UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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:

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]

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

      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.

      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:

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:

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.

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.

      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.

      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:

      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.

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

      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.

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

PART II

      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.

      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.

      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.

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

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:

      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.

      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.

Canada

Egypt

Australia

North Sea

      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

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

      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.

      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.

      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.

      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.

      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:

      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.

      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.

      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 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.

      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.

      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.