Our preliminary estimate of 2006 capital expenditures, excluding acquisitions, is in excess of $3.7 billion. We generally do not project estimates for acquisitions because their timing is unpredictable; however, in early 2006 we closed an acquisition announced in the latter part of 2005.

Also, on January 17, 2006, the Company announced an agreement with Pioneer Natural Resources (Pioneer). Please refer to the following Subsequent Acquisitions and Divestiture section. We continually look for properties which we believe will add value and earn adequate rates of return and will take advantage of those opportunities as they arise.

Operating Highlights

We currently have interests in seven countries: the United States, Canada, Egypt, Australia, the United Kingdom, China, and Argentina. Our reportable segments are the United States, Canada, Egypt, Australia, the North Sea, and Other International. In the U.S., our exploration and production activities are divided into two regions: Gulf Coast and Central. At the end of 2005, approximately 69 percent of our estimated proved reserves were located in North America. Also, our North American regions contributed approximately 57 percent of our worldwide 2005 production.

The following table sets out a brief comparative summary of certain key 2005 data for each area. More detailed information regarding oil, natural gas and natural gas liquids (NGLs) production and the average sales price received in each geographic area for 2005, 2004, and 2003 is available later in this section under “Production, Pricing and Lease Operating Cost Data”. Also, further discussion and analysis of this data is available in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. For information concerning the revenues, expenses, operating income (loss) and total assets attributable to each of our reportable segments, see Note 14, Supplemental Oil and Gas Disclosures (Unaudited), and Note 13, Business Segment Information of Item 15 in this Form 10-K. For information regarding Oil and Gas Capital Expenditures for each of the last three years, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity” in this Form 10-K.


									12/31/05		Percentage					2005
				Percentage			2005		Estimated		of Total			2005		Gross New
		2005		of Total			Production		Proved		Estimated			Gross New		Productive
		Production		2005			Revenue		Reserves		Proved			Wells		Wells
		(In MMboe)		Production			(In millions)		(In MMboe)		Reserves			Drilled		Drilled

Region/Country:

Gulf Coast			39.9		14.1	%	$	1,812		387.0		18.3	%		114		88
Central			23.4		24.0	%		1,012		502.2		23.7	%		364		352

	Total U.S.		63.3		38.1	%		2,824		889.2		42.0	%		478		440

Canada			31.7		19.1	%		1,451		564.6		26.7	%		1,674		1,551

	Total North America		95.0		57.2	%		4,275		1,453.8		68.7	%		2,152		1,991

Egypt			30.2		18.2	%		1,358		271.0		12.8	%		121		104
Australia			13.1		7.9	%		401		188.8		8.9	%		36		16
North Sea			24.0		14.5	%		1,275		196.5		9.3	%		23		15
China			3.0		1.8	%		131		5.0		.2	%		16		15
Argentina			.6		.4	%		17		2.1		.1	%		35		31

	Total International		70.9		42.8	%		3,182		663.4		31.3	%		231		181

	Total		165.9		100.0	%	$	7,457		2,117.2		100.0	%		2,383		2,172

The following discussions include references to our plans for 2006. These only represent initial estimates and could vary significantly from actual results. In recent years, there have been large differences between our capital expenditure forecasts and our actual activity. During the year, we routinely adjust our level of spending based on success and changing industry conditions.

United States

Gulf Coast — The Gulf Coast region comprises our interests in and along the Gulf of Mexico, primarily in the areas on- and offshore Louisiana and Texas. Apache is the largest acreage holder and the second largest producer in Gulf waters less than 1,200 feet deep. In both 2005 and 2004, the Gulf Coast was our leading region for both production volumes and revenues. This region performed 325 workover and recompletion operations during 2005 and completed 88 out of 114 total wells drilled. As of year-end 2005, the Gulf Coast region accounted for 18.3 percent of our estimated proved reserves. Although actual annual capital expenditures may change considerably in 2006, we currently estimate spending approximately $900 million to drill over 100 wells and to continue our production enhancement and exploitation programs. Our 2006 capital estimate does not include an estimated $340 million of 2006 expenditures for repair, redevelopment, and plugging and abandonment work required to repair damage caused by Hurricanes Katrina and Rita, a portion of which will be covered by insurance.

Central — The Central Region includes assets in the Permian Basin of West Texas and New Mexico, East Texas, and the Anadarko Basin of western Oklahoma, where the Company got its start over 50 years ago. As of year-end 2005, the Central region accounted for approximately 23.7 percent of our estimated proved reserves, the second largest in the Company. During 2005, we participated in 364 wells, 352 of which were completed as productive. Apache performed 861 workovers and recompletions in the region during the year. Although actual annual capital expenditures may change considerably in 2006, we currently estimate spending approximately $400 million, including $300 million to drill nearly 400 wells and to continue our production enhancement programs.

Marketing — The Company began directly marketing its own U.S. natural gas production in July 2003. Our primary objective is to increase the value we receive for our production through diversification of our customer base, optimization of our processing and transportation agreements, and real-time management of our sales process. The flexibility to transport our gas from the wellhead has provided us access to new markets as our customers now include Local Distribution Companies (LDCs), utilities, end-users, integrated majors and marketers. We manage the sales risk associated with our natural gas production fluctuations by selling a portion of our production into the daily market. We manage our credit risk by selling to creditworthy customers, monitoring our credit exposure daily and making adjustments as needed. [Prior to July 2003, Apache sold most of its U.S. natural gas production to Cinergy Marketing and Trading, LLC (Cinergy) under a long-term gas purchase agreement at prices based on a published index. See Note 12, Transactions with Related Parties and Major Customers of Item 15 in this Form 10-K.]

In general, most of our gas is being sold on a monthly basis at either monthly or daily market prices. In an effort to increase our sales to direct users of natural gas and meet the needs of our customers, we also periodically sell some of our gas under long-term contracts at prices that fluctuate with market conditions. Our relationships with LDCs and direct users of natural gas continue to be an important focus of our marketing efforts. Several years ago, we locked in fixed prices on a portion of our U.S. future natural gas production using long-term, fixed-price physical contracts. These contracts, which represented approximately 10 percent of our 2005 U.S. natural gas production, will expire in 2006 through 2008. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk “Commodity Risk” in this Form 10-K.

We market our own U.S. crude oil to integrated majors, marketers and refiners. Contracts are generally 30 days and renew automatically until canceled. These oil contracts generally provide for sales at prices that change with daily market conditions.

Canada

Overview — Our exploration and development activity in the Canadian region is concentrated in the Provinces of Alberta, British Columbia, Saskatchewan and the Northwest Territories. The region comprises 26.7 percent of our estimated proved reserves, the largest in the Company. We hold over 4.8 million net acres in Canada, the largest of the North American regions. Canada was our most active drilling area in 2005, with Apache participating in 1,674 gross wells, over 80 percent of which were shallow development wells. We completed 1,551 as producers and conducted 971 workover and recompletion projects.

Apache is targeting fields such as Provost and Nevis for coalbed methane (CBM) and in the process has emerged as the nation’s largest producer of CBM. The North and South Grant Lands obtained through ExxonMobil Corporation (ExxonMobil) farm-in agreements (discussed below) provide additional CBM potential. Although actual annual capital expenditures may change considerably with industry conditions and results, we currently estimate spending approximately $1 billion in 2006 to drill around 860 wells, continue our exploration and exploitation program and develop our gas processing infrastructure.

On May 5, 2005, Apache signed a farm-in agreement with ExxonMobil covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in a 2004 farm-in agreement with ExxonMobil. The 2004 farm-in agreement covered approximately 380,000 acres and stipulated drilling at least 250 wells over a two-year period beginning in October of 2004. Through the end of 2005, Apache drilled 457 wells on the 2004 farm-in acreage, earning 207 additional acreage sections.

Marketing — Our Canadian natural gas sales include sales to LDCs, utilities, end-users, integrated majors, supply aggregators and marketers in the United States and Canada. With the expansion of pipeline transport capacity out of Canada in recent years, Canadian prices have become more closely correlated with United States 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 currently have a limited number of longer term commitments to sell gas, but the volumes are relatively small and none of the terms extend beyond 2011. The prices we receive under these contracts fluctuate monthly with market indices. The remainder, which represents over 95 percent of our Canadian natural gas production, is sold on a monthly basis at either monthly or daily market prices.

Our Canadian crude oil is primarily sold to refiners, integrated majors and marketers. To increase the market value of our condensate and heavier crudes, our condensate is either used or sold for blending purposes. We sell our crude oil and NGLs on Canadian 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 on 12 pipelines to the major trading hubs within Alberta, Saskatchewan and Manitoba.

Egypt

Overview — In Egypt, our operations are generally conducted pursuant to production sharing contracts under which the contractor 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 to recover operating and capital expenditure costs. In general, the balance of the production is allocated between the contractor and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Apache is the largest acreage holder and the most active driller in the Western Desert of Egypt. Egypt is the country with our largest single acreage position where, as of December 31, 2005, we held over 7.5 million net acres in 18 separate concessions, including five new concessions and four exploration period extensions on existing concessions that received parliamentary approval in 2005. Development leases within concessions generally have a 25-year life with extensions possible for additional commercial discoveries, or on a negotiated basis. Apache is the largest producer of liquid hydrocarbons and natural gas in the Western Desert. Egypt contributed approximately 18 percent of both Apache’s production revenues and total production. Egypt accounted for 12.8 percent of total estimated proved reserves at December 31, 2005. Apache had an active drilling program in Egypt, completing 104 of 121 gross wells, an 86 percent success rate. Although actual annual capital expenditures may change considerably with industry conditions and success, we currently plan to spend approximately $700 million in 2006 drilling around 130 exploration, development and appraisal wells and installing and upgrading production facilities.

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 announced this transaction on October 13, 2005, and did not have any oil and gas reserves recorded for these properties as of year-end 2005.

Please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Critical Accounting Policies and Estimates, Allowance for Doubtful Accounts” in this Form 10-K for a discussion of our Egyptian receivables.

Marketing — Historically, we and our partners have sold our natural gas production to EGPC pursuant to 25-year take-or-pay contracts. Pricing under these contracts was originally based on the energy equivalent of 85 percent of Gulf of Suez Blend crude oil. Beginning in 2000, EGPC introduced an alternative natural gas pricing formula for certain quantities of gas they purchase. This Industry Pricing Formula is 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 upon reaching a Dated-Brent price of $21.00 per barrel. Generally, the Industry Pricing Formula applied to all new gas discovered and produced, however, in exchange for extension of the Khalda Concession lease in July 2004, Apache preserved the old Gulf of Suez Blend gas price formula until 2013 for up to 100 MMcf/d produced from the South Umbarka Concession and the Khalda, Khalda West, Salam and Tarek development leases and agreed to accept the Industry Pricing on all production in excess of that amount.

In Egypt, oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is either sold directly into the Egyptian oil pipeline grid or exported. Oil production that is presently sold to EGPC is sold on a spot basis at a “Western Desert” price (indexed to Brent Crude Oil). In 2005, we exported 21 cargoes (approximately 6.7 million barrels) of Western Desert crude oil from the El Hamra and Sidi Kerir terminals. These export cargoes were sold at market prices comparable to domestic sales to EGPC. Additionally, 10 cargoes representing 2.1 million barrels were sold in Egypt to other non-governmental purchasers. Additional export sales from both the Khalda and Qarun areas in the Western Desert have continued in 2006.

Australia

Overview — Our exploration activity in Australia is focused in the offshore Carnarvon, Gippsland, Browse, and Perth Basins where Apache holds 6.4 million net acres in 35 Exploration Permits, 10 Production Licenses, and six Retention Leases. Production operations are concentrated in the Carnarvon Basin which is the location of all 10 Production Licenses, nine of which are operated by Apache. In 2005, the region generated $401 million of production revenues producing 13.1 MMboe (7.9 percent of our total production) and accounted for 8.9 percent of our year-end estimated proved reserves. During the year we participated in drilling 36 wells; 26 exploration and 10 development wells. Eight of the exploration wells and eight of the development wells were productive for an overall 44 percent success rate.

Australian region 2005 exploration successes included the Albert, Artreus, and Mohave Flag Sandstone oil discoveries, the Kultarr gas discovery, and appraisal successes in the Legendre oil field and the John Brookes gas field. The three Flag discoveries were drilled from existing infrastructure within the Harriet Joint Venture acreage and as a result were able to be completed and placed on production in 2005. Additionally, three new developments commenced production in 2005, the Rose gas field in June, the John Brookes gas field in September, and the Bambra oil and gas field in October. Apache owns a 68.5 percent working and revenue interest in Rose and Bambra, both of which are located within the Harriet Joint Venture acreage, and a 55.0 percent working and revenue interest in John Brookes.

During 2006, the Australian region plans to expand the Bambra oil and gas development by drilling two additional production wells, and increase Stag’s water injection capacity through the addition of a western Stag-29H subsea injection well. Additionally, the region plans to further appraise the recently developed John Brookes gas field, as well as the Reindeer gas field and Vincent oil field. Key factors for success in 2006 will be maintaining oil production, increasing gas production to fulfill the requirements of six new gas contracts commencing in 2006, covering the significant increase in sales to Burrup Fertilisers and continuing success in our exploration program. Although actual annual capital expenditures may change considerably with industry

conditions and success, we currently estimate spending approximately $300 million in 2006 for around 50 exploration, appraisal and development wells, and various new facilities and facility upgrades.

Marketing — In Australia during 2005, we executed six new gas sales contracts, agreed to terms for three more sales by letter agreement, and increased our reserve commitment in two active contracts. In aggregate, we committed an additional 403 Bcf of gas (gross) for delivery. Under the two largest contracts, we will supply 357 Bcf of gas (gross) over a 16-year period commencing July 2006. As of December 31, 2005, Apache had a total of 31 active gas contracts with expiration dates ranging from June 2006 to July 2030.

Apache expects a significant increase in natural gas sales during 2006 compared to 2005 with Burrup Fertilisers scheduled to begin taking its full daily contractual volume of 48.2 MMcf of gas per day (net to Apache) and initiation of deliveries into the six new gas contracts previously discussed. Five of the six new contracts will be supplied solely by Apache, including a full year of sales into two of the contracts. 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. Apache realized an average price of US$1.72 per Mcf for gas sold in Australia during 2005.

We continue to export all of our crude oil production into the international market at prices which fluctuate with world market conditions.

North Sea

Overview — In 2003, we established a new core area in the North Sea with our acquisition of the Forties Field. First discovered in 1970, Forties has been one of the most productive fields in the North Sea. In 2005, the region generated $1.3 billion of oil revenue on 24 MMboe of production up 23 percent from 2004 and over 50 percent above the production level when Apache purchased the field. During 2005, the North Sea’s oil revenues and daily oil production were the highest in the Company. The Company spent $489 million in the North Sea, including $198 million on facility upgrades to improve the operating efficiency of the platforms. We drilled 23 exploration and development wells during 2005 with a 65 percent success rate, adding 45.2 MMboe of reserves. At year-end 2005, the Forties field alone accounted for 9.3 percent of the Company’s total estimated proved reserves.

Although actual annual capital expenditures may change considerably with industry conditions and success, we currently estimate spending approximately $400 million in 2006 of which around 80 percent will be spent on the continuation of the Forties drilling program (14 wells) and facility upgrades to increase the operating efficiency of the platforms. A new 3-D seismic survey across Forties completed in 2005 and now being processed will yield a new 4-D “snapshot” of Forties field and identify additional drilling targets for the future. The facility upgrades include new power generation infrastructure, new pipeline export pumps, new cranes, new automated control systems and increased water injection capacity. These upgrades will deliver additional oil volumes and reduce lifting costs in 2006 and beyond.

Approximately 20 percent of our 2006 estimated capital expenditures in the North Sea is projected to be spent on expanding business beyond the Forties area. Apache acquired 14 new blocks in the 2004 UK license bid round and an additional 22 North Sea blocks in the 2005 UK license bid round. In addition, Apache “farmed-in” to four prospects during 2005 with successful discoveries on three of those prospects that earned the Company ownership interests in an additional five North Sea blocks. Additional appraisal work is planned to determine the potential commerciality of those three discoveries. In 2006, we have a semi-submersible drilling rig under contract for the second half of the year and plan to drill five wells outside of Forties to evaluate the potential of a significant portion of the new acreage additions.

Marketing — Concurrent with the acquisition of the North Sea properties, the Company entered into a separate two year crude oil physical sales contract with BP PLC for 100 percent of our equity production. A portion of the crude oil (25,000 b/d through January 31, 2004 and 40,000 b/d for the remainder of the term) was sold at fixed prices while the remaining balance of crude oil was sold at prevailing market prices. This contract expired on December 31, 2004. For 2005, the Company entered into two new term contracts for the physical sale of our crude oil at prevailing market prices, which are composed of base market indices, adjusted for the higher quality of Forties crude relative to Brent and a premium to reflect the higher market value for term arrangements.

Other International

Argentina. In 2001, we acquired limited exploration and production assets from Fletcher Challenge and Anadarko Petroleum Corporation (Anadarko) in Argentina. As a result of these transactions, we hold interests in a small number of blocks in Argentina’s Neuquen Basin. We are the operator with a 100 percent interest in two blocks and hold smaller interests in three non-operated blocks. For 2005, these interests represented less than one percent of our estimated proved reserves and generated $17 million of production revenue. All of our production is currently sold under term arrangements into the domestic market under prevailing market prices which are subject to regulatory caps. Our December 31, 2005 net acreage position in Argentina was 304,801 developed acres.

As discussed below, in January 2006, we announced plans to increase greatly our holdings in Argentina by agreeing to buy Pioneer’s Argentina operations. The Pioneer transaction is expected to close in late March 2006. Our 2006 capital budget, which includes activity on the Pioneer properties, is approximately $100 million and includes $68 million to drill 107 wells.

China. In August 2003, first production came on stream from our interests in the Zhao Dong block in Bohai Bay, China, where we are currently the operator, with a 24.5 percent interest, pursuant to a production sharing contract through 2023. Since production began, our portion of the production was exported for sale to international markets outside of China at prevailing market prices. For the period from March 1, 2005 to December 31, 2005, we sold our equity crude oil into the domestic Chinese market pursuant to a term contract based upon international market prices for oil imported into China. In 2005, our Chinese interests produced $131 million of production revenue from 3 MMbbls of production. Although actual capital expenditures may change considerably with industry conditions and success, we currently estimate spending approximately $21 million on 12 new wells, recompletions and facility upgrades during 2006.

Subsequent Acquisitions and Divestiture

Amerada Hess

On January 5, 2006, the Company completed its purchase of Amerada Hess’s interest in eight fields located in the Permian Basin of West Texas and New Mexico for $269 million. Apache estimates that these fields had proved reserves of 27 million barrels of liquid hydrocarbons and 27 billion cubic feet of natural gas as of year-end 2005. The Company had previously announced on October 13, 2005 that it had agreed to purchase Amerada Hess’s interest for $404 million. The price and number of properties involved in this transaction were reduced as a result of third parties exercising their preferential rights.

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 announced this transaction on October 13, 2005 and did not have any oil and gas reserves recorded for these properties as of year-end 2005.

Pioneer Natural Resources

On January 17, 2006, we announced plans to increase greatly our holdings in Argentina by agreeing to buy Pioneer’s Argentina operations. The transaction includes interest in 36 separate blocks on approximately 1.8 million gross acres located in the Neuquen, Austral and San Jorge Basins. On January 1, 2006, the properties were producing approximately 9,000 barrels of liquids and 120 MMcf of natural gas per day. The Pioneer transaction is expected to close in late March 2006.

Drilling Statistics

Worldwide, in 2005, we participated in drilling 2,383 gross wells, with 2,172 (91 percent) completed as producers. We also performed over 2,157 workovers and recompletions during the year. Historically, our drilling activities in the U.S. generally concentrate 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. (63.6 net); 40 in Canada (36 net); 13 in Egypt (13 net); one in Australia (0.7 net); and one in the North Sea (one net).

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


		Net Exploratory						Net Development						Total Net Wells

		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total

2005

United States			5		3.1		8.1		248.8		24.1		272.9		253.8		27.2		281.0
Canada			273.4		107.6		381.0		1,057.0		—		1,057.0		1,330.4		107.6		1,438.0
Egypt			17.8		6.9		24.7		79.4		7.1		86.5		97.2		14.0		111.2
Australia			.7		6.8		7.5		11.8		4.8		16.6		12.5		11.6		24.1
North Sea			—		7.8		7.8		12.6		1.9		14.5		12.6		9.7		22.3
China			—		—		—		3.7		.2		3.9		3.7		.2		3.9
Argentina			6.3		3.0		9.3		15.6		1.0		16.6		21.9		4.0		25.9

	Total		303.2		135.2		438.4		1,428.9		39.1		1,468.0		1,732.1		174.3		1,906.4


2004

United States			3.3		3.5		6.8		202.8		24.2		227.0		206.1		27.7		233.8
Canada			6.7		9.3		16.0		1,102.3		84.2		1,186.5		1,109.0		93.5		1,202.5
Egypt			9.5		6.5		16.0		91.5		4.5		96.0		101.0		11.0		112.0
Australia			4.0		7.5		11.5		3.4		1.2		4.6		7.4		8.7		16.1
North Sea			—		1.0		1.0		11.7		3.9		15.6		11.7		4.9		16.6
China			—		—		—		3.7		.3		4.0		3.7		.3		4.0
Argentina			—		—		—		1.2		—		1.2		1.2		—		1.2

	Total		23.5		27.8		51.3		1,416.6		118.3		1,534.9		1,440.1		146.1		1,586.2


2003

United States			2.2		—		2.2		133.6		18.3		151.9		135.8		18.3		154.1
Canada			57.3		25.3		82.6		742.8		34.8		777.6		800.1		60.1		860.2
Egypt			15.5		5.2		20.7		76.2		6.0		82.2		91.7		11.2		102.9
Australia			8.4		10.8		19.2		2.3		—		2.3		10.7		10.8		21.5
North Sea			—		—		—		—		—		—		—		—		—
China			—		—		—		6.1		—		6.1		6.1		—		6.1
Other International			—		.6		.6		.3		—		.3		.3		.6		.9

	Total		83.4		41.9		125.3		961.3		59.1		1,020.4		1,044.7		101.0		1,145.7

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, 2005, is set forth below:


		Gas				Oil				Total

		Gross		Net		Gross		Net		Gross		Net

Gulf Coast			906		684		719		515		1,625		1,199
Central			2,734		1,378		5,106		3,009		7,840		4,387
Canada			7,241		6,291		2,413		961		9,654		7,252
Egypt			30		29		343		325		373		354
Australia			8		5		40		22		48		27
North Sea			—		—		62		60		62		60
China			—		—		24		6		24		6
Argentina			20		7		68		44		88		51

	Total		10,939		8,394		8,775		4,942		19,714		13,336

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 costs (including severance and other taxes) and average sales prices for each of the countries where we have operations.


		Production						Average		Average Sales Price
								Lease
		Oil		NGLs		Gas		Operating		Oil		NGLs		Gas
Year Ended December 31,		(Mbbls)		(Mbbls)		(MMcf)		Cost per Boe		(Per bbl)		(Per bbl)		(Per Mcf)

2005
United States			24,188		2,757		218,081	$	9.11	$	47.97	$	32.44	$	7.22
Canada			8,212		816		135,750		7.54		53.05		31.07		7.29
Egypt			20,126		—		60,484		3.85		53.69		—		4.59
Australia			5,613		—		45,003		7.17		57.61		—		1.72
North Sea			23,903		—		842		17.94		53.00		—		9.17
China			2,968		—		—		3.79		44.24		—		—
Argentina			424		—		1,137		6.54		37.54		—		1.14

	Total		85,434		3,573		461,297	$	8.87	$	51.66	$	32.13	$	6.35

2004
United States			24,841		3,026		236,663	$	6.53	$	38.75	$	26.66	$	5.45
Canada			9,262		947		119,669		6.49		38.57		24.44		5.30
Egypt			19,099		—		50,412		3.37		37.35		—		4.35
Australia			9,214		—		43,227		7.11		41.96		—		1.65
North Sea			19,338		—		684		4.22		24.22		—		5.53
China			2,775		—		—		3.89		32.88		—		—
Argentina			207		—		1,394		6.46		32.89		—		.65

	Total		84,736		3,973		452,049	$	5.73	$	35.24	$	26.13	$	4.91

2003
United States			25,332		2,766		242,782	$	5.14	$	27.48	$	21.70	$	5.22
Canada			9,205		571		116,263		5.41		29.06		19.25		4.69
Egypt			17,356		—		41,447		3.40		27.64		—		4.18
Australia			11,165		—		40,537		4.05		29.87		—		1.44
North Sea			10,680		—		626		11.94		25.40		—		2.77
China			1,019		—		—		5.18		26.33		—		—
Argentina			211		—		2,607		5.76		29.23		—		.47

	Total		74,968		3,337		444,262	$	5.27	$	27.76	$	21.28	$	4.61

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		Net		Gross		Net
		Acres		Acres		Acres		Acres

United States			1,551,097		950,008		2,953,641		1,756,869
Canada			4,107,595		2,913,825		2,885,456		2,116,981
Egypt			8,727,094		5,974,883		1,941,454		1,565,154
North Sea			653,785		486,368		29,924		29,068
Australia			10,376,130		6,115,900		527,450		307,290
China			840		206		5,911		1,448
Argentina			—		—		445,782		304,801

	Total Company		25,416,541		16,441,190		8,789,618		6,081,611

The “Other International” drilling statistics on the preceding page include activity in Poland. Apache ceased operations in Poland in 2003 and the remaining acreage was fully relinquished in early 2005.

Estimated Proved Reserves and Future Net Cash Flows

As of December 31, 2005, Apache had total estimated proved reserves of 976 MMbbls of crude oil, condensate and NGLs and 6.8 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 2.1 billion barrels of oil or 12.7 Tcf of natural gas. The Company’s estimated proved reserves grew for the 20th consecutive year.

The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2005, 2004, and 2003, 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 14, Supplemental Oil and Gas Disclosures (Unaudited) 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.

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. Reserve estimates are considered proved if economical producibility 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 who are 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.

We engage Ryder Scott Company, L.P. Petroleum Consultants as independent petroleum engineers to review our estimates of proved hydrocarbon liquid and gas reserves and provide an opinion letter on the reasonableness of Apache’s internal projections. During this review, they prepare independent projections for each reviewed property and determine if the Company’s estimates are within engineering tolerance by geographical area. The independent reviews typically cover a large percentage of major value fields, international properties and new wells drilled during the year. During 2005, 2004, and 2003, their review covered 74, 79 and 78 percent of Apache’s estimated reserve value, respectively.

Employees

On December 31, 2005, we had 2,806 employees. None of our employees is subject to collective bargaining agreements.

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 2005, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; Beijing, China; 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 information appearing in the table in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity, Contractual Obligations” and Note 10, Commitments and Contingencies, “Other Commitments and Contingencies, Contractual Obligations” of Item 15 in this Form 10-K.

Title to Interests

As is customary in our industry, a preliminary review of title records is made at the time we acquire properties, which may include opinions or reports of appropriate professionals or counsel. 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 which 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 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. Historically, these prices have been very volatile. A significant 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.

Our Commodity Hedging May Prevent Us From Benefiting Fully From Price Increases and May Expose Us to Other Risks

To the extent that we engage in hedging activities to protect ourselves from commodity price volatility, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

Acquisitions or Discoveries of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production

The rate of production from oil and gas properties generally declines as reserves are depleted. Except to the extent that we acquire additional properties containing estimated proved reserves, conduct successful

exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery 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.

Our Drilling Activities May Not Be Productive

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. 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

	•	shortages or delays in the delivery of equipment.

Certain 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.

Risks Arising From the Failure to Fully Identify Potential Problems Related to Acquired Reserves or to Properly Estimate Those Reserves

One of our primary growth strategies is the acquisition of oil and gas properties. Although we perform a review of the acquired properties that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual 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 a buyer to become sufficiently familiar with the properties to assess fully 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 actual 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.

We Are Subject to Domestic Governmental Risks That May Impact Our Operations

Our domestic operations have been, and at times in the future may be, affected by political developments and by federal, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price controls and environmental protection laws and regulations.

Global Political and Economic Developments May Impact Our Operations

Political and economic factors in international markets may have a material adverse effect on our operations. On an equivalent-barrel basis, approximately 62 percent of our oil, NGLs and natural gas production in 2005 was outside the United States, and approximately 58 percent of our estimated proved oil and gas reserves on December 31, 2005 were located outside of the United States.

There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, NGLs, and natural gas pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. These risks include: political and economic instability or war; the possibility that a foreign government may seize our property with or without compensation; confiscatory taxation; legal proceedings and claims arising from our foreign investments or operations; a foreign government attempting to renegotiate or revoke existing contractual arrangements, or failing to extend or renew such arrangements; fluctuating currency values and currency controls; and constrained natural gas markets dependent on demand in a single or limited geographical area.

On December 23, 2004, Apache entered into a 20-year insurance contract with the Overseas Private Investment Corporation (OPIC) which provides $300 million of political risk insurance for the Company’s Egyptian operations. This policy insures us against (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the Government of Egypt prevent Apache from exporting our share of production. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates, Allowance for Doubtful Accounts” in this Form 10-K for additional discussion of our Egyptian receivables.

Actions of the United States government through tax and other legislation, executive order and commercial restrictions can adversely affect our operating profitability in the U.S. as well as other countries. Various agencies of the United States and other governments have, from time to time, imposed restrictions which have limited our ability to gain attractive opportunities or even operate in various countries. These restrictions have in the past limited our foreign opportunities and may continue to do so in the future.

Weather and Climate May Have a Significant Impact on Our Revenues and Productivity

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impacts 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, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.

Costs Incurred Related to Environmental Matters

We, as an owner or lessee and operator of oil and gas properties, 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.

We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We also have established operational procedures and training programs designed to minimize the environmental impact of our field facilities. The costs incurred by these policies and procedures are inextricably connected to normal operating expenses such that we are unable

to separate the expenses related to environmental matters; however, we do not believe any such additional expenses are material to our financial position or results of operations.

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, its 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 our employees who are expected to devote a significant amount of time to any possible remediation effort. Our general policy is to limit any reserve additions to incidents or sites that are considered probable to result in an expected remediation cost exceeding $100,000. In October 2003, Apache was issued a Findings of Violation and Order for Compliance (an “Administrative Order”) by the United States Environmental Protection Agency (EPA), which cited certain paperwork administrative errors and effluent violations reported by Apache during the period May 1, 1998 to June 30, 2003, as part of our offshore discharge permit monitoring. Apache signed a Consent Agreement and Final Order (CAFO) to pay a monetary penalty of $21,000 and undertake a Supplemental Environmental Project (SEP) with an estimated cost of $94,500. The SEP Project was completed and certified on June 5, 2005, at which time we paid the amount of the penalty.

We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. As described in Note 10, Commitments and Contingencies of Item 15, in this Form 10-K, on December 31, 2005, we had an accrued liability of $11.8 million for environmental remediation. We have not incurred any material environmental remediation costs in any of the periods presented and we are not aware of any future environmental remediation matters that would be material to our financial position or results of operations.

Although environmental requirements have a substantial impact upon the energy industry, generally these requirements do not appear to affect us any differently, or to any greater or lesser extent, than other upstream companies in the industry. We do not believe that compliance with federal, provincial, state, local or foreign country provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of Apache or its subsidiaries; however, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact.

Industry Competition

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 reserves, equipment and labor required to explore, develop and operate those properties and the marketing of oil and natural gas production. Higher recent crude oil and natural gas prices have increased the costs of properties available for acquisition and there are a greater number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than those 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 changing worldwide 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.

Insurance Does 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. We maintain

insurance against certain losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance is not available to us against all operational risks.

In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage and substantially increased premium rates. As a result, there is no assurance that Apache will be able to arrange insurance to cover fully its Gulf of Mexico exposures at a reasonable cost when the current policies expire.

Investors In Our Securities May Encounter Difficulties in Obtaining, Or May Be Unable To Obtain, Recoveries From Arthur Andersen With Respect To Its Audits Of Our Financial Statements

On March 14, 2002, our previous independent public accountant, Arthur Andersen LLP (Arthur Andersen), was indicted on federal obstruction of justice charges arising from the federal government’s investigation of Enron Corp. On June 15, 2002, a jury returned with a guilty verdict against Arthur Andersen following a trial, though the conviction was later overturned by the United States Supreme Court. As a public company, we are required to file with the SEC periodic financial statements audited or reviewed by an independent public accountant. On March 29, 2002, we decided not to engage Arthur Andersen as our independent auditors, and engaged Ernst & Young LLP (Ernst & Young) to serve as our new independent auditors for 2002. Ernst & Young have served as our independent public accountants since that time. However, included in this annual report on Form 10-K are financial data and other information for 2001 that were audited by Arthur Andersen. Investors in our securities may encounter difficulties in obtaining, or be unable to obtain, from Arthur Andersen with respect to its audits of our financial statements, relief that may be available to investors under the federal securities laws against auditing firms.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

We had no comments from the staff of the SEC that were unresolved as of the date of filing of this report.


ITEM 3.	LEGAL PROCEEDINGS

See the information set forth in Note 10, Commitments and Contingencies of Item 15 and Item 1A, Risk Factors, “Costs Incurred Related to Environmental Matters” in this Form 10-K.


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.

PART II


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

During 2005, 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 2005 and 2004. 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.


	2005								2004

					Dividends Per								Dividends Per
	Price Range				Share				Price Range				Share

	High		Low		Declared		Paid		High		Low		Declared		Paid

First Quarter	$	65.90	$	47.45	$	.08	$	.08	$	43.49	$	36.79	$	.06	$	.06
Second Quarter		67.99		51.52		.08		.08		45.99		38.53		.06		.06
Third Quarter		78.60		64.85		.10		.08		51.00		42.45		.08		.06
Fourth Quarter		75.95		59.36		.10		.10		55.16		47.77		.08		.08

The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for February 28, 2006 , was $66.92. On February 28, 2006, there were 330,307,585 shares of our common stock outstanding held by approximately 7,500 shareholders of record and approximately 219,000 beneficial owners.

We have paid cash dividends on our common stock for 41 consecutive years through December 31, 2005. 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 and, the rights trade automatically with our shares of common stock. For a description of the rights, please refer to Note 8, Capital Stock of Item 15 in this Form 10-K.

In 2002, our board of directors declared a five percent dividend on our shares of common stock payable in common stock on April 2, 2003 to shareholders of record on March 12, 2003. Pursuant to the terms of the declared five percent stock dividend, we issued 15,736,496 shares (adjusted for the 2003 stock split) of our common stock on April 2, 2003 to the holders of the 307,819,628 shares of common stock outstanding on March 12, 2003. No fractional shares were issued in connection with the stock dividend and we made cash payments totaling approximately $1,437,000 in lieu of fractional shares.

In 2003, in conjunction with the acquisition from BP, the Company completed the public offering of 19.8 million shares (adjusted for the stock split) of Apache common stock, including 2.6 million shares (adjusted for the stock split) for the underwriters’ over-allotment option, at $29.05 per share. Net proceeds after placement fees totaled approximately $554 million. The proceeds were used to repay indebtedness under our commercial paper program and money market lines of credit and to invest in short-term treasury-only money market funds and treasury notes to hold funds for the $1.3 billion acquisition from BP.

In 2003, our board of directors declared a two-for-one common stock split which was distributed on January 14, 2004 to holders of record on December 31, 2003. In connection with the stock split, the Company issued 166,254,667 shares.

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 2006 annual meeting of stockholders, which is incorporated herein by reference.


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, 2005, which information has been derived from the Company’s audited financial statements. Our financial statements for the year 2001 were audited by Arthur Andersen. For a discussion of the risks relating to Arthur Andersen’s audit of our financial statements, please see discussion of issues related to Arthur Andersen in Item 1A, “Risk Factors” of this Form 10-K. 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 of or For the Year Ended December 31,

		2005		2004		2003		2002		2001

		(In thousands, except per share amounts)
Income Statement Data
Total revenues		$	7,584,244	$	5,332,577	$	4,190,299	$	2,559,873	$	2,809,391
Income (loss) attributable to common stock			2,618,050		1,663,074		1,116,205		543,514		703,798
Net income (loss) per common share:
	Basic		7.96		5.10		3.46		1.83		2.44
	Diluted		7.84		5.03		3.43		1.80		2.37
Cash dividends declared per common share			.36		.28		.22		.19		.17
Balance Sheet Data
Total assets		$	19,271,796	$	15,502,480	$	12,416,126	$	9,459,851	$	8,933,656
Long-term debt			2,191,954		2,588,390		2,326,966		2,158,815		2,244,357
Preferred interests of subsidiaries			—		—		—		436,626		440,683
Shareholders’ equity			10,541,215		8,204,421		6,532,798		4,924,280		4,418,483
Common shares outstanding			330,121		327,458		324,497		302,506		287,917

For a discussion of significant acquisitions, see Note 2 of Item 15 in this Form 10-K.


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

Overview

Apache Corporation is an independent energy company whose principle business includes exploration, development and production of crude oil, natural gas and natural gas liquids. The Company operates in five core countries which, collectively, contained over 99 percent of the Company’s 2005 year-end estimated proved reserves and accounted for over 98 percent of the Company’s 2005 oil and gas production revenues. These principle operations are located in the United States, Canada, Egypt, Australia and offshore the United Kingdom in the North Sea. The Company’s smaller non-core operations in 2005 were conducted offshore China and in Argentina.

Apache adheres to a portfolio approach to provide diversity in terms of hydrocarbon mix (crude oil and natural gas), reserve life, geologic risk and geographic location. Our growth strategy focuses on economic growth through drilling, acquisitions, or a combination of both, depending on, among other things, cost levels and availability of acquisition opportunities. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and liquidity needs. These obligations and needs are met with cash on hand, cash generated from our operations, unused committed borrowing capacity under our global credit facility, and the capital markets. The interest cost of debt and access to the equity markets are greatly influenced by the Company’s ability to maintain both a strong balance sheet and generate ongoing

operating cash flow. For these reasons, we strive to maintain a manageable debt load that is properly balanced with equity and our single-A credit ratings. We are also cognizant of the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Consequently, we closely monitor trends in drilling costs by operating area and the price at which properties are available for purchase, so that we may adjust our budgets accordingly and allocate funds to projects based on potential rate of return. We review operating costs monthly by operating area, on both an absolute dollar and per unit of production basis. We then compare these results to our historical norms factoring in the impact of property acquisitions and changes in industry conditions in order to actively manage individual cost elements as appropriate. Given the inherent volatility and unpredictability of commodity prices and changing industry conditions, we frequently revise our forecasts and adjust our budgets accordingly.

Throughout 2005, commodity prices were very strong as the precarious supply and demand balance for crude oil and natural gas was impacted by geopolitical factors and U.S. weather events. Apache’s 2005 consolidated average realized crude oil price of $51.66 was 47 percent higher than 2004, while the Company’s average realized natural gas price increased 29 percent to $6.35 per Mcf. Crude oil prices were up worldwide, while natural gas price gains were mainly concentrated in North America. The Company’s daily production averaged 454,495 barrels of oil equivalent (boe) per day, up one percent from 2004, as gains were limited by the impact of U.S. hurricanes (discussed below). These historically high commodity prices and solid production drove the Company’s attainment of several operational and financial milestones.

2005 Financial and operating results include:


	•	Our 2005 oil and gas revenues totaled $7.5 billion compared to $5.3 billion in 2004, a 40 percent increase.

	•	We generated earnings of $2.6 billion, $955 million higher than in 2004. On a diluted share basis, earnings increased $2.81 to $7.84 per share.

	•	Net cash provided by operating activities increased $1.1 billion from 2004 to $4.3 billion.

	•	We increased production for the 26th time out of the last 27 years. Natural gas production averaged 1,264 MMcf/d compared to 1,235 MMcf/d in 2004. Crude oil production averaged 234,070 b/d versus 231,519 b/d in 2004.

	•	Daily equivalent production in the North Sea increased approximately 24 percent from 2004. The increase reflects the success of the Echo drilling program, which began in early 2004, but also includes Bravo well work and results from the Alpha and Delta drilling programs.

	•	Oil production in Australia decreased 9,795 b/d compared to 2004 on loss of East Spar liquids, where production ceased early in the year, and natural decline at Legendre.

	•	We continue to see higher industry-wide service costs, particularly in North America. The steady rise in commodity prices has driven up fuel, power and ad valorem costs, while other service costs are rising with greater demand resulting from increased activity.

	•	Canada’s daily gas production increased 14 percent from 2004 to 372 MMcf/d, driven by new wells drilled at Nevis, Zama and on the North Grant Lands. We also completed six of the 11 gas plants under construction during 2005.

	•	The Company’s Central region increased oil production 27 percent compared to 2004. The higher production was driven by the ExxonMobil acquisition completed in the third quarter of 2004 and active drilling and recompletion programs.

	•	Estimated proved reserves grew nine percent to 2.12 billion boe, marking 2005 as our 20th consecutive year of reserve growth.

	•	Exploration and development expenditures totaled $3.4 billion, $1.0 billion higher than in 2004.

	•	Apache ended 2005 with debt at 17 percent of total capitalization, down seven percent from year-end 2004.


	•	On September 15, 2005, the Company’s Board of Directors voted to increase Apache’s quarterly cash dividend to 10 cents per share, effective with the November 2005 payment.


	Impact of 2005 Hurricanes

During the third quarter of 2005, four hurricanes struck the Gulf of Mexico that impacted the Company’s U.S. gulf coast operations, both onshore and offshore Louisiana and Texas. During each of these hurricanes, personnel were evacuated and production was shut-in. Two of these storms, Hurricanes Dennis and Emily, required only temporary curtailment of production and caused minor damage to the Company’s production platforms. The other two storms, Hurricanes Katrina and Rita, caused extensive damage to both onshore and offshore production and transportation facilities. In addition to Apache’s property damage, third-party pipelines, terminals and processing facilities, which the Company relies upon to transport and process the crude oil and natural gas it produces, were damaged. Restoration of full production is dependent on numerous factors, many of which are beyond the Company’s control. The impact on operations and results follows:

Production — The hurricanes reduced Apache’s 2005 average annual daily production of natural gas by 59 MMcf/d and of crude oil by 10,813 b/d. The bulk of the shut-in production was associated with Hurricanes Katrina and Rita, which struck in late August and late September 2005, respectively. As of December 31, 2005, approximately 59 MMcf/d of net natural gas production and 20 Mbbls/d of net crude oil production per day remained shut-in. While we have seen tremendous progress in restoring production, a portion of the production may remain shut-in for up to a year.

Financial Results — The impact on the Company’s 2005 financial results included a $397 million reduction of crude oil and natural gas revenues, approximately $30 million of additional lease operating expenses (LOE) and $30 million of additional capitalized costs. The additional LOE and capitalized costs include insurance deductibles, additional premiums assessed by Oil Insurance Limited (OIL) and an accrual for an insurance contingency assessed by OIL should Apache elect to withdraw from the insurance pool. The shut-in production also resulted in $57 million less depletion expense. As indicated below, the Company accrued approximately $79 million of business interruption insurance claims during the fourth quarter of 2005 in “Other” under “Revenues and Other” of the Statement of Consolidated Operations.

Assessment of Damage — Nine operated production platforms were lost and two were severely damaged during the storms. Production platforms lost or severely damaged during Hurricane Katrina were: Main Pass 312-JA; South Timbalier 161-A; 161-B; 161-D; South Pass (SP) 62-A; SP 62-B; West Delta (WD) 103-A; WD 103-B; WD104-C; and WD133-B. The production platform lost during Hurricane Rita was Ship Shoal 193-B. Additionally, 12 non-operated structures were destroyed or severely damaged: 10 Grand Isle 43 platforms; one South Marsh Island 108 platform; and one Eugene Island 330 platform. Prior to the hurricanes, aggregate production from the lost and damaged platforms was approximately 10 Mbbls of oil per day and 21 MMcf of gas per day. All of these platforms are expected to be abandoned over the next three years and the Company has recorded a present value obligation of approximately $492 million to reflect the estimated abandonment costs to be incurred (See Note 4, Asset Retirement Obligation of Item 15 in this Form 10-K). The adjustment for abandonment obligations is recorded in our property balance and will be reflected in income as additional depletion expense over time. The impact on fourth quarter 2005 depletion expense was approximately $7 million. A portion of the obligation will be recovered through insurance proceeds.

Numerous other operated offshore production platforms and onshore facilities sustained damage as a result of the storms. While not as severe as the above mentioned platforms, much of the repairs require replacing grating, handrails, and lost equipment. In addition, minor structural repairs will also be required. The Company estimates that approximately $230 million will be incurred to repair these platforms and facilities and expects nearly all of these repairs to be completed during 2006. Although the $230 million estimate may change, the Company expects to recover the majority of these costs through insurance proceeds.

Insurance Coverage — The Company carries property damage insurance of $250 million per event subject to a $7.5 million deductible per event, and another $100 million in aggregate for the policy year. The $250 million per event in coverage is provided through OIL, while the $100 million is provided under a separate commercial policy. The OIL policy is prorated down if total claims received by the insurer for a single

event exceed $1 billion. As of December 31, 2005, the Company was advised by OIL that total claims for Hurricane Katrina would exceed the $1 billion limit, reducing the Company’s ultimate recoveries by approximately 50 percent, or $125 million. The Company was also advised that as of December 31, 2005, total estimated claims for Hurricane Rita would exceed the $1 billion limit, reducing the Company’s claims for Rita by approximately 20 percent. Based on current assessments by OIL, the Company expects to recover from OIL between $225 million and $250 million for both storms combined. The Company further expects to recover the full $100 million on the commercial policy.

The Company also carries business interruption insurance coverage through its commercial policy to cover deferred and lost oil and natural gas production revenues. The business interruption insurance began 60 days after occurrence of each event subject to a daily limit of $750,000 per event and an aggregate limit of $150 million. Coverage is based on current market prices and began October 28, 2005 for shut-in production caused by Hurricane Katrina and November 22, 2005 for Hurricane Rita. The Company accrued claims in 2005 totaling $79 million, with the remainder of the aggregate $150 million limit available for 2006. Proceeds received from the Business Interruption Insurance are reflected in “Other” under “Revenues and Other” on the Statement of Consolidated Operations and are included in cash flows from operating activities.

In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage in the Gulf of Mexico and substantially increased premium rates. As a result, there is no assurance that Apache will be able to arrange adequate insurance to cover its Gulf of Mexico exposures at a reasonable cost when the current policies expire.


	Exploration and Development Activity

The Company spent $3.8 billion on capital expenditures in 2005, 52 percent, or $1.3 billion more than in 2004. Expenditures for 2005 exploration and production activity accounted for 90 percent, or $3.4 billion, of capital spending, a $1.0 billion increase over 2004. The balance of 2005 capital spending, which totaled $393 million, up $254 million, was for oil and gas processing facilities and pipelines in Canada, Egypt and Australia. The Company spent $39 million on acquisitions in 2005 compared to $1.1 billion in 2004, as 2005 market conditions provided a limited number of attractive acquisition opportunities. However, in early 2006, we closed an acquisition announced in late 2005. Also, on January 17, 2006, the Company announced an agreement to purchase the Argentine operations of Pioneer Natural Resources (Pioneer) for $675 million. Please refer to the Subsequent Acquisitions and Divestiture section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. Acquisition expenditures typically vary year to year based on the availability of opportunities that fit Apache’s overall strategy. Significant highlights in each of our core areas follow:

U.S.


	•	The Company spent $1.1 billion to drill 478 wells, adding 91.9 MMBoe of reserves through extension and development activity. The Company had one of the five most active drilling programs in the Gulf of Mexico and Western Oklahoma, and one of the top 10 drilling programs in West Texas. In the Gulf Coast region, we drilled 66 Gulf of Mexico wells and 48 onshore wells with a 77 percent success rate. In the Central region, we drilled 364 wells with a 97 percent success rate. The U.S. accounted for 38 percent of our 2005 equivalent production and 42 percent of the Company’s estimated proved reserves at year-end 2005, down from 41 percent and 44 percent in 2004, respectively.

	•	On January 5, 2006, the Company completed its purchase of Amerada Hess’s interest in eight fields located in the Permian Basin of West Texas and New Mexico for $269 million. Apache estimates that these fields had proved reserves of 27 million barrels of liquid hydrocarbons and 27 billion cubic feet of natural gas at year-end 2005. For additional details regarding this transaction refer to the Subsequent Acquisitions and Divestiture section of this Item 7.

Canada


	•	The Company spent $1.2 billion on exploration and development in Canada, drilling 1,551 successful wells out of a total 1,674 wells, adding 104.3 MMBoe of reserves. Approximately one-fourth of the wells will be brought on production during the first half of 2006 upon completion of facilities. Canada accounted for 19 percent of our 2005 equivalent production and 27 percent of the Company’s estimated proved reserves at year-end 2005, up from 18 percent and 25 percent in 2004, respectively.

	•	We also spent $180 million during 2005 constructing 11 new gas processing plants. Six of these plants were completed during 2005 with the remainder expected to be completed throughout 2006.

	•	We are currently only producing about 19 million gross cubic feet of natural gas per day (13 MMcf/d net) from the North Grant Lands area, which represents approximately 30 percent of our production capacity. Production is restricted because of limited processing infrastructure, including pipelines, compressors and gas plants, and regulations restricting commingling of coalbed methane zones and conventional zones. We are working with regulatory authorities and expect to resolve the commingling issue favorably during the first half of 2006. Construction of processing infrastructure is ongoing.

	•	On May 5, 2005, Apache signed a farm-in agreement with ExxonMobil covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in the 2004 farm-in agreement with ExxonMobil. The 2004 farm-in agreement covered approximately 380,000 acres and stipulated drilling at least 250 wells over a two-year period beginning in October of 2004. Through the end of 2005, Apache drilled 457 wells on the 2004 farm-in acreage, earning 207 additional acreage sections.

Egypt


	•	The Company spent $352 million on exploration and development in Egypt, adding 77.7 MMBoe of reserves. Egypt accounted for 18 percent of our 2005 equivalent production and 13 percent of the Company’s estimated proved reserves at year-end 2005, up from 17 percent and 12 percent in 2004, respectively.

	•	On April 5, 2005, we announced two discoveries in Egypt. The Syrah 1X wildcat, on the Company’s 100 percent-contractor-interest Khalda Concession, tested 46.5 MMcf/d of natural gas. The Tanzanite 1X, located onshore on Apache’s West Mediterranean Concession, tested 5,296 b/d and 7.4 MMcf/d.

	•	On July 5, 2005, the Company announced that the Tanzanite-2 well, on Egypt’s West Mediterranean Onshore Concession, tested 2,846 b/d and 640 thousand cubic feet per day (Mcf/d) of gas from the Cretaceous-age Alamein Dolomite formation in the Tanzanite Field.

	•	On July 5, 2005, Apache also announced a new field oil discovery, the El Diyur-2X, on the Apache-operated El Diyur Concession southwest of Egypt’s Western Desert. A test of the lower Bahariya formation flowed at a rate of 1,177 b/d.

	•	Apache spent $182 million during 2005 developing Qasr field facilities. Large scale gas production from the Qasr field was initiated during the third quarter of 2005. Gross natural gas production rates late in the fourth quarter of 2005 averaged 160 MMcf/d. Associated condensate production exceeded 8,000 b/d. Early in 2006, upon completion of the Tarek gas plant pipeline inter-connect, gross natural gas and condensate production exceeded 200 MMcf/d and 10,000 b/d, respectively. Additionally, the field is also producing over 9,000 barrels of oil per day from a shallower formation. Since all gas plants supplied by Qasr are running at full capacity, deliverability from Qasr will be restricted until additional capacity comes on line, currently anticipated in late 2007 or early in 2008.


	•	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. The gas sales agreement (the Memorandum of Understanding for which was previously announced on December 16, 2003) for the interests was assigned to Amerada Hess as a part of that sale. Apache first announced this transaction on October 13, 2005. For additional details regarding this transaction refer to the Subsequent Acquisitions and Divestiture section of this Item 7.

Australia


	•	The Company spent $218 million on exploration and development in Australia, adding 31.9 MMBoe of reserves. During 2005, we participated in drilling 36 wells; 26 exploration wells and 10 development wells. Australia accounted for 8 percent of our 2005 equivalent production and 9 percent of the Company’s estimated proved reserves at year-end 2005 compared to 10 percent and 9 percent in 2004, respectively.

	•	On June 15, 2005, Apache announced the development of its Rose gas/condensate field in Australia with the completion of the Rose 4 development well. The Rose 4 well, which is part of the Harriet Joint Venture, significantly enhances the joint venture’s gas deliverability. Production will be sold into 13 dedicated contracts.

	•	On July 18, 2005, Burrup Fertilisers claimed force majeure and defaulted its take-or-pay obligations on a 48.2 MMcf/d gas purchase contract, net to Apache. Settlement negotiations with Burrup Fertilisers are continuing and the plant is expected to be operational in the first half of 2006, at which time gas deliveries and payments are anticipated.

	•	On July 28, 2005, Apache announced that it initiated production from the Mohave-1H discovery in the Carnarvon Basin offshore Western Australia. The initial gross production rate was 10,690 b/d from the Flag Sandstone zone, a prolific but traditionally often smaller reservoir. Apache owns a 68.5 percent interest in the field.

	•	On August 24, 2005, the Company announced it signed a new 15-year term contract to supply gas to a major power station to be built in Kwinana, Western Australia. The terms call for delivery of approximately 215 billion cubic feet (bcf) gross (118 bcf net to Apache) at a daily gross rate of 39 MMcf. The Company expects to source the gas for the contract from its John Brookes field beginning in late 2008. The term can be extended an additional 10 years by mutual agreement.

North Sea


	•	The Company spent $489 million in the North Sea, including $198 million on facility upgrades to improve the operating efficiency of the platforms. We drilled 23 exploration and development wells during 2005 with a 65 percent success rate, adding 45.2 MMBoe of reserves. The North Sea accounted for 14 percent of our 2005 equivalent production and 9 percent of the Company’s estimated proved reserves at year-end 2005 compared to 12 percent and 9 percent in 2004, respectively.

	•	The Company acquired 22 North Sea blocks in the 2005 UK license bid round. Also, during 2005, Apache acquired interests in six additional North Sea blocks, one via a small acquisition and five earned through farm-ins on four prospects. We had oil discoveries in three of the four farm-in prospects. In 2004, Apache acquired 14 new blocks in the UK license bid round. At the end of 2005, Apache held interests in 45 North Sea blocks.

	•	During 2005, Apache shot three new 3D seismic surveys in the North Sea, and together with the purchase and reprocessing of various 3D data sets, currently have 3-D seismic coverage on 27 blocks of the total 45 Apache North Sea held blocks.


	Other

Our year-end 2005 estimated reserves remained relatively balanced with a 46 percent oil and 54 percent natural gas mix. This compares to 48 percent oil and 52 percent natural gas at the end of 2004. Estimated proved undeveloped reserves represented 30.4 percent of total year-end 2005 estimated proved reserves compared to 32.7 percent at year-end 2004.

Apache was challenged in 2005 by steadily increasing service costs resulting from increased demand with high commodity prices and the major Gulf of Mexico hurricanes. The increases were reflected in nearly all of our drilling and lease operating costs, including; rig rates, drill pipe costs, chemical costs and the costs of power and fuel. The Company reviews these costs for each core area on a routine basis and pursues alternatives in maintaining efficient levels of costs and expenses. While we are encouraged by the current financial outlook for 2006, we will continue to monitor costs, and depending on drilling costs relative to market prices, we may act to reduce our drilling expenditures as we did in 2001. This is particularly relevant in the U.S. where reserve targets generally continue to decrease in size. Acquisition costs also increased generally in 2005, and for that reason we were not very active during the year, completing $39 million of acquisitions. However, in early 2006, we closed an acquisition announced in late 2005. Also, on January 17, 2006, the Company announced an agreement with Pioneer Natural Resources (see Subsequent Acquisitions and Divestiture section in this Item 7). We believe we are well positioned to pursue future acquisitions should the appropriate opportunities arise. The Company also experienced unfavorable foreign exchange rate movements in Canada in 2005 which impacted our lease operating and drilling costs. We did see some favorable exchange rate movements in Australia and the U.K., although the favorable impact on our lease operating and drilling costs were much less than the unfavorable impact in Canada. Refer to the “Costs” section of this Item 7, Management Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of items impacting costs in 2005.

In May 2005, the Company’s stockholders approved a new targeted stock plan that provides incentives for employees to double Apache’s share price to $108 by the end of 2008, with an interim goal of $81 to be achieved by the end of 2007. To achieve the trigger price, the Company’s stock price must close at or above the stated threshold for 10 days out of any 30 consecutive trading days by the end of the stated period. Under the plan, if the first threshold is achieved, approximately 1.3 million shares would be awarded for an intrinsic cost of $106 million. Achieving the second threshold would result in approximately 2.0 million shares awarded for an intrinsic cost of $213 million.

In July 2004, the Company signed an amendment agreement with the EGPC which, among other things, extended the term of the Khalda, Khalda West and Salam development leases through 2024. These development leases would have expired in 2011, 2012 and 2010, respectively. Apache also received a five-year extension on the Khalda Offset exploration acreage with an option for an additional three-year extension. As part of this agreement and in conjunction with the Qasr 25-year Gas Sales Agreement signed in April 2004, we agreed to re-price natural gas volumes in excess of 100 MMcf/d produced from the Khalda Concession development leases and future Khalda Offset development leases. Under the new pricing formula, Apache receives a price indexed to crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu. Pricing for the first 100 MMcf/d remains subject to the original contract price (which is indexed to oil pricing, but without a minimum or maximum) until January 1, 2013, at which time all Khalda area gas will be priced under the new pricing formula. For 2005 and 2004, Apache’s prices, which were a blend of the old and new contracts, averaged $4.59 per Mcf and $4.35 per Mcf, respectively.

Results of Operations

This section includes a discussion of our 2005 and 2004 results of operations and provides insight into unique events and circumstances for each of the Company’s six reportable segments. Apache’s geographic segments include the United States, Canada, Egypt, Australia, the North Sea and Other International. These segments are primarily in the business of crude oil and natural gas exploration and production. Please refer to Note 13, Business Segment Information of Item 15 in this Form 10-K for segment information.

Acquisitions and Divestitures


	Subsequent Acquisitions and Divestiture


	Amerada Hess

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 oil and gas reserves recorded for these properties. Apache first announced this transaction on October 13, 2005.


	Pioneer Natural Resources


	2005 Acquisitions

During 2005, Apache completed acquisitions for $39 million, adding approximately 7.8 MMboe to the Company’s proved reserves.

On May 5, 2005, Apache signed a farm-in agreement with Exxon Mobil Corporation (ExxonMobil) covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in the 2004 farm-in agreement with ExxonMobil.


	2004 Acquisitions


	ExxonMobil

During the third quarter of 2004, Apache entered into separate arrangements with ExxonMobil that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and on the Gulf of Mexico-Outer Continental Shelf. Apache’s participation included cash payments of approximately $347 million, subject to normal post closing adjustments. The following summarizes these transactions:

ExxonMobil — Western Canada In August 2004, Apache signed a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta. Under the agreement, Apache has the right to earn acreage sections by drilling an initial well on each such section. By drilling at least 250 wells during the initial two-year earning period under the agreement, Apache will receive a one-year extension in which to earn additional sections. As to any sections earned by Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. Under certain circumstances, ExxonMobil has the right to convert its retained 35 percent working interest into a 12.5 percent overriding royalty. In addition, during the terms of this agreement, Apache is required to carry ExxonMobil’s retained working interest with respect to certain drilling, capping, completion, equipping and tie-in costs associated with wells drilled on leasehold acreage.

ExxonMobil — West Texas and New Mexico In September 2004, Apache acquired interests from ExxonMobil in 23 mature producing oil and gas fields in West Texas and New Mexico for $318 million. Apache separately contributed approximately $29 million into a partnership to obtain additional interests in the properties. ExxonMobil will retain interests in the properties through the partnership, including the right to receive, on certain fields, 60 percent of the oil proceeds above $30 per barrel in 2004, $29 per barrel in 2005 and $28 per barrel during the period from 2006 thru 2009.

ExxonMobil — Louisiana and Gulf of Mexico-Outer Continental Shelf Also in September 2004, Apache and ExxonMobil entered into joint exploration agreements to explore Apache’s acreage in South Louisiana and the Gulf of Mexico-Outer Continental Shelf. The agreements provide for an initial term of five years, with the potential for an additional five years based on expenditures by ExxonMobil. Pursuant to the agreement covering South Louisiana, Apache leased 50 percent of its interests below certain producing or productive formations in the acreage to ExxonMobil, subject to retention of a 20 percent royalty interest. Pursuant to the agreement covering the Gulf of Mexico-Outer Continental Shelf, no assignments will be made until a prospect has been proposed and the initial well has been drilled. Apache will retain all rights in each prospect above certain producing or productive formations and further will retain a three percent overriding royalty interest in any property assigned to ExxonMobil. See Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K for a complete discussion of those transactions.


	Anadarko

On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko’s Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields comprising approximately 70 percent of the production.

Prior to Apache’s purchase from Anadarko, Morgan Stanley paid Anadarko $646 million to acquire an overriding royalty interest in these properties. Anadarko’s sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP), the obligations of which Apache assumed along with its subsequent purchase. Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas production (20 MMboe) over four years beginning in October 2004. The VPP represents a non-operating interest in the properties that is free of all costs of operations and production. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP in any given month to satisfy these deliverables. However, Morgan Stanley has no right to look to other assets or production of Apache. The VPP is scheduled to terminate on August 31, 2008, but may be extended if all scheduled VPP volumes have not been delivered to Morgan Stanley and the properties are still producing. The VPP includes restrictions on the Company’s ability to sell the properties subject to the VPP or resign as operator of VPP properties it currently operates. Upon termination of the VPP, all rights, titles and interests revert back to Apache. Apache does not record the reserves and production volumes attributable to the VPP.

The strategic rationale for Apache buying these assets burdened by a volumetric production payment is several fold. First, because Morgan Stanley gets their production first and Apache receives the remainder, Morgan Stanley is paying substantially more per boe, thereby significantly reducing Apache’s cost per unit. Second, although Morgan Stanley’s priority call on production leaves Apache with more risk, in exchange we retain all the upside associated with finding more reserves on the acquired properties than anticipated at the time of the acquisition. This is a risk/reward scenario with which we are comfortable and that plays to our long history of adding value to numerous acquired properties through proactive operations. Third, our experience is that invariably we earn higher rates of return from drilling and related activities than we do from acquisitions, yet acquisitions bring an inventory of drilling and exploitation opportunities. Because Morgan Stanley paid Anadarko more than Apache for proved reserves, a higher percentage of Apache’s investment will be concentrated in the higher risk, but generally higher reward, future drilling activity. As a final note, Morgan Stanley, while having less risk, is not risk free. In the event that the properties purchased by Apache are

insufficient to deliver the volumes sold to Morgan Stanley, there is no recourse to any properties other than those acquired from Anadarko. See the Capital Resources and Liquidity section of this Item 7 for further discussion of VPPs.

The $537 million purchase price agreed to in the definitive agreement was subsequently adjusted for the exercise of preferential rights by third parties and other normal post-closing adjustments. After adjusting for these items, Apache paid $532 million for the properties and recorded estimated proved reserves of 60 MMboe, of which 50 percent is natural gas. In addition, an $84 million liability for the future cost to produce and deliver the VPP volumes was recorded by the Company. This liability will be settled through a reduction of lease operating expense as the volumes are produced and delivered to Morgan Stanley. Apache also recorded abandonment obligations for the properties of approximately $134 million and other obligations assumed from Anadarko in the amount of $27 million. Apache allocated $122 million of the purchase price to unproved property. The purchase price was funded by borrowings under the Company’s commercial paper program.

We routinely evaluate our property portfolio and divest those that are marginal or no longer fit into our strategic growth program. We divested $80 million, $4 million and $59 million of properties during 2005, 2004 and 2003, respectively.

Revenues

Our revenues are sensitive to changes in prices received for our products. A substantial portion of our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.


	Oil and Natural Gas Prices

While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a world-wide market, whereas natural gas, which has a limited global transportation system, is subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction, while natural gas price movements generally follow local market conditions. However, throughout 2005, the price differentials related to crude oil qualities were volatile, and the prices we received for our North American sour crude oil compared to the NYMEX Domestic Sweet index widened beyond historical averages. This price differential was exacerbated by Hurricanes Katrina and Rita which caused extensive damage to the refining complex along the U.S. Gulf Coast. These quality differentials, which impacted approximately one-third of our U.S. production, occurred largely because OPEC produced more sour crude to satisfy rising world demand, while U.S. sour crude refining capacity was hindered by the damage caused by the hurricanes. This excess in sour crude supply over the refining capacity created competition among producers driving a deeper discount for sour crude. During the fourth quarter of 2005, the sweet to sour crude oil quality differential averaged $6.50 per barrel.

Apache primarily sells its natural gas into three markets:


	1)	North America, which has a common market and where supply and demand are currently tightly balanced, creating a volatile pricing environment;

	2)	Australia, which has a local market with limited demand relative to available supply and long-term fixed price contracts; and

	3)	Egypt, which has a local market where the price received for our production is indexed to a weighted-average Dated-Brent crude oil price, a portion of which is subject to a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu.

The current outlook for 2006 indicates that the sour crude quality differentials, while narrowing somewhat, will remain above historical averages.

For specific marketing arrangements by segment, please refer to Item 1 and 2. Business and Properties of this Form 10-K.

Revenues

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


			For the Year Ended December 31,

			2005		2004		2003

Revenues (in thousands):
	Oil		$	4,413,934	$	2,986,208	$	2,081,283
	Natural gas			2,928,578		2,217,983		2,046,625
	Natural gas liquids			114,779		103,826		71,012

		Total	$	7,457,291	$	5,308,017	$	4,198,920

Oil Volume — Barrels per day:
	United States			66,268		67,872		69,404
	Canada			22,499		25,305		25,220
	Egypt			55,141		52,183		47,551
	Australia			15,379		25,174		30,589
	North Sea			65,488		52,836		29,260
	China			8,132		7,583		2,791
	Argentina			1,163		566		579

		Total		234,070		231,519		205,394

Average Oil Price — Per barrel:
	United States		$	47.97	$	38.75	$	27.48
	Canada			53.05		38.57		29.06
	Egypt			53.69		37.35		27.64
	Australia			57.61		41.96		29.87
	North Sea			53.00		24.22		25.40
	China			44.24		32.88		26.33
	Argentina			37.54		32.89		29.23
		Total		51.66		35.24		27.76
Natural Gas Volume — Mcf per day:
	United States			597,481		646,619		665,156
	Canada			371,917		326,965		318,528
	Egypt			165,710		137,737		113,554
	Australia			123,295		118,108		111,061
	North Sea			2,306		1,871		1,714
	Argentina			3,114		3,808		7,144

		Total		1,263,823		1,235,108		1,217,157

Average Natural Gas Price — Per Mcf:
	United States		$	7.22	$	5.45	$	5.22
	Canada			7.29		5.30		4.69
	Egypt			4.59		4.35		4.18
	Australia			1.72		1.65		1.44
	North Sea			9.17		5.53		2.77
	Argentina			1.14		.65		.47
		Total		6.35		4.91		4.61


			For the Year Ended December 31,

			2005		2004		2003

NGL Volume — Barrels per day:
	United States			7,553		8,268		7,578
	Canada			2,235		2,588		1,565

		Total		9,788		10,856		9,143

Average NGL Price — Per barrel:
	United States		$	32.44	$	26.66	$	21.70
	Canada			31.07		24.44		19.25
		Total		32.13		26.13		21.28


	Contributions to Oil and Natural Gas Revenues

As with production and reserves, a consequence of geographic diversification is a shifting geographic mix of our oil revenues and natural gas revenues. For the reasons discussed in the Oil and Natural Gas Prices section above, contributions to oil revenues and gas revenues should be viewed separately.

The following table presents each segment’s oil revenues and gas revenues as a percentage of total oil revenues and gas revenues, respectively.


		Oil Revenues									Gas Revenues
		For the Year Ended									For the Year Ended
		December 31,									December 31,

		2005			2004			2003			2005			2004			2003

United States			26	%		32	%		33	%		54	%		58	%		62	%
Canada			10	%		12	%		13	%		34	%		29	%		27	%

North America			36	%		44	%		46	%		88	%		87	%		89	%
Egypt			25	%		24	%		23	%		9	%		10	%		8	%
Australia			7	%		13	%		16	%		3	%		3	%		3	%
North Sea			29	%		16	%		13	%		—			—			—
Other International			3	%		3	%		2	%		—			—			—

	Total		100	%		100	%		100	%		100	%		100	%		100	%


	Crude Oil Contribution

In 2005, oil revenue contributions from outside the U.S. rose six percent to 74 percent ($3.3 billion) of our total 2005 consolidated oil revenues. Production growth and significantly higher price realizations drove the North Sea’s oil revenue contributions to 29 percent of consolidated oil revenues and were largely responsible for the growth of non-U.S. oil revenues. In 2004, the North Sea’s contribution totaled 16 percent. U.S. oil revenues, which have historically been the predominate contributor, made up 26 percent of 2005 oil revenues, partly a consequence of the U.S. hurricanes (including Hurricane Ivan whose effects were felt in 2005) which reduced 2005 oil revenues $221 million. Australia’s contribution to 2005 consolidated oil revenues fell to seven percent from 13 percent on a 39 percent decrease in production compared to 2004.

In 2004, oil revenues from areas outside the U.S. rose slightly to 68 percent of consolidated oil revenues, up from 67 percent in 2003. Lack of production growth reduced the U.S. overall contribution one percent to 32 percent of consolidated oil revenues. Canada’s contribution also declined one percent to 12 percent on lower relative production growth. Egypt’s share rose one percent to 24 percent as it saw both price gains and production growth. The North Sea’s contribution increased three percent on both an increase in average daily production and a full year of revenues versus nine months in 2003. Australia’s contribution fell three percent on lower production.


	Crude Oil Revenues

Crude oil revenues increased $1.4 billion, or 48 percent to $4.4 billion, in 2005 from 2004 on a $16.42 per barrel increase in average realized oil price and a one percent increase in production. All segments saw a significant increase in realized crude oil price, with the North Sea and Egypt also benefiting from production growth compared to 2004.

The North Sea’s 2005 crude oil revenues were $798 million higher than 2004, reflecting significantly higher price realizations and a 24 percent increase in production. The higher price realizations generated additional revenues of $557 million when compared to 2004, while the higher production added $242 million. Oil price realizations in 2004 were impacted by a lower fixed-price physical contract that expired in December 2004. The production growth reflects the benefits of the North Sea’s active drilling, workover and repair programs.

U.S. crude oil revenues for 2005 increased $198 million compared to 2004. This increase was the result of a 24 percent increase in crude oil price, as production decreased two percent. The 2005 U.S. average realized price includes a $2.39 per barrel hedge loss. (See Note 3, Hedging and Derivative Instruments, of this Form 10-K.) A full year of production from the ExxonMobil and Anadarko properties, which were acquired in the second half of 2004, and successful drilling and re-completion efforts partially offset natural production declines and approximately 11 Mbbls per day of downtime resulting from hurricanes.

Egypt contributed additional revenues of $367 million in 2005 compared to 2004. This increase in revenue was primarily attributable to a 44 percent increase in crude oil price. A six percent increase in production generated an additional $55 million of revenues. The production increase was related to drilling and recompletion activity on Egypt’s Western Mediterranean Concession, particularly completion of the Tanzanite-2 well and recompletion of the Tanzanite-1 well.

Canada’s 2005 revenues increased $79 million over 2004 on a 38 percent increase in price, which more than offset the impact of an 11 percent, or 2,806 b/d, decline in oil production. Canada’s production was impacted by natural decline in the Zama, Midale, Virginia Hills and Consort operated areas, as well as natural decline on non-operated Karr Simonette and Nevis areas.

China’s 2005 revenues were $40 million higher than 2004 on a 35 percent increase in crude oil price and a seven percent increase in net volumes. The higher realized price and volumes generated an additional $31 million and $9 million of revenues, respectively. China’s 2005 production outpaced 2004 primarily because production was ramping up during the first half of 2004.

Australia’s 2005 crude oil revenues were $63 million less than 2004. This decrease reflects a 39 percent decline in production resulting from natural decline, particularly in the Legendre field, and loss of liquids from East Spar, which ceased production early in 2005. These declines were partially offset by a 37 percent increase in realized price and a full year of production from the Mohave and Artreus fields, which commenced production during the third quarter of 2005.

Apache manages a small portion of its exposure to fluctuations in crude oil prices using financial derivatives. Approximately six percent of our worldwide crude oil production was subject to financial derivative hedging for 2005 compared to four percent in 2004. (See Note 3, Hedging and Derivative Instruments, of this Form 10-K for a summary of the current derivative positions and terms.) These financial derivative instruments reduced our 2005 and 2004 worldwide realized prices $.68 and $.21 per barrel, respectively.


	Natural Gas Contribution

Our North America operations contributed 88 percent of 2005 consolidated natural gas revenues, up one percent from 2004. The U.S. contributed 54 percent of 2005 consolidated natural gas revenues, a four percent decline from 2004, a consequence of the U.S. hurricanes (which reduced U.S. natural gas revenues approximately $229 million). Canada’s natural gas revenue contribution increased to 34 percent, reflecting both a 14 percent production growth and a slightly higher relative increase in realized price. While Egypt’s gas

production increased 20 percent, its contribution to 2005 gas revenues decreased slightly to nine percent as they only had marginal price improvement, a result of the new pricing formula enacted in 2004. Australia’s contribution to our total gas revenues was unchanged at three percent.

In 2004, 87 percent of Apache’s natural gas revenues came from North America of which 58 percent was from the U.S. and 29 percent was from Canada. The U.S. contribution decreased four percent from 2003, primarily because of production declines, the impact Hurricane Ivan had on U.S. Gulf of Mexico revenues, and the additional revenues generated by Canada and Egypt. Our U.S. Gulf Coast region, which contributed 69 percent of Apache’s U.S. 2004 production, down two percent from 2003, is characterized by reservoirs which demonstrate high initial production rates followed by steep declines when compared to most other U.S. producing areas. Canada’s contribution was up two percent from 2003 resulting from three percent production growth and higher price gains relative to other areas. Egypt’s contribution to total gas revenues increased to 10 percent from eight percent in 2003, on 21 percent production growth. Australia’s contribution to 2004 natural gas revenues remained the same as 2003 at three percent.


	Natural Gas Revenues

Our 2005 natural gas revenues increased $711 million from the prior-year on a 29 percent increase in realized natural gas price and a two percent increase in production. The higher prices generated an additional $652 million in gas revenues, while the production increase added another $59 million to 2005 revenues, relative to the prior year. While all of our reportable segments realized increased natural gas prices, the increases in the U.S. and Canada had the most significant impact on 2005 revenues, given their price advantage and the magnitude of their volumes, relative to the other countries. Canada, Egypt and Australia also contributed increased gas revenues from higher production, while the additional price-driven revenues generated in the U.S. were partially offset by an eight percent decline in production.

2005 U.S. natural gas revenues were $286 million higher than 2004. U.S. natural gas prices, which were up 32 percent, contributed $420 million of additional revenues, while an eight percent production decline lowered revenues $134 million when compared to 2004. While U.S. production was down year-over-year because of the hurricanes in our Gulf Coast region, an 11 percent gain in the Central region offset some of the hurricane impact. The Central region was up on active drilling and recompletion programs and acquisitions.

Canada’s 2005 natural gas revenues increased $356 million from 2004. Two-thirds of the increase related to a 38 percent increase in price, with the balance generated by a 14 percent increase in production. Production increased 45 MMcf/d, a result of successful drilling efforts at the Nevis, Zama, Hatton and Consort areas and the ExxonMobil acreage, which more than offset natural declines in the Ladyfern and other Northeast British Columbia areas.

Egypt contributed an additional $58 million to 2005 consolidated natural gas revenues compared to 2004. This increase is attributable to a six percent price improvement and a 20 percent increase in production. The year-over-year production growth came from development of the Khalda Concession Imhoptep and Atoun wells, development of the Qasr field, and first sales from the Northeast Abu Gharadig concession, which commenced in January 2005.

Australia’s 2005 natural gas revenues were $6 million higher than 2004. While Australia’s natural gas production and price were each up four percent over 2004, the impact on revenues was minimal given the relatively low natural gas price. The additional production was attributable to the Rose, John Brookes and Bambra fields.

Our 2004 natural gas revenues increased $171 million with a $.30 per Mcf increase in our average natural gas price realizations generating an additional $133 million of revenues. Higher production added the remaining $38 million. While all of our operating segments reported an increase in natural gas price realizations, most of the additional revenues attributable to price came from the U.S. and Canada. The additional revenues attributable to production were primarily generated in Egypt, where natural gas production increased 21 percent, reflecting the success of our drilling program. Canada and Australia also contributed to the increase in production revenues with production growth of three percent and six percent, respectively.

Canada’s increase is from new wells while Australia’s increase was driven by higher customer demand and new contractual sales. Partially offsetting these additional production revenues was a three percent decrease in U.S. production. The lower U.S. production was focused in the Gulf Coast region and is related to the impact of Hurricane Ivan and natural decline in mature fields.

Apache uses a variety of strategies to manage its exposure to fluctuations in natural gas prices, including fixed-price physical contracts and derivatives. The majority of our worldwide gas sales contracts are indexed to prevailing market prices; however, during 2005 and 2004, approximately ten percent and nine percent of our U.S. natural gas production, respectively, was subject to long-term, fixed-price physical contracts. The long-term, fixed-price physical contracts apply to a small portion of our future U.S. natural gas production and provide a measure of protection to the Company in the event of decreasing natural gas prices. These fixed-priced contracts reduced our 2005 and 2004 worldwide realized natural gas prices by $.19 per Mcf and $.10 per Mcf, respectively. Additionally, nearly all of our Australian natural gas production is subject to long-term, fixed-price supply contracts that are periodically adjusted for changes in Australia’s consumer price index. Since these contracts are denominated in Australian dollars, the resulting revenues are impacted by changes in the value of the Australian dollar relative to the U.S. dollar.

Approximately nine percent and 16 percent of our worldwide natural gas production was subject to financial derivative hedges for 2005 and 2004, respectively. Currently, all of our natural gas derivative positions have been designated against Gulf of Mexico production. These derivative financial instruments reduced our 2005 and 2004 consolidated realized prices $.15 per Mcf and $.20 per Mcf, respectively. (See Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K for a summary of current derivative positions and terms.) Also during 2004, we amortized specific unrealized gains and losses related to derivative positions closed in October and November 2001. This amortization, which terminated in July 2004, had a negligible impact on 2005 average realized prices.

Costs

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


			Year Ended December 31,						Year Ended December 31,

			2005		2004		2003		2005		2004		2003

			(In millions)						(Per boe)
Depreciation, depletion and amortization:
	Oil and gas property and equipment		$	1,325	$	1,149	$	1,003	$	7.99	$	7.01	$	6.59
	Other assets			91		73		70		.55		.44		.46
Asset retirement obligation accretion				54		46		38		.32		.28		.25
International impairments				—		—		13		—		—		.08
Lease operating costs				1,041		864		700		6.27		5.27		4.59
Gathering and transportation costs				100		82		60		.60		.50		.40
Severance and other taxes				453		94		122		2.73		.57		.80
General and administrative expenses				198		173		138		1.20		1.06		.91
China litigation				—		71		—		—		.43		—
Financing costs, net				116		117		115		.70		.71		.75

		Total	$	3,378	$	2,669	$	2,259	$	20.36	$	16.27	$	14.83


	Depreciation, Depletion and Amortization

Apache’s Depreciation, Depletion and Amortization (DD&A) of oil and gas properties is calculated 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 costs in the UOP calculation include both the net capitalized amounts on the balance sheet, and the estimated future costs to

access and develop reserves needing additional facilities, equipment or downhole work in order to produce. Under the full-cost method of accounting, the DD&A calculation is prepared separately for each country in which Apache operates. Absolute DD&A determines the expense reported each period, while the cost per unit of production (DD&A rate) provides insight into the overall costs of the company’s reserves growth. Current costs incurred to drill or acquire additional reserves that are higher than the historical cost level raises the overall DD&A rate. Conversely, if reserves are added in the current period at a rate per unit less than existing levels, they average down the company’s DD&A rate. Changes from period to period in absolute DD&A expense are determined by production levels, the mix of production (high cost country versus a low cost country) and the impact of recent spending (higher or lower DD&A rates).

Our 2005 full-cost DD&A expense totaled $1.3 billion, $176 million more than 2004. Our 2005 full-cost DD&A rate of $7.99 per boe was $.98 per boe more than 2004, driven by rising industry-wide drilling costs, especially in the U.S., Canada, the North Sea and Egypt. The higher commodity prices experienced over the past year, as well as the affect of the U.S. hurricanes, led to increased demand for drilling services and thus higher current drilling costs and higher estimated future development costs. The increase in North Sea’s rates per boe also reflects the continuation of facility upgrades to increase the overall efficiency of the platforms.

Full-cost DD&A expense of $1.1 billion in 2004, increased $146 million compared to 2003. Approximately 59 percent of the increase in absolute costs was related to higher production levels, mainly in the North Sea, Egypt and China. The balance was primarily attributable to higher drilling costs, as our 2004 DD&A rate increased $.42 to $7.01 per boe. The increase in per unit costs is primarily attributable to our North American operations where high commodity prices have led to increased demand for drilling services and thus higher drilling costs. A full year’s production from China, which carries the second highest DD&A rate in the Company, also contributed to the increase in the worldwide rate. These increases were partially offset by a decrease in the DD&A rate in Egypt from a successful exploration and development program which added significant reserves through drilling at lower costs.

Depreciation of other assets increased $18 million in 2005, reflecting new infrastructure built in Canada to accommodate development on acreage acquired from ExxonMobil in 2004 and new Qasr natural gas facilities in Egypt.

Depreciation of other assets increased $3 million in 2004, in line with our overall growth.


	Impairments

We assess all of our unproved properties for possible impairment on a quarterly basis based on geological trend analysis, dry holes or relinquishment of acreage. When an impairment occurs, costs associated with these properties are generally transferred to our proved property base where they become subject to amortization. Impairments in international areas without proved reserves are charged to earnings upon determination that impairment has occurred. In 2003, we impaired the final $13 million ($8 million after-tax) of unproved property costs in Poland.

Goodwill is subject to a periodic fair-value-based impairment assessment. Goodwill totaled $189 million on December 31, 2005, and no impairment was recorded in 2005, 2004 or 2003. For further discussion, see Note 1, Summary of Significant Accounting Policies of Item 15 in this Form 10-K.


	Lease Operating Costs

Lease operating costs (LOE) are generally comprised of several components: direct operating costs, repair and maintenance, workover costs and ad valorem taxes. LOE is driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties. Oil 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. Workovers continue to be an important part of our strategy enabling us to exploit our existing reserve base by accelerating production and taking advantage of high commodity prices. Commodity prices and exchange rates also impact LOE. Historically, electricity, fuel and other service costs have risen in high commodity price environments, leading to an increase in industry-wide LOE. Rising per

unit operating costs remained a challenge in 2005, especially in North America. The Company reviews production costs in each of its core areas on a monthly basis and pursues alternatives to maintain efficient levels of costs. Fluctuations in exchange rates also impact the Company’s LOE, with a weakening U.S. dollar adding to per unit costs and a stronger U.S. dollar lowering per unit costs. The U.S. dollar, which weakened against the Canadian dollar throughout 2005, strengthened marginally against the Australian dollar and British pound. Acquisitions increase absolute LOE costs, but they do not necessarily increase per unit costs or reduce margins. The following discussion will focus on per unit operating costs as this is the most informative method of analyzing LOE trends.

On a per unit/boe produced basis, 2005 LOE averaged $6.27 per boe, $1.00 per boe higher than 2004. Production shut-ins and additional insurance costs associated with the 2005 hurricanes added $.41 to the 2005 rate. The remaining increase reflects higher service costs associated with rising commodity prices and the associated increase in demand for services, an increase in workover activity, higher repair and maintenance costs and the impact a weaker U.S. dollar had on Canadian LOE. The slight strengthening against the Australian dollar and British pound had less impact on LOE.

Regionally, 2005 costs were up as follows:

U.S. — The U.S. added $.77 per boe to the 2005 consolidated rate with nearly one-third of the impact attributed to the additional insurance costs and production shut-ins caused by the 2005 hurricanes. Higher contract labor costs, workover activity, repair and maintenance, and various other commodity-price driven service costs accounted for the remaining impact.

Australia — Australia added $.15 per boe to the 2005 consolidated rate on a 20 percent drop in equivalent production. Australia also saw a rise in insurance cost. The lower production added $.13 per boe to the 2005 consolidated rate, while additional costs added $.02 per boe.

Canada — Canada added $.21 per boe to the 2005 consolidated rate increase, with costs adding $.27 per boe, partially offset by the impact of higher volumes, which reduced the rate $.06 per boe. 2005 costs were up $44 million from 2004, with 42 percent attributable to the strengthening Canadian dollar. The balance related to various other costs associated with an increase in activity and the general rise in costs, including higher contract labor, power and fuel, repair and maintenance and workover costs.

Egypt — Egypt’s 2005 costs were $23 million higher than 2004 on higher diesel fuel costs, an increase in workover activity, higher labor costs and insurance costs. The diesel fuel costs were previously subsidized by the Egyptian government. Egypt added $.04 per boe to the consolidated rate increase, with higher costs adding $.14 per boe and increased volumes lowering the rate $.10 per boe.

North Sea — The North Sea reduced the 2005 consolidated rate $.16 per boe on a 24 percent increase in production, partially offset by a two percent increase in costs. North Sea costs were up on increased repair and maintenance activity.

On a per unit produced basis, 2004 LOE increased $.68 to $5.27 per boe. The increase was primarily attributable to an increase in industry-wide service costs in North America with higher commodity prices, an increase in currency exchange rates in Canada, the North Sea and Australia, and higher expense resulting from our incentive programs, primarily stock-based programs which we began expensing in 2003. Per unit costs were also negatively impacted by the combined impact of lost production and additional costs related to Hurricane Ivan in the Gulf of Mexico and higher repair and maintenance costs in Australia. These increases offset the impact of a $2.75 decline in the unit cost in the North Sea, where our investments to increase production (and lower operating costs per unit) over the long-term began to pay off.


	Gathering and Transportation Costs

Apache generally sells oil and natural gas under two types of agreements, typical in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which Apache sells oil or natural gas at the wellhead and collects a price, net of transportation incurred by the purchaser. In this case, the Company records sales at the price received from the purchaser, which is net of transportation costs.

Under the other arrangement, Apache sells oil or natural gas at a specific delivery point, pays transportation to a third-party carrier and receives from the purchaser a price with no transportation deduction. In this case, the Company records the transportation cost as gathering and transportation costs. The Company’s treatment of transportation costs is pursuant to Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs” and as a result a portion of our transporting costs is reflected in sales prices and a portion is reflected as Gathering and Transportation Costs rendering the separately identified transportation costs incomplete.

In both the U.S. and Canada, Apache sells oil and natural gas under both types of arrangements. In the North Sea, Apache pays transportation to a third-party carrier and receives a purchase price with no transportation deduction. In Australia, oil and natural gas are sold under netback arrangements. In China, we incur costs for barges to transport crude oil to onshore terminal facilities. In Egypt, our oil and natural gas production has historically been sold to EGPC under netback arrangements. During 2005, Apache exported a portion of its Egyptian crude oil under both types of arrangements. Future export cargoes may be sold under netback arrangements or Apache may arrange shipping and receive prices without transportation deductions. The following table presents gathering and transportation costs paid directly by Apache to third-party carriers for each of the periods presented.


	For the Year Ended
	December 31,

	2005		2004		2003

	(In millions)
U.S.	$	30	$	28	$	21
Canada		33		31		28
North Sea		28		22		11
Egypt		8		—		—
China		1		1		—

Total Gathering and Transportation	$	100	$	82	$	60

These costs are primarily related to the transportation of natural gas in our North American operations, North Sea crude oil sales and Egyptian crude oil exports. The 22 percent increase in costs for 2005 was driven primarily by North Sea’s production growth and Egyptian crude exports. Apache began exporting Egyptian crude in the second half of 2004 and first incurred third-party transportation charges in early 2005.

Transportation costs in 2004 increased 37 percent from 2003 primarily because of production growth and a full year of production in the North Sea and an increase in volumes transported under third-party transportation contracts in the U.S., Canada’s 2004 costs were 11 percent higher than 2003 because of an increase in third-party transportation rates and the impact of a weaker U.S. dollar.


	Severance and Other Taxes

Severance and other taxes are primarily comprised of severance taxes on properties onshore and in state or provincial waters in the U.S. and Australia, and the United Kingdom (U.K.) Petroleum Revenue Tax (PRT). 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 subject fields in the U.K. North Sea. We are also subject to the Australian Petroleum Resources Rent Tax (PRRT), and various Canadian taxes including the Canadian Large Corporation Tax, Saskatchewan Capital

Tax, Saskatchewan Resource Surtax and Freehold Mineral Tax. The table below presents a comparison of these expenses.


	For the Year Ended
	December 31,

	2005		2004			2003

	(In millions)
Severance taxes	$	139	$	127		$	77
U.K. PRT		285		(61	)		20
Canadian taxes		22		23			20
Other		7		5			5

Total Severance and Other Taxes	$	453	$	94		$	122

Severance and other taxes totaled $453 million in 2005, $359 million greater than 2004. The U.K. PRT increased $346 million in 2005 on significantly higher oil price realizations and higher production. U.S. severance taxes increased $36 million on higher oil and gas prices. Australia’s severance taxes decreased $24 million, reflecting lower excise tax on production from Legendre, a result of declining production.

In 2004, severance and other taxes decreased 23 percent, or $28 million, with severance taxes representing the majority of these taxes. U.S. severance and other taxes increased $15 million, in line with higher production revenues. Australia’s taxes increased $36 million as production from the Legendre field crossed a cumulative threshold, triggering an excise tax. In 2004 Apache’s U.K. PRT was in a credit position as deductible capital spending exceeded taxable cash flows from the North Sea Forties field. Canadian taxes increased $3 million on an increase in Freehold Mineral Taxes.


	General and Administrative Expenses

General and administrative expenses (G&A) of $1.20 per boe for 2005 increased $.14 per boe over 2004. Absolute costs increased $25 million or 14 percent. Nearly three-fourths of the increase in year-over-year costs related to the impact of Apache’s stock-based compensation programs. Stock-based compensation costs increased relative to the prior-year because of new stock option grants issued in 2005, a new targeted stock plan approved by stockholders in May 2005, and the impact Apache’s rising common stock price had on stock-based compensation expense. The balance of the G&A increase was primarily attributed to the increased cost of insurance, a consequence of the hurricanes, higher charitable contributions and higher Sarbanes-Oxley compliance audit fees.

G&A of $1.06 per boe in 2004 increased $.15 per boe over 2003. Absolute costs increased $35 million, or 25 percent. Over $21 million, or 61 percent, of the additional expense was related to the impact Apache’s rising stock price had on stock-based compensation programs and incremental incentive compensation. The impact from the higher stock price stems from Apache’s decision, effective January 1, 2003, to expense stock-based compensation plans (see Note 8, Capital Stock of Item 15 in this Form 10-K). Approximately $3 million, or 8 percent, of the increase is related to our North Sea operations, with the first full year of operations in 2004. The balance of the increase was related to higher audit and tax fees, increased insurance premiums, and expansion of the Company’s gas marketing group.


	Financing Costs, Net

The major components of financing costs, net, include interest expense and capitalized interest.

Net financing costs for 2005 were slightly lower than 2004. While gross interest expense increased $7 million in 2005 on a higher average debt balance, it was mostly offset by a $6 million increase in the amount of interest capitalized, a result of a higher average unproved property balance. Our weighted-average cost of borrowing on December 31, 2005 was 6.7 percent and 2004 was 6.1 percent.

2004 net financing costs were slightly higher than 2003. Gross interest expense decreased $1 million in 2004, a result of a lower average debt balance. This decrease was offset by a $2 million decrease in the amount

of interest capitalized, a result of a lower average unproved property balance. Our weighted-average cost of borrowing on December 31, 2004 was 6.1 percent compared to 6.4 percent on December 31, 2003.


	Provision for Income Taxes

2005 income tax expense of $1.6 billion was $590 million higher than 2004. The additional income tax expense was driven by higher taxable income related to the increased oil and gas revenues in 2005, compared to 2004. Our effective tax rate was 37.62 percent in 2005 compared to 37.29 percent in 2004. Currency fluctuations added $13 million of additional deferred tax expense to 2005 and $58 million to 2004.

Income tax expense in 2004 of $993 million was $166 million or 20 percent higher than 2003. The higher taxes were primarily associated with higher income driven by higher oil and gas production revenues in 2004 compared to 2003. Our effective tax rate was 37.29 percent in 2004 compared to 43.02 percent in 2003. The 2003 effective tax rate included $172 million of additional deferred tax expense because of currency fluctuations compared to $58 million in 2004. For a discussion of Apache’s sensitivity to foreign currency fluctuations, please refer to Item 7A, Quantitative and Qualitative Disclosures about Market Risk, “Foreign Currency Risk” of this Form 10-K.

Capital Resources and Liquidity

Financial Indicators


	At December 31,

	2005			2004			2003
*Millions of dollars except as indicated*
Current ratio		.99			1.05			1.10
Net cash provided by operating activities	$	4,332		$	3,232		$	2,706
Total debt		2,192			2,588			2,327
Shareholders’ equity		10,541			8,204			6,533
Percent of total debt to capitalization		17	%		24	%		26	%
Floating-rate debt/total debt		—			15	%		6	%

Overview

Apache’s primary uses of cash are exploration, development and acquisition of oil and gas properties, costs and expenses necessary to maintain continued operations, repayment of principal and interest on outstanding debt and payment of dividends.

Our business, as with other extractive industries, is a depleting one in which each barrel produced must be replaced or the Company, and a critical source of our future liquidity, will shrink. Cash investments are continuously required to fund exploration and development projects and acquisitions which are necessary to offset the inherent declines in production and proven reserves. See Item 1 and 2, Business and Properties, “Risks Factors,” in this Form 10-K. Future success in maintaining and growing reserves and production will be highly dependent on having adequate capital resources available, on our success in both exploration and development activities and on acquiring additional reserves.

Our year-end reserve life index indicates an average decline of 7.8 percent per year. This projection is based on prices at year-end, except in those instances where future natural gas and oil sales are covered by physical contract terms providing for higher or lower prices, estimates of investments required to develop estimated proved undeveloped reserves, costs and taxes reflected in our standardized measure in Note 14, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K.

The Company funds its exploration and development activities primarily through net cash provided by operating activities (cash flow) and budgets capital expenditures based on projected cash flow. Our cash flow, 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, we only forecast, for internal use by management, an annual

cash flow. Longer-term cash flow and capital spending projections are not used by management to operate our business. The annual cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.

The Company has historically utilized internally generated cash flow, committed and uncommitted credit facilities and access to both debt and equity capital markets for all other liquidity and capital resources needs. Apache’s ability to access the debt capital market is supported by its investment grade credit ratings. Because of the liquidity and capital resources alternatives available to Apache, including internally generated cash flows, Apache’s management believes that its short-term and long-term liquidity is adequate to fund operations, including its capital spending program, repayment of debt maturities and any amounts that may ultimately be paid in connection with contingencies.

Apache’s senior unsecured debt is currently rated investment grade by Moody’s, Standard and Poor’s and Fitch with ratings of A3, A- and A, respectively.

The Company’s ratio of current assets to current liabilities was .99 on December 31, 2005 compared to 1.05 at the end of 2004. Current liabilities increased 70 percent ($904 million) in 2005 versus a 60 percent ($813 million) increase in current assets. While virtually all meaningful current asset and current liability categories increased in 2005, changes in the North Sea PRT liability, our current portion of derivative liabilities, and current ARO liabilities particularly impacted the ratio. The North Sea PRT liability, which is a component of “Other” current liabilities, increased approximately $171 million compared to the prior year. The current portion of FMV of derivatives increased nearly $235 million, which is eleven times the 2004 amount. Both the PRT and derivative liabilities reflect the impact of higher commodity prices. The current ARO liability of $94 million was established in 2005 because of damage caused by Hurricanes Katrina and Rita. Collectively, the increases in liabilities more than offset the higher current asset balances. Current receivables were up $505 million, or 54 percent, most of which related to oil and gas receivables impacted by commodity prices. Cash more than doubled to $229 million. Drilling advances, up 76 percent, and prepaid assets and other, up 130 percent, were other asset categories that also increased substantially. The drilling advance amount is in line with increased drilling activity in 2005 compared to 2004. The change in prepaid assets and other relates to higher taxes and other deposits.

Net Cash Provided by Operating Activities

Apache’s net cash provided by operating activities during 2005 totaled $4.3 billion, up from $3.2 billion in 2004. The increase in 2005 cash flow was attributed primarily to the significant increase in commodity prices. The Company’s average realized oil and natural gas prices increased 47 percent and 29 percent, respectively; a reflection of higher worldwide commodity prices. Higher production also added to our 2005 cash flow relative to 2004, albeit to a much less extent. These increases in cash flow were partially offset by higher production costs attributable to the effect of increased commodity prices, costs related to Hurricanes Katrina and Rita and an increase in exchange rates in Canada. The Company reviews production costs for each core area on a monthly basis and pursues alternatives in maintaining efficient levels of costs and expenses. For a more detailed discussion of commodity prices, production, costs and expenses, please refer to the Results of Operations section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Apache’s net cash provided by operating activities during 2004 totaled $3.2 billion, up from $2.7 billion in 2003. The increase in 2004 cash flow was primarily attributed to the significant increase in commodity prices. The Company’s averaged realized oil and natural gas prices increased 27 and 7 percent, respectively; a reflection of higher worldwide commodity prices. Higher production also increased our 2004 cash flow on a 13 percent and one percent increase in oil and natural gas production, respectively. These increases were partially offset by higher production costs attributable to the effect of increased commodity prices, an increase in exchange rates in Canada, North Sea and Australia, costs related to Hurricane Ivan and increases in costs from our stock-based employee incentive programs.

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

Debt

During 2005, we continued to strengthen our financial flexibility and to build on the solid financial positions of previous years. We exited 2005 with a debt-to-capitalization ratio of 17 percent, a decrease of seven percent from year-end 2004, with lower debt and increases in equity resulting from earnings. At year-end 2005 the Company had long-term debt of $2.2 billion, $396 million lower than year-end 2004, as the Company’s capital spending was less than internally generated cash flow. The Company’s outstanding debt consisted of notes and debentures maturing in the years 2006 through 2096. Approximately $.3 million, $173 million, $.4 million, $100 million and $1.9 billion mature in 2006, 2007, 2008, 2009 and thereafter, respectively. During 2005, the Company maintained its senior unsecured long-term debt ratings of A3 from Moody’s, A- from Standard and Poor’s and A from Fitch.

The Company has a $1.2 billion commercial paper program which enables Apache to borrow funds for up to 270 days at competitive interest rates. There was no commercial paper outstanding as of December 31, 2005. The commercial paper balance of $392 million on December 31, 2004 was classified as long-term debt in the accompanying consolidated balance sheet as the Company had the ability and intent to refinance such amount on a long-term basis through either the rollover of commercial paper or available borrowing capacity under its U.S. credit facilities. The weighted-average interest rate for commercial paper was 3.03 percent in 2005 and 1.79 percent in 2004.

As of December 31, 2005, available borrowing capacity under our credit facilities was $1.5 billion. We had $229 million in cash and cash equivalents on hand on December 31, 2005, compared to $111 million on December 31, 2004.

On May 12, 2005, the Company entered into a new $450 million revolving bank credit facility for the U.S., a $150 million revolving bank credit facility for Australia and a $150 million revolving bank credit facility for Canada. These new facilities replaced the Company’s existing credit facilities in the same amounts which were scheduled to mature in June 2007. These new facilities are scheduled to mature on May 12, 2010. There were no changes to the Company’s $750 million U.S. credit facility which matures in May 2009.

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., Canada and Australia of up to five percent of the Company’s consolidated assets, which approximated $964 million on December 31, 2005. There are no restrictions on incurring liens in countries other than the U.S., Canada and Australia. 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.

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., Canadian and Australian 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, 2005.

Stock Transactions

The Company periodically uses access to equity capital markets to fund significant acquisitions. On January 22, 2003, in conjunction with the BP transaction, we completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters’ over-allotment option, for net proceeds of $554 million. The Company currently has no plans to access equity capital markets.

On December 18, 2003, we announced that holders of our common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004.

Oil and Gas Capital Expenditures

The Company funded its exploration and production (E&D) capital expenditures, including Gathering, Transportation and Marketing (GTM) facilities, of $3.8 billion, $2.5 billion and $1.5 billion in 2005, 2004 and 2003, respectively, primarily with internally generated cash flow of $4.3 billion, $3.2 billion and $2.7 billion.

The Company uses a combination of internally generated cash flow, borrowings under the Company’s lines of credit and commercial paper program and, from time to time, issues of public debt or common stock to fund its significant acquisitions. During the three-year period presented, the Company primarily used internally generated cash flow or its lines of credit and commercial paper program; which were subsequently paid down with internally generated cash flow. However, in 2003, in conjunction with the BP acquisition, the Company completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters’ over-allotment option, for net proceeds of $554 million.

The following table presents a summary of the Company’s Capital Expenditures for each of our reportable segments for the past three years.


		Year Ended December 31,

		2005		2004		2003

		(In thousands)
Exploration and Development:
	United States	$	1,072,040	$	755,056	$	417,701
	Canada		1,188,096		756,912		568,856
	Egypt		352,324		301,912		242,652
	Australia		217,816		138,694		128,261
	North Sea		489,072		362,054		60,204
	Other International		48,484		26,493		35,098

		$	3,367,832	$	2,341,121	$	1,452,772

Capitalized Interest		$	56,988	$	50,748	$	52,891

Gas Gathering Transmission and Processing Facilities		$	392,872	$	138,738	$	38,533

Acquisitions:
	Oil and gas properties	$	39,228	$	1,063,851	$	1,568,106
	Gas gathering, transmission and processing facilities		—		—		5,484

		$	39,228	$	1,063,851	$	1,573,590

The Company completed its most active year to-date, drilling 2,383 wells throughout 2005 and spending nearly $400 million on oil and gas processing facilities and pipelines. Approximately two-thirds of our 2005 exploration and development expenditures were invested in Canada and the U.S., where nearly 69 percent of Apache’s 2005 year-end estimated proved reserves reside. Once again, Canada was our most active region, drilling 1,674 wells with a 93 percent success rate. Approximately 82 percent of Canada’s 2005 wells were shallow development wells. Canada was also very active in the North Grant Lands, undeveloped acreage Apache obtained through two farm-in agreements with ExxonMobil. Canada spent nearly $180 million

constructing 11 gas processing plants, six of which were completed by the end of 2005. In the Gulf Coast region, even with the disruptions caused by the Gulf of Mexico hurricanes, we drilled 114 wells, including 66 offshore. Seventy-seven percent of our Gulf Coast wells were productive. Our focus in the Gulf Coast region remained the same as 2004, development and exploitation of our existing asset base including the Gulf of Mexico properties acquired from Anadarko in the second half of 2004. The Central region was the second most active region, drilling 364 wells, with a 97 percent success rate. In the North Sea, we drilled a total of 23 wells, 18 Forties Field wells, and invested approximately $198 million of maintenance capital to continue to improve the operating efficiency of the Forties Field. We expect to complete the Forties power generation and gas ring by the summer of 2006, which will greatly reduce fuel oil generating costs and improve production reliability. In Egypt, we had another active and successful exploration and development program, drilling 121 wells of which 86 percent were productive. We also continued development of the Qasr field, where gross production average 128 MMcf/d in December 2005. In Australia, we participated in drilling 36 wells; 26 exploration wells and 10 development wells. China’s capital expenditures were flat compared to 2004 as they continued their development drilling program. The Company spent $39 million on acquisitions in 2005 compared to $1.1 billion in 2004, as the high-price commodity market in 2005 limited the number of attractive acquisition opportunities. Those that were pursued were slated to close in the first quarter of 2006. Acquisition expenditures typically vary year to year based on the availability of opportunities that fit Apache’s overall strategy.

In 2004, Apache drilled 1,735 wells and completed two significant acquisitions. In the Gulf of Mexico, the majority of our activity focused in and around our existing asset base, including continued exploitation of the properties purchased from BP and Shell in 2003 and the Anadarko properties purchased in 2004. In the Central region, where Apache got its start, estimated proved reserves increased 20 percent in 2004 through a combination of the ExxonMobil acquisition and an active drilling year, completing 268 of 283 wells in the region. Canada was our most active area in 2004 with over 1,300 wells drilled, three-fourths of which were shallow development wells, with over 92 percent completed as producers. At the Forties Field, an experienced workforce began tackling projects to extend the life of the largest field discovered in the United Kingdom sector of the North Sea. Production increases at Forties — the anchor of Apache’s newest core area — were driven by Apache’s first drilling program since acquiring the field and a maintenance program aimed at improving efficiency of the field. During 2004, Apache completed 12 of 17 wells drilled as part of a $362 million capital program, including $150 million of maintenance and operations capital expenditures. In Egypt and Australia, Apache continued its successful exploration programs with several new discoveries. Our continuing development program in Egypt increased gross production to over 100,000 b/d for the first time. Capital expenditures in China decreased in 2004 with the completion of production facilities and first production in the second half of 2003. In 2004, Apache added 444.7 MMboe of estimated proved reserves through acquisitions, drilling and revisions. During 2004, GTM expenditures included additional gathering system pipelines in Egypt and a gas plant expansion on Varanus Island in Australia.

For 2006, we plan another active year of drilling. Because we revise our estimates of exploration and development capital expenditures frequently throughout the year based on industry conditions and results to date, accurately projecting future expenditures is difficult at best. However, our 2006 preliminary estimate of exploration and development capital and oil and gas processing facilities and pipelines is in excess of $3.7 billion. We generally do not project estimates for acquisitions because their timing is unpredictable; however, in early 2006 we closed an acquisition announced in late 2005. Also, on January 17, 2006, the Company announced an agreement with Pioneer Natural Resources. Please refer to the Subsequent Acquisitions and Divestiture section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. We continually look for properties which we believe will add value and earn adequate rates of return and will take advantage of those opportunities as they arise.

Cash Dividend Payments

The Company has paid cash dividends on its common stock for 41 consecutive years through 2005. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other relevant factors. Common dividends paid during 2005 rose 32 percent to $112 million, reflecting the increase

in common shares outstanding and the higher common stock dividend rate. The Company increased its quarterly cash dividend 25 percent, to 10 cents per share from eight cents per share, effective with the November 2005 dividend payment.

During 2005 and 2004, Apache paid a total of $6 million in dividends each year on its Series B Preferred Stock issued in August 1998. See Note 8, Capital Stock of Item 15 in this Form 10-K. Common dividends paid during 2004 rose 26 percent to $85 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate.

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. The following table summarizes the Company’s contractual obligations as of December 31, 2005. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for further information regarding these obligations.


	Note
Contractual Obligations	Reference		Total		2006		2007		2008		2009		2010		Thereafter

	(In thousands)
Debt		Note 5	$	2,192,228	$	274	$	172,678	$	353	$	99,733	$	—	$	1,919,190
Operating leases and other commitments		Note 10		503,724		226,410		136,070		43,026		18,736		16,421		63,061
International lease commitments		Note 10		222,463		33,533		106,714		24,154		58,062		—		—
Operating costs associated with pre-existing volumetric production payments on acquired properties		Note 2		70,145		37,815		24,088		8,242		—		—		—

Total Contractual Obligations(a)(b)			$	2,988,560	$	298,032	$	439,550	$	75,775	$	176,531	$	16,421	$	1,982,251


(a)		This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1.5 billion. The Company records a separate liability for the fair value of this asset retirement obligation. 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 pension or postretirement benefit obligations. See Note 10, Commitments and Contingencies 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 any impact on future liquidity. Such obligations include environmental contingencies and potential settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations. The Company has reserved approximately $11 million for environmental remediation. The Company has also reserved approximately $12 million for various legal liabilities, in addition to the $71 million, plus interest, we accrued for the Texaco China B.V. litigation. See Note 10, 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 accrued approximately $22 million as of December 31, 2005, 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.

As discussed under Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache assumed obligations for pre-existing VPPs in the 2004 acquisition of properties from Anadarko and the 2003 acquisition of properties from Shell. Under the terms of the VPP agreements, Apache is scheduled to deliver a total of 7.8 MMboe in 2006, 4.7 MMboe in 2007 and 1.6 MMboe in 2008 to Morgan Stanley as owner of the VPP interests. Morgan Stanley is entitled to the first production and may demand up to 90 percent of the production from the assets encumbered by each VPP in any given month to satisfy the VPP interests. However, they have no right to look to other assets or production of Apache. Apache does not record the reserves and production volumes attributable to the VPPs. As of December 31, 2005, Apache has booked a total of 93.5 MMboe of reserves attributable to the Anadarko and Shell transactions. The VPPs are non-operating interests, free of costs incurred for operations and production. Apache provided a liability for these costs as reflected in the preceding table.

Upon closing of our 2003 acquisition of the North Sea properties, Apache assumed BP’s abandonment obligation for those properties and such costs were considered in determining the purchase price. The purchase of the properties, however, did not relieve BP of its liabilities if Apache fails to satisfy the abandonment obligation. Although not currently required, to ensure Apache’s payment of these costs, Apache agreed to deliver a letter of credit to BP if the rating of our senior unsecured debt is lowered by both Moody’s and Standard and Poor’s from the Company’s current ratings of A3 and A-, respectively. Any such letter of credit would be in an amount equal to the net present value of future abandonment costs of the North Sea properties as of the date of any such ratings change. If Apache is required to provide a letter of credit, it will expire if either rating agency restores its rating to the present level. The letter of credit amount would be 127 million British pounds, an amount that represents the letter of credit requirement through March 2006, and will be negotiated annually based on Apache’s future abandonment obligation estimates.

The Company’s future liquidity could be impacted by a significant downgrade of its credit ratings by Standard and Poor’s and Moody’s; however, we do not believe that such a sharp downgrade is reasonably likely. The Company’s credit facilities do not require the Company to maintain a minimum credit rating. The negative covenants associated with our debt are outlined in greater detail under “Capital Resources and Liquidity, Debt” in this section of this Form 10-K. In addition, generally under our commodity hedge agreements, Apache may be required to post margin or terminate outstanding positions if the Company’s credit ratings decline significantly.

Off-Balance Sheet Arrangements

Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions. Apache entered into a partnership with ExxonMobil to obtain additional interests in specific West Texas and New Mexico oil & gas properties acquired from ExxonMobil in September 2004. As discussed in Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache contributed $29 million into this partnership which was determined to be a variable interest entity as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46 “Variable Interest Entities.” Apache concluded that they were not the primary beneficiary of the partnership and, therefore, proportionately consolidated only the Company’s portion of the oil and gas properties.

Critical Accounting Policies and Estimates

Full-Cost Method of Accounting for Oil and Gas Operations

The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Under the successful-efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to their respective full-cost pool. In the measurement of impairment of oil and gas properties, the

successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect on the last day of the reporting period (ceiling limitation). If the full-cost pool is in excess of the ceiling limitation, the excess amount is charged through income.

We have elected to use the full-cost method to account for our investment in oil and gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs for the purpose of finding oil and gas reserves, including salaries, benefits and other internal costs directly attributable to these finding activities. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. As a result, we believe that the full-cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful-efforts method of accounting for our oil and gas investments. Generally, the application of the full-cost method of accounting for oil and gas property results in higher capitalized costs and higher DD&A rates compared to similar companies applying the successful efforts methods of accounting.

Reserve Estimates

Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. 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.

We engage an independent petroleum engineering firm to review our estimates of proved hydrocarbon liquid and gas reserves. During 2005, 2004 and 2003, their review covered 74, 79 and 78 percent of the reserve value, respectively.

Costs Excluded

Under the full-cost method of accounting, oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. Apache excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly by the Company’s accounting, exploration and engineering staffs to determine if impairment has occurred. Nonproducing leases are evaluated based on the progress of the Company’s exploration program to date. Exploration costs are transferred to the DD&A pool upon completion of drilling individual wells. If geological and geophysical (G&G) costs cannot be associated with specific properties, they are included in the amortization base as incurred. The amount of any impairment is transferred to the capitalized costs being

amortized (the DD&A pool) or a charge is made against earnings for those international operations where a proved reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate for that country. For international operations where a reserve base has not yet been established, all costs associated with a prospect or play would be considered quarterly for impairment upon full evaluation of such prospect or play. This evaluation considers among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions.

Allowance for Doubtful Accounts

We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. Many of our receivables are from joint interest owners on properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Our crude oil and natural gas receivables are typically collected within two months. We accrue 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.

Beginning in 2001, we experienced a gradual decline in the timeliness of receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic conditions in Egypt lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. During 2005, we experienced wide variability in the timing of cash receipts, but our past due balance improved as of December 31, 2005. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and have no indication that we will not be able to collect our receivable.

Asset Retirement Obligation

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 regulations 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. Prior to 2003, under the full-cost method of accounting, as described in the preceding critical accounting policy sections, the estimated undiscounted costs of the abandonment obligations, net of the value of salvage, were included as a component of our depletion base and expensed over the production life of the oil and gas properties.

In 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” Apache adopted this statement effective January 1, 2003, as discussed in Note 4, Asset Retirement Obligation of Item 15 of this Form 10-K. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, the new statement requires the Company to record a separate liability for the discounted present value of the Company’s asset retirement obligations, with an offsetting increase to the related oil and gas properties on the balance sheet. As such, beginning in 2003 our depletion expense is reduced since we will deplete a discounted ARO rather than the undiscounted value previously depleted in our oil and gas property base. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which reflects increases in the discounted asset retirement obligation over time.

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, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing Asset Retirement Obligation 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 seven 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.

Derivatives

Apache uses derivative contracts on a limited basis to manage its exposure to oil and gas price volatility and foreign currency volatility. The Company accounts for the contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The estimated fair values of Apache’s derivative contracts within the scope of this statement are carried on the Company’s consolidated balance sheet. For oil and gas derivative contracts designated and qualifying as cash flow hedges, realized gains and losses are recognized in oil and gas production revenues when the forecasted transaction occurs. For foreign currency forward contracts designated as qualifying as cash flow hedges, realized gains and losses are generally recognized in lease operating expense when the forecasted transaction occurs. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be “marked-to-market” and reported in current period income, rather than in the period in which the hedged transaction is settled. Realized gains and losses on derivative contracts not qualifying as cash flow hedges are reported in “Other” under “Revenues and Other” of the Statement of Consolidated Operations.

The fair value estimate of Apache’s derivative contracts requires judgment; however, the Company’s derivative contracts are either exchange traded or valued by reference to commodities and currencies that are traded in highly liquid markets. As such, the ultimate fair value is determined by references to readily available public data. Option valuations are verified against independent third-party quotations. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, “Commodity Risk” in this Form 10-K for commodity price sensitivity information and the Company’s policies related to the use of derivatives.

Stock-Based Compensation

During 2002, Apache began modifying its stock compensation plans in order to reflect the cost of these plans in the Statement of Consolidated Operations. As part of this effort, Apache began issuing stock appreciation rights and restricted stock and, effective January 1, 2003, adopted the expense provisions of SFAS No. 123 “Accounting for Stock Based Compensation,” as amended, on a prospective basis for all stock options granted under the Company’s existing option plans. Consistent with the Company’s desire to reflect the ultimate cost of stock compensation plans on the income statement, Apache early adopted the provisions of SFAS No. 123-R “Share-Based Payment” upon the FASB’s issuance of the revised statement in the fourth quarter 2004.

Upon adoption of SFAS No. 123-R, all stock based compensation awards that vested during 2004 are now reflected in the Company’s net income for the year. Awards that vested in prior years continue to be

reflected in the income statement under the accounting guidelines in place for the applicable year. Awards granted in future periods will be valued on the date of grant and expensed using a straight-line basis over the required service period. Pro-forma income statement presentations have been provided for in Note 1. Summary of Significant Accounting Policies of Item 15 in this Form 10-K to present a comparative basis of all plans outstanding during the reported periods.

The Company chose to adopt the statement under the “Modified Retrospective” approach as prescribed under SFAS No. 123-R. Under this approach, the Company is required to expense all options and stock-based compensation that vested during the year of adoption based on the fair value of the stock compensation determined on the date of grant. Had the Company not early adopted SFAS No. 123-R under this transition approach, 2004 net income would have been lower by $89 million ($56 million after tax) or $.17 per diluted share. Normally, net income would be negatively impacted by adopting SFAS No. 123-R under this transition method. However, the Company’s Share Appreciation Plan, which triggered in 2004, has a fair market value-based expense recorded under the provisions of SFAS No. 123-R that is substantially less than the intrinsic value cost that would have been recorded under the provisions of APB Opinion No. 25. Please refer to Note 8, Capital Stock of Item 15 of this Form 10-K for a detailed description of the Share Appreciation Plan and costs associated with our stock compensation plans.

Also, inherent in expensing stock options and other stock-based compensation under SFAS No. 123-R are several judgments and estimates that must be made. These include determining the underlying valuation methodology for stock compensation awards and the related inputs utilized in each valuation, such as the Company’s expected stock price volatility, expected term of the employee option, expected dividend yield, the expected risk-free interest rate, the underlying stock price and the exercise price of the option. Changes to these assumptions could result in different valuations for individual share awards and will be carefully scrutinized for each material grant. For option valuations, Apache utilizes the Black-Scholes option pricing model, however, the Company does run lattice models to verify that the assumptions used are reasonable. For valuing the Share Appreciation Awards, the Company utilizes a Monte Carlo simulation model developed by a third party.


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

The major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to our United States and Canadian natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. Monthly oil price realizations, including the impact of fixed-price contracts and hedges, ranged from a low of $42.63 per barrel to a high of $61.31 per barrel during 2005. Average gas price realizations, including the impact of fixed-price contracts and hedges, ranged from a monthly low of $5.16 per Mcf to a monthly high of $8.02 per Mcf during the same period. Based on the Company’s 2005 worldwide oil production levels, a $1.00 per barrel change in the weighted-average realized price of oil would increase or decrease revenues by $85 million. Based on the Company’s 2005 worldwide gas production levels, a $.10 per Mcf change in the weighted-average realized price of gas would increase or decrease revenues by $46 million.

If oil and gas prices decline significantly, even if only for a short period of time, it is possible that non-cash write-downs of our oil and gas properties could occur under the full-cost accounting method allowed by the Securities Exchange Commission (SEC). Under these rules, we review the carrying value of our proved oil and gas properties each quarter on a country-by-country basis to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization, and deferred income taxes do not exceed the “ceiling.” This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this ceiling, the excess is charged to additional DD&A expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under

long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows.

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. As indicated in Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K, the Company entered into several derivative positions in conjunction with our 2003 and 2004 acquisitions. These positions were entered into to preserve our strong financial position in a period of cyclically high oil and gas prices and were designated as cash flow hedges of anticipated production.

Apache has historically only hedged long-term oil and gas prices related to a portion of its expected production associated with acquisitions. As such, the Company’s use of hedging activity remains at a correspondingly low level. In 2005, financial derivative hedges represented approximately nine percent of the total worldwide natural gas production and six percent of the total worldwide crude oil production. Heading into 2006, hedges in place are entirely related to U.S. production and will represent approximately seven percent of worldwide production for natural gas and crude oil.

On December 31, 2005, the Company had open natural gas derivative positions with a fair value of $(260) million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $64 million, while a 10 percent decrease in prices would increase the fair value by approximately $63 million. The Company also had open crude oil derivative positions with a fair value of $(148) million. A 10 percent change in oil prices would change the fair value by plus or minus $37 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2005. 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 Chief Financial Officer, Controller, 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.

Governmental Risk

Apache’s U.S. and international operations have been, and at times in the future may be, affected by political developments and by federal, state and local laws and regulations impacting production levels, taxes, environmental requirements and other assessments including a potential Windfall Profits Tax.

The Company anticipates that announced changes to the taxation scheme in the North Sea will impact that region’s results. Primarily, the corporate tax rate in the North Sea is expected to increase 10 percent to an effective rate of 50 percent. Once the announcement is ratified, the new rate change will be effective as of January 1, 2006.

Weather and Climate Risk

equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.

Foreign Currency Risk

The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts and gas production is sold under fixed-price Australian dollar contracts. Over half the costs incurred for Australian operations are paid in Australian 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 contrast, all oil and gas production in Egypt is sold for U.S. dollars and the majority of the costs incurred are denominated in U.S. dollars. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars and British pounds are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date.

A 10 percent strengthening of the Australian and Canadian dollars and the British pound as of December 31, 2005 would result in a foreign currency net loss of approximately $128 million. This is primarily driven from foreign currency effects on the Company’s deferred tax liability positions in Canada and Australia. The Company began hedging a portion of its foreign exchange risk associated with lease operating expenditures in 2004. The Company’s treasury department administers this hedging program. The Company did not have any open hedging positions associated with lease operating expenditures as of December 31, 2005. For information on open derivative contracts, please see Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K.

Interest Rate Risk

As of December 31, 2005, the Company had no interest rate risk exposure since the Company did not have any floating-rate debt.

Forward-Looking Statements and Risk

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

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


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-64 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, 2005, 2004 and 2003, included in this report, have been audited by Ernst & Young LLP, independent public auditors, as stated in their audit report appearing herein.


ITEM 9A.	CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

G. Steven Farris, the Company’s President, Chief Executive Officer and Chief Operating Officer, and Roger B. Plank, the Company’s Executive Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2005, 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 were effective, providing effective means to insure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported in a timely manner. We also made no significant changes in internal controls over financial reporting during the quarter ending December 31, 2005 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 report.

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

Changes in Internal Control Over Financial Reporting

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


ITEM 9B.	OTHER INFORMATION

None.

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 2006 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 Investor Relations page of the Company’s website at http://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. 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 “Summary Compensation Table,” “Option/ SAR Exercises and Year-End Value Table,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements” and “Director Compensation” 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

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


ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information set forth under the caption “Independent 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:

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, 2005			F-4
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2005			F-5
Consolidated balance sheet as of December 31, 2005 and 2004			F-6
Statement of consolidated shareholders’ equity for each of the three years in the period ended December 31, 2005			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 February 5, 2004 (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, 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).


Exhibit
No.				Description

	4	.3	—	Form of Certificate for Registrant’s Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 001-4300).
	4	.4	—	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	.5	—	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).
	10	.1	—	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	.2	—	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	.3	—	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	.4	—	Form of Five-Year Credit Agreement, dated May 28, 2004, 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 Barclays Bank PLC and UBS Loan Finance LLC. as Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).


Exhibit
No.				Description

	10	.5	—	Form of First Amendment to Combined Credit Agreements, dated May 28, 2004, among Registrant, Apache Energy Limited, Apache Canada Ltd., the Lenders named therein, JP Morgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, and Citibank, N.A., as Global Documentation Agent (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).
	10	.6	—	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	.7	—	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	.8	—	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	.9	—	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	.10	—	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	.11	—	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	.12	—	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	.13	—	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	.14	—	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	.15	—	Apache Corporation 401(k) Savings Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 001-4300).


Exhibit
No.				Description

	†10	.16	—	Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 001-4300).
	*†10	.17	—	Amendment to Apache Corporation 401(k) Savings Plan, dated December 16, 2005.
	†10	.18	—	Apache Corporation Money Purchase Retirement Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 001-4300).
	†10	.19	—	Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 001-4300).
	†10	.20	—	Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
	†10	.21	—	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant’s Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000).
	†10	.22	—	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 001-4300).
	†10	.23	—	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004 (incorporated by reference to Exhibit 10.24 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	†10	.24	—	Apache Corporation 1990 Stock Incentive Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
	†10	.25	—	Apache Corporation 1995 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.26	—	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	.27	—	Apache Corporation 1996 Performance Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
	†10	.28	—	Apache Corporation 1998 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).


Exhibit
No.				Description

	†10	.29	—	Apache Corporation 2000 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.30	—	Apache Corporation 2003 Stock Appreciation Rights Plan, dated and effective May 1, 2003 (incorporated by reference to Exhibit 10.31 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	†10	.31	—	Apache Corporation 2005 Stock Option Plan, dated February 3, 2005 (incorporated by reference to Appendix B to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
	†10	.32	—	Apache Corporation 2005 Share Appreciation Plan, dated February 3, 2005 (incorporated by reference to Appendix C to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
	†10	.33	—	1990 Employee Stock Option Plan of The Phoenix Resource Companies, Inc., as amended through September 29, 1995, effective April 9, 1990 (incorporated by reference to Exhibit 10.33 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.34	—	Apache Corporation Income Continuance Plan, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.30 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, SEC File No. 001-4300).
	†10	.35	—	Apache Corporation Deferred Delivery Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	*†10	.36	—	Apache Corporation Executive Restricted Stock Plan, as amended and restated December 14, 2005, effective January 1, 2005.
	†10	.37	—	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.38	—	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.8 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.39	—	Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 5, 2004 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	†10	.40	—	Amended and Restated Employment Agreement, dated December 5, 1990, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.41	—	First Amendment, dated April 4, 1996, to Restated Employment Agreement between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.42	—	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	.43	—	Employment Agreement, dated June 6, 1988, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1989, SEC File No. 001-4300).


Exhibit
No.				Description

	†10	.44	—	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	.45	—	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	.46	—	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 Chief Executive Officer
	*31	.2	—	Certification of Chief Financial Officer
	*32	.1	—	Certification of Chief Executive Officer and Chief 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) Reports filed on Form 8-K


	The following current reports on Form 8-K were filed by the Company during the fiscal quarter ended December 31, 2005:

	ITEM 8.01 — Other Events — dated and filed October 13, 2005

	On October 13, 2005, Apache announced that it agreed to sell its interest in the deepwater section of Egypt’s West Mediterranean concession to Amerada Hess and that Apache agreed to purchase interests in eight fields located in the Permian Basin of West Texas and New Mexico from Amerada Hess.

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, thereunto duly authorized.


	APACHE CORPORATION

	/s/ G. STEVEN FARRIS

	G. Steven Farris
	President, Chief Executive Officer and
	Chief Operating Officer

Dated: March 10, 2006

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, Thomas L. Mitchell, and Jeffrey B. King, 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	Director, President, Chief Executive Officer and Chief Operating Officer (Principal Executive Officer)	March 10, 2006

/s/ ROGER B. PLANK Roger B. Plank	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 10, 2006

/s/ THOMAS L. MITCHELL Thomas L. Mitchell	Vice President and Controller (Principal Accounting Officer)	March 10, 2006

/s/ RAYMOND PLANK Raymond Plank	Chairman of the Board	March 10, 2006

/s/ FREDERICK M. BOHEN Frederick M. Bohen	Director	March 10, 2006

/s/ RANDOLPH M. FERLIC Randolph M. Ferlic	Director	March 10, 2006

/s/ EUGENE C. FIEDOREK Eugene C. Fiedorek	Director	March 10, 2006

/s/ A. D. FRAZIER, JR. A. D. Frazier, Jr.	Director	March 10, 2006


Name	Title	Date


/s/ PATRICIA ALBJERG GRAHAM Patricia Albjerg Graham	Director	March 10, 2006

/s/ JOHN A. KOCUR John A. Kocur	Director	March 10, 2006

/s/ GEORGE D. LAWRENCE George D. Lawrence	Director	March 10, 2006

/s/ F. H. MERELLI F. H. Merelli	Director	March 10, 2006

/s/ RODMAN D. PATTON Rodman D. Patton	Director	March 10, 2006

/s/ CHARLES J. PITMAN Charles J. Pitman	Director	March 10, 2006

/s/ JAY A. PRECOURT Jay A. Precourt	Director	March 10, 2006

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 of 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, 2005. 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, 2005.

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, management’s assessment of the effectiveness of the Company’s internal control over financial reporting 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
	President, Chief Executive Officer
	and Chief Operating Officer

	Roger B. Plank
	Executive Vice President and Chief Financial Officer

	Thomas L. Mitchell
	Vice President and Controller
	(Chief Accounting Officer)

Houston, Texas

March 10, 2006

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, 2005 and 2004, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 audit provides 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 as of December 31, 2005 and 2004 and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As described in Note 8 to the consolidated financial statements, during 2004, the Company adopted the modified prospective provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123(revised), “Share-Based Payment.” In addition, as described in Notes 1 and 4, effective January 1, 2003, the Company adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations” and the prospective provisions of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.”

We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2006 expressed an unqualified opinion thereon.


	ERNST & YOUNG LLP

Houston, Texas

March 10, 2006

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Apache Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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, 2005 and 2004, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 and our report dated March 10, 2006 expressed an unqualified opinion thereon.


	ERNST & YOUNG LLP

Houston, Texas

March 10, 2006

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS


			For the Year Ended December 31,

			2005			2004			2003

			(In thousands, except per common share data)
REVENUES AND OTHER:
	Oil and gas production revenues		$	7,457,291		$	5,308,017		$	4,198,920
	Other			126,953			24,560			(8,621	)

				7,584,244			5,332,577			4,190,299

OPERATING EXPENSES:
	Depreciation, depletion and amortization			1,415,682			1,222,152			1,073,286
	Asset retirement obligation accretion			53,720			46,060			37,763
	International impairments			—			—			12,813
	Lease operating costs			1,040,475			864,378			699,663
	Gathering and transportation costs			100,260			82,261			60,460
	Severance and other taxes			453,258			93,748			121,793
	General and administrative			198,272			173,194			138,524
	China litigation provision			—			71,216			—
	Financing costs:
		Interest expense		175,419			168,090			169,090
		Amortization of deferred loan costs		3,748			2,471			2,163
		Capitalized interest		(56,988	)		(50,748	)		(52,891	)
		Interest income		(5,856	)		(3,328	)		(3,290	)

				3,377,990			2,669,494			2,259,374

PREFERRED INTERESTS OF SUBSIDIARIES				—			—			8,668

INCOME BEFORE INCOME TAXES				4,206,254			2,663,083			1,922,257
	Provision for income taxes			1,582,524			993,012			827,004

INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE				2,623,730			1,670,071			1,095,253
	Cumulative effect of change in accounting principle, net of income tax			—			(1,317	)		26,632

NET INCOME				2,623,730			1,668,754			1,121,885
	Preferred stock dividends			5,680			5,680			5,680

INCOME ATTRIBUTABLE TO COMMON STOCK			$	2,618,050		$	1,663,074		$	1,116,205

BASIC NET INCOME PER COMMON SHARE:
	Before change in accounting principle		$	7.96		$	5.10		$	3.38
	Cumulative effect of change in accounting principle			—			—			.08

			$	7.96		$	5.10		$	3.46

DILUTED NET INCOME PER COMMON SHARE:
	Before change in accounting principle		$	7.84		$	5.04		$	3.35
	Cumulative effect of change in accounting principle			—			(.01	)		.08

			$	7.84		$	5.03		$	3.43

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,

				2005			2004			2003

				(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	2,623,730		$	1,668,754		$	1,121,885
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization			1,415,682			1,222,152			1,073,286
		Provision for deferred income taxes			598,927			444,906			546,357
		Asset retirement obligation accretion			53,720			46,060			37,763
		Amortization of deferred loan costs			3,748			2,471			2,163
		International impairments			—			—			12,813
		Cumulative effect of change in accounting principle, net of income tax			—			1,317			(26,632	)
		Other			48,526			39,694			32,923
	Changes in operating assets and liabilities, net of effects of acquisitions:
		(Increase) decrease in receivables			(504,038	)		(296,383	)		(94,295	)
		(Increase) decrease in inventories			11,295			(659	)		(4,216	)
		(Increase) decrease in drilling advances and other			(144,154	)		(35,761	)		(19,881	)
		(Increase) decrease in deferred charges and other			(26,454	)		(35,328	)		(29,520	)
		Increase (decrease) in accounts payable			97,447			182,454			68,176
		Increase (decrease) in accrued expenses			214,491			28,431			11,227
		Increase (decrease) in advances from gas purchasers			(22,108	)		(18,331	)		(16,246	)
		Increase (decrease) in deferred credits and noncurrent liabilities			(38,542	)		(18,258	)		(9,903	)

			NET CASH PROVIDED BY OPERATING ACTIVITIES		4,332,270			3,231,519			2,705,900

CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to property and equipment				(3,715,856	)		(2,456,488	)		(1,616,936	)
	Acquisition of ExxonMobil properties				—			(348,173	)		—
	Acquisition of Anadarko properties				—			(531,963	)		—
	Acquisition of BP properties				—			—			(1,140,156	)
	Acquisition of Shell properties				—			—			(203,033	)
	Proceeds from sales of oil and gas properties				79,663			4,042			58,944
	Other				(95,649	)		(78,431	)		(57,576	)

			NET CASH USED IN INVESTING ACTIVITIES		(3,731,842	)		(3,411,013	)		(2,958,757	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Long-term borrowings				153,368			544,824			1,780,870
	Payments on long-term debt				(549,530	)		(283,400	)		(1,613,362	)
	Dividends paid				(117,395	)		(90,369	)		(72,832	)
	Common stock activity				18,864			21,595			583,837
	Treasury stock activity, net				6,620			12,472			4,378
	Cost of debt and equity transactions				(861	)		(2,303	)		(5,417	)
	Repurchase of preferred interests of subsidiaries				—			—			(443,000	)
	Other				6,273			54,265			—

			NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(482,661	)		257,084			234,474

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					117,767			77,590			(18,383	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					111,093			33,503			51,886

CASH AND CASH EQUIVALENTS AT END OF YEAR				$	228,860		$	111,093		$	33,503

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,

			2005			2004

			(In thousands)
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	228,860		$	111,093
	Receivables, net of allowance			1,444,545			939,736
	Inventories			209,670			157,293
	Drilling advances			146,047			82,889
	Prepaid assets and other			132,955			57,771

				2,162,077			1,348,782

PROPERTY AND EQUIPMENT:
	Oil and gas, on the basis of full cost accounting:
		Proved properties		23,836,789			19,933,041
		Unproved properties and properties under development, not being amortized		795,706			777,690
	Gas gathering, transmission and processing facilities			1,359,477			966,605
	Other			312,970			284,069

				26,304,942			21,961,405
	Less: Accumulated depreciation, depletion and amortization			(9,513,602	)		(8,101,046	)

				16,791,340			13,860,359

OTHER ASSETS:
	Goodwill, net			189,252			189,252
	Deferred charges and other			129,127			104,087

			$	19,271,796		$	15,502,480


LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable		$	714,598		$	542,074
	Accrued operating expense			66,609			80,741
	Accrued exploration and development			460,203			341,063
	Accrued compensation and benefits			125,022			83,636
	Accrued interest			32,564			32,575
	Accrued income taxes			120,153			78,042
	Current debt			274			—
	Asset retirement obligation			93,557			—
	Derivative instruments			256,115			21,273
	Other			317,469			103,487

				2,186,564			1,282,891

LONG-TERM DEBT				2,191,954			2,588,390

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
	Income taxes			2,580,629			2,146,637
	Advances from gas purchasers			68,768			90,876
	Asset retirement obligation			1,362,358			932,004
	Derivative instruments			152,430			31,417
	Other			187,878			225,844

				4,352,063			3,426,778

COMMITMENTS AND CONTINGENCIES (Note 10)
SHAREHOLDERS’ EQUITY:
	Preferred stock, no par value, 5,000,000 shares authorized — Series B, 5.68% Cumulative Preferred Stock, 100,000 shares issued and outstanding			98,387			98,387
	Common stock, $0.625 par, 430,000,000 shares authorized, 336,997,053 and 334,912,505 shares issued, respectively			210,623			209,320
	Paid-in capital			4,170,714			4,106,182
	Retained earnings			6,516,863			4,017,339
	Treasury stock, at cost, 6,875,823 and 7,455,002 shares, respectively			(89,764	)		(97,325	)
	Accumulated other comprehensive loss			(365,608	)		(129,482	)

				10,541,215			8,204,421

			$	19,271,796		$	15,502,480

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, 2002						$	98,387	$	194,331	$	3,427,450	$	1,427,607		$	(110,559	)	$	(112,936	)	$	4,924,280
	Comprehensive income (loss):
		Net income	$	1,121,885			—		—		—		1,121,885			—			—			1,121,885
		Commodity hedges		(39,007	)		—		—		—		—			—			(39,007	)		(39,007	)

	Comprehensive income		$	1,082,878

	Cash dividends:
		Preferred					—		—		—		(5,680	)		—			—			(5,680	)
		Common ($.22 per share)					—		—		—		(72,200	)		—			—			(72,200	)
	Five percent common stock dividend						—		581		25,333		(25,914	)		—			—			—
	Common shares issued						—		12,906		579,107		—			—			—			592,013
	Treasury shares issued, net						—		—		4,109		—			5,390			—			9,499
	Other						—		—		2,008		—			—			—			2,008

BALANCE AT DECEMBER 31, 2003							98,387		207,818		4,038,007		2,445,698			(105,169	)		(151,943	)		6,532,798
	Comprehensive income (loss):
		Net income	$	1,668,754			—		—		—		1,668,754			—			—			1,668,754
		Commodity hedges		22,461			—		—		—		—			—			22,461			22,461

	Comprehensive income		$	1,691,215

	Cash dividends:
		Preferred					—		—		—		(5,680	)		—			—			(5,680	)
		Common ($.28 per share)					—		—		—		(91,433	)		—			—			(91,433	)
	Five percent common stock dividend						—		—		—		—			—			—			—
	Common shares issued						—		1,502		56,660		—			—			—			58,162
	Treasury shares issued, net						—		—		11,144		—			7,844			—			18,988
	Other						—		—		371		—			—			—			371

BALANCE AT DECEMBER 31, 2004							98,387		209,320		4,106,182		4,017,339			(97,325	)		(129,482	)		8,204,421
	Comprehensive income (loss):
		Net income	$	2,623,730			—		—		—		2,623,730			—			—			2,623,730
		Commodity hedges		(236,126	)		—		—		—		—			—			(236,126	)		(236,126	)

	Comprehensive income		$	2,387,604

	Cash dividends:
		Preferred					—		—		—		(5,680	)		—			—			(5,680	)
		Common ($.36 per share)					—		—		—		(118,526	)		—			—			(118,526	)
	Common shares issued						—		1,303		57,386		—			—			—			58,689
	Treasury shares issued, net						—		—		7,003		—			7,561			—			14,564
	Other						—		—		143		—			—			—			143

BALANCE AT DECEMBER 31, 2005						$	98,387	$	210,623	$	4,170,714	$	6,516,863		$	(89,764	)	$	(365,608	)	$	10,541,215

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


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 U.S. operating regions (Central and Gulf Coast) and a Canadian region. Approximately 69 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), offshore The People’s Republic of China (China) and in Argentina. In 2003, we ceased operations in Poland.

The Company’s future financial condition and results of operations will depend upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. The vast majority of the Company’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.

All share and per share information in these financial statements and notes thereto has been restated to reflect the two-for-one stock split in 2003. See Note 8, Capital Stock, for further discussion.

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 interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.

Cash Equivalents — The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.

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 which 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. However, beginning in 2001, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC). Deteriorating economic conditions in Egypt lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. During 2005, we experienced wide variability in the timing of cash receipts, but our past due balance improved at year-end. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and we have no indication that we will not be able to collect our receivable.

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, 2005 and 2004, the Company had an allowance for doubtful accounts of $22 million.

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 amortized cost. Investments in debt and equity securities classified as “available for sale” are recorded at fair value with unrealized gains and losses recognized in other comprehensive income, net of

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

income taxes. The Company utilizes the average-cost method in computing realized gains and losses, which are included in Revenues and Other in the consolidated statements of operations.

Inventories — Inventories consist principally of tubular goods and production equipment, stated at the lower of weighted-average cost or market, and oil produced but not sold, stated at the lower of cost (a combination of production costs and depreciation, depletion and amortization (DD&A) expense) or market.

Property and Equipment — The Company uses the full-cost method of accounting for its investment in oil and gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves, including salaries, benefits and other internal costs directly attributable to these 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 $141 million, $107 million and $65 million of these internal costs in 2005, 2004 and 2003, respectively. Costs associated with production and general corporate activities, however, are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. The Company also includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance (see Note 4, Asset Retirement Obligation). Unless a significant portion of the Company’s proved reserve quantities in a particular country are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized.

Apache computes the DD&A of oil and gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved properties are excluded from the amortizable base until evaluated. The cost of exploratory dry wells is transferred to proved properties and thus subject to amortization immediately upon determination that a well is dry in those countries where proved reserves exist. In countries where the Company has not booked proved reserves, all costs associated with a prospect or play are considered quarterly for impairment upon full evaluation of such prospect or play. This evaluation considers among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. If geological and geophysical (G&G) costs cannot be associated with specific properties, they are included in the amortization base as incurred.

In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If capitalized costs exceed this limit, the excess is charged as additional DD&A expense. The Company calculates future net cash flows by applying end-of-the-period prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Also, included in the estimated future net cash flows are Canadian provincial tax credits expected to be realized beyond the date at which the legislation, under its provisions, could be repealed. To date, the Canadian provincial governments have not indicated an intention to repeal this legislation. See Note 14, Supplemental Oil and Gas Disclosures (Unaudited) “Future Net Cash Flows” for a discussion on calculation of estimated future net cash flows.

In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 to provide guidance on how asset retirement obligations should impact the calculation of the ceiling test limitation on the amount of properties that can be capitalized. The guidance states that because asset retirement obligation costs are reflected in the property balance, the future net cash flow calculation should omit the expected abandonment costs to provide for a comparable basis. Apache previously included abandonment costs in its future net cash flow calculation, but adjusted the capitalized amounts by the accrued abandonment obligation. The Company’s adoption of SAB No. 106 did not have a material impact on financial results.

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

Unproved properties are assessed quarterly for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to proved properties. For international operations where a reserve base has not yet been established, the impairment is charged to earnings. Apache began impairing its unproved property costs in Poland in 2001, impairing $20 million ($12 million after tax) in 2002 and the remaining $13 million ($8 million after tax) in 2003.

Buildings, equipment and gas gathering, transmission and processing facilities 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 $467 million and $380 million at December 31, 2005 and 2004, respectively.

Goodwill — Goodwill totaled $189 million at December 31, 2005 and 2004, representing the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in the Fletcher Challenge Energy (Fletcher) and Repsol YPF (Repsol) 2001 acquisitions. Approximately $103 million and $86 million of goodwill remain in Canada and Egypt, respectively. Apache deemed the geographic areas to be the reporting unit. Goodwill of each reporting unit is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that would reduce the fair value of the reporting unit below its carrying amount. No impairment of goodwill was recognized during 2005, 2004 and 2003.

Accounts Payable — Included in accounts payable at December 31, 2005 and 2004, are liabilities of approximately $125 million and $116 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.

Revenue Recognition — 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 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 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, usually up to 40 percent, is available to the contractor partners to recover all operating and capital costs. The balance of the production is split among the contractor partners and EGPC on a contractually defined basis.

Apache began marketing its U.S. natural gas production in July 2003. As the Company’s production fluctuates because of operational issues, it is occasionally necessary for the Company 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

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

against the related sales proceeds totaled $158 million, $107 million and $41 million, for 2005, 2004 and 2003, respectively.

Derivative Instruments and Hedging Activities — Apache periodically enters into derivative contracts to manage its exposure to foreign currency risk and 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. Realized gains and losses on foreign currency cash flow hedges are generally recognized in lease operating expense 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.” 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 under Revenues and Other in the statement of consolidated operations.

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 would then reflect 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.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 its provision for income taxes, while all other foreign currency gains and losses are reflected in Revenues and Other. The Company recorded additional deferred tax expense of $13 million, $58 million and $172 million in 2005, 2004 and 2003, respectively (see Note 6, Income Taxes). Other foreign currency gains and losses in Revenues and Other netted to a gain of $11 million in 2005, and losses of $5 million and $2 million in 2004 and 2003, respectively.

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. Currency translation adjustment 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.

Insurance Coverage — The Company carries property damage insurance of $250 million per insurable event subject to a $7.5 million deductible per event. The policy is prorated down if total claims received by the insurer for a single event exceed $1 billion. As of December 31, 2005, the Company was advised by its insurance carrier that total claims for Hurricane Katrina would exceed the $1 billion limit, reducing the Company’s ultimate recoveries by approximately 50 percent, or $125 million. The Company was also advised that as of December 31, 2005, total estimated claims for Hurricane Rita would exceed the $1 billion limit, reducing the Company’s claims for Rita by approximately 20 percent. Based on current assessments by OIL, the Company expects to recover from OIL between $225 million and $250 million for both storms combined. The Company also carries another $100 million of casualty insurance under a separate commercial policy. The Company expects to recover the full $100 million on the commercial policy.

The Company also carries business interruption insurance to cover deferred and lost oil and natural gas production revenues. The business interruption insurance begins 60 days after the occurrence of an insurable event, subject to a daily limit of $750,000 per event and an aggregate limit of $150 million. Coverage is based on current market prices and began October 28, 2005 for shut-in production caused by Hurricane Katrina and November 22, 2005 for Hurricane Rita. The Company accrued claims in 2005 totaling $79 million, with the remainder of the aggregate $150 million limit available for 2006. Proceeds received from the Business Interruption Insurance are reflected in “Other” under “Revenues and Other” on the “Statement of Consolidated Operations” and are included in cash flows from operating activities.

Net Income Per Common Share — The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury stock method, that could occur if options were exercised and if 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 — On December 31, 2005, the Company had several stock-based employee compensation plans, which include the Stock Option Plans, the Performance Plan, the Share Appreciation Plans and restricted stock. These plans are defined and described more fully in Note 8, Capital Stock. The Company accounts for these plans under the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended and revised. Stock compensation awards granted are valued on the date of grant and are expensed using a straight-line basis over the required service period.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During the fourth quarter of 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123-R, a revision to SFAS No. 123, which requires all companies to expense stock-based compensation. The rule is effective for the first fiscal year that begins after June 15, 2005. Apache early adopted this statement in 2004 electing to transition under the “Modified Retrospective Approach” as allowed under SFAS No. 123-R. Under this approach, the Company is required to expense all options and stock-based compensation that vested in the year of adoption based on the fair value of the stock compensation determined at the date of grant. Stock vesting in years prior to 2004 was expensed in accordance with the rules applied by the Company during such period. Had the Company not early adopted SFAS No. 123-R, net income would have been lower by $89 million ($56 million after tax), or $.17 per share on both a basic and diluted per share basis. Normally, net income would be negatively impacted by adopting SFAS No. 123-R. However, the Company’s Share Appreciation Plan, which certain awards were triggered in 2004, has a fair-market-value-based expense recorded under the provisions of SFAS No. 123-R that is substantially less than the intrinsic-value base cost of approximately $175 million that would have been recorded under the old APB No. 25 accounting.

In addition to the expensing provisions discussed above, SFAS No. 123-R requires the Company to begin estimating expected future forfeitures under each stock compensation plan and to start valuing the Company’s liability-based compensation plan (Stock Appreciation Rights) under a fair value approach instead of the previously applied intrinsic valuation. The effects of changing the forfeiture estimates on existing stock plans and the valuation methodology for the Company’s liability plans resulted in Apache recording a Cumulative Effect of Change in Accounting Principle of $2.1 million ($1.3 million after tax). SFAS No. 123-R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow rather than as an operating cash flow as historically reported. The Company classified $27 million and $32 million as financing cash inflows in 2005 and 2004, respectively, that would have been classified as operating cash inflows had the Company not adopted the Statement.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For 2003, the Company applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock Based Compensation”, as amended by SFAS No. 148 prospectively to all awards granted, modified, or settled after January 1, 2003. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on income attributable to common stock and earnings per share for the year 2003 had the fair-value based provisions of SFAS No. 123-R been applied to all stock-based compensation.


			For the Year
			Ended
			December 31,
			2003

			(In thousands)
Income attributable to Common Stock, as reported			$	1,116,205
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects				2,644
Deduct: Total stock-based employee compensation expense determined under fair-value based method for all stock-based awards (see Note 8), net of related tax effects				(15,311	)

Pro forma Income Attributable to Common Stock			$	1,103,538

Net Income per Common Share:
	Basic:
		As reported	$	3.46
		Pro forma		3.42
	Diluted:
		As reported	$	3.43
		Pro forma		3.39

The stock appreciation rights, described in Note 8, Capital Stock, are not included in the table above because it is a cash-based liability plan already reflected in net income attributable to common stock. Similar to cash-based salaries and benefits, stock-based compensation directly attributable to acquisition, exploration and development activities are capitalized.

Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the U.S., requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related 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. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Apache evaluates its estimates and assumptions on a regular basis. 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. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. See Note 14, Supplemental Oil and Gas Disclosure (Unaudited).

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Impact of Recently Issued Accounting Standards — On December 21, 2004, the FASB issued Staff Position 109-1 (FSP No. 109-1), Application of FASB Statement No. 109 (SFAS No. 109) “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the Act). FSP No. 109-1 clarifies guidance that applies to the new tax deduction for qualified domestic production activities. When fully phased-in, the deduction will be up to nine percent of the lesser of “qualified production activities income” or taxable income. FSP No. 109-1 clarifies that the deduction should be accounted for as a special deduction under SFAS No. 109 and will reduce tax expense in the period or periods that the amounts are deductible on the tax return because the deduction is contingent on performing activities identified in the Act. As a result, companies qualifying for the special deduction will not have a one-time adjustment to deferred tax assets and liabilities in the period the Act is enacted. Tax benefits resulting from the new deduction are effective for the Company’s fiscal year ending December 31, 2005. The adoption of FSP No. 109-1 did not have a material impact on the Company’s financial statements.

In March 2005, the FASB issued FASB Interpretation Number 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations”. The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005 and application of the interpretation did not change how abandonment obligations are currently calculated by the Company.

In June 2005, the FASB ratified the consensus in Emerging Issue Task Force (EITF) Issue Number 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights”. EITF Issue Number 04-5 states that the general partner in a limited partnership is presumed to control the partnership and must consolidate the entity on its financial statements. The presumption of control and consolidation requirement may be overcome if the limited partners have substantive participating rights or have the ability to effectively liquidate the partnership. Application of this statement did not impact the Company’s consolidated financial statements.

In September 2005, the EITF reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” concluding that purchases and sales of inventory with the same party in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. Apache presents such purchase and sale activities related to its marketing activities on a net basis in its Statement of Consolidated Operations. The consensus reached on EITF Issue No. 04-13 did not have any impact on the Company’s consolidated financial statements.

Reclassifications — Certain other prior period amounts have been reclassified to conform with current year presentations.


2.	ACQUISITIONS AND DIVESTITURES

Subsequent Acquisitions


	Amerada Hess

On January 5, 2006 the Company completed its purchase of Amerada Hess’s interest in eight fields located in the Permian Basin of West Texas and New Mexico for $269 million. Apache estimates that these fields had proved reserves of 27 million barrels of liquid hydrocarbons and 27 billion cubic feet of natural gas as of year-end 2005. The Company had previously announced on October 13, 2005 that it had agreed to purchase Amerada Hess’s interest for $404 million. The number of properties involved and price were reduced as a result of third parties exercising their preferential rights.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 first announced this transaction on October 13, 2005. Apache did not have any oil and gas reserves recorded for these properties at year-end 2005.


	Pioneer Natural Resources

2005 Acquisitions

During 2005, Apache completed numerous minor acquisitions totaling $39 million. These acquisitions added approximately 7.8 MMboe to the Company’s proved reserves.

2004 Acquisitions

ExxonMobil

During the third quarter of 2004, Apache entered into separate arrangements with Exxon Mobil Corporation and its affiliates (ExxonMobil) that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and the Gulf of Mexico-Outer Continental Shelf. Apache’s participation included cash payments of approximately $347 million, subject to normal post closing adjustments. The following details these transactions:

ExxonMobil — Western Canada In August 2004, Apache signed a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta. Under the agreement, Apache has the right to earn acreage sections by drilling an initial well on each such section. By drilling at least 250 wells during the initial two year earning period under the agreement, Apache will receive a one-year extension in which to earn additional sections. As to any sections earned by Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. Under certain circumstances, ExxonMobil has the right to convert its retained 35 percent working interest into a 12.5 percent overriding royalty. In addition, during the term of this agreement, Apache is required to carry ExxonMobil’s retained working interest with respect to certain drilling, capping, completion, equipping and tie-in costs associated with wells drilled on leasehold acreage.

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The partnership is subject to the provisions of FASB Interpretation 46 “variable interest entities” (FIN 46). Apache has concluded that it is not the primary beneficiary of the partnership as defined in that interpretation and will proportionately consolidate its partnership portion of the oil and gas properties. Apache’s maximum exposure to loss as a result of its involvement with the partnership was $55 million at December 31, 2005. Under the partnership agreement, the Company’s subsidiaries are also subject to environmental and legal claims that could arise in the ordinary course of business. Apache will operate the oil and gas properties under contract for the partnership.

Anadarko Petroleum

On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko Petroleum Corporation’s (Anadarko) Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields with approximately 70 percent of the production.

Prior to Apache’s purchase from Anadarko, Morgan Stanley Capital Group, Inc. (Morgan Stanley) paid Anadarko $646 million to acquire an overriding royalty interest in these properties. Anadarko’s sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP), the obligations of which Apache assumed along with its purchase. Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas production (20 MMboe) over four years beginning in October 2004. The VPP represents a non-operating interest that is free of costs incurred for operations and production. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP, but Morgan Stanley may look only to the acquired properties for delivery of the scheduled volumes. The VPP is scheduled to terminate on August 31, 2008, but may be extended if all scheduled VPP volumes have not been delivered to Morgan Stanley and the properties are still producing. The VPP includes restrictions on the Company’s ability to sell the properties subject to the VPP or resign as operator of VPP properties it currently operates. Upon termination of the VPP, all rights, titles and interests revert back to Apache. The Company does not record the reserves and production volumes attributable to the VPP.

The $537 million purchase price agreed to in the definitive agreement was subsequently adjusted for the exercise of preferential rights by third parties and other normal post-closing adjustments. After adjusting for these items, Apache paid $532 million for the properties and recorded estimated proved reserves of 60 million barrels of oil equivalent (boe), of which 50 percent was natural gas. In addition, an $84 million liability for the future cost to produce and deliver the VPP volumes was recorded by the Company. This liability will be settled through a reduction of lease operating expenses as the volumes are produced and delivered to Morgan Stanley. Apache also recorded abandonment obligations for the properties of approximately $134 million and other obligations assumed from Anadarko in the amount of $27 million. Apache allocated $122 million of the

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

purchase price to unproved property. The purchase price was funded by borrowings under the Company’s lines of credit and commercial paper program.

In 2004, the Company also completed other acquisitions for $73 million. These acquisitions added approximately 11 MMboe to the Company’s proved reserves.

2003 Acquisitions

On January 13, 2003, Apache announced that it had entered into agreements to purchase producing properties in the North Sea and Gulf of Mexico from subsidiaries of BP p.l.c. (BP) for $1.3 billion, with $670 million allocated to the Gulf of Mexico properties and $630 million allocated to properties in the North Sea. The properties included estimated proved reserves of 233.2 million barrels of oil equivalent (MMboe), 147.6 MMboe located in the North Sea with the balance in the Gulf of Mexico. Both purchase agreements were effective as of January 1, 2003. The exercise of preferential rights by third parties reduced the purchase price by $73 million and estimated reserves by 9.6 MMboe.

On July 3, 2003, Apache announced that it had completed the acquisition of producing properties on the outer Continental Shelf of the Gulf of Mexico from Shell Exploration and Production Company (Shell) for $200 million, subject to normal post-closing adjustments, including preferential rights. The acquisition included interests in 26 fields and interest in two onshore gas plants, and was effective July 1, 2003. Apache became operator of 15 of the fields with 91 percent of the production. At the time of the acquisition, Apache recorded estimated proved recoverable reserves of 124.6 billion cubic feet (Bcf) of natural gas and 6.6 million barrels of oil. Apache may be required to issue a letter of credit to BP to cover the present value of related asset retirement obligations if the rating of the Company’s senior unsecured debt is lowered by both Moody’s and Standard and Poor’s from its current ratings of A3 and A-, respectively. Should this occur, the letter of credit amount would be 127 million British pounds.

Prior to Apache’s transaction with Shell, Morgan Stanley paid Shell $300 million to acquire an overriding royalty interest in a portion of the reserves to be produced and delivered under a VPP agreement. Under the terms of the VPP obligation which Apache assumed, Morgan Stanley is to receive a total of 11.4 MMboe of production from the properties over the period from August 2003 through October 2007. Morgan Stanley may receive up to 90 percent of production associated with Apache’s interest, but may look only to the properties for delivery of the scheduled volumes. The VPP may be extended beyond October 2007 if all scheduled VPP volumes have not been delivered to Morgan Stanley and the acquired properties are still producing. The VPP represents a non-operating interest that is free of all costs related to operations and production. As a result of this VPP obligation, Apache assumed and recorded a $60 million liability for the future cost to produce and deliver volumes subject to the VPP. This liability is being settled through a reduction of lease operating expenses as the volumes are produced and delivered to Morgan Stanley. Apache does not record the reserves or production attributable to the VPP volumes. Apache’s purchase price was funded by borrowings under the Company’s lines of credit and commercial paper program.

In 2003, the Company also completed other acquisitions for $126 million. These acquisitions added approximately 28 MMboe to the Company’s proved reserves.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Acquisition Pro Forma

The following unaudited pro forma information shows the effect on the Company’s consolidated results of operations as if the acquisition from BP occurred on January 1, 2003. The pro forma information includes numerous assumptions, and is not necessarily indicative of future results of operations:


		For the Year Ended
		December 31, 2003

		As Reported		Pro Forma
(Unaudited)
		(In thousands, except per
		common share data)
Revenues and other		$	4,190,229	$	4,428,261
Net income			1,121,885		1,195,082
Preferred stock dividends			5,680		5,680
Income attributable to common stock			1,116,205		1,189,402
Net income per common share:
	Basic	$	3.46	$	3.68
	Diluted		3.43		3.64
Average common shares outstanding(1)			322,498		323,583


(1)	Pro forma shares assume the issuance of 19.8 million common shares as of January 1, 2003.

Each transaction described above has been accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Apache since the date of acquisition.

Divestitures

During 2005, Apache also sold marginal properties containing 11.8 MMboe of proved reserves, for $80 million. Apache used the sales proceeds to reduce bank debt.

During 2004, Apache sold marginal properties containing ..5 MMboe of proved reserves, for $4 million. Apache used the sales proceeds to reduce bank debt.

During 2003, Apache sold marginal properties containing 6.9 MMboe of proved reserves, for $59 million. Apache used the sales proceeds to reduce bank debt.


3.	HEDGING AND DERIVATIVE INSTRUMENTS

Apache uses a variety of strategies to manage its exposure to fluctuations in crude oil and natural gas commodity prices. As established by the Company’s hedging policy, Apache primarily enters into cash flow hedges in connection with selected acquisitions to protect against commodity price volatility. The success of these acquisitions is significantly influenced by Apache’s ability to achieve targeted production at forecasted prices. These hedges effectively reduce price risk on a portion of the production from the acquisitions.

Apache entered into, and designated as cash flow hedges, various fixed-price swaps, option collars and puts in conjunction with the Anadarko and ExxonMobil property acquisitions. These positions were entered into in accordance with the Company’s hedging policy and involved counterparties which were rated A+ or

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

better. As of December 31, 2005, the outstanding positions of our natural gas and crude oil cash flow hedges were as follows:


		Total		Weighted		Fair Value
		Volumes		Average		Asset/
Production Period	Instrument Type	(MMBtu/Bbl)		Floor/Ceiling		(Liability)

						(In thousands)
2006	Gas Collars		32,850,000		$5.50/ 6.66	$	(133,936	)
	Gas Fixed-Price Swap		4,404,000		5.87		(21,232	)
	Oil Collars		4,307,000		32.07/ 40.66		(95,583	)
	Oil Fixed-Price Swap		224,000		38.50		(5,365	)
	Oil Put Option		1,533,000		28.00		16
2007	Gas Collars		24,570,000		5.25/ 6.20		(96,917	)
	Gas Fixed-Price Swap		1,761,000		5.57		(7,997	)
	Oil Collars		1,911,000		33.00/ 39.25		(45,533	)
	Oil Fixed-Price Swap		78,000		36.89		(1,982	)

The natural gas and crude oil positions shown in the above table are based on the NYMEX index and have been valued using actively quoted prices and quotes obtained from the counterparties to the derivative agreements. The above prices represent a weighted average of several contracts entered into and are on a per MMBtu or per barrel basis for gas and oil derivatives, respectively.

Apache entered into a separate crude oil physical sales contract with BP in February 2003, which ended December 31, 2004. Under the terms of the agreement, Apache physically delivered 22.5 million barrels of crude oil at an average fixed Brent index price of $23.38 per barrel. The contract was designated as a normal purchase and sale under SFAS No. 133 and, therefore, the Company accounted for the contract under the accrual method.

Apache hedged a portion of its 2005 foreign currency exchange risk associated with its forecasted Canadian, Australian and North Sea lease operating expenditures by entering into forward purchase contracts. The Company purchased a total of $144 million Canadian dollars at an average exchange rate of .840, $22 million Australian dollars at an average exchange rate of .763 and 42 million British pounds at an average exchange rate of 1.853. The forward contracts matured from January through December 2005 and caused the Company to recognize $3 million of increased lease operating expense during the year.

A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders’ equity related to Apache’s commodity and foreign currency derivative activities is presented in the table below:


	Gross			After Tax

	(In thousands)
Unrealized loss on derivatives at December 31, 2004	$	(33,113	)	$	(20,732	)
Net losses realized into earnings		135,996			87,644
Net change in derivative fair value		(501,112	)		(323,770	)

Unrealized loss on derivatives at December 31, 2005	$	(398,229	)	$	(256,858	)

Differences between the fair values and the unrealized loss on derivatives before income taxes recognized in accumulated other comprehensive income (loss) are primarily related to premiums, recognition of unrealized gains and losses on certain derivatives that did not qualify for hedge accounting and hedge ineffectiveness. Based on applicable market prices as of year-end 2005, the Company recorded an unrealized loss in other comprehensive income (loss) of $398 million ($257 million after tax), representing oil and gas derivative hedges. Any loss will be realized in future earnings contemporaneously with the related sales of

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

natural gas and crude oil production applicable to specific hedges. Of the $398 million unrealized loss on derivatives at December 31, 2005, approximately $247 million ($160 million after tax) applies to the next 12 months. However, these amounts are likely to vary materially as a result of changes in market conditions. The contracts designated as hedges qualified and continue to qualify for hedge accounting in accordance with SFAS No. 133, as amended.


4.	ASSET RETIREMENT OBLIGATION

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the 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. The fair value of the ARO is measured using expected future cash outflows discounted at the company’s credit-adjusted risk-free interest rate.

The Company adopted SFAS No. 143 on January 1, 2003, and recorded an increase to net oil and gas properties of $410 million and associated liabilities of $369 million. These amounts reflect the ARO of the Company had the provisions of SFAS No. 143 been applied since inception and resulted in a non-cash cumulative effect increase to earnings of $27 million ($41 million pre-tax).

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

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


	2005			2004

	(In thousands)
Asset retirement obligation at beginning of period	$	932,004		$	739,775
Liabilities incurred		87,794			199,505
Liabilities settled		(84,445	)		(47,784	)
Accretion expense		53,720			46,060
Revisions in estimated liabilities		466,842			(5,552	)

Asset retirement obligation at December 31,	$	1,455,915		$	932,004

In accordance with SFAS No. 143, the Company records an abandonment liability associated with its oil and gas wells, facilities and platforms when those assets are placed in service, which for 2005 and 2004 is reflected above in liabilities incurred. Liabilities settled relate to individual properties plugged and abandoned or sold during the period. Revisions to the estimated liability normally result from annual reassessments of the expected cash outflows and assumptions inherent in the ARO calculation. However, during the third quarter of 2005, nine of the Company’s offshore platforms in the Gulf of Mexico were toppled, two platforms were severely damaged and approximately 12 non-operated structures were also destroyed as a result of Hurricanes Katrina and Rita. Upon completing our assessment of hurricane related costs during the fourth quarter, the Company increased the discounted ARO liability on the affected properties to $492 million. The revision reflects increased costs and acceleration in expected timing to abandon these platforms. Approximately $94 million has been classified as a current liability.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	DEBT


	Long-Term Debt


		December 31,

		2005			2004

		(In thousands)
Apache:
	Money market lines of credit	$	—		$	4,000
	Commercial paper		—			392,000
	6.25-percent debentures due 2012, net of discount		398,006			397,758
	7-percent notes due 2018, net of discount		148,639			148,570
	7.625-percent notes due 2019, net of discount		149,222			149,190
	7.7-percent notes due 2026, net of discount		99,678			99,671
	7.95-percent notes due 2026, net of discount		178,683			178,659
	7.375-percent debentures due 2047, net of discount		148,028			148,021
	7.625-percent debentures due 2096, net of discount		149,175			149,175

			1,271,431			1,667,044

Subsidiary and other obligations:
	Fletcher notes		4,526			5,356
	Apache Finance Australia 6.5-percent notes due 2007, net of discount		169,678			169,530
	Apache Finance Australia 7-percent notes due 2009, net of discount		99,733			99,662
	Apache Finance Canada 4.375-percent notes due 2015, net of discount		349,732			349,709
	Apache Finance Canada 7.75-percent notes due 2029, net of discount		297,128			297,089

			920,797			921,346

Total debt			2,192,228			2,588,390
Less: current maturities			(274	)		—

Long-term debt		$	2,191,954		$	2,588,390

As detailed above, the Company currently has $1.5 billion of syndicated bank credit facilities. 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., Canada and Australia of up to five percent of the Company’s consolidated assets, which approximated $964 million as of December 31, 2005. There are no restrictions on incurring liens in countries other than the U.S., Canada and Australia. 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.

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2005. The Company’s debt-to-capitalization ratio as of December 31, 2005 was 17 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 Interbank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $750 million and the $450 million credit facilities (U.S. credit facilities) also allow the Company to borrow under competitive auctions.

At December 31, 2005, the margin over LIBOR for committed loans was .27 percent on the $750 million facility and ..23 percent on the other three facilities. If the total amount of the loans borrowed under the $750 million facility equals or exceeds 50 percent of the total facility commitments, then an additional .10 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 ..08 percent on the total amount of the $750 million 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. The available borrowing capacity under the credit facilities at December 31, 2005 was $1.5 billion.

The Company has certain uncommitted money market lines of credit which are used from time to time for working capital purposes, of which no balance was outstanding as of December 31, 2005.

The Company has a $1.2 billion commercial paper program which enables Apache to borrow funds for up to 270 days at competitive interest rates. There was no commercial paper outstanding as of December 31, 2005. The commercial paper balance at December 31, 2004 was classified as long-term debt in the accompanying consolidated balance sheet as the Company had the ability and intent to refinance such amount on a long-term basis through either the rollover of commercial paper or available borrowing capacity under the U.S. credit facilities. The weighted-average interest rate for commercial paper was 3.03 percent in 2005 and 1.79 percent in 2004.

On May 15, 2003, Apache Finance Canada Corporation (Apache Finance Canada) issued $350 million of 4.375 percent, 12-year, senior unsecured notes in a private placement. On March 4, 2004, the Company completed an exchange offer with the holders of the notes, issuing publicly traded, registered notes of the same principal amount and with the same interest rates, payment terms and maturity. The notes are irrevocably and unconditionally guaranteed by Apache and are redeemable, as a whole or in part, at Apache Finance Canada’s option, subject to a make-whole premium. Interest is payable semi-annually on May 15 and November 15 of each year commencing on November 15, 2003. The proceeds of the original note offering were used to reduce bank debt and outstanding commercial paper and for general corporate purposes.

The Company does not have the right to redeem any of its notes or debentures (other than the Apache Corporation 6.25-percent notes due April 15, 2012, the Apache Finance Australia 6.5-percent notes due 2007 and the Apache Finance Canada 4.375-percent notes due 2015) prior to maturity. Under certain conditions, the Company has the right to advance maturity on the 7.7-percent notes, 7.95-percent notes, 7.375-percent debentures and 7.625-percent debentures.

The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache and, in the case of Apache Finance Australia, 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 Australia and Apache Finance Canada have the right to redeem the notes prior to maturity. The Apache Finance Australia 6.5-percent notes and the Apache Finance Canada 4.375-percent notes may be redeemed at the Company’s option subject to a make-whole premium (see Note 16. Supplemental Guarantor Information).

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The $12 million of discounts on the Company’s debt as of December 31, 2005, is being amortized over the life of the debt issuances as additional interest expense.

As of December 31, 2005 and 2004, the Company had approximately $18 million and $21 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 amortized to expense over the life of the related debt.

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.


	Aggregate Maturities of Debt


	(In thousands)
2006	$	274
2007		172,678
2008		353
2009		99,733
2010		—
Thereafter		1,919,190

	$	2,192,228

The Company made cash payments for interest, net of amounts capitalized, of $107 million for the years ended December 31, 2005 and 2004, and $96 million for the year ended December 31, 2003.


6.	INCOME TAXES

Income before income taxes is composed of the following:


		For the Year Ended December 31,

		2005		2004		2003

		(In thousands)
United States		$	1,502,467	$	1,120,906	$	918,432
Foreign			2,703,787		1,542,177		1,003,825

	Total	$	4,206,254	$	2,663,083	$	1,922,257

The total provision for income taxes consists of the following:


		For the Year Ended December 31,

		2005			2004		2003

		(In thousands)
Current taxes:
	Federal	$	291,604		$	145,164	$	37,472
	State		(2,424	)		4,330		2,296
	Foreign		694,417			398,612		240,879
Deferred taxes			598,927			444,906		546,357

	Total	$	1,582,524		$	993,012	$	827,004

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A reconciliation of the U.S. federal statutory income tax amounts to the effective amounts is shown below:


	For the Year Ended December 31,

	2005			2004			2003

	(In thousands)
Statutory income tax	$	1,472,189		$	932,079		$	672,790
State income tax, less federal benefit		12,579			28,023			22,961
Taxes related to foreign operations		147,059			86,263			49,657
Realized tax basis in investment		(9,282	)		(16,923	)		(23,234	)
Canadian tax rate reduction		(28,611	)		(31,350	)		(71,340	)
Current and deferred taxes related to currency fluctuations		13,332			58,049			171,930
Domestic benefit from tax law change		(9,853	)		—			—
Australian consolidation benefit from tax law change		(9,649	)		(50,713	)		—
Benefit of previously unrecognized Canadian losses		—			(18,226	)		—
All other, net		(5,240	)		5,810			4,240

	$	1,582,524		$	993,012		$	827,004

The net deferred tax liability is comprised of the following:


			December 31,

			2005			2004

			(In thousands)
Deferred tax assets:
	Deferred income		$	(5,968	)	$	(1,473	)
	State net operating loss carryforwards			(13,439	)		(9,500	)
	Foreign net operating loss carryforwards			(6,154	)		(224,137	)
	Accrued expenses and liabilities			(5,773	)		(5,465	)
	Other			(9,492	)		(830	)

		Total deferred tax assets		(40,826	)		(241,405	)
	Valuation allowance			—			—

		Net deferred tax assets		(40,826	)		(241,405	)

Deferred tax liabilities:
	Depreciation, depletion and amortization			2,621,455			2,388,042

		Total deferred tax liabilities		2,621,455			2,388,042

Net deferred income tax liability			$	2,580,629		$	2,146,637

The Company has not recorded deferred income taxes on the undistributed earnings of its foreign subsidiaries as management intends to permanently reinvest such earnings. As of December 31, 2005, the undistributed earnings of the foreign subsidiaries amounted to approximately $7.4 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.

At December 31, 2005, the Company had state net operating loss carryforwards of $267 million and foreign net operating loss carryforwards of $18 million for Canada. The state net operating losses will expire over the next 20 years, if they are not otherwise utilized. The foreign net operating loss for Canada has a seven-year carryover period.

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company is currently under audit by the Internal Revenue Service (IRS) for the 2002 and 2003 income tax years. We are in the process of responding to normal requests for information regarding the federal income tax returns for these two years. The Company believes that it has adequately provided for income taxes.

The Company made payments for income and other taxes, net of refunds, of $977 million, $466 million and $309 million for the years ended December 31, 2005, 2004 and 2003, respectively.


7.	ADVANCES FROM GAS PURCHASERS

Advances from gas purchasers represent cash received by Apache prior to 2000 for future natural gas deliveries. It also includes cash received in 2001 upon the termination of gas price swaps related to these future deliveries. These proceeds will be recognized in monthly sales based on the portion of the proceeds applicable to each production month over the remaining life of the contracts. On December 31, 2005 and 2004, advances of $69 and $91 million, respectively, were outstanding.

Contracted volumes relating to these arrangements are included in the Company’s unaudited supplemental oil and gas disclosures.


8.	CAPITAL STOCK


	Common Stock Outstanding


		2005		2004			2003

Balance, beginning of year			327,457,503		324,497,176			302,506,424
Treasury shares issued (acquired), net			579,179		66,080			130,636
Shares issued for:
	Public offering (1)		—		—			19,803,000
	Stock compensation plans		2,084,548		2,897,327			2,101,844
	Fractional shares repurchased		—		(3,080	)		(44,728	)

Balance, end of year (2)			330,121,230		327,457,503			324,497,176


(1)	On January 22, 2003, in conjunction with the BP transaction, we completed a public offering of 19.8 million shares of common stock, including 2.6 million shares for the underwriters’ over-allotment option, raising net proceeds of $554 million.

(2)	On December 18, 2003, the Company announced that holders of its common stock approved a proposal to increase the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2005, 2004 and 2003 is presented in the table below:


		2005						2004						2003

		Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share

		(In thousands, except per share amounts)
Basic:
	Income attributable to common stock	$	2,618,050		328,929	$	7.96	$	1,663,074		326,046	$	5.10	$	1,116,205		322,498	$	3.46

Effect of Dilutive Securities:
	Stock options and other		—		4,820				—		4,431				—		2,832

Diluted:
	Income attributable to common stock, including assumed conversions	$	2,618,050		333,749	$	7.84	$	1,663,074		330,477	$	5.03	$	1,116,205		325,330	$	3.43

Two-for-One Stock Split

On December 18, 2003, the Company announced that holders of its common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004.


	Stock Compensation Plans

During 2002, Apache began modifying its stock compensation plans in order to reflect the cost of these plans in the Statement of Consolidated Operations. As part of this effort, Apache began issuing stock appreciation rights and restricted stock and, effective January 1, 2003, adopted the expense provisions of SFAS No. 123, as amended, on a prospective basis for all stock options granted under the Company’s existing option plans. Consistent with the Company’s desire to expense stock compensation plans, Apache early adopted the provisions of SFAS 123-R upon the FASBs issuance of the statement in the fourth quarter of 2004. See Note 1, Summary of Significant Accounting Policies. A description of the Company’s stock-based compensation plans and related costs follows. Costs related to the plans are capitalized or expensed based on the nature of the employee’s activities.


		2005		2004		2003

		(In millions)
Stock-based compensation expensed:
	General and administrative	$	40	$	25	$	8
	Lease operating costs		21		18		1
Stock-based compensation capitalized			29		19		1

Stock Options

As of December 31, 2005, 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). 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. Under the Stock Option Plans, the exercise price of each option equals the market price of Apache’s common stock on the date of grant. Options generally become exercisable ratably over a four-year period and

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expire after 10 years. 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 key employees. Under the Performance Plan, the exercise price of each option equals the market price of Apache common stock on the date of grant. All options become exercisable after nine and one-half years and expire 10 years from the date of grant. Under the terms of the Performance Plan, no grants were made after December 31, 1998.

A summary of the status of the Stock Option Plans and the 1996 Performance Stock Option Plan is presented in the table and narrative below as of December 31, 2005, 2004 and 2003, and for changes during the years then ended (shares in thousands):


	2005					2004					2003

				Weighted					Weighted					Weighted
	Shares			Average		Shares			Average		Shares			Average
	Under			Exercise		Under			Exercise		Under			Exercise
	Option			Price		Option			Price		Option			Price

Outstanding, beginning of year		7,342		$	21.33		9,141		$	20.59		11,328		$	19.53
Granted		2,066			56.27		290			44.73		280			30.97
Exercised		(1,804	)		21.38		(1,913	)		20.35		(2,198	)		8.54
Forfeited or expired		(124	)		44.99		(176	)		25.39		(269	)		11.43

Outstanding, end of year (1)		7,480			30.55		7,342			21.33		9,141			20.59

Expected to vest (1)		3,613					2,783					3,596

Exercisable, end of year (1)		3,465			24.00		4,250			20.36		5,146			19.21

Available for grant, end of year		3,275					2,819					3,042

Weighted average fair value of options granted during the year	$	19.32				$	14.45				$	10.14


(1)	As of December 31, 2005, the remaining contractual life for options outstanding, expected to vest, and exercisable is 5.3 years, 5.3 years and 4.8 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest and exercisable at year-end was $284 million, $117 million and $154 million, respectively.

The following table summarizes information about stock options covered by the plans described above that are outstanding as of December 31, 2005 (shares in thousands):


		Options Outstanding				Options Exercisable

		Number of				Number of
		Shares		Weighted		Shares		Weighted
		Under		Average		Under		Average
		Outstanding		Exercise		Exercisable		Exercise
Range of Exercise Prices		Options		Price		Options		Price

$10.66 - $18.37			2,834	$	15.20		1,204	$	15.16
	19.68 - 28.78		2,369		25.65		1,914		25.06
	32.97 - 42.68		186		40.86		49		40.26
	45.30 - 73.34		2,091		55.98		298		50.19

			7,480				3,465

The fair value of each 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

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

based on implied volatilities of traded options on the Company’s stock, historical volatility of the Company’s stock, and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of options granted represents the period of time that the 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.


	2005			2004			2003

Expected volatility		33.60	%		36.10	%		36.60	%
Expected dividend yields		.56	%		.55	%		.66	%
Expected term (in years)		5.5			4.5			4.5
Risk-free rate		3.82	%		3.65	%		2.86	%

The intrinsic value of options exercised during 2005 was approximately $68 million and the Company realized an additional tax benefit of approximately $16 million for the amount of intrinsic value in excess of compensation cost recognized. As of December 31, 2005, the total compensation cost related to non-vested options not yet recognized was $28 million, which will be recognized over the remaining vesting period of the options.

Stock Appreciation Rights

During 2003 and 2004, the Company issued a total of 1,328,400 and 1,802,210, respectively, of stock appreciation rights (SARs) to non-executive employees in lieu of stock options. None were issued in 2005. SARs will be settled in cash upon exercise throughout their 10-year life. The weighted-average exercise price of the SARs was $42.68 and $28.78 for those issued in 2004 and 2003, respectively. The number of SARs outstanding as of December 31, 2005 was 2,425,062, of which 745,715 were exercisable. The vesting period is over four years and the Company records compensation expense on the vested SARs outstanding based on the fair value of the SARs at the end of each period. As of year-end, the weighted-average fair value of SARs outstanding was $38.55 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2005, 279,600 SARs were exercised and approximately 83,000 were forfeited. No material cash payments were made to settle SARs that were exercised.

Restricted Stock

On May 5, 2002, Apache’s board of directors approved an executive restricted stock plan for all executive officers and certain key employees. At the time of grant, participants in the executive restricted stock plan may elect to defer income from restricted stock vesting into the Deferred Delivery Plan. The Company awarded 155,300, 87,500 and 121,000 restricted shares at a per share market price of $55.90, $42.68 and $28.78 in 2005, 2004 and 2003, respectively. The value of the stock issued was established by the market price on the date of grant and will be recorded as compensation expense ratably over the four-year vesting terms. During 2005, 2004 and 2003, $4.3 million, $2.8 million and $2 million, respectively, was charged to expense as shares vested. As of December 31, 2005, there was $11 million of total unrecognized compensation cost

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

related to approximately 319,943 unvested shares. The weighted-average remaining life of unvested shares is approximately 2.5 years.


					Weighted-Average
					Grant-Date
Restricted Stock		Shares			Fair Value

Non-vested at January 1, 2005			268,920		$	32.87
	Granted		155,300			55.90
	Vested		(97,131	)		31.39
	Forfeited		(7,146	)		32.41

Non-vested at December 31, 2005			319,943		$	44.51

In December 1998, the Company granted a conditional stock award to an executive of the Company for a total 230,992 shares (adjusted for subsequent stock dividends and a stock split) of the Company’s common stock. The award was composed of five annual installments, commencing on January 1, 1999 and each successive January through January 1, 2003. Vesting occurs on the fifth anniversary following each installment. Under the terms of the award, forty percent of the conditional grants are paid in cash at the market value of the Company’s stock on the date of payment and the balance is issued in Apache common stock. The first two periodic installments vested on January 1, 2004 and January 1, 2005. The latter three annual installments will vest on January 1, 2006, 2007 and 2008, respectively.

2005 Share Appreciation Plan

On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan that provides incentives for employees to double Apache’s share price to $108 by the end of 2008, with an interim goal of $81 to be achieved by the end of 2007. To achieve the trigger price, the Company’s stock price must close at or above the stated threshold for 10 days out of any 30 consecutive trading days by the end of the stated period. Under the plan, if the first threshold is achieved, approximately 1.4 million shares would be awarded for an intrinsic cost of $111 million. Achieving the second threshold would result in approximately 2.1 million shares awarded for an intrinsic cost of $223 million. Shares ultimately issued would be reduced for any minimum tax withholding requirements. Under the terms of this targeted stock plan, awards are payable in four equal installments, beginning with the date the trigger stock price is met and on each succeeding anniversary date.

Current accounting practices dictate that, regardless of whether these thresholds are ultimately achieved, the Company will recognize the fair value cost at the grant date based on numerous assumptions, including an estimate of the likelihood that Apache’s stock price will achieve these thresholds and the expected forfeiture rate. As a result, the Company will recognize expense and capitalized costs of approximately $76 million over the expected service life of the plan. For 2005, $6.6 million ($4.3 million after tax) was expensed and $3.4 million was capitalized. No material forfeitures occurred during 2005.

The weighted average fair value, based on the Monte Carlo Simulation Model, was $25.11 per share, determined by using expected volatility of 28.30 percent, an expected dividend yield of 0.56 percent, and a risk free interest rate of 3.81 percent. The fair value determination was calculated using assumptions similar to the option valuation discussed above.

2000 Share Appreciation Plan

In October 2000, the Company adopted the 2000 Share Appreciation Plan under which grants were made to substantially all full-time employees, including officers. The Share Appreciation Plan provided for issuance of up to an aggregate of 8.08 million shares of Apache common stock, based on attainment of one or more of three share price goals (Share Price Goals) and/or a separate production goal (Production Goal). Generally, shares are issued in three installments over 24 months after achievement of each goal. The shares of Apache

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

common stock contingently issuable under the Share Appreciation Plan were excluded from the computation of income per common share until the stated goals were met as described below.

The Share Price Goals were based on achieving a closing price of $43.29, $51.95 and $77.92 per share on any 10 days out of any 30 consecutive trading days prior to January 1, 2005. Apache’s share price exceeded the first threshold ($43.29) under this plan on April 28, 2004. As such, the Company will issue approximately 900,000 shares of its common stock, after minimum tax withholding requirements, which will be distributed in three annual installments. The first and second installments were issued in May 2004 and 2005, respectively. The third installment will be issued in 2006 to employees remaining with, or having retired from, the Company during the period. Also, on October 26, 2004, Apache’s share price exceeded the second threshold of $51.95. Accordingly, Apache will issue approximately 2.2 million additional shares of its common stock, after minimum tax withholding requirements, in three equal installments. The first and second installments were issued in November 2004 and 2005, respectively. The third installment will be issued in 2006 to employees remaining with, or having retired from, the Company during the period. The third share-price threshold ($77.92) did not trigger and the related shares were cancelled as of December 31, 2004. A summary of the number of shares contingently issued under the Share Price Goals as of December 31, 2005, 2004 and 2003 is presented in the table below:


	Shares Subject to
	Conditional Grants

	2005			2004			2003

	(In thousands)
Outstanding, beginning of year		3,008			6,324			6,234
Granted		—			15			522
Issued		(1,483	)		(1,531	)		—
Forfeited or cancelled		(83	)		(1,800	)		(432	)

Outstanding, end of year(1)		1,442			3,008			6,324

Weighted-average fair value of conditional grants — Share Price Goals(2)	$	—		$	19.74		$	6.75


(1)	The outstanding shares at the end of 2005 and 2004 represent those shares remaining to be issued as a result of attainment of the $43.29 and $51.95 per share price goals. These outstanding shares will be issued net of minimum tax withholding as employees fulfill the one-year remaining service period requirement. The outstanding shares shown at the end of 2003 represent shares that would have been issued, had the $43.29, $51.95 and $77.92 been attained, 1,370,624 shares, 3,431,250 shares and 1,522,818 shares, respectively for 2003.

(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 2004 and 2003, respectively: (i) risk-free interest rate of 3.04 and 2.77 percent; (ii) expected volatility of 35.97 and 36.69 percent; and (iii) expected dividend yield of .96 and .70 percent.

Timing of expense recognition under the 2000 Share Appreciation Plan was based on the accounting policies in place for each year the plan was outstanding and vesting (See Note 1, Summary of Significant Accounting Policies). The shares were initially granted in 2000 and were not expensed under APB Opinion No. 25. In 2004, Apache adopted SFAS 123-R retrospectively, to January 1, 2004, and expensed stock based compensation vesting during the year. Under SFAS No. 123-R expense amounts are determined based on the fair value of the plan on the date of grant and for 2005 and 2004, respectively, the Company recorded $6.3 million ($4.1 million after-tax) and $13.1 million ($8.2 million after-tax) of expense, net of capitalized amounts for this plan of $3.5 million and $6.5 million. An immaterial amount of expense will be recorded in 2006 as the initial service period is completed.

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Production Goal was not attained prior to January 1, 2005 and, therefore, no shares were issued under that goal.


	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).

Rights to Purchase 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 common stock. In addition, if a person or group becomes the beneficial owner of 20 percent or more 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive Income

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


	For the Year Ended December 31,

	2005			2004			2003

	(In thousands)
Currency translation adjustments	$	(108,750	)	$	(108,750	)	$	(108,750	)
Unrealized gain (loss) on derivatives (Note 3)		(256,858	)		(20,732	)		(43,193	)

Accumulated other comprehensive loss	$	(365,608	)	$	(129,482	)	$	(151,943	)


9.	FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2005 and 2004. See Note 3, Hedging and Derivative Instruments for a discussion of the Company’s derivative instruments.


			2005				2004

			Carrying				Carrying
			Amount		Fair Value		Amount		Fair Value

			(In thousands)
Long-term debt:
	Apache
		Money market lines of credit	$	—	$	—	$	4,000	$	4,000
		Commercial paper		—		—		392,000		392,000
		6.25-percent debentures		398,006		430,120		397,758		445,960
		7-percent notes		148,639		168,750		148,570		179,040
		7.625-percent notes		149,222		176,775		149,190		189,780
		7.7-percent notes		99,678		126,490		99,671		124,100
		7.95-percent notes		178,683		234,828		178,659		228,960
		7.375-percent debentures		148,028		188,700		148,021		188,385
		7.625-percent debentures		149,175		193,680		149,175		188,187
	Subsidiary and other obligations
		Fletcher notes		4,526		4,652		5,356		5,719
		Apache Finance Australia 6.5-percent notes		169,678		175,151		169,530		183,260
		Apache Finance Australia 7-percent notes		99,733		106,160		99,662		111,010
		Apache Finance Canada 4.375-percent notes		349,732		336,805		349,709		338,838
		Apache Finance Canada 7.75-percent notes		297,128		390,540		297,089		387,960

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 and trade payables are by their very nature short-term. The carrying values included in the accompanying consolidated balance sheet approximate fair value at December 31, 2005 and 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	COMMITMENTS AND CONTINGENCIES

Litigation

Texaco China B.V.

Apache recorded a reserve in the second quarter of 2004 to fully reflect a pre-tax $71 million international arbitration award to Texaco China B.V. (Texaco China). The arbitration award was subject to interest at nine percent until May 6, 2005, the date following the federal district court ruling discussed below. On May 6, 2005, the interest rate dropped to 3.33 percent. Apache accrued $3.2 million of interest expense in 2004 and an additional $3.8 million of interest expense in 2005. In September 2001, Texaco China initiated an arbitration proceeding against Apache China Corporation LDC (Apache China), later adding Apache Bohai Corporation LDC (Apache Bohai) to the arbitration. In the arbitration Texaco China claimed damages, plus interest, arising from Apache Bohai’s alleged failure to drill three wells, prior to re-assignment of the interest to Texaco China. Apache believes that the finding of the arbitrator is unsupported by the facts and the law, and Apache filed an application to vacate the award in federal court. Texaco China filed an application to confirm the award in the same court. On May 5, 2005, the federal district court ruled in favor of Texaco China. The Company has appealed that decision to the circuit court of appeals. In January 2005, while awaiting the decision of the U.S. federal courts, Texaco China also filed a proceeding against Apache China and Apache Bohai in the People’s Republic of China to recognize the award, apparently seeking the same relief as sought in U.S. federal court. The parties subsequently agreed to stay enforcement of the arbitration award in China and elsewhere pending the final, determinative outcome of all possible appeals in the U.S. federal courts. A hearing on the appeal has been set for April 2006.

Predator

In December 2000, certain subsidiaries of the Company and Murphy Oil Corporation (Murphy) filed a lawsuit in Canada charging The Predator Corporation Ltd. (Predator) and others with misappropriation and misuse of confidential well data to obtain acreage offsetting a significant natural gas discovery in the Ladyfern area of northeast British Columbia made by Apache Canada Ltd. (Apache Canada) and Murphy during 2000. In February 2001, Predator filed a counterclaim seeking more than C$6 billion and later reduced this amount to approximately C$3.6 billion. In September 2004, the Canadian court granted Apache Canada’s motion for summary judgment on the counterclaim, dismissing more than C$3 billion of Predator’s claims against Apache Canada and Murphy, and dismissing all claims against both Murphy’s president and Apache Canada’s president. Predator has appealed the summary judgment. On February 28, 2006, the Court of Appeal of Alberta dismissed Predator’s appeal. Predator may seek review by the Supreme Court of Canada. The trial court also granted Apache Canada’s request for costs and disbursements in the approximate amount of C$700,000, which Predator has paid. The Canadian court has also granted Predator’s request to add some new mismanagement of operations claims to its counterclaim. At this time, Predator’s counterclaims against Murphy and Apache Canada for mismanaging operations still survive in the trial court and a trial is scheduled to begin in April 2006 unless the appellate court has not, by March 16, 2006, decided Predator’s appeal of the summary judgment dismissing more than C$3 billion of Predator’s claims against Apache Canada and Murphy. The combined claims, for mismanagement of operations, total approximately C$365 million, plus interest and attorneys’ fees. While management believes Predator’s counterclaim against Apache Canada is without merit, an adverse judgment is possible. Exposure related to this lawsuit is not currently determinable. Apache and Murphy’s claims against Predator, filed in December 2000, are still pending.

Grynberg

In 1997, Jack J. Grynberg began filing lawsuits against other natural gas producers, gatherers, and pipelines claiming that the defendants have underpaid 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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

mis-measured natural gas. In 2004, 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. Other plaintiffs have made or may be expected to make similar claims. The Grynberg lawsuits have, for the most part, been consolidated through a federal Multi-District Litigation (MDL) action located in Wyoming federal court for discovery and pre-trial purposes. The defendants in the MDL, jointly and/or separately, filed motions to dismiss based upon certain statutory requirements Grynberg is required to prove to proceed with these qui tam lawsuits. These motions were referred to a magistrate for recommendation for decision. The magistrate has recommended some defendants be dismissed. Subsequent motions are pending before the federal district court by both sides on these recommendations for confirmation and/or denial of the recommendation. It is unclear from the Magistrate’s recommendation if there was a ruling on Apache’s filing for dismissal; however, at this time, Apache has not been dismissed. Apache has filed additional pleadings to obtain rulings on its separate request for dismissal. 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.

Egypt Tax Authority

As of the end of 2004, the Egyptian Tax Authority (ETA) had issued claims for back taxes against various Apache subsidiaries in Egypt totaling approximately $113.4 million (at current exchange rates) relating to periods as far back as 1994. In July 2005, the ETA made a new claim for approximately $85 million of additional taxes for the 1994-99 tax years. On January 30, 2006, the Tax Authority cancelled the new claim in its entirety, with no liability to Apache.

With respect to the remaining claims (those existing at the end of 2004), while an adverse judgment against Apache is possible, Egyptian concession agreements clearly provide that the Egyptian General Petroleum Corporation is responsible for the payment of all taxes related to the operation of the concessions. Apache believes that the claims of the ETA are unsupported by either the facts or the language of the concession agreements, which have the force of law in Egypt. Apache’s subsidiaries have, therefore, contested liability with respect to those claims by filing actions in Egyptian civil court. In addition, pursuant to a 2005 change in the Egyptian tax law, Apache has petitioned the Committee for the Reconsideration of Final Assessment for reconsideration of the original claims. The Committee for the Reconsideration of Final Assessment, which is the final appeal committee in the Tax Authority and is empowered to overrule Tax Authority claims, has accepted Apache’s petition for reconsideration. A decision by the Committee is expected sometime during the first half of 2006. Apache plans to vigorously pursue its remedies with respect to these claims.

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 for 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.

Hurricane Related Litigation

A class action lawsuit has been filed styled Barasich, et al., individually and as representatives of all those similarly situated vs. Columbia Gulf Transmission Co., et al, No. 05-4161, United States District Court,

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Eastern District of Louisiana, against all oil and gas and pipeline companies that drilled or dredged in the marshes of South Louisiana. The lawsuit claims defendants were negligent by constructing canals and conducting oil and gas operations, which plaintiffs contend is the sole and/or almost the sole cause of the alleged destruction of the marshes in South Louisiana, which plaintiffs blame for all and/or substantially all loss of life and destruction of property which was incurred from Hurricane Katrina. Apache was not named, but if a defendant class is certified, would fall within the definition alleged. Apache believes such claims are without merit, and if joined will undertake an active defense to such claims.

General

The Company is involved in other litigation and is subject to governmental and regulatory controls arising in the ordinary course of business. The Company has an accrued liability of approximately $2 million for other legal contingencies that are probable of occurring and can be reasonably estimated. It is management’s opinion that the loss for any such other litigation matters and claims that are reasonably possible to occur will not have a material adverse affect on the Company’s financial position or results of operations.

Other Commitments and Contingencies

Environmental

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 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, its 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 $100,000. 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, 2005, the Company had an undiscounted reserve for environmental remediation of approximately $11 million. Apache is not aware of any environmental claims existing as of December 31, 2005, 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.

International Lease Concessions

The Company, through its subsidiaries, has acquired or has been conditionally or unconditionally granted exploration rights in Australia, Egypt, China and the North Sea. In order to comply with the contracts and

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreements granting these rights, the Company, through various wholly-owned subsidiaries, is committed to expend approximately $222 million through 2009.

Contractual Obligations

The Company has leases for buildings, facilities and equipment with varying expiration dates through 2035. Net rental expense was $20 million for 2005, and $17 million for 2004 and 2003.

As of December 31, 2005, minimum rental commitments under long-term operating leases, net of sublease rental income, drilling rigs and long-term pipeline transportation commitments, ranging from one to 30 years, are as follows:


	Net Minimum Commitments

							Pipeline
	Total		Leases		Drilling Rigs		Transmission

	(In thousands)
2006	$	226,410	$	13,540	$	178,159	$	34,711
2007		136,070		13,114		92,522		30,434
2008		43,026		12,493		8,696		21,837
2009		18,736		12,624		—		6,112
2010		16,421		12,328		—		4,093
Thereafter		63,061		36,578		—		26,483

	$	503,724	$	100,677	$	279,377	$	123,670

Retirement and Deferred Compensation Plans

The Company provides a 401(k) savings plan for employees which allows participating employees to elect to contribute up to 25 percent of their salaries (50 percent effective January 1, 2006), with Apache making matching contributions up to a maximum of six percent of each employee’s salary. 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 which limit the amount of each employee’s contributions.

For certain eligible employees, the Company also provides a non-qualified retirement/savings plan which allows the deferral of up to 50 percent of each employee’s salary, and which accepts employee contributions and the Company’s matching contributions in excess of the above-referenced restrictions on the 401(k) savings plan and money purchase retirement plan. 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.

Vesting in the Company’s contributions to 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, vesting is immediate. Total costs under all plans were $39 million, $31 million and $25 million for 2005, 2004 and 2003, respectively.

Effective July 1, 2003, as part of the BP North Sea acquisition, Apache assumed a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering existing BP North Sea employees hired by the Company as part of the acquisition. Contributions made by Apache to BP’s plan were immaterial prior to Apache’s plan becoming effective. The pension plan provides defined benefits based on years of service and final average salary. The plan is closed to newly hired employees.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache also has a postretirement benefit plan covering substantially all of its U.S. employees. The postretirement benefit plan provides for medical benefits up until the age of 65. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not pay benefits once participants become eligible for Medicare and is not affected by the Medicare Modernization Act of 2003.

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2005 and 2004 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.


			2005						2004

			Pension			Postretirement			Pension			Postretirement
			Benefits			Benefits			Benefits			Benefits

			(In thousands)
Change in Projected Benefit Obligation
	Projected benefit obligation beginning of period		$	88,726		$	11,039		$	63,642		$	9,439
	Service cost			6,286			1,399			5,507			969
	Interest cost			4,463			812			3,661			628
	Foreign currency exchange rate changes			(10,864	)		—			7,132			—
	Amendments			—			—			—			—
	Actuarial losses/(gains)			14,893			2,848			8,793			91
	Effect of curtailment and settlements			—			—			—			—
	Benefits paid			(137	)		(129	)		(9	)		(177	)
	Retiree contributions			—			84			—			89

	Projected benefit obligation at end of year			103,367			16,053			88,726			11,039
Change in Plan Assets
	Fair value of plan assets at beginning of period			82,022			—			52,420			—
	Actual return on plan assets			13,780			—			6,529			—
	Foreign currency exchange rate changes			(9,756	)		—			6,752			—
	Employer contributions			4,977			45			16,330			88
	Benefits paid			(137	)		(129	)		(9	)		(177	)
	Retiree contributions			—			84			—			89

	Fair value of plan assets at end of year			90,886			—			82,022			—
Reconciliation of Funded Status
	Funded status of plan			(12,481	)		(16,053	)		(6,704	)		(11,039	)
	Unrecognized actuarial (gain)/loss			7,576			6,385			2,219			3,913
	Unrecognized prior service cost			—			—			—			—
	Unrecognized net transition obligation			—			485			—			529

	Plan benefit asset/(obligation)			(4,905	)		(9,183	)		(4,485	)		(6,597	)
Weighted Average Assumptions used as of December 31
	Discount rate			4.70	%		5.50	%		5.30	%		5.75	%
	Salary increases			3.80	%		N/A			3.80	%		N/A
	Expected return on assets			5.75	%		N/A			6.25	%		N/A
	Healthcare cost trend
		— Initial		N/A			9.00	%		N/A			9.00	%
		— Ultimate in 2010		N/A			5.00	%		N/A			5.00	%

As of December 31, 2005 and 2004, the accumulated benefit obligation for the pension plan was $76 million and $65 million, respectively.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 holdings and the target allocation for the Company’s plan assets are summarized below.


						Percentage of Plan Assets at
						Year-End
			Target Allocation
			2005			2005			2004

Asset Category
	Equity securities			50	%		51	%		49	%
	Debt securities			50	%		49	%		51	%

		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, 2005, 2004 and 2003.


			2005						2004						2003

			Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
			Benefits			Benefits			Benefits			Benefits			Benefits			Benefits

			(In thousands)
Components of Net Periodic Benefit Costs
	Service cost		$	6,286		$	1,399		$	5,507		$	969		$	2,668		$	780
	Interest cost			4,463			812			3,661			628			1,562			525
	Expected return on assets			(4,822	)		—			(3,589	)		—			(1,260	)		—
	Amortization of:
		Prior service cost		—			—			—			—			—			—
		Transition obligation		—			44			—			44			—			44
		Actuarial (gain)/loss		—			331			—			250			—			203
	Effect of curtailment and settlements			—			—			—			—			—			—

	Net periodic benefit cost		$	5,927		$	2,586		$	5,579		$	1,891		$	2,970		$	1,552

Weighted Average Assumptions used to determine Net Periodic Benefit Costs for the Years ended December 31
	Discount rate			5.30	%		5.75	%		5.50	%		6.25	%		5.50	%		6.75	%
	Salary increases			3.80	%		N/A			3.75	%		N/A			3.75	%		N/A
	Expected return on assets			6.00	%		N/A			6.25	%		N/A			6.50	%		N/A
	Healthcare cost trend
		— Initial		N/A			9.00	%		N/A			10.00	%		N/A			10.00	%
		— Ultimate in 2009		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

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	$	289	$	(250	)
Effect on postretirement benefit obligation		1,930		(1,684	)

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache expects to contribute approximately $5 million to its pension plan and $321,000 to its postretirement benefit plan in 2006. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension		Postretirement
	Benefits		Benefits

	(In thousands)
2006	$	206	$	321
2007		515		475
2008		841		646
2009		858		838
2010		876		1,070
Years 2011 — 2015		11,073		8,905


11.	PREFERRED INTERESTS OF SUBSIDIARIES

On September 26, 2003, Apache repurchased and retired preferred interests in the Company for approximately $443 million, plus an additional $1 million for accrued dividends and distributions. The transaction involved the purchase of preferred stock issued by two of the Company’s subsidiaries for approximately $82 million and the retirement of a limited partnership interest in a partnership controlled by a subsidiary of the Company for approximately $361 million. Apache funded the transactions with available cash on hand and by issuing commercial paper under its existing commercial paper facility.

Prior to the early repurchase, dividends paid on the preferred stock and distributions made on the limited partner interests were reflected as preferred interests of subsidiaries in the statement of consolidated operations.


12.	TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS

Cinergy Corp.

In 1995, Apache and other natural gas producers formed Producers Energy Marketing LLC (ProEnergy), to market substantially all of its members’ domestic natural gas. In June 1998, Apache sold its 57 percent interest in ProEnergy to Cinergy Corp. and contracted with Cinergy Corp. to market substantially all the Company’s natural gas production from the U.S. and agreed to develop terms for the marketing of most of Apache’s Canadian production under an amended and restated gas purchase agreement effective July 1, 1998. Apache received 771,258 shares of Cinergy Corp. common stock for its interest, which the Company subsequently sold for $26 million. In December 1998, Apache and Cinergy Corp. agreed to postpone the negotiation of terms to market most of Apache’s Canadian production. Under the terms of the original gas purchase agreement, ProEnergy, renamed Cinergy Marketing and Trading LLC (Cinergy), was to market Apache’s North American natural gas production until June 30, 2008, with an option, following prior notice, to terminate on June 30, 2004. During this period, Apache was generally obligated to deliver most of its U.S. gas production to Cinergy and, under certain circumstances, reimburse Cinergy if certain gas throughput thresholds were not met. The prices received for its gas production under this agreement approximated market prices.

In June 2003, Apache and Cinergy agreed to terminate their agreement concerning marketing of Apache’s U.S. natural gas production and to dismiss the arbitration between them. The parties reached an amicable settlement, the amounts of which were immaterial to Apache’s financial position and results of operations. Consequently, the Company began marketing its U.S. natural gas production previously marketed by Cinergy beginning with July 2003 production.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Related Parties

In the ordinary course of business, Cimarex Energy, Co. (Cimarex), formerly Key Production Company, Inc., paid to Apache $7 million during 2005, $6 million during 2004 and $4 million during 2003 for Cimarex’s proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Cimarex owns interests and of which Apache is the operator. Cimarex was paid approximately $5 million in 2005 and 2004, and $6 million in 2003 directly by Apache or related entities for its proportionate share of revenues from wells in which Cimarex owns an interest and of which Apache is operator. Apache paid to Cimarex approximately $1 million during 2005, $5 million during 2004 and $1 million during 2003 for Apache’s proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Apache owns interests and of which Cimarex is the operator. Apache was paid approximately $4 million in 2005, $3 million in 2004 and $2 million in 2003 directly by Cimarex for its proportionate share of revenues from wells in which Apache owns an interest and of which Cimarex is operator. F. H. Merelli, a member of Apache’s Board of Directors, is chairman of the board, chief executive officer and president of Cimarex.

George D. Lawrence, a member of the Company’s board of directors and the former President and Chief Executive Officer of Phoenix Resource Companies, Inc. (Phoenix), joined Apache’s board in conjunction with the Company’s acquisition of Phoenix by a merger (the Merger) on May 20, 1996, through which Phoenix became a wholly-owned subsidiary of Apache. Upon consummation of the Merger, Apache assumed Phoenix stock options that remained outstanding on May 20, 1996, including those granted to Mr. Lawrence pursuant to Phoenix’s 1990 Employee Stock Option Plan. In March 2003, Mr. Lawrence received 8,291 shares of Apache common stock (16,582 shares after adjustment for the stock split) as a result of the exercise of all of his remaining stock options from the Phoenix 1990 Employee Stock Option Plan. Such exercise was for 21,656 shares of Apache common stock at an exercise price of $21.50 per share (43,312 shares of Apache common stock at an exercise price of $10.75 per share after adjustment for the stock split). Mr. Lawrence paid the net exercise price of $466,000 and required taxes of $345,000 by surrendering 13,365 shares of Apache common stock valued at $60.65 per share (26,730 shares at $30.33 after adjustment for the stock split).

In the ordinary course of business, Matador Petroleum Corporation or related entities (Matador) paid to Apache approximately $793,000 during 2003 for Matador’s proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Matador owns interests and of which Apache is the operator. Matador was paid approximately $1 million in 2003 directly by Apache for its proportionate share of revenues from wells in which Matador marketed its revenues with Apache as operator. Apache paid to Matador approximately $654,000 during 2003 for Apache’s proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Apache owns interests and of which Matador is the operator. Apache was paid approximately $915,000 in 2003, directly by Matador for its proportionate share of revenues from wells in which Apache marketed its revenues with Matador as operator. Eugene C. Fiedorek, a member of Apache’s board of directors, was a member of the board of directors of Matador until its acquisition by Tom Brown, Inc. in March 2003.

In the ordinary course of business, Hunt Petroleum Corporation and affiliates (Hunt) paid to Apache during 2005 approximately $5.7 million for Hunt’s proportionate share of drilling, recompletion and workover costs, and routine expenses relating to oil and gas wells in which Hunt owns interests and of which Apache is the operator. Hunt was paid approximately $2.1 million directly by Apache or related entities for its proportionate share of revenues from wells in which Hunt owns an interest and of which Apache is operator. Apache paid to Hunt during 2005 approximately $677,000 for Apache’s proportionate share of drilling and workover costs, and routine expenses relating to oil and gas wells in which Apache owns interests and of which Hunt is the operator. Apache was paid approximately $560,000 directly by Hunt for its proportionate share of revenues from wells in which Apache owns an interest and of which Hunt is operator. In November 2005,

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Hunt paid $200,000 to Apache to settle an indemnity claim for the cleanup of oil pits on certain properties in Texas. Janice K. Hartrick, vice president and associate general counsel of Apache, married John W. Creecy, president and chief executive officer of Hunt on January 1, 2006.

Apache and its subsidiaries made donations of $34,000, $103,000 and $201,000, in cash, property and services, to Ucross Foundation in 2005, 2004 and 2003, respectively. Apache also paid $13,000 and $22,000 during 2005 and 2004, respectively, to Ucross Foundation for food, lodging and other expenses incurred in connection with executive and board meetings held by Apache at Ucross Foundation’s facilities. In February 2004, Apache purchased Clear Creek Hunting Preserve, Inc. (CCHP) from Ucross Foundation for a total purchase price of $77,000 and paid $36,000 and $34,000 to Ucross Foundation during 2005 and 2004, respectively, for the lease of land and other services utilized by CCHP. In December 2005, Apache Foundation (a charitable subsidiary of Apache) entered into a 30-year lease with Ucross Foundation, effective 2006, for the use of Ucross ranch property, for an annual consideration of $110,000, indexed for inflation, plus payment of certain other expenses related to the ranch property. During 2005, Apache subsidiaries purchased from Ucross Foundation land and buildings for $497,000. Also during 2005, Ucross Foundation donated $1.3 million to Apache Foundation for conservation projects. Ucross Foundation was founded in 1981 as a non-profit organization whose primary objectives include the restoration of the historic Clear Fork headquarters of the Pratt and Ferris Cattle Company of Wyoming, the promotion of the preservation of other historical sites in the area, pursuit of holistic ranching practices and conservation, and the maintenance of an artists-in-residence program for writers and other artists. To help ensure the continuity of Ucross Foundation and its charitable purposes, Apache’s board of directors approved a conditional charitable contribution of $10 million to be made to Ucross Foundation in the event of a change of control of Apache, as defined in its income continuance plan. George D. Lawrence, a director of Apache, is chairman of the board of trustees of Ucross Foundation. Raymond Plank, chairman of Apache’s board of directors, G. Steven Farris, a director and officer of Apache, and Roger B. Plank, an officer of Apache, are each trustees of Ucross Foundation.

During 2005, 2004 and 2003, Apache and its subsidiaries made donations of $5,011,000, $5,033,000 and $500,000, in cash, property and services, to The Fund for Teachers: A Foundation to Recognize, Stimulate and Enhance (Fund for Teachers), a Texas non-profit corporation. In addition, during 2005, Apache made a pledge to Fund for Teachers for $5 million in cash, property and services that will be paid in 2006. Fund for Teachers seeks to provide resources directly to teachers to support learning experiences of their own design to increase effectiveness with students, and is currently focused on funding summer sabbaticals for selected applicants. Frederick M. Bohen, a director of Apache, is chairman of the board of Fund for Teachers, and Patricia Albjerg Graham, a director of Apache, is a director of Fund for Teachers. Raymond Plank, chairman of Apache’s board of directors, is the founder and a director of Fund for Teachers.

During 2005, Apache and its subsidiaries made donations of $565,000 in cash, property and services to Springboard — Educating the Future (Springboard), a U.S. based non-profit organization supporting Egypt’s National Council for Childhood and Motherhood. Apache initiated Springboard, whose mission is to encourage innovative partnerships to increase educational opportunities for disadvantaged children. Springboard works with governmental and non-governmental organizations, generous individuals and corporations to provide supplemental financial and in-kind resources for construction and operation of school facilities for girls in Egypt. George D. Lawrence, a director of Apache, is chairman of the board of Springboard and Rodney J. Eichler, an executive vice president of the Company, is the president and a director of Springboard.

During 2005, Apache paid $94,000 to Piney Creek Construction for the management of construction projects undertaken by Apache subsidiaries. Piney Creek Construction is owned by Michael R. Plank, a son of Raymond Plank, chairman of Apache’s board of directors, and a brother of Roger B. Plank, an officer of Apache.

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During 2005, Indian Creek Holdings Ltd., a Texas limited partnership, whose general partner is Indian Creek Management LLC, leased approximately one-half acre of land to Apache Foundation rent free for a period of ten years for the purpose of locating a restored historic farmhouse on the site in New Ulm, Texas. The house is used for meetings, seminars, retreats, community events and other activities which are educational, scientific, cultural, recreational, religious, civic or non-profit in nature. Also during 2005, Apache Foundation spent $66,000 for restoration and moving the farmhouse. Roger B. Plank, an officer of Apache, is president of Indian Creek Management LLC.


	Major Customers

In 2005, purchases by BP and Shell each accounted for 16 percent of the Company’s oil and gas production revenues.

In 2004, purchases by EGPC and BP accounted for 17 percent and 15 percent, respectively, of the Company’s oil and gas production revenues.

In 2003, purchases by Cinergy, EGPC and BP accounted for 12 percent, 16 percent and 15 percent of the Company’s oil and gas production revenues, respectively.


	Concentration of Credit Risk

The Company’s revenues are derived principally from uncollateralized sales to customers in the oil and gas industry; therefore, customers may be similarly affected by changes in economic and other conditions within the industry. Apache has not experienced significant credit losses on such sales. Apache sells a large portion of its Egyptian crude oil and natural gas to EGPC for U.S. dollars. Beginning in 2001, we experienced a gradual decline in timeliness of receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic conditions during 2001 in Egypt lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. During 2005, we experienced variability in the timing of cash receipts, but our past due balance improved by year-end. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and have no indication that we will not be able to collect our receivable.


13.	BUSINESS SEGMENT INFORMATION

Apache has six reportable segments which are primarily in the business of crude oil and natural gas exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before income and expense items incidental to oil and gas operations and income taxes.

F-43

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache’s reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:


												Other
		United States		Canada		Egypt		Australia		North Sea		International		Total

		(In thousands)
2005
Oil and gas production revenues		$	2,824,522	$	1,450,801	$	1,358,183	$	400,791	$	1,274,470	$	148,524	$	7,457,291
Operating Expenses:
	Depreciation, depletion and amortization		580,294		266,780		221,230		102,139		187,315		57,924		1,415,682
	Asset retirement obligation accretion		31,657		6,811		—		2,414		12,709		129		53,720
	Lease operating costs		477,780		229,592		116,160		55,666		146,015		15,262		1,040,475
	Gathering and transportation costs		29,954		33,309		7,991		—		28,248		758		100,260
	Severance and other taxes		107,300		22,279		—		38,386		285,293		—		453,258

Operating Income (Loss)		$	1,597,537	$	892,030	$	1,012,802	$	202,186	$	614,890	$	74,451		4,393,896

Other Income (Expense):
	Other														126,953
	General and administrative														(198,272	)
	Financing costs, net														(116,323	)

Income Before Income Taxes														$	4,206,254

Net Property and Equipment		$	7,745,703	$	4,526,113	$	1,894,141	$	1,113,181	$	1,391,048	$	121,154	$	16,791,340

Total Assets		$	8,690,410	$	4,952,561	$	2,509,970	$	1,318,233	$	1,625,168	$	175,454	$	19,271,796

Additions to Net Property and Equipment		$	1,656,780	$	1,454,636	$	541,732	$	252,787	$	467,421	$	59,134	$	4,432,490

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


													Other
		United States		Canada		Egypt		Australia		North Sea			International		Total

		(In thousands)
2004
Oil and gas production revenues		$	2,332,064	$	1,014,097	$	932,767	$	458,006	$	472,091		$	98,992	$	5,308,017
Operating Expenses:
	Depreciation, depletion and amortization		554,598		204,181		176,307		118,183		126,667			42,216		1,222,152
	Asset retirement obligation accretion		25,531		6,078		—		2,277		12,048			126		46,060
	Lease operating costs		376,608		186,043		92,791		52,309		143,453			13,174		864,378
	Gathering and transportation costs		28,324		30,741		—		—		22,619			577		82,261
	Severance and other taxes		67,544		22,766		—		64,345		(61,361	)		454		93,748

Operating Income (Loss)		$	1,279,459	$	564,288	$	663,669	$	220,892	$	228,665		$	42,445		2,999,418

Other Income (Expense):
	Other															24,560
	General and administrative															(173,194	)
	Financing costs, net															(116,485	)
	China litigation provision															(71,216	)

Income Before Income Taxes															$	2,663,083

Net Property and Equipment		$	6,754,515	$	3,338,990	$	1,573,639	$	951,704	$	1,112,451		$	129,060	$	13,860,359

Total Assets		$	7,394,542	$	3,633,469	$	1,948,833	$	1,131,026	$	1,244,419		$	150,191	$	15,502,480

Additions to Net Property and Equipment		$	2,050,025	$	816,198	$	392,300	$	178,280	$	369,542		$	26,587	$	3,832,932

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


												Other
		United States		Canada		Egypt		Australia		North Sea		International			Total

		(In thousands)
2003
Oil and gas production revenues		$	2,023,492	$	823,273	$	652,913	$	391,968	$	273,044	$	34,230		$	4,198,920
Operating Expenses:
	Depreciation, depletion and amortization		512,691		172,056		182,209		120,322		72,053		13,955			1,073,286
	Asset retirement obligation accretion		18,861		5,275		—		2,239		11,282		106			37,763
	International impairments		—		—		—		—		—		12,813			12,813
	Lease operating costs		302,095		153,598		82,558		44,395		109,140		7,877			699,663
	Gathering and transportation costs		21,128		28,154		—		—		11,178		—			60,460
	Severance and other taxes		52,651		20,183		—		28,245		19,591		1,123			121,793

Operating Income (Loss)		$	1,116,066	$	444,007	$	388,146	$	196,767	$	49,800	$	(1,644	)		2,193,142

Other Income (Expense):
	Other															(8,621	)
	General and administrative															(138,524	)
	Financing costs, net															(115,072	)
	Preferred interests of subsidiaries															(8,668	)

Income Before Income Taxes															$	1,922,257

Net Property and Equipment		$	5,268,990	$	2,727,620	$	1,357,646	$	891,567	$	869,574	$	144,688		$	11,260,085

Total Assets		$	5,621,681	$	2,961,111	$	1,744,164	$	970,764	$	941,577	$	176,829		$	12,416,126

Additions to Net Property and Equipment		$	1,489,457	$	630,515	$	276,293	$	159,923	$	941,629	$	33,622		$	3,531,439

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


14.	SUPPLEMENTAL OIL AND GAS DISCLOSURES (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.


		United											Other
		States		Canada		Egypt		Australia		North Sea			International		Total

		(In thousands)
2005
Oil and gas production revenues		$	2,824,522	$	1,450,801	$	1,358,183	$	400,791	$	1,274,470		$	148,524	$	7,457,291

Operating costs:
	Depreciation, depletion and amortization(1)		556,922		261,195		221,230		100,798		186,675			57,892		1,384,712
	Asset retirement obligation accretion		31,657		6,811		—		2,414		12,709			129		53,720
	Lease operating expenses		477,780		229,592		116,160		55,666		146,015			15,262		1,040,475
	Gathering and transportation costs		29,954		33,309		7,991		—		28,248			758		100,260
	Production taxes(2)		99,009		9,112		—		38,386		285,293			—		431,800
	Income tax		578,366		332,435		486,145		69,199		246,212			24,697		1,737,054

			1,773,688		872,454		831,526		266,463		905,152			98,738		4,748,021

Results of operations		$	1,050,834	$	578,347	$	526,657	$	134,328	$	369,318		$	49,786	$	2,709,270

Amortization rate per boe		$	8.78	$	7.71	$	6.34	$	6.82	$	7.76		$	16.16	$	7.99

2004
Oil and gas production revenues		$	2,332,064	$	1,014,097	$	932,767	$	458,006	$	472,091		$	98,992	$	5,308,017

Operating costs:
	Depreciation, depletion and amortization(1)		531,593		200,155		176,307		117,098		126,237			42,186		1,193,576
	Asset retirement obligation accretion		25,531		6,078		—		2,277		12,048			126		46,060
	Lease operating expenses		376,608		186,043		92,791		52,309		143,453			13,174		864,378
	Gathering and transportation costs		28,324		30,741		—		—		22,619			577		82,261
	Production taxes(2)		62,791		9,551		—		64,345		(61,361	)		454		75,780
	Income tax		490,206		233,949		318,561		75,472		98,511			14,060		1,230,759

			1,515,053		666,517		587,659		311,501		341,507			70,577		3,492,814

Results of operations		$	817,011	$	347,580	$	345,108	$	146,505	$	130,584		$	28,415	$	1,815,203

Amortization rate per boe		$	7.88	$	6.28	$	5.60	$	6.53	$	6.49		$	13.12	$	7.01

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		United										Other
		States		Canada		Egypt		Australia		North Sea		International			Total

		(In thousands)
2003
Oil and gas production revenues		$	2,023,492	$	823,273	$	652,913	$	391,968	$	273,044	$	34,230		$	4,198,920

Operating costs:
	Depreciation, depletion and amortization(1)		489,969		169,029		182,209		119,455		71,956		13,914			1,046,532
	Asset retirement obligation accretion		18,861		5,275		—		2,239		11,282		106			37,763
	International impairments		—		—		—		—		—		12,813			12,813
	Lease operating expenses		302,095		153,598		82,558		44,395		109,140		7,877			699,663
	Gathering and transportation costs		21,128		28,154		—		—		11,178		—			60,460
	Production taxes(2)		50,615		4,180		—		28,245		19,591		1,123			103,754
	Income tax		427,809		201,421		186,310		67,196		21,456		(1,077	)		903,115

			1,310,477		561,657		451,077		261,530		244,603		34,756			2,864,100

Results of operations		$	713,015	$	261,616	$	201,836	$	130,438	$	28,441	$	(526	)	$	1,334,820

Amortization rate per boe		$	7.13	$	5.43	$	6.62	$	6.13	$	6.67	$	8.36		$	6.59


(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 13, Business Segment Information.

(2)	This amount only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with severance and other taxes reflected on Note 13, Business Segment Information.

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


		United												Other
		States		Canada		Egypt		Australia			North Sea			International		Total

		(In thousands)
2005
Acquisitions:
	Proved	$	10,747	$	24,252	$	—	$	—		$	—		$	—	$	34,999
	Unproved		2,721		—		—		1,508			—			—		4,229
Purchase of non-producing leases			18,232		89,008		—		—			—			—		107,240
Exploration			49,111		197,719		66,529		91,658			21,267			22,491		448,775
Development			1,004,697		901,369		285,795		126,158			467,805			25,993		2,811,817
Capitalized interest			25,600		17,336		7,725		2,727			3,600			—		56,988

Costs incurred before asset retirement obligations			1,111,108		1,229,684		360,049		222,051			492,672			48,484		3,464,048

Plus: Asset retirement obligation costs			532,784		31,021		—		10,624			(27,760	)		—		546,669

Costs incurred		$	1,643,892	$	1,260,705	$	360,049	$	232,675		$	464,912		$	48,484	$	4,010,717

2004
Acquisitions:
	Proved	$	926,088	$	9,839	$	—	$	—		$	1,154		$	—	$	937,081
	Unproved		126,770		—		—		—			—			—		126,770
Purchase of non-producing leases			19,717		46,085		—		—			—			—		65,802
Exploration			65,658		142,753		62,651		51,988			8,717			4,277		336,044
Development			669,681		568,074		239,261		86,706			353,337			22,216		1,939,275
Capitalized interest			21,000		15,152		6,563		1,748			6,285			—		50,748

Costs incurred before asset retirement obligations			1,828,914		781,903		308,475		140,442			369,493			26,493		3,455,720

Plus: Asset retirement obligation costs			183,915		10,681		—		—			(643	)		—		193,953

Costs incurred		$	2,012,829	$	792,584	$	308,475	$	140,442		$	368,850		$	26,493	$	3,649,673

2003
Acquisitions:
	Proved	$	728,486	$	5,272	$	—	$	27,105		$	622,899		$	—	$	1,383,762
	Unproved		118,250		1,094		—		—			65,000			—		184,344
Purchase of non-producing leases			5,795		44,939		—		—			—			—		50,734
Exploration			32,020		114,924		54,305		68,493			4,314			3,669		277,725
Development			379,886		408,993		188,347		59,768			55,890			31,429		1,124,313
Capitalized interest			16,150		23,934		7,568		1,973			3,266			—		52,891

Costs incurred before asset retirement obligations			1,280,587		599,156		250,220		157,339			751,369			35,098		3,073,769

Plus: Asset retirement obligation costs			165,374		17,465		—		(3,589	)		189,190			350		368,790

Costs incurred		$	1,445,961	$	616,621	$	250,220	$	153,750		$	940,559		$	35,448	$	3,442,559

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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			International			Total

	(In thousands)
2005
Proved properties	$	12,983,185		$	5,117,868		$	2,193,279		$	1,512,215		$	1,735,646		$	294,596		$	23,836,789
Unproved properties		264,147			291,120			132,509			49,566			38,675			19,689			795,706

		13,247,332			5,408,988			2,325,788			1,561,781			1,774,321			314,285			24,632,495
Accumulated DD&A		(5,607,170	)		(1,208,397	)		(1,008,660	)		(645,244	)		(384,868	)		(191,849	)		(9,046,188	)

	$	7,640,162		$	4,200,591		$	1,317,128		$	916,537		$	1,389,453		$	122,436		$	15,586,307

2004
Proved properties	$	11,378,189		$	3,929,136		$	1,836,436		$	1,292,165		$	1,252,911		$	244,204		$	19,933,041
Unproved properties		313,009			220,340			129,303			38,450			56,498			20,090			777,690

		11,691,198			4,149,476			1,965,739			1,330,615			1,309,409			264,294			20,710,731
Accumulated DD&A		(5,051,373	)		(964,454	)		(817,100	)		(555,797	)		(198,193	)		(133,957	)		(7,720,874	)

	$	6,639,825		$	3,185,022		$	1,148,639		$	774,818		$	1,111,216		$	130,337		$	12,989,857

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2005, 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.


										2002 and
		Total		2005		2004		2003		Prior

		(In thousands)
Property acquisition costs		$	501,439	$	136,586	$	144,660	$	86,941	$	133,252
Exploration and development			278,256		130,753		59,278		50,676		37,549
Capitalized interest			16,011		6,021		2,769		1,407		5,814

	Total	$	795,706	$	273,360	$	206,707	$	139,024	$	176,615

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil and Gas Reserve Information

Proved oil and gas reserve quantities are based on estimates prepared by the Company’s engineers in accordance with Rule 4-10 of Regulation S-X. The Company engages Ryder Scott Company, L.P. Petroleum Consultants as independent petroleum engineers, to review the Company’s estimates of proved hydrocarbon liquid and gas reserves and provide an opinion letter on the reasonableness of Apache’s internal projections. During this review, they prepare independent projections for each reviewed property and determine if the Company’s estimates are within engineering tolerance by geographical area. The independent reviews typically cover a large percentage of major value fields, international properties and new wells drilled during the year. During 2005, 2004 and 2003, their review covered 74, 79 and 78 percent of the Apache’s estimated reserve value, respectively.

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.


			Crude Oil, Condensate and Natural Gas Liquids																					Natural Gas																					Total

																																													(Thousand
			(Thousands of barrels)																					(Millions of cubic feet)																					barrels of
			United												North			Other						United												North			Other						oil
			States			Canada			Egypt			Australia			Sea			Int’l			Total			States			Canada			Egypt			Australia			Sea			Int’l			Total			equivalent)

Proved developed reserves:
		December 31, 2002		240,880			89,554			51,162			31,746			—			1,033			414,375			1,444,677			1,255,068			246,529			256,790			—			3,469			3,206,533			948,797
		December 31, 2003		265,135			91,501			54,881			26,999			147,880			7,293			593,689			1,565,855			1,411,877			337,844			218,745			3,902			2,750			3,540,973			1,183,851
		December 31, 2004		320,752			87,914			57,084			18,919			172,260			5,721			662,650			1,722,803			1,479,271			474,028			158,789			6,804			2,364			3,844,059			1,303,327
		December 31, 2005		313,580			87,012			59,197			22,550			189,385			4,966			676,690			1,711,060			1,799,102			605,687			649,972			7,475			2,594			4,775,890			1,472,672
Total proved reserves:
	Balance December 31, 2002			333,422			163,639			74,791			52,248			—			12,665			636,765			1,784,093			1,338,751			370,667			557,656			—			3,469			4,054,636			1,312,538
		Extensions, discoveries and other additions		35,378			15,649			15,090			11,712			14,489			640			92,958			113,552			387,533			217,455			127,516			105			2,084			848,245			234,333
		Purchases of minerals in-place		48,886			574			—			309			144,071			—			193,840			391,510			4,510			—			38,638			4,423			—			439,081			267,019
		Revisions of previous estimates		953			12			648			(2	)		—			(113	)		1,498			6,073			(8,177	)		4,292			—			—			1			2,189			1,863
		Production		(28,098	)		(9,776	)		(17,356	)		(11,165	)		(10,680	)		(1,230	)		(78,305	)		(242,782	)		(116,263	)		(41,447	)		(40,537	)		(626	)		(2,607	)		(444,262	)		(152,349	)
		Sales of properties		(1,176	)		(1,692	)		—			—			—			—			(2,868	)		(23,054	)		(671	)		—			—			—			(196	)		(23,921	)		(6,855	)

	Balance December 31, 2003			389,365			168,406			73,173			53,102			147,880			11,962			843,888			2,029,392			1,605,683			550,967			683,273			3,902			2,751			4,875,968			1,656,549
		Extensions, discoveries and other additions		26,600			1,106			26,865			10,422			45,261			186			110,440			291,303			542,779			452,509			54,272			3,575			1,007			1,345,445			334,681
		Purchases of minerals in-place		84,375			165			—			—			389			—			84,929			268,386			17,273			—			—			12			—			285,671			132,541
		Revisions of previous estimates		(13,588	)		(1,207	)		(2,955	)		2			(4	)		(348	)		(18,100	)		53,816			(61,695	)		(18,572	)		1			—			1			(26,449	)		(22,508	)
		Production		(27,867	)		(10,209	)		(19,099	)		(9,214	)		(19,338	)		(2,982	)		(88,709	)		(236,660	)		(119,669	)		(50,412	)		(43,228	)		(685	)		(1,395	)		(452,049	)		(164,050	)
		Sales of properties		(408	)		—			—			—			—			—			(408	)		(657	)		—			—			—			—			—			(657	)		(518	)

Balance December 31, 2004				458,477			158,261			77,984			54,312			174,188			8,818			932,040			2,405,580			1,984,371			934,492			694,318			6,804			2,364			6,027,929			1,936,695
		Extensions, discoveries and other additions		27,055			16,531			37,431			2,623			44,977			1,307			129,924			388,844			526,876			241,420			175,502			1,441			1,350			1,335,433			352,496
		Purchases of minerals in-place		2,020			1,874			—			—			—			—			3,894			17,792			5,749			—			—			—			—			23,541			7,818
		Revisions of previous estimates		4,039			2,591			(4,396	)		—			1			(65	)		2,170			23,470			(13,717	)		(35,071	)		—			72			17			(25,229	)		(2,035	)
		Production		(26,945	)		(9,028	)		(20,126	)		(5,613	)		(23,904	)		(3,392	)		(89,008	)		(218,080	)		(135,749	)		(60,484	)		(45,003	)		(842	)		(1,137	)		(461,295	)		(165,890	)
		Sales of properties		(3,078	)		(32	)		—			—			—			—			(3,110	)		(51,419	)		(938	)		—			—			—			—			(52,357	)		(11,836	)

Balance December 31, 2005				461,568			170,197			90,893			51,322			195,262			6,668			975,910			2,566,187			2,366,592			1,080,357			824,817			7,475			2,594			6,848,022			2,117,248

As of December 31, 2005, 2004 and 2003, on a barrel of equivalent basis 30, 33 and 29 percent of our estimated worldwide reserves, respectively, were classified as proved undeveloped. Approximately 23 percent of our year-end 2005 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 may be regarded as less certain 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 14, under “Future Net Cash Flows.”

F-51

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															Other
	States			Canada(1)			Egypt			Australia			North Sea			International			Total

	(In thousands)
2005
Cash inflows	$	47,315,554		$	29,305,244		$	8,545,414		$	4,298,054		$	10,879,416		$	329,658		$	100,673,340
Production costs		(10,164,938	)		(7,299,065	)		(972,441	)		(1,132,858	)		(6,345,449	)		(64,770	)		(25,979,521	)
Development costs		(2,355,717	)		(1,189,550	)		(1,072,391	)		(537,257	)		(650,721	)		(37,858	)		(5,843,494	)
Income tax expense		(11,098,793	)		(6,232,460	)		(2,307,759	)		(715,294	)		(1,355,266	)		(45,652	)		(21,755,224	)

Net cash flows		23,696,106			14,584,169			4,192,823			1,912,645			2,527,980			181,378			47,095,101
10 percent discount rate		(11,617,808	)		(7,868,888	)		(1,537,495	)		(723,140	)		(787,319	)		(32,102	)		(22,566,752	)

Discounted future net cash flows(2)	$	12,078,298		$	6,715,281		$	2,655,328		$	1,189,505		$	1,740,661		$	149,276		$	24,528,349

2004
Cash inflows	$	32,557,246		$	17,140,078		$	6,233,328		$	3,065,332		$	6,783,414		$	323,963		$	66,103,361
Production costs		(8,185,633	)		(7,451,626	)		(818,876	)		(891,117	)		(4,098,870	)		(89,280	)		(21,535,402	)
Development costs		(1,620,421	)		(584,160	)		(596,249	)		(422,045	)		(569,435	)		(25,220	)		(3,817,530	)
Income tax expense		(7,342,348	)		(2,461,911	)		(1,790,617	)		(423,263	)		(617,244	)		(42,314	)		(12,677,697	)

Net cash flows		15,408,844			6,642,381			3,027,586			1,328,907			1,497,865			167,149			28,072,732
10 percent discount rate		(7,414,246	)		(3,177,411	)		(1,165,331	)		(568,722	)		(418,169	)		(32,775	)		(12,776,654	)

Discounted future net cash flows(2)	$	7,994,598		$	3,464,970		$	1,862,255		$	760,185		$	1,079,696		$	134,374		$	15,296,078

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United															Other
	States			Canada(1)			Egypt			Australia			North Sea			International			Total

	(In thousands)
2003
Cash inflows	$	23,117,256		$	12,533,197		$	3,999,829		$	2,737,289		$	4,193,438		$	378,032		$	46,959,041
Production costs		(6,012,893	)		(3,049,847	)		(545,505	)		(658,132	)		(2,622,103	)		(63,384	)		(12,951,864	)
Development costs		(1,152,182	)		(451,491	)		(397,493	)		(397,206	)		(593,778	)		(17,431	)		(3,009,581	)
Income tax expense		(4,834,389	)		(2,595,286	)		(997,847	)		(433,667	)		(195,756	)		(59,616	)		(9,116,561	)

Net cash flows		11,117,792			6,436,573			2,058,984			1,248,284			781,801			237,601			21,881,035
10 percent discount rate		(5,222,609	)		(3,353,451	)		(726,933	)		(536,921	)		(204,248	)		(59,029	)		(10,103,191	)

Discounted future net cash flows(2)	$	5,895,183		$	3,083,122		$	1,332,051		$	711,363		$	577,553		$	178,572		$	11,777,844


(1)	Included in the estimated future net cash flows are Canadian provincial tax credits expected to be realized beyond the date at which the legislation, under its provisions, could be repealed. To date, the Canadian provincial government has not indicated an intention to repeal this legislation.

(2)	Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $35.9 billion, $22.2 billion and $16.4 billion as of December 31, 2005, 2004 and 2003, respectively.

F-53

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,

	2005			2004			2003

	(In thousands)
Sales, net of production costs	$	(5,990,000	)	$	(4,383,289	)	$	(3,312,728	)
Net change in prices and production costs		13,133,104			1,119,906			224,609
Discoveries and improved recovery, net of related costs		5,572,707			4,404,964			2,808,283
Change in future development costs		(635,122	)		103,481			48,531
Revision of quantities		(298,487	)		(242,005	)		22,807
Purchases of minerals in-place		201,719			2,051,068			2,743,936
Accretion of discount		2,226,336			1,660,486			1,317,894
Change in income taxes		(4,426,510	)		(2,091,187	)		(795,143	)
Sales of properties		(121,773	)		(5,825	)		(90,263	)
Change in production rates and other		(429,703	)		900,635			(341,703	)

	$	9,232,271		$	3,518,234		$	2,626,223

Impact of Pricing

The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future natural gas or oil sales are covered by physical contracts at specified prices. Forward price volatility is largely attributable to supply and demand perceptions for natural gas and oil.

Under full-cost accounting rules, the Company reviews 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 at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects (the “ceiling”). These rules generally require pricing future oil and gas production at the unescalated oil and gas prices at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded. Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur in the future.

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


15.	SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)


		First		Second		Third		Fourth			Total

		(In thousands, except per share amounts)
2005
Revenues		$	1,662,288	$	1,759,231	$	2,061,052	$	2,101,673		$	7,584,244
Expenses, net			1,101,805		1,171,201		1,374,057		1,313,451			4,960,514

Net income		$	560,483	$	588,030	$	686,995	$	788,222		$	2,623,730

Income attributable to common stock		$	559,063	$	586,610	$	685,575	$	786,802		$	2,618,050

Net income per common share(1):
	Basic	$	1.70	$	1.79	$	2.08	$	2.39		$	7.96

	Diluted	$	1.67	$	1.76	$	2.05	$	2.35		$	7.84

2004(2)
Revenues		$	1,149,939	$	1,240,733	$	1,407,002	$	1,534,903		$	5,332,577
Expenses, net			803,614		857,207		976,527		1,025,158			3,662,506

Income before change in accounting principle			346,325		383,526		430,475		509,745			1,670,071
Cumulative effect of change in accounting principle, net of income tax			—		—		—		(1,317	)		(1,317	)

Net income		$	346,325	$	383,526	$	430,475	$	508,428		$	1,668,754

Income attributable to common stock		$	344,905	$	382,106	$	429,055	$	507,008		$	1,663,074

Net income per common share(1):
	Basic	$	1.06	$	1.17	$	1.31	$	1.55		$	5.10

	Diluted	$	1.05	$	1.16	$	1.30	$	1.52		$	5.03


(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.

(2)	The first, second and third-quarter totals for 2004 will not agree to the applicable Form 10-Q filing because interim amounts have been restated to reflect the early adoption of SFAS No. 123-R, refer to Note 1, Summary of Significant Accounting Policies.


16.	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 guaranteed by Apache and, beginning in 2001, Apache North America, Inc. The guarantors of Apache Finance Australia have joint and several liability. 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.

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2005


												All Other
						Apache						Subsidiaries
		Apache		Apache		Finance			Apache			of Apache			Reclassifications
		Corporation		North America		Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
Revenues and Other:
	Oil and gas production revenues	$	2,784,339	$	—	$	—		$	—		$	5,002,331		$	(329,379	)	$	7,457,291
	Equity in net income of affiliates		1,636,571		34,622		46,839			275,191			(49,699	)		(1,943,524	)		—
	Other		125,812		—		(25	)		—			1,166			—			126,953

			4,546,722		34,622		46,814			275,191			4,953,798			(2,272,903	)		7,584,244

Operating Expenses:
	Depreciation, depletion and amortization		575,748		—		—			—			839,934			—			1,415,682
	Asset retirement obligation accretion		31,657		—		—			—			22,063			—			53,720
	Lease operating costs		477,780		—		—			—			892,074			(329,379	)		1,040,475
	Gathering and transportation costs		30,025		—		—			—			70,235			—			100,260
	Severance and other taxes		103,381		—		—			1			349,876			—			453,258
	Administrative, selling and other		167,011		—		—			—			31,261			—			198,272
	Financing costs, net		76,004		—		18,050			56,440			(34,171	)		—			116,323

			1,461,606		—		18,050			56,441			2,171,272			(329,379	)		3,377,990

Income (Loss) Before Income Taxes			3,085,116		34,622		28,764			218,750			2,782,526			(1,943,524	)		4,206,254
	Provision (benefit) for income taxes		461,386		—		(5,858	)		(18,959	)		1,145,955			—			1,582,524

Net Income			2,623,730		34,622		34,622			237,709			1,636,571			(1,943,524	)		2,623,730
	Preferred stock dividends		5,680		—		—			—			—			—			5,680

Income Attributable to Common Stock		$	2,618,050	$	34,622	$	34,622		$	237,709		$	1,636,571		$	(1,943,524	)	$	2,618,050

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2004


													All Other
							Apache						Subsidiaries
		Apache			Apache		Finance			Apache			of Apache			Reclassifications
		Corporation			North America		Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
Revenues and Other:
	Oil and gas production revenues	$	2,313,901		$	—	$	—		$	—		$	3,295,849		$	(301,733	)	$	5,308,017
	Equity in net income of affiliates		978,881			51,888		63,859			152,823			33,641			(1,281,092	)		—
	Other		47,321			—		(25	)		—			(22,736	)		—			24,560

			3,340,103			51,888		63,834			152,823			3,306,754			(1,582,825	)		5,332,577

Operating Expenses:
	Depreciation, depletion and amortization		551,057			—		—			—			671,095			—			1,222,152
	Asset retirement obligation accretion		25,531			—		—			—			20,529			—			46,060
	Lease operating costs		375,894			—		—			—			790,217			(301,733	)		864,378
	Gathering and transportation costs		28,317			—		—			—			53,944			—			82,261
	Severance and other taxes		65,559			—		—			(208	)		28,397			—			93,748
	Administrative, selling and other		138,058			—		—			—			35,136			—			173,194
	China litigation provision		—			—		—			—			71,216			—			71,216
	Financing costs, net		86,980			—		18,047			40,363			(28,905	)		—			116,485

			1,271,396			—		18,047			40,155			1,641,629			(301,733	)		2,669,494

Income (Loss) Before Income Taxes			2,068,707			51,888		45,787			112,668			1,665,125			(1,281,092	)		2,663,083
	Provision (benefit) for income taxes		398,636			—		(6,101	)		(85,767	)		686,244			—			993,012

Income (Loss) Before Change in Accounting Principle			1,670,071			51,888		51,888			198,435			978,881			(1,281,092	)		1,670,071
	Cumulative effect of change in accounting principle, net of income tax		(1,317	)		—		—			—			—			—			(1,317	)

Net Income			1,668,754			51,888		51,888			198,435			978,881			(1,281,092	)		1,668,754
	Preferred stock dividends		5,680			—		—			—			—			—			5,680

Income Attributable to Common Stock		$	1,663,074		$	51,888	$	51,888		$	198,435		$	978,881		$	(1,281,092	)	$	1,663,074

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2003


													All Other
							Apache						Subsidiaries
		Apache			Apache		Finance			Apache			of Apache			Reclassifications
		Corporation			North America		Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
Revenues and Other:
	Oil and gas production revenues	$	1,687,609		$	—	$	—		$	—		$	2,729,966		$	(218,655	)	$	4,198,920
	Equity in net income of affiliates		597,020			21,189		33,117			111,274			(37,160	)		(725,440	)		—
	Other		(4,250	)		—		(25	)		—			(4,346	)		—			(8,621	)

			2,280,379			21,189		33,092			111,274			2,688,460			(944,095	)		4,190,299

Operating Expenses:
	Depreciation, depletion and amortization		374,534			—		—			—			698,752			—			1,073,286
	Asset retirement obligation accretion		15,944			—		—			—			21,819			—			37,763
	International impairments		—			—		—			—			12,813			—			12,813
	Lease operating costs		264,311			—		—			—			654,007			(218,655	)		699,663
	Gathering and transportation costs		19,558			—		—			—			40,902			—			60,460
	Severance and other taxes		50,899			—		—			63			70,831			—			121,793
	Administrative, selling and other		111,984			—		—			—			26,540			—			138,524
	Financing costs, net		102,142			—		18,047			40,064			(45,181	)		—			115,072

			939,372			—		18,047			40,127			1,480,483			(218,655	)		2,259,374

Preferred Interests of Subsidiaries			(592	)		—		—			—			9,260			—			8,668

Income (Loss) Before Income Taxes			1,341,599			21,189		15,045			71,147			1,198,717			(725,440	)		1,922,257
	Provision (benefit) for income taxes		239,471			—		(6,144	)		(14,895	)		608,572			—			827,004

Income (Loss) Before Change in Accounting Principle			1,102,128			21,189		21,189			86,042			590,145			(725,440	)		1,095,253
	Cumulative effect of change in accounting principle, net of income tax		19,757			—		—			—			6,875			—			26,632

Net Income			1,121,885			21,189		21,189			86,042			597,020			(725,440	)		1,121,885
	Preferred stock dividends		5,680			—		—			—			—			—			5,680

Income Attributable to Common Stock		$	1,116,205		$	21,189	$	21,189		$	86,042		$	597,020		$	(725,440	)	$	1,116,205

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2005


														All Other
								Apache						Subsidiaries
		Apache			Apache			Finance			Apache			of Apache			Reclassifications
		Corporation			North America			Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
Cash Provided by (Used in) Operating Activities		$	1,976,399		$	—		$	(21,000	)	$	(40,186	)	$	2,417,057		$	—		$	4,332,270

Cash Flows from Investing Activities:
	Additions to property and equipment		(1,572,043	)		—			—			—			(2,143,813	)		—			(3,715,856	)
	Proceeds from sales of oil and gas properties		78,468			—			—			—			1,195			—			79,663
	Investment in and advances to subsidiaries, net		26,088			(18,050	)		—			—			(60,908	)		52,870			—
	Other, net		(23,612	)		—			—			—			(72,037	)		—			(95,649	)

Net Cash Used in Investing Activities			(1,491,099	)		(18,050	)		—			—			(2,275,563	)		52,870			(3,731,842	)

Cash Flows from Financing Activities:
	Long-term borrowings		153,087			—			2,950			554			(49,058	)		45,835			153,368
	Payments on long-term debt		(548,700	)		—			—			—			(830	)		—			(549,530	)
	Dividends paid		(117,395	)		—			—			—			—			—			(117,395	)
	Common stock activity		18,864			18,050			18,050			39,630			22,975			(98,705	)		18,864
	Treasury stock activity, net		6,620			—			—			—			—			—			6,620
	Cost of debt and equity transactions		(861	)		—			—			—			—			—			(861	)
	Other		6,273			—			—			—			—			—			6,273

Net Cash Provided by Financing Activities			(482,112	)		18,050			21,000			40,184			(26,913	)		(52,870	)		(482,661	)

Net Increase (Decrease) in Cash and Cash Equivalents			3,188			—			—			(2	)		114,581			—			117,767
Cash and Cash Equivalents at Beginning of Year			597			—			2			3			110,491			—			111,093

Cash and Cash Equivalents at End of Year		$	3,785		$	—		$	2		$	1		$	225,072		$	—		$	228,860

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2004


														All Other
								Apache						Subsidiaries
		Apache			Apache			Finance			Apache			of Apache			Reclassifications
		Corporation			North America			Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
Cash Provided by (Used in) Operating Activities		$	1,486,100		$	—		$	(17,500	)	$	(356,371	)	$	2,119,290		$	—		$	3,231,519

Cash Flows from Investing Activities:
	Additions to property and equipment		(900,464	)		—			—			—			(1,556,024	)		—			(2,456,488	)
	Acquisitions		(880,136	)		—			—			—			—			—			(880,136	)
	Proceeds from sales of oil and gas properties		3,210			—			—			—			832			—			4,042
	Investment in and advances to subsidiaries, net		62,069			(18,050	)		—			—			(373,353	)		329,334			—
	Other, net		(27,003	)		—			—			—			(51,428	)		—			(78,431	)

Net Cash Used in Investing Activities			(1,742,324	)		(18,050	)		—			—			(1,979,973	)		329,334			(3,411,013	)

Cash Flows from Financing Activities:
	Long-term borrowings		544,561			—			(550	)		347,550			(184,717	)		(162,020	)		544,824
	Payments on long-term debt		(283,400	)		—			—			—			—			—			(283,400	)
	Dividends paid		(90,369	)		—			—			—			—			—			(90,369	)
	Common stock activity		21,595			18,050			18,050			8,823			122,391			(167,314	)		21,595
	Treasury stock activity, net		12,472			—			—			—			—			—			12,472
	Cost of debt and equity transactions		(2,303	)		—			—			—			—			—			(2,303	)
	Other		54,265			—			—			—			—			—			54,265

Net Cash Provided by Financing Activities			256,821			18,050			17,500			356,373			(62,326	)		(329,334	)		257,084

Net Increase (Decrease) in Cash and Cash Equivalents			597			—			—			2			76,991			—			77,590
Cash and Cash Equivalents at Beginning of Year			—			—			2			1			33,500			—			33,503

Cash and Cash Equivalents at End of Year		$	597		$	—		$	2		$	3		$	110,491		$	—		$	111,093

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2003


														All Other
								Apache						Subsidiaries
		Apache			Apache			Finance			Apache			of Apache			Reclassifications
		Corporation			North America			Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
Cash Provided by (Used in) Operating Activities		$	1,136,019		$	—		$	(19,604	)	$	(39,675	)	$	1,629,160		$	—		$	2,705,900

Cash Flows from Investing Activities:
	Additions to property and equipment		(516,941	)		—			—			—			(1,099,995	)		—			(1,616,936	)
	Acquisitions		(714,651	)		—			—			—			(628,538	)		—			(1,343,189	)
	Proceeds from sales of oil and gas properties		45,678			—			—			—			13,266			—			58,944
	Investment in and advances to subsidiaries, net		(480,105	)		(18,113	)		—			—			(76,689	)		574,907			—
	Other, net		(33,763	)		—			—			—			(23,813	)		—			(57,576	)

Net Cash Used in Investing Activities			(1,699,782	)		(18,113	)		—			—			(1,815,769	)		574,907			(2,958,757	)

Cash Flows from Financing Activities:
	Long-term borrowings		1,555,361			—			1,491			2,102			(404,380	)		626,296			1,780,870
	Payments on long-term debt		(1,419,788	)		—			—			—			(193,574	)		—			(1,613,362	)
	Dividends paid		(72,832	)		—			—			—			—			—			(72,832	)
	Common stock activity		583,837			18,113			18,113			37,447			1,127,530			(1,201,203	)		583,837
	Treasury stock activity, net		4,378			—			—			—			—			—			4,378
	Cost of debt and equity transactions		(5,417	)		—			—			—			—			—			(5,417	)
	Repurchase of preferred interests of subsidiaries		(82,000	)		—			—			—			(361,000	)		—			(443,000	)

Net Cash Provided by Financing Activities			563,539			18,113			19,604			39,549			168,576			(574,907	)		234,474

Net Increase (Decrease) in Cash and Cash Equivalents			(224	)		—			—			(126	)		(18,033	)		—			(18,383	)
Cash and Cash Equivalents at Beginning of Year			224			—			2			127			51,533			—			51,886

Cash and Cash Equivalents at End of Year		$	—		$	—		$	2		$	1		$	33,500		$	—		$	33,503

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

For the Year Ended December 31, 2005


												All Other
						Apache						Subsidiaries
		Apache		Apache		Finance			Apache			of Apache			Reclassifications
		Corporation		North America		Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents	$	3,785	$	—	$	2		$	1		$	225,072		$	—		$	228,860
	Receivables, net of allowance		516,208		—		—			—			928,337			—			1,444,545
	Inventories		30,276		—		—			—			179,394			—			209,670
	Drilling advances and other		188,607		—		—			—			90,395			—			279,002

			738,876		—		2			1			1,423,198			—			2,162,077

Property and Equipment, Net			7,680,469		—		—			—			9,110,871			—			16,791,340

Other Assets:
	Intercompany receivable, net		1,058,228		—		(3,936	)		(254,216	)		(800,076	)		—			—
	Goodwill, net		—		—		—			—			189,252			—			189,252
	Equity in affiliates		5,833,283		315,460		558,215			1,609,007			(1,183,600	)		(7,132,365	)		—
	Deferred charges and other		44,974		—		—			4,301			79,852			—			129,127

		$	15,355,830	$	315,460	$	554,281		$	1,359,093		$	8,819,497		$	(7,132,365	)	$	19,271,796


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable	$	378,247	$	—	$	—		$	946		$	335,405		$	—		$	714,598
	Accrued expenses and other		687,125		—		5,619			38,343			740,879			—			1,471,966

			1,065,372		—		5,619			39,289			1,076,284			—			2,186,564

Long-Term Debt			1,271,431		—		269,411			646,860			4,252			—			2,191,954

Deferred Credits and Other Noncurrent Liabilities:
	Income taxes		1,140,457		—		(36,209	)		4,782			1,471,599			—			2,580,629
	Advances from gas purchasers		68,768		—		—			—			—			—			68,768
	Asset retirement obligation		972,024		—		—			—			390,334			—			1,362,358
	Oil and gas derivative instruments		152,430		—		—			—			—			—			152,430
	Other		144,133		—		—			—			43,745			—			187,878

			2,477,812		—		(36,209	)		4,782			1,905,678			—			4,352,063

Commitments and Contingencies Shareholders’ Equity			10,541,215		315,460		315,460			668,162			5,833,283			(7,132,365	)		10,541,215

		$	15,355,830	$	315,460	$	554,281		$	1,359,093		$	8,819,497		$	(7,132,365	)	$	19,271,796

F-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

For the Year Ended December 31, 2004


												All Other
						Apache						Subsidiaries
		Apache		Apache		Finance			Apache			of Apache			Reclassifications
		Corporation		North America		Australia			Finance Canada			Corporation			& Eliminations			Consolidated

		(In thousands)
ASSETS
Current Assets:
	Cash and cash equivalents	$	597	$	—	$	2		$	3		$	110,491		$	—		$	111,093
	Receivables, net of allowance		367,359		—		—			—			572,377			—			939,736
	Inventories		28,000		—		—			—			129,293			—			157,293
	Drilling advances and other		82,837		—		—			—			57,823			—			140,660

			478,793		—		2			3			869,984			—			1,348,782

Property and Equipment, Net			6,683,499		—		—			—			7,176,860			—			13,860,359

Other Assets:
	Intercompany receivable, net		1,107,286		—		(1,205	)		(253,724	)		(852,357	)		—			—
	Goodwill, net		—		—		—			—			189,252			—			189,252
	Equity in affiliates		4,173,788		258,437		506,806			1,250,590			(1,178,450	)		(5,011,171	)		—
	Deferred charges and other		43,460		—		—			4,617			56,010			—			104,087

		$	12,486,826	$	258,437	$	505,603		$	1,001,486		$	6,261,299		$	(5,011,171	)	$	15,502,480


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable	$	280,754	$	—	$	—		$	—		$	261,320		$	—		$	542,074
	Accrued expenses and other		306,511		—		3,335			29,946			401,025			—			740,817

			587,265		—		3,335			29,946			662,345			—			1,282,891

Long-Term Debt			1,667,044		—		269,192			646,798			5,356			—			2,588,390

Deferred Credits and Other Noncurrent Liabilities:
	Income taxes		1,132,618		—		(25,361	)		4,233			1,035,147			—			2,146,637
	Advances from gas purchasers		90,876		—		—			—			—			—			90,876
	Asset retirement obligation		568,862		—		—			—			363,142			—			932,004
	Oil and gas derivative instruments		31,417		—		—			—			—			—			31,417
	Other		204,323		—		—			—			21,521			—			225,844

			2,028,096		—		(25,361	)		4,233			1,419,810			—			3,426,778

Commitments and Contingencies Shareholders’ Equity			8,204,421		258,437		258,437			320,509			4,173,788			(5,011,171	)		8,204,421

		$	12,486,826	$	258,437	$	505,603		$	1,001,486		$	6,261,299		$	(5,011,171	)	$	15,502,480

F-64

Board of Directors

Frederick M. Bohen(3)(5)

Former Executive Vice President and

Chief Operating Officer,

The Rockefeller University

G. Steven Farris(1)

President, Chief Executive Officer and

Chief Operating 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,

WolfCreek Broadcasting, Inc.

Patricia Albjerg Graham(4)

Charles Warren Research Professor

of the History of American Education,

Harvard University

John A. Kocur(1)(3)

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;

Sole Member, Shaker Mountain Energy Associates, LLC

Raymond Plank(1)

Chairman of the Board, Apache Corporation

Jay A. Precourt(4)

Chairman of the Board, Hermes Consolidated, Inc.

Officers

Raymond Plank

Chairman of the Board

G. Steven Farris

President, Chief Executive Officer and

Chief Operating Officer

Michael S. Bahorich

Executive Vice President — Exploration and Production Technology

John A. Crum

Executive Vice President and Managing Director,

Apache North Sea Ltd.

Rodney J. Eichler

Executive Vice President and General Manager,

Apache Egypt Companies

Roger B. Plank

Executive Vice President and Chief Financial Officer

Floyd R. Price

Executive Vice President — Eurasia, Latin America

and New Ventures

Jon A. Jeppesen

Senior Vice President

P. Anthony Lannie

Senior Vice President and General Counsel

Jeffrey M. Bender

Vice President — Human Resources

Michael J. Benson

Vice President — Security

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

Janice K. Hartrick

Vice President and Associate General Counsel

Anthony R. Lentini, Jr.

Vice President — Public and International Affairs

Janine J. McArdle

Vice President — Oil and Gas Marketing

Thomas L. Mitchell

Vice President and Controller

W. Kregg Olson

Vice President — Corporate Reservoir Engineering

Jon W. Sauer

Vice President — Tax

Cheri L. Peper

Corporate Secretary


(1)	Executive Committee

(2)	Audit Committee

(3)	Management Development and Compensation Committee

(4)	Corporate Governance and Nominating Committee

(5)	Stock Option Plan Committee

Shareholder Information

Stock Data


					Dividends
	Price Range*				per Share*

	High		Low		Declared		Paid

2005
First Quarter	$	65.90	$	47.45	$	.08	$	.08
Second Quarter		67.99		51.52		.08		.08
Third Quarter		78.60		64.85		.10		.08
Fourth Quarter		75.95		59.36		.10		.10
2004
First Quarter	$	43.49	$	36.79	$	.06	$	.06
Second Quarter		45.99		38.53		.06		.06
Third Quarter		51.00		42.45		.08		.06
Fourth Quarter		55.16		47.77		.08		.08

The Company has paid cash dividends on its common stock for 41 consecutive years through December 31, 2005. 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, 2005, the Company’s shares of common stock outstanding were held by approximately 7,500 shareholders of record and 219,000 beneficial owners. Also listed on the New York Stock Exchange are:


	o	Apache Finance Canada’s 7.75% notes, due 2029 (symbol APA 29)

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 website: http://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 4, 2006, at 10 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: http://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: http://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) 296-6107.

Web site: http://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 February 5, 2004 (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, 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	—	Form of Certificate for Registrant’s Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 001-4300).
	4	.4	—	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	.5	—	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).
	10	.1	—	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).


Exhibit
No.				Description

	10	.2	—	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	.3	—	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	.4	—	Form of Five-Year Credit Agreement, dated May 28, 2004, 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 Barclays Bank PLC and UBS Loan Finance LLC. as Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).
	10	.5	—	Form of First Amendment to Combined Credit Agreements, dated May 28, 2004, among Registrant, Apache Energy Limited, Apache Canada Ltd., the Lenders named therein, JP Morgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, and Citibank, N.A., as Global Documentation Agent (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).
	10	.6	—	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	.7	—	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	.8	—	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	.9	—	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).


Exhibit
No.				Description

	10	.10	—	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	.11	—	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	.12	—	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	.13	—	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	.14	—	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	.15	—	Apache Corporation 401(k) Savings Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 001-4300).
	†10	.16	—	Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 001-4300).
	*†10	.17	—	Amendment to Apache Corporation 401(k) Savings Plan, dated December 16, 2005.
	†10	.18	—	Apache Corporation Money Purchase Retirement Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No.001-4300).
	†10	.19	—	Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 001-4300).
	†10	.20	—	Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
	†10	.21	—	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant’s Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000).
	†10	.22	—	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 001-4300).


Exhibit
No.				Description

	†10	.23	—	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004 (incorporated by reference to Exhibit 10.24 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	†10	.24	—	Apache Corporation 1990 Stock Incentive Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
	†10	.25	—	Apache Corporation 1995 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.26	—	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	.27	—	Apache Corporation 1996 Performance Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
	†10	.28	—	Apache Corporation 1998 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.29	—	Apache Corporation 2000 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.30	—	Apache Corporation 2003 Stock Appreciation Rights Plan, dated and effective May 1, 2003 (incorporated by reference to Exhibit 10.31 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	†10	.31	—	Apache Corporation 2005 Stock Option Plan, dated February 3, 2005 (incorporated by reference to Appendix B to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
	†10	.32	—	Apache Corporation 2005 Share Appreciation Plan, dated February 3, 2005 (incorporated by reference to Appendix C to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
	†10	.33	—	1990 Employee Stock Option Plan of The Phoenix Resource Companies, Inc., as amended through September 29, 1995, effective April 9, 1990 (incorporated by reference to Exhibit 10.33 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.34	—	Apache Corporation Income Continuance Plan, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.30 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, SEC File No. 001-4300).
	†10	.35	—	Apache Corporation Deferred Delivery Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	*†10	.36	—	Apache Corporation Executive Restricted Stock Plan, as amended and restated December 14, 2005, effective January 1, 2005.
	†10	.37	—	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).


Exhibit
No.				Description

	†10	.38	—	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.8 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
	†10	.39	—	Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 5, 2004 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
	†10	.40	—	Amended and Restated Employment Agreement, dated December 5, 1990, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.41	—	First Amendment, dated April 4, 1996, to Restated Employment Agreement between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
	†10	.42	—	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	.43	—	Employment Agreement, dated June 6, 1988, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1989, SEC File No. 001-4300).
	†10	.44	—	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	.45	—	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	.46	—	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 Chief Executive Officer
	*31	.2	—	Certification of Chief Financial Officer
	*32	.1	—	Certification of Chief Executive Officer and Chief 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.