10-K 1 h33750e10vk.htm APACHE CORPORATION - DECEMBER 31, 2005 e10vk
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
     
(Mark One)
   
[X]
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005,
OR
 
[ ]
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the Transition Period from           to
Commission File Number 1-4300
Apache Corporation
A Delaware Corporation                             IRS Employer No. 41-0747868
One Post Oak Central
2000 Post Oak Boulevard, Suite 100
Houston, Texas 77056-4400
Telephone Number (713) 296-6000
Securities Registered Pursuant to Section 12(b) of the Act:
     
    Name of Each Exchange
Title of Each Class   On Which Registered
     
Common Stock, $0.625 par value   New York Stock Exchange
Chicago Stock Exchange
NASDAQ National Market
Preferred Stock Purchase Rights   New York Stock Exchange
Chicago Stock Exchange
Apache Finance Canada Corporation
7.75% Notes Due 2029
Irrevocably and Unconditionally
Guaranteed by Apache Corporation
  New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $0.625 par value
      Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.    Yes [X]    No [ ]
      Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes [ ]    No [X]
      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes [X]    No [ ]
      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    [ ]
      Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [X]         Accelerated filer [ ]         Non-accelerated filer [ ]
      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes [ ]    No [X]
         
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2005
  $ 21,243,517,363  
Number of shares of registrant’s common stock outstanding as of February 28, 2006
    330,307,585  
DOCUMENTS INCORPORATED BY REFERENCE:
      Portions of registrant’s proxy statement relating to registrant’s 2006 annual meeting of stockholders have been incorporated by reference into Part III hereof.
 
 


 

TABLE OF CONTENTS
DESCRIPTION
                 
Item       Page
         
 PART I
 
 1.    BUSINESS     1  
 1A.    RISK FACTORS     13  
 1B.    UNRESOLVED STAFF COMMENTS     17  
 2.    PROPERTIES     1  
 3.    LEGAL PROCEEDINGS     17  
 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS     17  
 PART II
 
 5.    MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS     18  
 6.    SELECTED FINANCIAL DATA     19  
 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS     19  
 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK     48  
 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     51  
 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE     51  
 9A.    CONTROLS AND PROCEDURES     51  
 9B.    OTHER INFORMATION     51  
 PART III
 
 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT     51  
 11.    EXECUTIVE COMPENSATION     52  
 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT     52  
 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS     52  
 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES     52  
 PART IV
 
 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K     53  
 Amendment to 401(k) Savings Plan
 Executive Restricted Stock Plan
 Computation of Ratios of Earnings to Fixed Charges
 Subsidiaries of Registrant
 Consent of Ernst & Young LLP
 Consent of Ryder Scott Company L.P.
 Certification of Chief Executive Officer
 Certification of Chief Financial Officer
 Certification of CEO & CFO
      All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Oil is quantified in terms of barrels (bbls); thousands of barrels (Mbbls) and millions of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural gas liquids are compared with natural gas in terms of million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Daily oil and gas production is expressed in terms of barrels of oil per day (b/d) and thousands or millions of cubic feet of gas per day (Mcf/d and MMcf/d, respectively) or millions of British thermal units per day (MMBtu/d). Gas sales volumes may be expressed in terms of one million British thermal units (MMBtu), which is approximately equal to one Mcf. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.


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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

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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.

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Also, on January 17, 2006, the Company announced an agreement with Pioneer Natural Resources (Pioneer). Please refer to the following Subsequent Acquisitions and Divestiture section. We continually look for properties which we believe will add value and earn adequate rates of return and will take advantage of those opportunities as they arise.
Operating Highlights
      We currently have interests in seven countries: the United States, Canada, Egypt, Australia, the United Kingdom, China, and Argentina. Our reportable segments are the United States, Canada, Egypt, Australia, the North Sea, and Other International. In the U.S., our exploration and production activities are divided into two regions: Gulf Coast and Central. At the end of 2005, approximately 69 percent of our estimated proved reserves were located in North America. Also, our North American regions contributed approximately 57 percent of our worldwide 2005 production.
      The following table sets out a brief comparative summary of certain key 2005 data for each area. More detailed information regarding oil, natural gas and natural gas liquids (NGLs) production and the average sales price received in each geographic area for 2005, 2004, and 2003 is available later in this section under “Production, Pricing and Lease Operating Cost Data”. Also, further discussion and analysis of this data is available in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. For information concerning the revenues, expenses, operating income (loss) and total assets attributable to each of our reportable segments, see Note 14, Supplemental Oil and Gas Disclosures (Unaudited), and Note 13, Business Segment Information of Item 15 in this Form 10-K. For information regarding Oil and Gas Capital Expenditures for each of the last three years, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity” in this Form 10-K.
                                                           
                12/31/05   Percentage       2005
        Percentage   2005   Estimated   of Total   2005   Gross New
    2005   of Total   Production   Proved   Estimated   Gross New   Productive
    Production   2005   Revenue   Reserves   Proved   Wells   Wells
    (In MMboe)   Production   (In millions)   (In MMboe)   Reserves   Drilled   Drilled
                             
Region/Country:
                                                       
 
Gulf Coast
    39.9       14.1 %   $ 1,812       387.0       18.3 %     114       88  
Central
    23.4       24.0 %     1,012       502.2       23.7 %     364       352  
                                           
 
Total U.S. 
    63.3       38.1 %     2,824       889.2       42.0 %     478       440  
                                           
Canada
    31.7       19.1 %     1,451       564.6       26.7 %     1,674       1,551  
                                           
 
Total North America
    95.0       57.2 %     4,275       1,453.8       68.7 %     2,152       1,991  
                                           
Egypt
    30.2       18.2 %     1,358       271.0       12.8 %     121       104  
Australia
    13.1       7.9 %     401       188.8       8.9 %     36       16  
North Sea
    24.0       14.5 %     1,275       196.5       9.3 %     23       15  
China
    3.0       1.8 %     131       5.0       .2 %     16       15  
Argentina
    .6       .4 %     17       2.1       .1 %     35       31  
                                           
 
Total International
    70.9       42.8 %     3,182       663.4       31.3 %     231       181  
                                           
 
Total
    165.9       100.0 %   $ 7,457       2,117.2       100.0 %     2,383       2,172  
                                           
      The following discussions include references to our plans for 2006. These only represent initial estimates and could vary significantly from actual results. In recent years, there have been large differences between our capital expenditure forecasts and our actual activity. During the year, we routinely adjust our level of spending based on success and changing industry conditions.

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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.

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      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.

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      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

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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.

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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).

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      The following table shows the results of the oil and gas wells drilled and tested for each of the last three fiscal years:
                                                                           
    Net Exploratory   Net Development   Total Net Wells
             
    Productive   Dry   Total   Productive   Dry   Total   Productive   Dry   Total
                                     
2005
                                                                       
 
United States
    5       3.1       8.1       248.8       24.1       272.9       253.8       27.2       281.0  
Canada
    273.4       107.6       381.0       1,057.0             1,057.0       1,330.4       107.6       1,438.0  
Egypt
    17.8       6.9       24.7       79.4       7.1       86.5       97.2       14.0       111.2  
Australia
    .7       6.8       7.5       11.8       4.8       16.6       12.5       11.6       24.1  
North Sea
          7.8       7.8       12.6       1.9       14.5       12.6       9.7       22.3  
China
                      3.7       .2       3.9       3.7       .2       3.9  
Argentina
    6.3       3.0       9.3       15.6       1.0       16.6       21.9       4.0       25.9  
                                                       
 
Total
    303.2       135.2       438.4       1,428.9       39.1       1,468.0       1,732.1       174.3       1,906.4  
                                                       
 
2004
                                                                       
 
United States
    3.3       3.5       6.8       202.8       24.2       227.0       206.1       27.7       233.8  
Canada
    6.7       9.3       16.0       1,102.3       84.2       1,186.5       1,109.0       93.5       1,202.5  
Egypt
    9.5       6.5       16.0       91.5       4.5       96.0       101.0       11.0       112.0  
Australia
    4.0       7.5       11.5       3.4       1.2       4.6       7.4       8.7       16.1  
North Sea
          1.0       1.0       11.7       3.9       15.6       11.7       4.9       16.6  
China
                      3.7       .3       4.0       3.7       .3       4.0  
Argentina
                      1.2             1.2       1.2             1.2  
                                                       
 
Total
    23.5       27.8       51.3       1,416.6       118.3       1,534.9       1,440.1       146.1       1,586.2  
                                                       
 
2003
                                                                       
 
United States
    2.2             2.2       133.6       18.3       151.9       135.8       18.3       154.1  
Canada
    57.3       25.3       82.6       742.8       34.8       777.6       800.1       60.1       860.2  
Egypt
    15.5       5.2       20.7       76.2       6.0       82.2       91.7       11.2       102.9  
Australia
    8.4       10.8       19.2       2.3             2.3       10.7       10.8       21.5  
North Sea
                                                     
China
                      6.1             6.1       6.1             6.1  
Other International
          .6       .6       .3             .3       .3       .6       .9  
                                                       
 
Total
    83.4       41.9       125.3       961.3       59.1       1,020.4       1,044.7       101.0       1,145.7  
                                                       

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Productive Oil and Gas Wells
      The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2005, is set forth below:
                                                   
    Gas   Oil   Total
             
    Gross   Net   Gross   Net   Gross   Net
                         
Gulf Coast
    906       684       719       515       1,625       1,199  
Central
    2,734       1,378       5,106       3,009       7,840       4,387  
Canada
    7,241       6,291       2,413       961       9,654       7,252  
Egypt
    30       29       343       325       373       354  
Australia
    8       5       40       22       48       27  
North Sea
                62       60       62       60  
China
                24       6       24       6  
Argentina
    20       7       68       44       88       51  
                                     
 
Total
    10,939       8,394       8,775       4,942       19,714       13,336  
                                     

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Production, Pricing and Lease Operating Cost Data
      The following table describes, for each of the last three fiscal years, oil, NGLs and gas production, average lease operating costs (including severance and other taxes) and average sales prices for each of the countries where we have operations.
                                                           
    Production   Average   Average Sales Price
        Lease    
    Oil   NGLs   Gas   Operating   Oil   NGLs   Gas
Year Ended December 31,   (Mbbls)   (Mbbls)   (MMcf)   Cost per Boe   (Per bbl)   (Per bbl)   (Per Mcf)
                             
2005
                                                       
United States
    24,188       2,757       218,081     $ 9.11     $ 47.97     $ 32.44     $ 7.22  
Canada
    8,212       816       135,750       7.54       53.05       31.07       7.29  
Egypt
    20,126             60,484       3.85       53.69             4.59  
Australia
    5,613             45,003       7.17       57.61             1.72  
North Sea
    23,903             842       17.94       53.00             9.17  
China
    2,968                   3.79       44.24              
Argentina
    424             1,137       6.54       37.54             1.14  
                                           
 
Total
    85,434       3,573       461,297     $ 8.87     $ 51.66     $ 32.13     $ 6.35  
                                           
2004
                                                       
United States
    24,841       3,026       236,663     $ 6.53     $ 38.75     $ 26.66     $ 5.45  
Canada
    9,262       947       119,669       6.49       38.57       24.44       5.30  
Egypt
    19,099             50,412       3.37       37.35             4.35  
Australia
    9,214             43,227       7.11       41.96             1.65  
North Sea
    19,338             684       4.22       24.22             5.53  
China
    2,775                   3.89       32.88              
Argentina
    207             1,394       6.46       32.89             .65  
                                           
 
Total
    84,736       3,973       452,049     $ 5.73     $ 35.24     $ 26.13     $ 4.91  
                                           
2003
                                                       
United States
    25,332       2,766       242,782     $ 5.14     $ 27.48     $ 21.70     $ 5.22  
Canada
    9,205       571       116,263       5.41       29.06       19.25       4.69  
Egypt
    17,356             41,447       3.40       27.64             4.18  
Australia
    11,165             40,537       4.05       29.87             1.44  
North Sea
    10,680             626       11.94       25.40             2.77  
China
    1,019                   5.18       26.33              
Argentina
    211             2,607       5.76       29.23             .47  
                                           
 
Total
    74,968       3,337       444,262     $ 5.27     $ 27.76     $ 21.28     $ 4.61  
                                           
Gross and Net Undeveloped and Developed Acreage
      The following table sets out our gross and net acreage position in each country where we have operations.
                                   
    Undeveloped Acreage   Developed Acreage
         
    Gross   Net   Gross   Net
    Acres   Acres   Acres   Acres
                 
United States
    1,551,097       950,008       2,953,641       1,756,869  
Canada
    4,107,595       2,913,825       2,885,456       2,116,981  
Egypt
    8,727,094       5,974,883       1,941,454       1,565,154  
North Sea
    653,785       486,368       29,924       29,068  
Australia
    10,376,130       6,115,900       527,450       307,290  
China
    840       206       5,911       1,448  
Argentina
                445,782       304,801  
                         
 
Total Company
    25,416,541       16,441,190       8,789,618       6,081,611  
                         

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      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.

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Offices
      Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2005, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; Beijing, China; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2013. For information regarding the Company’s obligations under its office leases, see the information appearing in the table in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity, Contractual Obligations” and Note 10, Commitments and Contingencies, “Other Commitments and Contingencies, Contractual Obligations” of Item 15 in this Form 10-K.
Title to Interests
      As is customary in our industry, a preliminary review of title records is made at the time we acquire properties, which may include opinions or reports of appropriate professionals or counsel. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions which do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, and other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.
ITEM 1A.  RISK FACTORS
      Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future.
Our Profitability is Highly Dependent on the Prices of Crude Oil, Natural Gas and Natural Gas Liquids, Which Have Historically Been Very Volatile
      Our estimated proved reserves, revenues, profitability, operating cash flows and future rate of growth are highly dependent on the prices of crude oil, natural gas and NGLs, which are affected by numerous factors beyond our control. Historically, these prices have been very volatile. A significant downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow, and could result in a reduction in the carrying value of our oil and gas properties and the amounts of our estimated proved oil and gas reserves.
Our Commodity Hedging May Prevent Us From Benefiting Fully From Price Increases and May Expose Us to Other Risks
      To the extent that we engage in hedging activities to protect ourselves from commodity price volatility, we may be prevented from realizing the benefits of price increases above the levels of the hedges.
Acquisitions or Discoveries of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production
      The rate of production from oil and gas properties generally declines as reserves are depleted. Except to the extent that we acquire additional properties containing estimated proved reserves, conduct successful

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exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.
Our Drilling Activities May Not Be Productive
      Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
  •  unexpected drilling conditions;
 
  •  pressure or irregularities in formations;
 
  •  equipment failures or accidents;
 
  •  fires, explosions, blowouts and surface cratering;
 
  •  marine risks such as capsizing, collisions and hurricanes;
 
  •  other adverse weather conditions; and
 
  •  shortages or delays in the delivery of equipment.
      Certain future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
Risks Arising From the Failure to Fully Identify Potential Problems Related to Acquired Reserves or to Properly Estimate Those Reserves
      One of our primary growth strategies is the acquisition of oil and gas properties. Although we perform a review of the acquired properties that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.
We Are Subject to Domestic Governmental Risks That May Impact Our Operations
      Our domestic operations have been, and at times in the future may be, affected by political developments and by federal, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price controls and environmental protection laws and regulations.

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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

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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

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insurance against certain losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance is not available to us against all operational risks.
      In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage and substantially increased premium rates. As a result, there is no assurance that Apache will be able to arrange insurance to cover fully its Gulf of Mexico exposures at a reasonable cost when the current policies expire.
Investors In Our Securities May Encounter Difficulties in Obtaining, Or May Be Unable To Obtain, Recoveries From Arthur Andersen With Respect To Its Audits Of Our Financial Statements
      On March 14, 2002, our previous independent public accountant, Arthur Andersen LLP (Arthur Andersen), was indicted on federal obstruction of justice charges arising from the federal government’s investigation of Enron Corp. On June 15, 2002, a jury returned with a guilty verdict against Arthur Andersen following a trial, though the conviction was later overturned by the United States Supreme Court. As a public company, we are required to file with the SEC periodic financial statements audited or reviewed by an independent public accountant. On March 29, 2002, we decided not to engage Arthur Andersen as our independent auditors, and engaged Ernst & Young LLP (Ernst & Young) to serve as our new independent auditors for 2002. Ernst & Young have served as our independent public accountants since that time. However, included in this annual report on Form 10-K are financial data and other information for 2001 that were audited by Arthur Andersen. Investors in our securities may encounter difficulties in obtaining, or be unable to obtain, from Arthur Andersen with respect to its audits of our financial statements, relief that may be available to investors under the federal securities laws against auditing firms.
ITEM 1B.  UNRESOLVED STAFF COMMENTS
      We had no comments from the staff of the SEC that were unresolved as of the date of filing of this report.
ITEM 3.  LEGAL PROCEEDINGS
      See the information set forth in Note 10, Commitments and Contingencies of Item 15 and Item 1A, Risk Factors, “Costs Incurred Related to Environmental Matters” in this Form 10-K.
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
      No matters were submitted to a vote of our security holders during the most recently ended fiscal quarter.

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PART II
ITEM 5.  MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
      During 2005, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock exchanges, and the NASDAQ National Market under the symbol APA. The table below provides certain information regarding our common stock for 2005 and 2004. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per share prices and quarterly dividends shown below have been rounded to the indicated decimal place.
                                                                 
    2005   2004
         
        Dividends Per       Dividends Per
    Price Range   Share   Price Range   Share
                 
    High   Low   Declared   Paid   High   Low   Declared   Paid
                                 
First Quarter
  $ 65.90     $ 47.45     $ .08     $ .08     $ 43.49     $ 36.79     $ .06     $ .06  
Second Quarter
    67.99       51.52       .08       .08       45.99       38.53       .06       .06  
Third Quarter
    78.60       64.85       .10       .08       51.00       42.45       .08       .06  
Fourth Quarter
    75.95       59.36       .10       .10       55.16       47.77       .08       .08  
      The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for February 28, 2006 , was $66.92. On February 28, 2006, there were 330,307,585 shares of our common stock outstanding held by approximately 7,500 shareholders of record and approximately 219,000 beneficial owners.
      We have paid cash dividends on our common stock for 41 consecutive years through December 31, 2005. When, and if, declared by our board of directors, future dividend payments will depend upon our level of earnings, financial requirements and other relevant factors.
      In 1995, under our stockholder rights plan, each of our common stockholders received a dividend of one “preferred stock purchase right (a “right”)” for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and a two-for-one stock split) that the stockholder owned. These rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the rights were reset to one right per share of common stock and the expiration was extended to January 31, 2016. Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights and, the rights trade automatically with our shares of common stock. For a description of the rights, please refer to Note 8, Capital Stock of Item 15 in this Form 10-K.
      In 2002, our board of directors declared a five percent dividend on our shares of common stock payable in common stock on April 2, 2003 to shareholders of record on March 12, 2003. Pursuant to the terms of the declared five percent stock dividend, we issued 15,736,496 shares (adjusted for the 2003 stock split) of our common stock on April 2, 2003 to the holders of the 307,819,628 shares of common stock outstanding on March 12, 2003. No fractional shares were issued in connection with the stock dividend and we made cash payments totaling approximately $1,437,000 in lieu of fractional shares.
      In 2003, in conjunction with the acquisition from BP, the Company completed the public offering of 19.8 million shares (adjusted for the stock split) of Apache common stock, including 2.6 million shares (adjusted for the stock split) for the underwriters’ over-allotment option, at $29.05 per share. Net proceeds after placement fees totaled approximately $554 million. The proceeds were used to repay indebtedness under our commercial paper program and money market lines of credit and to invest in short-term treasury-only money market funds and treasury notes to hold funds for the $1.3 billion acquisition from BP.
      In 2003, our board of directors declared a two-for-one common stock split which was distributed on January 14, 2004 to holders of record on December 31, 2003. In connection with the stock split, the Company issued 166,254,667 shares.

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      Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2006 annual meeting of stockholders, which is incorporated herein by reference.
ITEM 6.  SELECTED FINANCIAL DATA
      The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2005, which information has been derived from the Company’s audited financial statements. Our financial statements for the year 2001 were audited by Arthur Andersen. For a discussion of the risks relating to Arthur Andersen’s audit of our financial statements, please see discussion of issues related to Arthur Andersen in Item 1A, “Risk Factors” of this Form 10-K. This information should be read in connection with, and is qualified in its entirety by the more detailed information in the Company’s financial statements of Item 15 in this Form 10-K.
                                           
    As of or For the Year Ended December 31,
     
    2005   2004   2003   2002   2001
                     
    (In thousands, except per share amounts)
Income Statement Data
                                       
Total revenues
  $ 7,584,244     $ 5,332,577     $ 4,190,299     $ 2,559,873     $ 2,809,391  
Income (loss) attributable to common stock
    2,618,050       1,663,074       1,116,205       543,514       703,798  
Net income (loss) per common share:
                                       
 
Basic
    7.96       5.10       3.46       1.83       2.44  
 
Diluted
    7.84       5.03       3.43       1.80       2.37  
Cash dividends declared per common share
    .36       .28       .22       .19       .17  
Balance Sheet Data
                                       
Total assets
  $ 19,271,796     $ 15,502,480     $ 12,416,126     $ 9,459,851     $ 8,933,656  
Long-term debt
    2,191,954       2,588,390       2,326,966       2,158,815       2,244,357  
Preferred interests of subsidiaries
                      436,626       440,683  
Shareholders’ equity
    10,541,215       8,204,421       6,532,798       4,924,280       4,418,483  
Common shares outstanding
    330,121       327,458       324,497       302,506       287,917  
      For a discussion of significant acquisitions, see Note 2 of Item 15 in this Form 10-K.
ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
      Apache Corporation is an independent energy company whose principle business includes exploration, development and production of crude oil, natural gas and natural gas liquids. The Company operates in five core countries which, collectively, contained over 99 percent of the Company’s 2005 year-end estimated proved reserves and accounted for over 98 percent of the Company’s 2005 oil and gas production revenues. These principle operations are located in the United States, Canada, Egypt, Australia and offshore the United Kingdom in the North Sea. The Company’s smaller non-core operations in 2005 were conducted offshore China and in Argentina.
      Apache adheres to a portfolio approach to provide diversity in terms of hydrocarbon mix (crude oil and natural gas), reserve life, geologic risk and geographic location. Our growth strategy focuses on economic growth through drilling, acquisitions, or a combination of both, depending on, among other things, cost levels and availability of acquisition opportunities. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and liquidity needs. These obligations and needs are met with cash on hand, cash generated from our operations, unused committed borrowing capacity under our global credit facility, and the capital markets. The interest cost of debt and access to the equity markets are greatly influenced by the Company’s ability to maintain both a strong balance sheet and generate ongoing

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operating cash flow. For these reasons, we strive to maintain a manageable debt load that is properly balanced with equity and our single-A credit ratings. We are also cognizant of the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Consequently, we closely monitor trends in drilling costs by operating area and the price at which properties are available for purchase, so that we may adjust our budgets accordingly and allocate funds to projects based on potential rate of return. We review operating costs monthly by operating area, on both an absolute dollar and per unit of production basis. We then compare these results to our historical norms factoring in the impact of property acquisitions and changes in industry conditions in order to actively manage individual cost elements as appropriate. Given the inherent volatility and unpredictability of commodity prices and changing industry conditions, we frequently revise our forecasts and adjust our budgets accordingly.
      Throughout 2005, commodity prices were very strong as the precarious supply and demand balance for crude oil and natural gas was impacted by geopolitical factors and U.S. weather events. Apache’s 2005 consolidated average realized crude oil price of $51.66 was 47 percent higher than 2004, while the Company’s average realized natural gas price increased 29 percent to $6.35 per Mcf. Crude oil prices were up worldwide, while natural gas price gains were mainly concentrated in North America. The Company’s daily production averaged 454,495 barrels of oil equivalent (boe) per day, up one percent from 2004, as gains were limited by the impact of U.S. hurricanes (discussed below). These historically high commodity prices and solid production drove the Company’s attainment of several operational and financial milestones.
      2005 Financial and operating results include:
  •  Our 2005 oil and gas revenues totaled $7.5 billion compared to $5.3 billion in 2004, a 40 percent increase.
 
  •  We generated earnings of $2.6 billion, $955 million higher than in 2004. On a diluted share basis, earnings increased $2.81 to $7.84 per share.
 
  •  Net cash provided by operating activities increased $1.1 billion from 2004 to $4.3 billion.
 
  •  We increased production for the 26th time out of the last 27 years. Natural gas production averaged 1,264 MMcf/d compared to 1,235 MMcf/d in 2004. Crude oil production averaged 234,070 b/d versus 231,519 b/d in 2004.
 
  •  Daily equivalent production in the North Sea increased approximately 24 percent from 2004. The increase reflects the success of the Echo drilling program, which began in early 2004, but also includes Bravo well work and results from the Alpha and Delta drilling programs.
 
  •  Oil production in Australia decreased 9,795 b/d compared to 2004 on loss of East Spar liquids, where production ceased early in the year, and natural decline at Legendre.
 
  •  We continue to see higher industry-wide service costs, particularly in North America. The steady rise in commodity prices has driven up fuel, power and ad valorem costs, while other service costs are rising with greater demand resulting from increased activity.
 
  •  Canada’s daily gas production increased 14 percent from 2004 to 372 MMcf/d, driven by new wells drilled at Nevis, Zama and on the North Grant Lands. We also completed six of the 11 gas plants under construction during 2005.
 
  •  The Company’s Central region increased oil production 27 percent compared to 2004. The higher production was driven by the ExxonMobil acquisition completed in the third quarter of 2004 and active drilling and recompletion programs.
 
  •  Estimated proved reserves grew nine percent to 2.12 billion boe, marking 2005 as our 20th consecutive year of reserve growth.
 
  •  Exploration and development expenditures totaled $3.4 billion, $1.0 billion higher than in 2004.
 
  •  Apache ended 2005 with debt at 17 percent of total capitalization, down seven percent from year-end 2004.

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  •  On September 15, 2005, the Company’s Board of Directors voted to increase Apache’s quarterly cash dividend to 10 cents per share, effective with the November 2005 payment.
Impact of 2005 Hurricanes
      During the third quarter of 2005, four hurricanes struck the Gulf of Mexico that impacted the Company’s U.S. gulf coast operations, both onshore and offshore Louisiana and Texas. During each of these hurricanes, personnel were evacuated and production was shut-in. Two of these storms, Hurricanes Dennis and Emily, required only temporary curtailment of production and caused minor damage to the Company’s production platforms. The other two storms, Hurricanes Katrina and Rita, caused extensive damage to both onshore and offshore production and transportation facilities. In addition to Apache’s property damage, third-party pipelines, terminals and processing facilities, which the Company relies upon to transport and process the crude oil and natural gas it produces, were damaged. Restoration of full production is dependent on numerous factors, many of which are beyond the Company’s control. The impact on operations and results follows:
      Production — The hurricanes reduced Apache’s 2005 average annual daily production of natural gas by 59 MMcf/d and of crude oil by 10,813 b/d. The bulk of the shut-in production was associated with Hurricanes Katrina and Rita, which struck in late August and late September 2005, respectively. As of December 31, 2005, approximately 59 MMcf/d of net natural gas production and 20 Mbbls/d of net crude oil production per day remained shut-in. While we have seen tremendous progress in restoring production, a portion of the production may remain shut-in for up to a year.
      Financial Results — The impact on the Company’s 2005 financial results included a $397 million reduction of crude oil and natural gas revenues, approximately $30 million of additional lease operating expenses (LOE) and $30 million of additional capitalized costs. The additional LOE and capitalized costs include insurance deductibles, additional premiums assessed by Oil Insurance Limited (OIL) and an accrual for an insurance contingency assessed by OIL should Apache elect to withdraw from the insurance pool. The shut-in production also resulted in $57 million less depletion expense. As indicated below, the Company accrued approximately $79 million of business interruption insurance claims during the fourth quarter of 2005 in “Other” under “Revenues and Other” of the Statement of Consolidated Operations.
      Assessment of Damage — Nine operated production platforms were lost and two were severely damaged during the storms. Production platforms lost or severely damaged during Hurricane Katrina were: Main Pass 312-JA; South Timbalier 161-A; 161-B; 161-D; South Pass (SP) 62-A; SP 62-B; West Delta (WD) 103-A; WD 103-B; WD104-C; and WD133-B. The production platform lost during Hurricane Rita was Ship Shoal 193-B. Additionally, 12 non-operated structures were destroyed or severely damaged: 10 Grand Isle 43 platforms; one South Marsh Island 108 platform; and one Eugene Island 330 platform. Prior to the hurricanes, aggregate production from the lost and damaged platforms was approximately 10 Mbbls of oil per day and 21 MMcf of gas per day. All of these platforms are expected to be abandoned over the next three years and the Company has recorded a present value obligation of approximately $492 million to reflect the estimated abandonment costs to be incurred (See Note 4, Asset Retirement Obligation of Item 15 in this Form 10-K). The adjustment for abandonment obligations is recorded in our property balance and will be reflected in income as additional depletion expense over time. The impact on fourth quarter 2005 depletion expense was approximately $7 million. A portion of the obligation will be recovered through insurance proceeds.
      Numerous other operated offshore production platforms and onshore facilities sustained damage as a result of the storms. While not as severe as the above mentioned platforms, much of the repairs require replacing grating, handrails, and lost equipment. In addition, minor structural repairs will also be required. The Company estimates that approximately $230 million will be incurred to repair these platforms and facilities and expects nearly all of these repairs to be completed during 2006. Although the $230 million estimate may change, the Company expects to recover the majority of these costs through insurance proceeds.
      Insurance Coverage — The Company carries property damage insurance of $250 million per event subject to a $7.5 million deductible per event, and another $100 million in aggregate for the policy year. The $250 million per event in coverage is provided through OIL, while the $100 million is provided under a separate commercial policy. The OIL policy is prorated down if total claims received by the insurer for a single

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event exceed $1 billion. As of December 31, 2005, the Company was advised by OIL that total claims for Hurricane Katrina would exceed the $1 billion limit, reducing the Company’s ultimate recoveries by approximately 50 percent, or $125 million. The Company was also advised that as of December 31, 2005, total estimated claims for Hurricane Rita would exceed the $1 billion limit, reducing the Company’s claims for Rita by approximately 20 percent. Based on current assessments by OIL, the Company expects to recover from OIL between $225 million and $250 million for both storms combined. The Company further expects to recover the full $100 million on the commercial policy.
      The Company also carries business interruption insurance coverage through its commercial policy to cover deferred and lost oil and natural gas production revenues. The business interruption insurance began 60 days after occurrence of each event subject to a daily limit of $750,000 per event and an aggregate limit of $150 million. Coverage is based on current market prices and began October 28, 2005 for shut-in production caused by Hurricane Katrina and November 22, 2005 for Hurricane Rita. The Company accrued claims in 2005 totaling $79 million, with the remainder of the aggregate $150 million limit available for 2006. Proceeds received from the Business Interruption Insurance are reflected in “Other” under “Revenues and Other” on the Statement of Consolidated Operations and are included in cash flows from operating activities.
      In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage in the Gulf of Mexico and substantially increased premium rates. As a result, there is no assurance that Apache will be able to arrange adequate insurance to cover its Gulf of Mexico exposures at a reasonable cost when the current policies expire.
Exploration and Development Activity
      The Company spent $3.8 billion on capital expenditures in 2005, 52 percent, or $1.3 billion more than in 2004. Expenditures for 2005 exploration and production activity accounted for 90 percent, or $3.4 billion, of capital spending, a $1.0 billion increase over 2004. The balance of 2005 capital spending, which totaled $393 million, up $254 million, was for oil and gas processing facilities and pipelines in Canada, Egypt and Australia. The Company spent $39 million on acquisitions in 2005 compared to $1.1 billion in 2004, as 2005 market conditions provided a limited number of attractive acquisition opportunities. However, in early 2006, we closed an acquisition announced in late 2005. Also, on January 17, 2006, the Company announced an agreement to purchase the Argentine operations of Pioneer Natural Resources (Pioneer) for $675 million. Please refer to the Subsequent Acquisitions and Divestiture section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. Acquisition expenditures typically vary year to year based on the availability of opportunities that fit Apache’s overall strategy. Significant highlights in each of our core areas follow:
U.S.
  •  The Company spent $1.1 billion to drill 478 wells, adding 91.9 MMBoe of reserves through extension and development activity. The Company had one of the five most active drilling programs in the Gulf of Mexico and Western Oklahoma, and one of the top 10 drilling programs in West Texas. In the Gulf Coast region, we drilled 66 Gulf of Mexico wells and 48 onshore wells with a 77 percent success rate. In the Central region, we drilled 364 wells with a 97 percent success rate. The U.S. accounted for 38 percent of our 2005 equivalent production and 42 percent of the Company’s estimated proved reserves at year-end 2005, down from 41 percent and 44 percent in 2004, respectively.
 
  •  On January 5, 2006, the Company completed its purchase of Amerada Hess’s interest in eight fields located in the Permian Basin of West Texas and New Mexico for $269 million. Apache estimates that these fields had proved reserves of 27 million barrels of liquid hydrocarbons and 27 billion cubic feet of natural gas at year-end 2005. For additional details regarding this transaction refer to the Subsequent Acquisitions and Divestiture section of this Item 7.

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Canada
  •  The Company spent $1.2 billion on exploration and development in Canada, drilling 1,551 successful wells out of a total 1,674 wells, adding 104.3 MMBoe of reserves. Approximately one-fourth of the wells will be brought on production during the first half of 2006 upon completion of facilities. Canada accounted for 19 percent of our 2005 equivalent production and 27 percent of the Company’s estimated proved reserves at year-end 2005, up from 18 percent and 25 percent in 2004, respectively.
 
  •  We also spent $180 million during 2005 constructing 11 new gas processing plants. Six of these plants were completed during 2005 with the remainder expected to be completed throughout 2006.
 
  •  We are currently only producing about 19 million gross cubic feet of natural gas per day (13 MMcf/d net) from the North Grant Lands area, which represents approximately 30 percent of our production capacity. Production is restricted because of limited processing infrastructure, including pipelines, compressors and gas plants, and regulations restricting commingling of coalbed methane zones and conventional zones. We are working with regulatory authorities and expect to resolve the commingling issue favorably during the first half of 2006. Construction of processing infrastructure is ongoing.
 
  •  On May 5, 2005, Apache signed a farm-in agreement with ExxonMobil covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in the 2004 farm-in agreement with ExxonMobil. The 2004 farm-in agreement covered approximately 380,000 acres and stipulated drilling at least 250 wells over a two-year period beginning in October of 2004. Through the end of 2005, Apache drilled 457 wells on the 2004 farm-in acreage, earning 207 additional acreage sections.
Egypt
  •  The Company spent $352 million on exploration and development in Egypt, adding 77.7 MMBoe of reserves. Egypt accounted for 18 percent of our 2005 equivalent production and 13 percent of the Company’s estimated proved reserves at year-end 2005, up from 17 percent and 12 percent in 2004, respectively.
 
  •  On April 5, 2005, we announced two discoveries in Egypt. The Syrah 1X wildcat, on the Company’s 100 percent-contractor-interest Khalda Concession, tested 46.5 MMcf/d of natural gas. The Tanzanite 1X, located onshore on Apache’s West Mediterranean Concession, tested 5,296 b/d and 7.4 MMcf/d.
 
  •  On July 5, 2005, the Company announced that the Tanzanite-2 well, on Egypt’s West Mediterranean Onshore Concession, tested 2,846 b/d and 640 thousand cubic feet per day (Mcf/d) of gas from the Cretaceous-age Alamein Dolomite formation in the Tanzanite Field.
 
  •  On July 5, 2005, Apache also announced a new field oil discovery, the El Diyur-2X, on the Apache-operated El Diyur Concession southwest of Egypt’s Western Desert. A test of the lower Bahariya formation flowed at a rate of 1,177 b/d.
 
  •  Apache spent $182 million during 2005 developing Qasr field facilities. Large scale gas production from the Qasr field was initiated during the third quarter of 2005. Gross natural gas production rates late in the fourth quarter of 2005 averaged 160 MMcf/d. Associated condensate production exceeded 8,000 b/d. Early in 2006, upon completion of the Tarek gas plant pipeline inter-connect, gross natural gas and condensate production exceeded 200 MMcf/d and 10,000 b/d, respectively. Additionally, the field is also producing over 9,000 barrels of oil per day from a shallower formation. Since all gas plants supplied by Qasr are running at full capacity, deliverability from Qasr will be restricted until additional capacity comes on line, currently anticipated in late 2007 or early in 2008.

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  •  On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. The gas sales agreement (the Memorandum of Understanding for which was previously announced on December 16, 2003) for the interests was assigned to Amerada Hess as a part of that sale. Apache first announced this transaction on October 13, 2005. For additional details regarding this transaction refer to the Subsequent Acquisitions and Divestiture section of this Item 7.
Australia
  •  The Company spent $218 million on exploration and development in Australia, adding 31.9 MMBoe of reserves. During 2005, we participated in drilling 36 wells; 26 exploration wells and 10 development wells. Australia accounted for 8 percent of our 2005 equivalent production and 9 percent of the Company’s estimated proved reserves at year-end 2005 compared to 10 percent and 9 percent in 2004, respectively.
 
  •  On June 15, 2005, Apache announced the development of its Rose gas/condensate field in Australia with the completion of the Rose 4 development well. The Rose 4 well, which is part of the Harriet Joint Venture, significantly enhances the joint venture’s gas deliverability. Production will be sold into 13 dedicated contracts.
 
  •  On July 18, 2005, Burrup Fertilisers claimed force majeure and defaulted its take-or-pay obligations on a 48.2 MMcf/d gas purchase contract, net to Apache. Settlement negotiations with Burrup Fertilisers are continuing and the plant is expected to be operational in the first half of 2006, at which time gas deliveries and payments are anticipated.
 
  •  On July 28, 2005, Apache announced that it initiated production from the Mohave-1H discovery in the Carnarvon Basin offshore Western Australia. The initial gross production rate was 10,690 b/d from the Flag Sandstone zone, a prolific but traditionally often smaller reservoir. Apache owns a 68.5 percent interest in the field.
 
  •  On August 24, 2005, the Company announced it signed a new 15-year term contract to supply gas to a major power station to be built in Kwinana, Western Australia. The terms call for delivery of approximately 215 billion cubic feet (bcf) gross (118 bcf net to Apache) at a daily gross rate of 39 MMcf. The Company expects to source the gas for the contract from its John Brookes field beginning in late 2008. The term can be extended an additional 10 years by mutual agreement.
North Sea
  •  The Company spent $489 million in the North Sea, including $198 million on facility upgrades to improve the operating efficiency of the platforms. We drilled 23 exploration and development wells during 2005 with a 65 percent success rate, adding 45.2 MMBoe of reserves. The North Sea accounted for 14 percent of our 2005 equivalent production and 9 percent of the Company’s estimated proved reserves at year-end 2005 compared to 12 percent and 9 percent in 2004, respectively.
 
  •  The Company acquired 22 North Sea blocks in the 2005 UK license bid round. Also, during 2005, Apache acquired interests in six additional North Sea blocks, one via a small acquisition and five earned through farm-ins on four prospects. We had oil discoveries in three of the four farm-in prospects. In 2004, Apache acquired 14 new blocks in the UK license bid round. At the end of 2005, Apache held interests in 45 North Sea blocks.
 
  •  During 2005, Apache shot three new 3D seismic surveys in the North Sea, and together with the purchase and reprocessing of various 3D data sets, currently have 3-D seismic coverage on 27 blocks of the total 45 Apache North Sea held blocks.

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Other
      Our year-end 2005 estimated reserves remained relatively balanced with a 46 percent oil and 54 percent natural gas mix. This compares to 48 percent oil and 52 percent natural gas at the end of 2004. Estimated proved undeveloped reserves represented 30.4 percent of total year-end 2005 estimated proved reserves compared to 32.7 percent at year-end 2004.
      Apache was challenged in 2005 by steadily increasing service costs resulting from increased demand with high commodity prices and the major Gulf of Mexico hurricanes. The increases were reflected in nearly all of our drilling and lease operating costs, including; rig rates, drill pipe costs, chemical costs and the costs of power and fuel. The Company reviews these costs for each core area on a routine basis and pursues alternatives in maintaining efficient levels of costs and expenses. While we are encouraged by the current financial outlook for 2006, we will continue to monitor costs, and depending on drilling costs relative to market prices, we may act to reduce our drilling expenditures as we did in 2001. This is particularly relevant in the U.S. where reserve targets generally continue to decrease in size. Acquisition costs also increased generally in 2005, and for that reason we were not very active during the year, completing $39 million of acquisitions. However, in early 2006, we closed an acquisition announced in late 2005. Also, on January 17, 2006, the Company announced an agreement with Pioneer Natural Resources (see Subsequent Acquisitions and Divestiture section in this Item 7). We believe we are well positioned to pursue future acquisitions should the appropriate opportunities arise. The Company also experienced unfavorable foreign exchange rate movements in Canada in 2005 which impacted our lease operating and drilling costs. We did see some favorable exchange rate movements in Australia and the U.K., although the favorable impact on our lease operating and drilling costs were much less than the unfavorable impact in Canada. Refer to the “Costs” section of this Item 7, Management Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of items impacting costs in 2005.
      In May 2005, the Company’s stockholders approved a new targeted stock plan that provides incentives for employees to double Apache’s share price to $108 by the end of 2008, with an interim goal of $81 to be achieved by the end of 2007. To achieve the trigger price, the Company’s stock price must close at or above the stated threshold for 10 days out of any 30 consecutive trading days by the end of the stated period. Under the plan, if the first threshold is achieved, approximately 1.3 million shares would be awarded for an intrinsic cost of $106 million. Achieving the second threshold would result in approximately 2.0 million shares awarded for an intrinsic cost of $213 million.
      In July 2004, the Company signed an amendment agreement with the EGPC which, among other things, extended the term of the Khalda, Khalda West and Salam development leases through 2024. These development leases would have expired in 2011, 2012 and 2010, respectively. Apache also received a five-year extension on the Khalda Offset exploration acreage with an option for an additional three-year extension. As part of this agreement and in conjunction with the Qasr 25-year Gas Sales Agreement signed in April 2004, we agreed to re-price natural gas volumes in excess of 100 MMcf/d produced from the Khalda Concession development leases and future Khalda Offset development leases. Under the new pricing formula, Apache receives a price indexed to crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu. Pricing for the first 100 MMcf/d remains subject to the original contract price (which is indexed to oil pricing, but without a minimum or maximum) until January 1, 2013, at which time all Khalda area gas will be priced under the new pricing formula. For 2005 and 2004, Apache’s prices, which were a blend of the old and new contracts, averaged $4.59 per Mcf and $4.35 per Mcf, respectively.
Results of Operations
      This section includes a discussion of our 2005 and 2004 results of operations and provides insight into unique events and circumstances for each of the Company’s six reportable segments. Apache’s geographic segments include the United States, Canada, Egypt, Australia, the North Sea and Other International. These segments are primarily in the business of crude oil and natural gas exploration and production. Please refer to Note 13, Business Segment Information of Item 15 in this Form 10-K for segment information.

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Acquisitions and Divestitures
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 did not have any oil and gas reserves recorded for these properties. Apache first announced this transaction on October 13, 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.
2005 Acquisitions
      During 2005, Apache completed acquisitions for $39 million, adding approximately 7.8 MMboe to the Company’s proved reserves.
      On May 5, 2005, Apache signed a farm-in agreement with Exxon Mobil Corporation (ExxonMobil) covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in the 2004 farm-in agreement with ExxonMobil.
2004 Acquisitions
ExxonMobil
      During the third quarter of 2004, Apache entered into separate arrangements with ExxonMobil that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and on the Gulf of Mexico-Outer Continental Shelf. Apache’s participation included cash payments of approximately $347 million, subject to normal post closing adjustments. The following summarizes these transactions:
      ExxonMobil — Western Canada  In August 2004, Apache signed a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta. Under the agreement, Apache has the right to earn acreage sections by drilling an initial well on each such section. By drilling at least 250 wells during the initial two-year earning period under the agreement, Apache will receive a one-year extension in which to earn additional sections. As to any sections earned by Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. Under certain circumstances, ExxonMobil has the right to convert its retained 35 percent working interest into a 12.5 percent overriding royalty. In addition, during the terms of this agreement, Apache is required to carry ExxonMobil’s retained working interest with respect to certain drilling, capping, completion, equipping and tie-in costs associated with wells drilled on leasehold acreage.

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      ExxonMobil — West Texas and New Mexico  In September 2004, Apache acquired interests from ExxonMobil in 23 mature producing oil and gas fields in West Texas and New Mexico for $318 million. Apache separately contributed approximately $29 million into a partnership to obtain additional interests in the properties. ExxonMobil will retain interests in the properties through the partnership, including the right to receive, on certain fields, 60 percent of the oil proceeds above $30 per barrel in 2004, $29 per barrel in 2005 and $28 per barrel during the period from 2006 thru 2009.
      ExxonMobil — Louisiana and Gulf of Mexico-Outer Continental Shelf  Also in September 2004, Apache and ExxonMobil entered into joint exploration agreements to explore Apache’s acreage in South Louisiana and the Gulf of Mexico-Outer Continental Shelf. The agreements provide for an initial term of five years, with the potential for an additional five years based on expenditures by ExxonMobil. Pursuant to the agreement covering South Louisiana, Apache leased 50 percent of its interests below certain producing or productive formations in the acreage to ExxonMobil, subject to retention of a 20 percent royalty interest. Pursuant to the agreement covering the Gulf of Mexico-Outer Continental Shelf, no assignments will be made until a prospect has been proposed and the initial well has been drilled. Apache will retain all rights in each prospect above certain producing or productive formations and further will retain a three percent overriding royalty interest in any property assigned to ExxonMobil. See Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K for a complete discussion of those transactions.
Anadarko
      On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko’s Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields comprising approximately 70 percent of the production.
      Prior to Apache’s purchase from Anadarko, Morgan Stanley paid Anadarko $646 million to acquire an overriding royalty interest in these properties. Anadarko’s sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP), the obligations of which Apache assumed along with its subsequent purchase. Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas production (20 MMboe) over four years beginning in October 2004. The VPP represents a non-operating interest in the properties that is free of all costs of operations and production. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP in any given month to satisfy these deliverables. However, Morgan Stanley has no right to look to other assets or production of Apache. The VPP is scheduled to terminate on August 31, 2008, but may be extended if all scheduled VPP volumes have not been delivered to Morgan Stanley and the properties are still producing. The VPP includes restrictions on the Company’s ability to sell the properties subject to the VPP or resign as operator of VPP properties it currently operates. Upon termination of the VPP, all rights, titles and interests revert back to Apache. Apache does not record the reserves and production volumes attributable to the VPP.
      The strategic rationale for Apache buying these assets burdened by a volumetric production payment is several fold. First, because Morgan Stanley gets their production first and Apache receives the remainder, Morgan Stanley is paying substantially more per boe, thereby significantly reducing Apache’s cost per unit. Second, although Morgan Stanley’s priority call on production leaves Apache with more risk, in exchange we retain all the upside associated with finding more reserves on the acquired properties than anticipated at the time of the acquisition. This is a risk/reward scenario with which we are comfortable and that plays to our long history of adding value to numerous acquired properties through proactive operations. Third, our experience is that invariably we earn higher rates of return from drilling and related activities than we do from acquisitions, yet acquisitions bring an inventory of drilling and exploitation opportunities. Because Morgan Stanley paid Anadarko more than Apache for proved reserves, a higher percentage of Apache’s investment will be concentrated in the higher risk, but generally higher reward, future drilling activity. As a final note, Morgan Stanley, while having less risk, is not risk free. In the event that the properties purchased by Apache are

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insufficient to deliver the volumes sold to Morgan Stanley, there is no recourse to any properties other than those acquired from Anadarko. See the Capital Resources and Liquidity section of this Item 7 for further discussion of VPPs.
      The $537 million purchase price agreed to in the definitive agreement was subsequently adjusted for the exercise of preferential rights by third parties and other normal post-closing adjustments. After adjusting for these items, Apache paid $532 million for the properties and recorded estimated proved reserves of 60 MMboe, of which 50 percent is natural gas. In addition, an $84 million liability for the future cost to produce and deliver the VPP volumes was recorded by the Company. This liability will be settled through a reduction of lease operating expense as the volumes are produced and delivered to Morgan Stanley. Apache also recorded abandonment obligations for the properties of approximately $134 million and other obligations assumed from Anadarko in the amount of $27 million. Apache allocated $122 million of the purchase price to unproved property. The purchase price was funded by borrowings under the Company’s commercial paper program.
      We routinely evaluate our property portfolio and divest those that are marginal or no longer fit into our strategic growth program. We divested $80 million, $4 million and $59 million of properties during 2005, 2004 and 2003, respectively.
Revenues
      Our revenues are sensitive to changes in prices received for our products. A substantial portion of our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.
Oil and Natural Gas Prices
      While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a world-wide market, whereas natural gas, which has a limited global transportation system, is subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction, while natural gas price movements generally follow local market conditions. However, throughout 2005, the price differentials related to crude oil qualities were volatile, and the prices we received for our North American sour crude oil compared to the NYMEX Domestic Sweet index widened beyond historical averages. This price differential was exacerbated by Hurricanes Katrina and Rita which caused extensive damage to the refining complex along the U.S. Gulf Coast. These quality differentials, which impacted approximately one-third of our U.S. production, occurred largely because OPEC produced more sour crude to satisfy rising world demand, while U.S. sour crude refining capacity was hindered by the damage caused by the hurricanes. This excess in sour crude supply over the refining capacity created competition among producers driving a deeper discount for sour crude. During the fourth quarter of 2005, the sweet to sour crude oil quality differential averaged $6.50 per barrel.
      Apache primarily sells its natural gas into three markets:
  1)  North America, which has a common market and where supply and demand are currently tightly balanced, creating a volatile pricing environment;
 
  2)  Australia, which has a local market with limited demand relative to available supply and long-term fixed price contracts; and
 
  3)  Egypt, which has a local market where the price received for our production is indexed to a weighted-average Dated-Brent crude oil price, a portion of which is subject to a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu.

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      The current outlook for 2006 indicates that the sour crude quality differentials, while narrowing somewhat, will remain above historical averages.
      For specific marketing arrangements by segment, please refer to Item 1 and 2. Business and Properties of this Form 10-K.
Revenues
      The table below presents oil and gas production revenues, production and average prices received from sales of natural gas, oil and natural gas liquids.
                             
    For the Year Ended December 31,
     
    2005   2004   2003
             
Revenues (in thousands):
                       
 
Oil
  $ 4,413,934     $ 2,986,208     $ 2,081,283  
 
Natural gas
    2,928,578       2,217,983       2,046,625  
 
Natural gas liquids
    114,779       103,826       71,012  
                   
   
Total
  $ 7,457,291     $ 5,308,017     $ 4,198,920  
                   
Oil Volume — Barrels per day:
                       
 
United States
    66,268       67,872       69,404  
 
Canada
    22,499       25,305       25,220  
 
Egypt
    55,141       52,183       47,551  
 
Australia
    15,379       25,174       30,589  
 
North Sea
    65,488       52,836       29,260  
 
China
    8,132       7,583       2,791  
 
Argentina
    1,163       566       579  
                   
   
Total
    234,070       231,519       205,394  
                   
Average Oil Price — Per barrel:
                       
 
United States
  $ 47.97     $ 38.75     $ 27.48  
 
Canada
    53.05       38.57       29.06  
 
Egypt
    53.69       37.35       27.64  
 
Australia
    57.61       41.96       29.87  
 
North Sea
    53.00       24.22       25.40  
 
China
    44.24       32.88       26.33  
 
Argentina
    37.54       32.89       29.23  
   
Total
    51.66       35.24       27.76  
Natural Gas Volume — Mcf per day:
                       
 
United States
    597,481       646,619       665,156  
 
Canada
    371,917       326,965       318,528  
 
Egypt
    165,710       137,737       113,554  
 
Australia
    123,295       118,108       111,061  
 
North Sea
    2,306       1,871       1,714  
 
Argentina
    3,114       3,808       7,144  
                   
   
Total
    1,263,823       1,235,108       1,217,157  
                   
Average Natural Gas Price — Per Mcf:
                       
 
United States
  $ 7.22     $ 5.45     $ 5.22  
 
Canada
    7.29       5.30       4.69  
 
Egypt
    4.59       4.35       4.18  
 
Australia
    1.72       1.65       1.44  
 
North Sea
    9.17       5.53       2.77  
 
Argentina
    1.14       .65       .47  
   
Total
    6.35       4.91       4.61  

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    For the Year Ended December 31,
     
    2005   2004   2003
             
NGL Volume — Barrels per day:
                       
 
United States
    7,553       8,268       7,578  
 
Canada
    2,235       2,588       1,565  
                   
   
Total
    9,788       10,856       9,143  
                   
Average NGL Price — Per barrel:
                       
 
United States
  $ 32.44     $ 26.66     $ 21.70  
 
Canada
    31.07       24.44       19.25  
   
Total
    32.13       26.13       21.28  
Contributions to Oil and Natural Gas Revenues
      As with production and reserves, a consequence of geographic diversification is a shifting geographic mix of our oil revenues and natural gas revenues. For the reasons discussed in the Oil and Natural Gas Prices section above, contributions to oil revenues and gas revenues should be viewed separately.
      The following table presents each segment’s oil revenues and gas revenues as a percentage of total oil revenues and gas revenues, respectively.
                                                   
    Oil Revenues   Gas Revenues
    For the Year Ended   For the Year Ended
    December 31,   December 31,
         
    2005   2004   2003   2005   2004   2003
                         
United States
    26 %     32 %     33 %     54 %     58 %     62 %
Canada
    10 %     12 %     13 %     34 %     29 %     27 %
                                     
North America
    36 %     44 %     46 %     88 %     87 %     89 %
Egypt
    25 %     24 %     23 %     9 %     10 %     8 %
Australia
    7 %     13 %     16 %     3 %     3 %     3 %
North Sea
    29 %     16 %     13 %                  
Other International
    3 %     3 %     2 %                  
                                     
 
Total
    100 %     100 %     100 %     100 %     100 %     100 %
                                     
Crude Oil Contribution
      In 2005, oil revenue contributions from outside the U.S. rose six percent to 74 percent ($3.3 billion) of our total 2005 consolidated oil revenues. Production growth and significantly higher price realizations drove the North Sea’s oil revenue contributions to 29 percent of consolidated oil revenues and were largely responsible for the growth of non-U.S. oil revenues. In 2004, the North Sea’s contribution totaled 16 percent. U.S. oil revenues, which have historically been the predominate contributor, made up 26 percent of 2005 oil revenues, partly a consequence of the U.S. hurricanes (including Hurricane Ivan whose effects were felt in 2005) which reduced 2005 oil revenues $221 million. Australia’s contribution to 2005 consolidated oil revenues fell to seven percent from 13 percent on a 39 percent decrease in production compared to 2004.
      In 2004, oil revenues from areas outside the U.S. rose slightly to 68 percent of consolidated oil revenues, up from 67 percent in 2003. Lack of production growth reduced the U.S. overall contribution one percent to 32 percent of consolidated oil revenues. Canada’s contribution also declined one percent to 12 percent on lower relative production growth. Egypt’s share rose one percent to 24 percent as it saw both price gains and production growth. The North Sea’s contribution increased three percent on both an increase in average daily production and a full year of revenues versus nine months in 2003. Australia’s contribution fell three percent on lower production.

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Crude Oil Revenues
      Crude oil revenues increased $1.4 billion, or 48 percent to $4.4 billion, in 2005 from 2004 on a $16.42 per barrel increase in average realized oil price and a one percent increase in production. All segments saw a significant increase in realized crude oil price, with the North Sea and Egypt also benefiting from production growth compared to 2004.
      The North Sea’s 2005 crude oil revenues were $798 million higher than 2004, reflecting significantly higher price realizations and a 24 percent increase in production. The higher price realizations generated additional revenues of $557 million when compared to 2004, while the higher production added $242 million. Oil price realizations in 2004 were impacted by a lower fixed-price physical contract that expired in December 2004. The production growth reflects the benefits of the North Sea’s active drilling, workover and repair programs.
      U.S. crude oil revenues for 2005 increased $198 million compared to 2004. This increase was the result of a 24 percent increase in crude oil price, as production decreased two percent. The 2005 U.S. average realized price includes a $2.39 per barrel hedge loss. (See Note 3, Hedging and Derivative Instruments, of this Form 10-K.) A full year of production from the ExxonMobil and Anadarko properties, which were acquired in the second half of 2004, and successful drilling and re-completion efforts partially offset natural production declines and approximately 11 Mbbls per day of downtime resulting from hurricanes.
      Egypt contributed additional revenues of $367 million in 2005 compared to 2004. This increase in revenue was primarily attributable to a 44 percent increase in crude oil price. A six percent increase in production generated an additional $55 million of revenues. The production increase was related to drilling and recompletion activity on Egypt’s Western Mediterranean Concession, particularly completion of the Tanzanite-2 well and recompletion of the Tanzanite-1 well.
      Canada’s 2005 revenues increased $79 million over 2004 on a 38 percent increase in price, which more than offset the impact of an 11 percent, or 2,806 b/d, decline in oil production. Canada’s production was impacted by natural decline in the Zama, Midale, Virginia Hills and Consort operated areas, as well as natural decline on non-operated Karr Simonette and Nevis areas.
      China’s 2005 revenues were $40 million higher than 2004 on a 35 percent increase in crude oil price and a seven percent increase in net volumes. The higher realized price and volumes generated an additional $31 million and $9 million of revenues, respectively. China’s 2005 production outpaced 2004 primarily because production was ramping up during the first half of 2004.
      Australia’s 2005 crude oil revenues were $63 million less than 2004. This decrease reflects a 39 percent decline in production resulting from natural decline, particularly in the Legendre field, and loss of liquids from East Spar, which ceased production early in 2005. These declines were partially offset by a 37 percent increase in realized price and a full year of production from the Mohave and Artreus fields, which commenced production during the third quarter of 2005.
      Apache manages a small portion of its exposure to fluctuations in crude oil prices using financial derivatives. Approximately six percent of our worldwide crude oil production was subject to financial derivative hedging for 2005 compared to four percent in 2004. (See Note 3, Hedging and Derivative Instruments, of this Form 10-K for a summary of the current derivative positions and terms.) These financial derivative instruments reduced our 2005 and 2004 worldwide realized prices $.68 and $.21 per barrel, respectively.
Natural Gas Contribution
      Our North America operations contributed 88 percent of 2005 consolidated natural gas revenues, up one percent from 2004. The U.S. contributed 54 percent of 2005 consolidated natural gas revenues, a four percent decline from 2004, a consequence of the U.S. hurricanes (which reduced U.S. natural gas revenues approximately $229 million). Canada’s natural gas revenue contribution increased to 34 percent, reflecting both a 14 percent production growth and a slightly higher relative increase in realized price. While Egypt’s gas

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production increased 20 percent, its contribution to 2005 gas revenues decreased slightly to nine percent as they only had marginal price improvement, a result of the new pricing formula enacted in 2004. Australia’s contribution to our total gas revenues was unchanged at three percent.
      In 2004, 87 percent of Apache’s natural gas revenues came from North America of which 58 percent was from the U.S. and 29 percent was from Canada. The U.S. contribution decreased four percent from 2003, primarily because of production declines, the impact Hurricane Ivan had on U.S. Gulf of Mexico revenues, and the additional revenues generated by Canada and Egypt. Our U.S. Gulf Coast region, which contributed 69 percent of Apache’s U.S. 2004 production, down two percent from 2003, is characterized by reservoirs which demonstrate high initial production rates followed by steep declines when compared to most other U.S. producing areas. Canada’s contribution was up two percent from 2003 resulting from three percent production growth and higher price gains relative to other areas. Egypt’s contribution to total gas revenues increased to 10 percent from eight percent in 2003, on 21 percent production growth. Australia’s contribution to 2004 natural gas revenues remained the same as 2003 at three percent.
Natural Gas Revenues
      Our 2005 natural gas revenues increased $711 million from the prior-year on a 29 percent increase in realized natural gas price and a two percent increase in production. The higher prices generated an additional $652 million in gas revenues, while the production increase added another $59 million to 2005 revenues, relative to the prior year. While all of our reportable segments realized increased natural gas prices, the increases in the U.S. and Canada had the most significant impact on 2005 revenues, given their price advantage and the magnitude of their volumes, relative to the other countries. Canada, Egypt and Australia also contributed increased gas revenues from higher production, while the additional price-driven revenues generated in the U.S. were partially offset by an eight percent decline in production.
      2005 U.S. natural gas revenues were $286 million higher than 2004. U.S. natural gas prices, which were up 32 percent, contributed $420 million of additional revenues, while an eight percent production decline lowered revenues $134 million when compared to 2004. While U.S. production was down year-over-year because of the hurricanes in our Gulf Coast region, an 11 percent gain in the Central region offset some of the hurricane impact. The Central region was up on active drilling and recompletion programs and acquisitions.
      Canada’s 2005 natural gas revenues increased $356 million from 2004. Two-thirds of the increase related to a 38 percent increase in price, with the balance generated by a 14 percent increase in production. Production increased 45 MMcf/d, a result of successful drilling efforts at the Nevis, Zama, Hatton and Consort areas and the ExxonMobil acreage, which more than offset natural declines in the Ladyfern and other Northeast British Columbia areas.
      Egypt contributed an additional $58 million to 2005 consolidated natural gas revenues compared to 2004. This increase is attributable to a six percent price improvement and a 20 percent increase in production. The year-over-year production growth came from development of the Khalda Concession Imhoptep and Atoun wells, development of the Qasr field, and first sales from the Northeast Abu Gharadig concession, which commenced in January 2005.
      Australia’s 2005 natural gas revenues were $6 million higher than 2004. While Australia’s natural gas production and price were each up four percent over 2004, the impact on revenues was minimal given the relatively low natural gas price. The additional production was attributable to the Rose, John Brookes and Bambra fields.
      Our 2004 natural gas revenues increased $171 million with a $.30 per Mcf increase in our average natural gas price realizations generating an additional $133 million of revenues. Higher production added the remaining $38 million. While all of our operating segments reported an increase in natural gas price realizations, most of the additional revenues attributable to price came from the U.S. and Canada. The additional revenues attributable to production were primarily generated in Egypt, where natural gas production increased 21 percent, reflecting the success of our drilling program. Canada and Australia also contributed to the increase in production revenues with production growth of three percent and six percent, respectively.

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Canada’s increase is from new wells while Australia’s increase was driven by higher customer demand and new contractual sales. Partially offsetting these additional production revenues was a three percent decrease in U.S. production. The lower U.S. production was focused in the Gulf Coast region and is related to the impact of Hurricane Ivan and natural decline in mature fields.
      Apache uses a variety of strategies to manage its exposure to fluctuations in natural gas prices, including fixed-price physical contracts and derivatives. The majority of our worldwide gas sales contracts are indexed to prevailing market prices; however, during 2005 and 2004, approximately ten percent and nine percent of our U.S. natural gas production, respectively, was subject to long-term, fixed-price physical contracts. The long-term, fixed-price physical contracts apply to a small portion of our future U.S. natural gas production and provide a measure of protection to the Company in the event of decreasing natural gas prices. These fixed-priced contracts reduced our 2005 and 2004 worldwide realized natural gas prices by $.19 per Mcf and $.10 per Mcf, respectively. Additionally, nearly all of our Australian natural gas production is subject to long-term, fixed-price supply contracts that are periodically adjusted for changes in Australia’s consumer price index. Since these contracts are denominated in Australian dollars, the resulting revenues are impacted by changes in the value of the Australian dollar relative to the U.S. dollar.
      Approximately nine percent and 16 percent of our worldwide natural gas production was subject to financial derivative hedges for 2005 and 2004, respectively. Currently, all of our natural gas derivative positions have been designated against Gulf of Mexico production. These derivative financial instruments reduced our 2005 and 2004 consolidated realized prices $.15 per Mcf and $.20 per Mcf, respectively. (See Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K for a summary of current derivative positions and terms.) Also during 2004, we amortized specific unrealized gains and losses related to derivative positions closed in October and November 2001. This amortization, which terminated in July 2004, had a negligible impact on 2005 average realized prices.
Costs
      The tables below compare our costs on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference either expenses on a boe basis or expenses on an absolute dollar basis, or both, depending on their relevance.
                                                     
    Year Ended December 31,   Year Ended December 31,
         
    2005   2004   2003   2005   2004   2003
                         
    (In millions)   (Per boe)
Depreciation, depletion and amortization:
                                               
 
Oil and gas property and equipment
  $ 1,325     $ 1,149     $ 1,003     $ 7.99     $ 7.01     $ 6.59  
 
Other assets
    91       73       70       .55       .44       .46  
Asset retirement obligation accretion
    54       46       38       .32       .28       .25  
International impairments
                13                   .08  
Lease operating costs
    1,041       864       700       6.27       5.27       4.59  
Gathering and transportation costs
    100       82       60       .60       .50       .40  
Severance and other taxes
    453       94       122       2.73       .57       .80  
General and administrative expenses
    198       173       138       1.20       1.06       .91  
China litigation
          71                   .43        
Financing costs, net
    116       117       115       .70       .71       .75  
                                     
   
Total
  $ 3,378     $ 2,669     $ 2,259     $ 20.36     $ 16.27     $ 14.83  
                                     
Depreciation, Depletion and Amortization
      Apache’s Depreciation, Depletion and Amortization (DD&A) of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation in simplest terms multiplies the percentage of estimated proved reserves produced each quarter times the costs of those reserves. The result is to recognize expense at the same pace that the reservoirs are actually depleting. The costs in the UOP calculation include both the net capitalized amounts on the balance sheet, and the estimated future costs to

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access and develop reserves needing additional facilities, equipment or downhole work in order to produce. Under the full-cost method of accounting, the DD&A calculation is prepared separately for each country in which Apache operates. Absolute DD&A determines the expense reported each period, while the cost per unit of production (DD&A rate) provides insight into the overall costs of the company’s reserves growth. Current costs incurred to drill or acquire additional reserves that are higher than the historical cost level raises the overall DD&A rate. Conversely, if reserves are added in the current period at a rate per unit less than existing levels, they average down the company’s DD&A rate. Changes from period to period in absolute DD&A expense are determined by production levels, the mix of production (high cost country versus a low cost country) and the impact of recent spending (higher or lower DD&A rates).
      Our 2005 full-cost DD&A expense totaled $1.3 billion, $176 million more than 2004. Our 2005 full-cost DD&A rate of $7.99 per boe was $.98 per boe more than 2004, driven by rising industry-wide drilling costs, especially in the U.S., Canada, the North Sea and Egypt. The higher commodity prices experienced over the past year, as well as the affect of the U.S. hurricanes, led to increased demand for drilling services and thus higher current drilling costs and higher estimated future development costs. The increase in North Sea’s rates per boe also reflects the continuation of facility upgrades to increase the overall efficiency of the platforms.
      Full-cost DD&A expense of $1.1 billion in 2004, increased $146 million compared to 2003. Approximately 59 percent of the increase in absolute costs was related to higher production levels, mainly in the North Sea, Egypt and China. The balance was primarily attributable to higher drilling costs, as our 2004 DD&A rate increased $.42 to $7.01 per boe. The increase in per unit costs is primarily attributable to our North American operations where high commodity prices have led to increased demand for drilling services and thus higher drilling costs. A full year’s production from China, which carries the second highest DD&A rate in the Company, also contributed to the increase in the worldwide rate. These increases were partially offset by a decrease in the DD&A rate in Egypt from a successful exploration and development program which added significant reserves through drilling at lower costs.
      Depreciation of other assets increased $18 million in 2005, reflecting new infrastructure built in Canada to accommodate development on acreage acquired from ExxonMobil in 2004 and new Qasr natural gas facilities in Egypt.
      Depreciation of other assets increased $3 million in 2004, in line with our overall growth.
Impairments
      We assess all of our unproved properties for possible impairment on a quarterly basis based on geological trend analysis, dry holes or relinquishment of acreage. When an impairment occurs, costs associated with these properties are generally transferred to our proved property base where they become subject to amortization. Impairments in international areas without proved reserves are charged to earnings upon determination that impairment has occurred. In 2003, we impaired the final $13 million ($8 million after-tax) of unproved property costs in Poland.
      Goodwill is subject to a periodic fair-value-based impairment assessment. Goodwill totaled $189 million on December 31, 2005, and no impairment was recorded in 2005, 2004 or 2003. For further discussion, see Note 1, Summary of Significant Accounting Policies of Item 15 in this Form 10-K.
Lease Operating Costs
      Lease operating costs (LOE) are generally comprised of several components: direct operating costs, repair and maintenance, workover costs and ad valorem taxes. LOE is driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties. Oil is inherently more expensive to produce than natural gas. Repair and maintenance costs are higher on offshore properties and in areas with remote plants and facilities. Workovers continue to be an important part of our strategy enabling us to exploit our existing reserve base by accelerating production and taking advantage of high commodity prices. Commodity prices and exchange rates also impact LOE. Historically, electricity, fuel and other service costs have risen in high commodity price environments, leading to an increase in industry-wide LOE. Rising per

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unit operating costs remained a challenge in 2005, especially in North America. The Company reviews production costs in each of its core areas on a monthly basis and pursues alternatives to maintain efficient levels of costs. Fluctuations in exchange rates also impact the Company’s LOE, with a weakening U.S. dollar adding to per unit costs and a stronger U.S. dollar lowering per unit costs. The U.S. dollar, which weakened against the Canadian dollar throughout 2005, strengthened marginally against the Australian dollar and British pound. Acquisitions increase absolute LOE costs, but they do not necessarily increase per unit costs or reduce margins. The following discussion will focus on per unit operating costs as this is the most informative method of analyzing LOE trends.
      On a per unit/boe produced basis, 2005 LOE averaged $6.27 per boe, $1.00 per boe higher than 2004. Production shut-ins and additional insurance costs associated with the 2005 hurricanes added $.41 to the 2005 rate. The remaining increase reflects higher service costs associated with rising commodity prices and the associated increase in demand for services, an increase in workover activity, higher repair and maintenance costs and the impact a weaker U.S. dollar had on Canadian LOE. The slight strengthening against the Australian dollar and British pound had less impact on LOE.
      Regionally, 2005 costs were up as follows:
      U.S. — The U.S. added $.77 per boe to the 2005 consolidated rate with nearly one-third of the impact attributed to the additional insurance costs and production shut-ins caused by the 2005 hurricanes. Higher contract labor costs, workover activity, repair and maintenance, and various other commodity-price driven service costs accounted for the remaining impact.
      Australia — Australia added $.15 per boe to the 2005 consolidated rate on a 20 percent drop in equivalent production. Australia also saw a rise in insurance cost. The lower production added $.13 per boe to the 2005 consolidated rate, while additional costs added $.02 per boe.
      Canada — Canada added $.21 per boe to the 2005 consolidated rate increase, with costs adding $.27 per boe, partially offset by the impact of higher volumes, which reduced the rate $.06 per boe. 2005 costs were up $44 million from 2004, with 42 percent attributable to the strengthening Canadian dollar. The balance related to various other costs associated with an increase in activity and the general rise in costs, including higher contract labor, power and fuel, repair and maintenance and workover costs.
      Egypt — Egypt’s 2005 costs were $23 million higher than 2004 on higher diesel fuel costs, an increase in workover activity, higher labor costs and insurance costs. The diesel fuel costs were previously subsidized by the Egyptian government. Egypt added $.04 per boe to the consolidated rate increase, with higher costs adding $.14 per boe and increased volumes lowering the rate $.10 per boe.
      North Sea — The North Sea reduced the 2005 consolidated rate $.16 per boe on a 24 percent increase in production, partially offset by a two percent increase in costs. North Sea costs were up on increased repair and maintenance activity.
      On a per unit produced basis, 2004 LOE increased $.68 to $5.27 per boe. The increase was primarily attributable to an increase in industry-wide service costs in North America with higher commodity prices, an increase in currency exchange rates in Canada, the North Sea and Australia, and higher expense resulting from our incentive programs, primarily stock-based programs which we began expensing in 2003. Per unit costs were also negatively impacted by the combined impact of lost production and additional costs related to Hurricane Ivan in the Gulf of Mexico and higher repair and maintenance costs in Australia. These increases offset the impact of a $2.75 decline in the unit cost in the North Sea, where our investments to increase production (and lower operating costs per unit) over the long-term began to pay off.
Gathering and Transportation Costs
      Apache generally sells oil and natural gas under two types of agreements, typical in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which Apache sells oil or natural gas at the wellhead and collects a price, net of transportation incurred by the purchaser. In this case, the Company records sales at the price received from the purchaser, which is net of transportation costs.

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Under the other arrangement, Apache sells oil or natural gas at a specific delivery point, pays transportation to a third-party carrier and receives from the purchaser a price with no transportation deduction. In this case, the Company records the transportation cost as gathering and transportation costs. The Company’s treatment of transportation costs is pursuant to Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs” and as a result a portion of our transporting costs is reflected in sales prices and a portion is reflected as Gathering and Transportation Costs rendering the separately identified transportation costs incomplete.
      In both the U.S. and Canada, Apache sells oil and natural gas under both types of arrangements. In the North Sea, Apache pays transportation to a third-party carrier and receives a purchase price with no transportation deduction. In Australia, oil and natural gas are sold under netback arrangements. In China, we incur costs for barges to transport crude oil to onshore terminal facilities. In Egypt, our oil and natural gas production has historically been sold to EGPC under netback arrangements. During 2005, Apache exported a portion of its Egyptian crude oil under both types of arrangements. Future export cargoes may be sold under netback arrangements or Apache may arrange shipping and receive prices without transportation deductions. The following table presents gathering and transportation costs paid directly by Apache to third-party carriers for each of the periods presented.
                         
    For the Year Ended
    December 31,
     
    2005   2004   2003
             
    (In millions)
U.S. 
  $ 30     $ 28     $ 21  
Canada
    33       31       28  
North Sea
    28       22       11  
Egypt
    8              
China
    1       1        
                   
Total Gathering and Transportation
  $ 100     $ 82     $ 60  
                   
      These costs are primarily related to the transportation of natural gas in our North American operations, North Sea crude oil sales and Egyptian crude oil exports. The 22 percent increase in costs for 2005 was driven primarily by North Sea’s production growth and Egyptian crude exports. Apache began exporting Egyptian crude in the second half of 2004 and first incurred third-party transportation charges in early 2005.
      Transportation costs in 2004 increased 37 percent from 2003 primarily because of production growth and a full year of production in the North Sea and an increase in volumes transported under third-party transportation contracts in the U.S., Canada’s 2004 costs were 11 percent higher than 2003 because of an increase in third-party transportation rates and the impact of a weaker U.S. dollar.
Severance and Other Taxes
      Severance and other taxes are primarily comprised of severance taxes on properties onshore and in state or provincial waters in the U.S. and Australia, and the United Kingdom (U.K.) Petroleum Revenue Tax (PRT). Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts (revenues less qualifying operating costs and capital spending) from subject fields in the U.K. North Sea. We are also subject to the Australian Petroleum Resources Rent Tax (PRRT), and various Canadian taxes including the Canadian Large Corporation Tax, Saskatchewan Capital

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Tax, Saskatchewan Resource Surtax and Freehold Mineral Tax. The table below presents a comparison of these expenses.
                         
    For the Year Ended
    December 31,
     
    2005   2004   2003
             
    (In millions)
Severance taxes
  $ 139     $ 127     $ 77  
U.K. PRT
    285       (61 )     20  
Canadian taxes
    22       23       20  
Other
    7       5       5  
                   
Total Severance and Other Taxes
  $ 453     $ 94     $ 122  
                   
      Severance and other taxes totaled $453 million in 2005, $359 million greater than 2004. The U.K. PRT increased $346 million in 2005 on significantly higher oil price realizations and higher production. U.S. severance taxes increased $36 million on higher oil and gas prices. Australia’s severance taxes decreased $24 million, reflecting lower excise tax on production from Legendre, a result of declining production.
      In 2004, severance and other taxes decreased 23 percent, or $28 million, with severance taxes representing the majority of these taxes. U.S. severance and other taxes increased $15 million, in line with higher production revenues. Australia’s taxes increased $36 million as production from the Legendre field crossed a cumulative threshold, triggering an excise tax. In 2004 Apache’s U.K. PRT was in a credit position as deductible capital spending exceeded taxable cash flows from the North Sea Forties field. Canadian taxes increased $3 million on an increase in Freehold Mineral Taxes.
General and Administrative Expenses
      General and administrative expenses (G&A) of $1.20 per boe for 2005 increased $.14 per boe over 2004. Absolute costs increased $25 million or 14 percent. Nearly three-fourths of the increase in year-over-year costs related to the impact of Apache’s stock-based compensation programs. Stock-based compensation costs increased relative to the prior-year because of new stock option grants issued in 2005, a new targeted stock plan approved by stockholders in May 2005, and the impact Apache’s rising common stock price had on stock-based compensation expense. The balance of the G&A increase was primarily attributed to the increased cost of insurance, a consequence of the hurricanes, higher charitable contributions and higher Sarbanes-Oxley compliance audit fees.
      G&A of $1.06 per boe in 2004 increased $.15 per boe over 2003. Absolute costs increased $35 million, or 25 percent. Over $21 million, or 61 percent, of the additional expense was related to the impact Apache’s rising stock price had on stock-based compensation programs and incremental incentive compensation. The impact from the higher stock price stems from Apache’s decision, effective January 1, 2003, to expense stock-based compensation plans (see Note 8, Capital Stock of Item 15 in this Form 10-K). Approximately $3 million, or 8 percent, of the increase is related to our North Sea operations, with the first full year of operations in 2004. The balance of the increase was related to higher audit and tax fees, increased insurance premiums, and expansion of the Company’s gas marketing group.
Financing Costs, Net
      The major components of financing costs, net, include interest expense and capitalized interest.
      Net financing costs for 2005 were slightly lower than 2004. While gross interest expense increased $7 million in 2005 on a higher average debt balance, it was mostly offset by a $6 million increase in the amount of interest capitalized, a result of a higher average unproved property balance. Our weighted-average cost of borrowing on December 31, 2005 was 6.7 percent and 2004 was 6.1 percent.
      2004 net financing costs were slightly higher than 2003. Gross interest expense decreased $1 million in 2004, a result of a lower average debt balance. This decrease was offset by a $2 million decrease in the amount

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of interest capitalized, a result of a lower average unproved property balance. Our weighted-average cost of borrowing on December 31, 2004 was 6.1 percent compared to 6.4 percent on December 31, 2003.
Provision for Income Taxes
      2005 income tax expense of $1.6 billion was $590 million higher than 2004. The additional income tax expense was driven by higher taxable income related to the increased oil and gas revenues in 2005, compared to 2004. Our effective tax rate was 37.62 percent in 2005 compared to 37.29 percent in 2004. Currency fluctuations added $13 million of additional deferred tax expense to 2005 and $58 million to 2004.
      Income tax expense in 2004 of $993 million was $166 million or 20 percent higher than 2003. The higher taxes were primarily associated with higher income driven by higher oil and gas production revenues in 2004 compared to 2003. Our effective tax rate was 37.29 percent in 2004 compared to 43.02 percent in 2003. The 2003 effective tax rate included $172 million of additional deferred tax expense because of currency fluctuations compared to $58 million in 2004. For a discussion of Apache’s sensitivity to foreign currency fluctuations, please refer to Item 7A, Quantitative and Qualitative Disclosures about Market Risk, “Foreign Currency Risk” of this Form 10-K.
Capital Resources and Liquidity
Financial Indicators
                         
    At December 31,
     
    2005   2004   2003
Millions of dollars except as indicated            
Current ratio
    .99       1.05       1.10  
Net cash provided by operating activities
  $ 4,332     $ 3,232     $ 2,706  
Total debt
    2,192       2,588       2,327  
Shareholders’ equity
    10,541       8,204       6,533  
Percent of total debt to capitalization
    17 %     24 %     26 %
Floating-rate debt/total debt
          15 %     6 %
Overview
      Apache’s primary uses of cash are exploration, development and acquisition of oil and gas properties, costs and expenses necessary to maintain continued operations, repayment of principal and interest on outstanding debt and payment of dividends.
      Our business, as with other extractive industries, is a depleting one in which each barrel produced must be replaced or the Company, and a critical source of our future liquidity, will shrink. Cash investments are continuously required to fund exploration and development projects and acquisitions which are necessary to offset the inherent declines in production and proven reserves. See Item 1 and 2, Business and Properties, “Risks Factors,” in this Form 10-K. Future success in maintaining and growing reserves and production will be highly dependent on having adequate capital resources available, on our success in both exploration and development activities and on acquiring additional reserves.
      Our year-end reserve life index indicates an average decline of 7.8 percent per year. This projection is based on prices at year-end, except in those instances where future natural gas and oil sales are covered by physical contract terms providing for higher or lower prices, estimates of investments required to develop estimated proved undeveloped reserves, costs and taxes reflected in our standardized measure in Note 14, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K.
      The Company funds its exploration and development activities primarily through net cash provided by operating activities (cash flow) and budgets capital expenditures based on projected cash flow. Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire or find high-margin reserves at competitive prices. For these reasons, we only forecast, for internal use by management, an annual

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cash flow. Longer-term cash flow and capital spending projections are not used by management to operate our business. The annual cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.
      The Company has historically utilized internally generated cash flow, committed and uncommitted credit facilities and access to both debt and equity capital markets for all other liquidity and capital resources needs. Apache’s ability to access the debt capital market is supported by its investment grade credit ratings. Because of the liquidity and capital resources alternatives available to Apache, including internally generated cash flows, Apache’s management believes that its short-term and long-term liquidity is adequate to fund operations, including its capital spending program, repayment of debt maturities and any amounts that may ultimately be paid in connection with contingencies.
      Apache’s senior unsecured debt is currently rated investment grade by Moody’s, Standard and Poor’s and Fitch with ratings of A3, A- and A, respectively.
      The Company’s ratio of current assets to current liabilities was .99 on December 31, 2005 compared to 1.05 at the end of 2004. Current liabilities increased 70 percent ($904 million) in 2005 versus a 60 percent ($813 million) increase in current assets. While virtually all meaningful current asset and current liability categories increased in 2005, changes in the North Sea PRT liability, our current portion of derivative liabilities, and current ARO liabilities particularly impacted the ratio. The North Sea PRT liability, which is a component of “Other” current liabilities, increased approximately $171 million compared to the prior year. The current portion of FMV of derivatives increased nearly $235 million, which is eleven times the 2004 amount. Both the PRT and derivative liabilities reflect the impact of higher commodity prices. The current ARO liability of $94 million was established in 2005 because of damage caused by Hurricanes Katrina and Rita. Collectively, the increases in liabilities more than offset the higher current asset balances. Current receivables were up $505 million, or 54 percent, most of which related to oil and gas receivables impacted by commodity prices. Cash more than doubled to $229 million. Drilling advances, up 76 percent, and prepaid assets and other, up 130 percent, were other asset categories that also increased substantially. The drilling advance amount is in line with increased drilling activity in 2005 compared to 2004. The change in prepaid assets and other relates to higher taxes and other deposits.
Net Cash Provided by Operating Activities
      Apache’s net cash provided by operating activities during 2005 totaled $4.3 billion, up from $3.2 billion in 2004. The increase in 2005 cash flow was attributed primarily to the significant increase in commodity prices. The Company’s average realized oil and natural gas prices increased 47 percent and 29 percent, respectively; a reflection of higher worldwide commodity prices. Higher production also added to our 2005 cash flow relative to 2004, albeit to a much less extent. These increases in cash flow were partially offset by higher production costs attributable to the effect of increased commodity prices, costs related to Hurricanes Katrina and Rita and an increase in exchange rates in Canada. The Company reviews production costs for each core area on a monthly basis and pursues alternatives in maintaining efficient levels of costs and expenses. For a more detailed discussion of commodity prices, production, costs and expenses, please refer to the Results of Operations section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
      Apache’s net cash provided by operating activities during 2004 totaled $3.2 billion, up from $2.7 billion in 2003. The increase in 2004 cash flow was primarily attributed to the significant increase in commodity prices. The Company’s averaged realized oil and natural gas prices increased 27 and 7 percent, respectively; a reflection of higher worldwide commodity prices. Higher production also increased our 2004 cash flow on a 13 percent and one percent increase in oil and natural gas production, respectively. These increases were partially offset by higher production costs attributable to the effect of increased commodity prices, an increase in exchange rates in Canada, North Sea and Australia, costs related to Hurricane Ivan and increases in costs from our stock-based employee incentive programs.

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      Historically, fluctuations in commodity prices have been the primary reason for the Company’s short-term changes in cash flow from operating activities. Sales volume changes have also impacted cash flow in the short-term, but have not been as volatile as commodity prices in the past. Apache’s long-term cash flow from operating activities is dependent on commodity prices, reserve replacement and the level of costs and expenses required for continued operations.
Debt
      During 2005, we continued to strengthen our financial flexibility and to build on the solid financial positions of previous years. We exited 2005 with a debt-to-capitalization ratio of 17 percent, a decrease of seven percent from year-end 2004, with lower debt and increases in equity resulting from earnings. At year-end 2005 the Company had long-term debt of $2.2 billion, $396 million lower than year-end 2004, as the Company’s capital spending was less than internally generated cash flow. The Company’s outstanding debt consisted of notes and debentures maturing in the years 2006 through 2096. Approximately $.3 million, $173 million, $.4 million, $100 million and $1.9 billion mature in 2006, 2007, 2008, 2009 and thereafter, respectively. During 2005, the Company maintained its senior unsecured long-term debt ratings of A3 from Moody’s, A- from Standard and Poor’s and A from Fitch.
      The Company has a $1.2 billion commercial paper program which enables Apache to borrow funds for up to 270 days at competitive interest rates. There was no commercial paper outstanding as of December 31, 2005. The commercial paper balance of $392 million on December 31, 2004 was classified as long-term debt in the accompanying consolidated balance sheet as the Company had the ability and intent to refinance such amount on a long-term basis through either the rollover of commercial paper or available borrowing capacity under its U.S. credit facilities. The weighted-average interest rate for commercial paper was 3.03 percent in 2005 and 1.79 percent in 2004.
      As of December 31, 2005, available borrowing capacity under our credit facilities was $1.5 billion. We had $229 million in cash and cash equivalents on hand on December 31, 2005, compared to $111 million on December 31, 2004.
      On May 12, 2005, the Company entered into a new $450 million revolving bank credit facility for the U.S., a $150 million revolving bank credit facility for Australia and a $150 million revolving bank credit facility for Canada. These new facilities replaced the Company’s existing credit facilities in the same amounts which were scheduled to mature in June 2007. These new facilities are scheduled to mature on May 12, 2010. There were no changes to the Company’s $750 million U.S. credit facility which matures in May 2009.
      The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics liens. The Company may incur liens on assets located in the U.S., Canada and Australia of up to five percent of the Company’s consolidated assets, which approximated $964 million on December 31, 2005. There are no restrictions on incurring liens in countries other than the U.S., Canada and Australia. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group.
      There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes (MAC clauses). The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S., Canadian and Australian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2005.

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Stock Transactions
      The Company periodically uses access to equity capital markets to fund significant acquisitions. On January 22, 2003, in conjunction with the BP transaction, we completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters’ over-allotment option, for net proceeds of $554 million. The Company currently has no plans to access equity capital markets.
      On December 18, 2003, we announced that holders of our common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004.
Oil and Gas Capital Expenditures
      The Company funded its exploration and production (E&D) capital expenditures, including Gathering, Transportation and Marketing (GTM) facilities, of $3.8 billion, $2.5 billion and $1.5 billion in 2005, 2004 and 2003, respectively, primarily with internally generated cash flow of $4.3 billion, $3.2 billion and $2.7 billion.
      The Company uses a combination of internally generated cash flow, borrowings under the Company’s lines of credit and commercial paper program and, from time to time, issues of public debt or common stock to fund its significant acquisitions. During the three-year period presented, the Company primarily used internally generated cash flow or its lines of credit and commercial paper program; which were subsequently paid down with internally generated cash flow. However, in 2003, in conjunction with the BP acquisition, the Company completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters’ over-allotment option, for net proceeds of $554 million.
      The following table presents a summary of the Company’s Capital Expenditures for each of our reportable segments for the past three years.
                           
    Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
Exploration and Development:
                       
 
United States
  $ 1,072,040     $ 755,056     $ 417,701  
 
Canada
    1,188,096       756,912       568,856  
 
Egypt
    352,324       301,912       242,652  
 
Australia
    217,816       138,694       128,261  
 
North Sea
    489,072       362,054       60,204  
 
Other International
    48,484       26,493       35,098  
                   
    $ 3,367,832     $ 2,341,121     $ 1,452,772  
                   
Capitalized Interest
  $ 56,988     $ 50,748     $ 52,891  
                   
Gas Gathering Transmission and Processing Facilities
  $ 392,872     $ 138,738     $ 38,533  
                   
Acquisitions:
                       
 
Oil and gas properties
  $ 39,228     $ 1,063,851     $ 1,568,106  
 
Gas gathering, transmission and processing facilities
                5,484  
                   
    $ 39,228     $ 1,063,851     $ 1,573,590  
                   
      The Company completed its most active year to-date, drilling 2,383 wells throughout 2005 and spending nearly $400 million on oil and gas processing facilities and pipelines. Approximately two-thirds of our 2005 exploration and development expenditures were invested in Canada and the U.S., where nearly 69 percent of Apache’s 2005 year-end estimated proved reserves reside. Once again, Canada was our most active region, drilling 1,674 wells with a 93 percent success rate. Approximately 82 percent of Canada’s 2005 wells were shallow development wells. Canada was also very active in the North Grant Lands, undeveloped acreage Apache obtained through two farm-in agreements with ExxonMobil. Canada spent nearly $180 million

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constructing 11 gas processing plants, six of which were completed by the end of 2005. In the Gulf Coast region, even with the disruptions caused by the Gulf of Mexico hurricanes, we drilled 114 wells, including 66 offshore. Seventy-seven percent of our Gulf Coast wells were productive. Our focus in the Gulf Coast region remained the same as 2004, development and exploitation of our existing asset base including the Gulf of Mexico properties acquired from Anadarko in the second half of 2004. The Central region was the second most active region, drilling 364 wells, with a 97 percent success rate. In the North Sea, we drilled a total of 23 wells, 18 Forties Field wells, and invested approximately $198 million of maintenance capital to continue to improve the operating efficiency of the Forties Field. We expect to complete the Forties power generation and gas ring by the summer of 2006, which will greatly reduce fuel oil generating costs and improve production reliability. In Egypt, we had another active and successful exploration and development program, drilling 121 wells of which 86 percent were productive. We also continued development of the Qasr field, where gross production average 128 MMcf/d in December 2005. In Australia, we participated in drilling 36 wells; 26 exploration wells and 10 development wells. China’s capital expenditures were flat compared to 2004 as they continued their development drilling program. The Company spent $39 million on acquisitions in 2005 compared to $1.1 billion in 2004, as the high-price commodity market in 2005 limited the number of attractive acquisition opportunities. Those that were pursued were slated to close in the first quarter of 2006. Acquisition expenditures typically vary year to year based on the availability of opportunities that fit Apache’s overall strategy.
      In 2004, Apache drilled 1,735 wells and completed two significant acquisitions. In the Gulf of Mexico, the majority of our activity focused in and around our existing asset base, including continued exploitation of the properties purchased from BP and Shell in 2003 and the Anadarko properties purchased in 2004. In the Central region, where Apache got its start, estimated proved reserves increased 20 percent in 2004 through a combination of the ExxonMobil acquisition and an active drilling year, completing 268 of 283 wells in the region. Canada was our most active area in 2004 with over 1,300 wells drilled, three-fourths of which were shallow development wells, with over 92 percent completed as producers. At the Forties Field, an experienced workforce began tackling projects to extend the life of the largest field discovered in the United Kingdom sector of the North Sea. Production increases at Forties — the anchor of Apache’s newest core area — were driven by Apache’s first drilling program since acquiring the field and a maintenance program aimed at improving efficiency of the field. During 2004, Apache completed 12 of 17 wells drilled as part of a $362 million capital program, including $150 million of maintenance and operations capital expenditures. In Egypt and Australia, Apache continued its successful exploration programs with several new discoveries. Our continuing development program in Egypt increased gross production to over 100,000 b/d for the first time. Capital expenditures in China decreased in 2004 with the completion of production facilities and first production in the second half of 2003. In 2004, Apache added 444.7 MMboe of estimated proved reserves through acquisitions, drilling and revisions. During 2004, GTM expenditures included additional gathering system pipelines in Egypt and a gas plant expansion on Varanus Island in Australia.
      For 2006, we plan another active year of drilling. Because we revise our estimates of exploration and development capital expenditures frequently throughout the year based on industry conditions and results to date, accurately projecting future expenditures is difficult at best. However, our 2006 preliminary estimate of exploration and development capital and oil and gas processing facilities and pipelines is in excess of $3.7 billion. We generally do not project estimates for acquisitions because their timing is unpredictable; however, in early 2006 we closed an acquisition announced in late 2005. Also, on January 17, 2006, the Company announced an agreement with Pioneer Natural Resources. Please refer to the Subsequent Acquisitions and Divestiture section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. We continually look for properties which we believe will add value and earn adequate rates of return and will take advantage of those opportunities as they arise.
Cash Dividend Payments
      The Company has paid cash dividends on its common stock for 41 consecutive years through 2005. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other relevant factors. Common dividends paid during 2005 rose 32 percent to $112 million, reflecting the increase

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in common shares outstanding and the higher common stock dividend rate. The Company increased its quarterly cash dividend 25 percent, to 10 cents per share from eight cents per share, effective with the November 2005 dividend payment.
      During 2005 and 2004, Apache paid a total of $6 million in dividends each year on its Series B Preferred Stock issued in August 1998. See Note 8, Capital Stock of Item 15 in this Form 10-K. Common dividends paid during 2004 rose 26 percent to $85 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate.
Contractual Obligations
      We are subject to various financial obligations and commitments in the normal course of operations. These contractual obligations represent known future cash payments that we are required to make and relate primarily to long-term debt, operating leases, pipeline transportation commitments and international commitments. The Company expects to fund these contractual obligations with cash generated from operating activities. The following table summarizes the Company’s contractual obligations as of December 31, 2005. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for further information regarding these obligations.
                                                                 
    Note                            
Contractual Obligations   Reference   Total   2006   2007   2008   2009   2010   Thereafter
                                 
    (In thousands)
Debt
    Note 5     $ 2,192,228     $ 274     $ 172,678     $ 353     $ 99,733     $     $ 1,919,190  
Operating leases and other commitments
    Note 10       503,724       226,410       136,070       43,026       18,736       16,421       63,061  
International lease commitments
    Note 10       222,463       33,533       106,714       24,154       58,062              
Operating costs associated with pre-existing volumetric production payments on acquired properties
    Note 2       70,145       37,815       24,088       8,242                    
           
Total Contractual Obligations(a)(b)
          $ 2,988,560     $ 298,032     $ 439,550     $ 75,775     $ 176,531     $ 16,421     $ 1,982,251  
           
(a) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1.5 billion. The Company records a separate liability for the fair value of this asset retirement obligation. See Note 4, Asset Retirement Obligation of Item 15 in this Form 10-K for further discussion.
 
(b) This table does not include the Company’s pension or postretirement benefit obligations. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for further discussion.
 
     Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess any impact on future liquidity. Such obligations include environmental contingencies and potential settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations. The Company has reserved approximately $11 million for environmental remediation. The Company has also reserved approximately $12 million for various legal liabilities, in addition to the $71 million, plus interest, we accrued for the Texaco China B.V. litigation. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for a detailed discussion of the Company’s environmental and legal contingencies.
      The Company accrued approximately $22 million as of December 31, 2005, for an insurance contingency because of our involvement with Oil Insurance Limited (OIL). Apache is a member of this insurance pool which insures specific property, pollution liability and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay termination fees were we to elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential termination

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fee is calculated annually based on past losses and the liability reflecting this potential charge has been accrued as required.
      As discussed under Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache assumed obligations for pre-existing VPPs in the 2004 acquisition of properties from Anadarko and the 2003 acquisition of properties from Shell. Under the terms of the VPP agreements, Apache is scheduled to deliver a total of 7.8 MMboe in 2006, 4.7 MMboe in 2007 and 1.6 MMboe in 2008 to Morgan Stanley as owner of the VPP interests. Morgan Stanley is entitled to the first production and may demand up to 90 percent of the production from the assets encumbered by each VPP in any given month to satisfy the VPP interests. However, they have no right to look to other assets or production of Apache. Apache does not record the reserves and production volumes attributable to the VPPs. As of December 31, 2005, Apache has booked a total of 93.5 MMboe of reserves attributable to the Anadarko and Shell transactions. The VPPs are non-operating interests, free of costs incurred for operations and production. Apache provided a liability for these costs as reflected in the preceding table.
      Upon closing of our 2003 acquisition of the North Sea properties, Apache assumed BP’s abandonment obligation for those properties and such costs were considered in determining the purchase price. The purchase of the properties, however, did not relieve BP of its liabilities if Apache fails to satisfy the abandonment obligation. Although not currently required, to ensure Apache’s payment of these costs, Apache agreed to deliver a letter of credit to BP if the rating of our senior unsecured debt is lowered by both Moody’s and Standard and Poor’s from the Company’s current ratings of A3 and A-, respectively. Any such letter of credit would be in an amount equal to the net present value of future abandonment costs of the North Sea properties as of the date of any such ratings change. If Apache is required to provide a letter of credit, it will expire if either rating agency restores its rating to the present level. The letter of credit amount would be 127 million British pounds, an amount that represents the letter of credit requirement through March 2006, and will be negotiated annually based on Apache’s future abandonment obligation estimates.
      The Company’s future liquidity could be impacted by a significant downgrade of its credit ratings by Standard and Poor’s and Moody’s; however, we do not believe that such a sharp downgrade is reasonably likely. The Company’s credit facilities do not require the Company to maintain a minimum credit rating. The negative covenants associated with our debt are outlined in greater detail under “Capital Resources and Liquidity, Debt” in this section of this Form 10-K. In addition, generally under our commodity hedge agreements, Apache may be required to post margin or terminate outstanding positions if the Company’s credit ratings decline significantly.
Off-Balance Sheet Arrangements
      Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions. Apache entered into a partnership with ExxonMobil to obtain additional interests in specific West Texas and New Mexico oil & gas properties acquired from ExxonMobil in September 2004. As discussed in Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache contributed $29 million into this partnership which was determined to be a variable interest entity as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46 “Variable Interest Entities.” Apache concluded that they were not the primary beneficiary of the partnership and, therefore, proportionately consolidated only the Company’s portion of the oil and gas properties.
Critical Accounting Policies and Estimates
Full-Cost Method of Accounting for Oil and Gas Operations
      The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Under the successful-efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to their respective full-cost pool. In the measurement of impairment of oil and gas properties, the

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successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect on the last day of the reporting period (ceiling limitation). If the full-cost pool is in excess of the ceiling limitation, the excess amount is charged through income.
      We have elected to use the full-cost method to account for our investment in oil and gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs for the purpose of finding oil and gas reserves, including salaries, benefits and other internal costs directly attributable to these finding activities. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. As a result, we believe that the full-cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful-efforts method of accounting for our oil and gas investments. Generally, the application of the full-cost method of accounting for oil and gas property results in higher capitalized costs and higher DD&A rates compared to similar companies applying the successful efforts methods of accounting.
Reserve Estimates
      Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. As such, our reserve engineers review and revise the Company’s reserve estimates at least annually.
      Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.
      We engage an independent petroleum engineering firm to review our estimates of proved hydrocarbon liquid and gas reserves. During 2005, 2004 and 2003, their review covered 74, 79 and 78 percent of the reserve value, respectively.
Costs Excluded
      Under the full-cost method of accounting, oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. Apache excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly by the Company’s accounting, exploration and engineering staffs to determine if impairment has occurred. Nonproducing leases are evaluated based on the progress of the Company’s exploration program to date. Exploration costs are transferred to the DD&A pool upon completion of drilling individual wells. If geological and geophysical (G&G) costs cannot be associated with specific properties, they are included in the amortization base as incurred. The amount of any impairment is transferred to the capitalized costs being

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amortized (the DD&A pool) or a charge is made against earnings for those international operations where a proved reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate for that country. For international operations where a reserve base has not yet been established, all costs associated with a prospect or play would be considered quarterly for impairment upon full evaluation of such prospect or play. This evaluation considers among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions.
Allowance for Doubtful Accounts
      We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. Many of our receivables are from joint interest owners on properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Our crude oil and natural gas receivables are typically collected within two months. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated.
      Beginning in 2001, we experienced a gradual decline in the timeliness of receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic conditions in Egypt lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. During 2005, we experienced wide variability in the timing of cash receipts, but our past due balance improved as of December 31, 2005. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and have no indication that we will not be able to collect our receivable.
Asset Retirement Obligation
      The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Prior to 2003, under the full-cost method of accounting, as described in the preceding critical accounting policy sections, the estimated undiscounted costs of the abandonment obligations, net of the value of salvage, were included as a component of our depletion base and expensed over the production life of the oil and gas properties.
      In 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” Apache adopted this statement effective January 1, 2003, as discussed in Note 4, Asset Retirement Obligation of Item 15 of this Form 10-K. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, the new statement requires the Company to record a separate liability for the discounted present value of the Company’s asset retirement obligations, with an offsetting increase to the related oil and gas properties on the balance sheet. As such, beginning in 2003 our depletion expense is reduced since we will deplete a discounted ARO rather than the undiscounted value previously depleted in our oil and gas property base. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which reflects increases in the discounted asset retirement obligation over time.
      Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing Asset Retirement Obligation liability, a corresponding adjustment is made to the oil and gas property balance.

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Income Taxes
      Our oil and gas exploration and production operations are currently located in seven countries. As a result, we are subject to taxation on our income in numerous jurisdictions. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).
      The Company regularly assesses and, if required, establishes accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. Tax reserves have been established, and include any related interest, despite the belief by the Company that certain tax positions have been fully documented in the Company’s tax returns. These reserves are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law and any new legislation. The Company believes that the reserves established are adequate in relation to the potential for any additional tax assessments.
Derivatives
      Apache uses derivative contracts on a limited basis to manage its exposure to oil and gas price volatility and foreign currency volatility. The Company accounts for the contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The estimated fair values of Apache’s derivative contracts within the scope of this statement are carried on the Company’s consolidated balance sheet. For oil and gas derivative contracts designated and qualifying as cash flow hedges, realized gains and losses are recognized in oil and gas production revenues when the forecasted transaction occurs. For foreign currency forward contracts designated as qualifying as cash flow hedges, realized gains and losses are generally recognized in lease operating expense when the forecasted transaction occurs. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be “marked-to-market” and reported in current period income, rather than in the period in which the hedged transaction is settled. Realized gains and losses on derivative contracts not qualifying as cash flow hedges are reported in “Other” under “Revenues and Other” of the Statement of Consolidated Operations.
      The fair value estimate of Apache’s derivative contracts requires judgment; however, the Company’s derivative contracts are either exchange traded or valued by reference to commodities and currencies that are traded in highly liquid markets. As such, the ultimate fair value is determined by references to readily available public data. Option valuations are verified against independent third-party quotations. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, “Commodity Risk” in this Form 10-K for commodity price sensitivity information and the Company’s policies related to the use of derivatives.
Stock-Based Compensation
      During 2002, Apache began modifying its stock compensation plans in order to reflect the cost of these plans in the Statement of Consolidated Operations. As part of this effort, Apache began issuing stock appreciation rights and restricted stock and, effective January 1, 2003, adopted the expense provisions of SFAS No. 123 “Accounting for Stock Based Compensation,” as amended, on a prospective basis for all stock options granted under the Company’s existing option plans. Consistent with the Company’s desire to reflect the ultimate cost of stock compensation plans on the income statement, Apache early adopted the provisions of SFAS No. 123-R “Share-Based Payment” upon the FASB’s issuance of the revised statement in the fourth quarter 2004.
      Upon adoption of SFAS No. 123-R, all stock based compensation awards that vested during 2004 are now reflected in the Company’s net income for the year. Awards that vested in prior years continue to be

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reflected in the income statement under the accounting guidelines in place for the applicable year. Awards granted in future periods will be valued on the date of grant and expensed using a straight-line basis over the required service period. Pro-forma income statement presentations have been provided for in Note 1. Summary of Significant Accounting Policies of Item 15 in this Form 10-K to present a comparative basis of all plans outstanding during the reported periods.
      The Company chose to adopt the statement under the “Modified Retrospective” approach as prescribed under SFAS No. 123-R. Under this approach, the Company is required to expense all options and stock-based compensation that vested during the year of adoption based on the fair value of the stock compensation determined on the date of grant. Had the Company not early adopted SFAS No. 123-R under this transition approach, 2004 net income would have been lower by $89 million ($56 million after tax) or $.17 per diluted share. Normally, net income would be negatively impacted by adopting SFAS No. 123-R under this transition method. However, the Company’s Share Appreciation Plan, which triggered in 2004, has a fair market value-based expense recorded under the provisions of SFAS No. 123-R that is substantially less than the intrinsic value cost that would have been recorded under the provisions of APB Opinion No. 25. Please refer to Note 8, Capital Stock of Item 15 of this Form 10-K for a detailed description of the Share Appreciation Plan and costs associated with our stock compensation plans.
      Also, inherent in expensing stock options and other stock-based compensation under SFAS No. 123-R are several judgments and estimates that must be made. These include determining the underlying valuation methodology for stock compensation awards and the related inputs utilized in each valuation, such as the Company’s expected stock price volatility, expected term of the employee option, expected dividend yield, the expected risk-free interest rate, the underlying stock price and the exercise price of the option. Changes to these assumptions could result in different valuations for individual share awards and will be carefully scrutinized for each material grant. For option valuations, Apache utilizes the Black-Scholes option pricing model, however, the Company does run lattice models to verify that the assumptions used are reasonable. For valuing the Share Appreciation Awards, the Company utilizes a Monte Carlo simulation model developed by a third party.
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Risk
      The major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to our United States and Canadian natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. Monthly oil price realizations, including the impact of fixed-price contracts and hedges, ranged from a low of $42.63 per barrel to a high of $61.31 per barrel during 2005. Average gas price realizations, including the impact of fixed-price contracts and hedges, ranged from a monthly low of $5.16 per Mcf to a monthly high of $8.02 per Mcf during the same period. Based on the Company’s 2005 worldwide oil production levels, a $1.00 per barrel change in the weighted-average realized price of oil would increase or decrease revenues by $85 million. Based on the Company’s 2005 worldwide gas production levels, a $.10 per Mcf change in the weighted-average realized price of gas would increase or decrease revenues by $46 million.
      If oil and gas prices decline significantly, even if only for a short period of time, it is possible that non-cash write-downs of our oil and gas properties could occur under the full-cost accounting method allowed by the Securities Exchange Commission (SEC). Under these rules, we review the carrying value of our proved oil and gas properties each quarter on a country-by-country basis to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization, and deferred income taxes do not exceed the “ceiling.” This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this ceiling, the excess is charged to additional DD&A expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under

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long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows.
      We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. Apache may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from the Company’s price risk management activities are recognized in oil and gas production revenues when the associated production occurs. Apache does not generally hold or issue derivative instruments for trading purposes. As indicated in Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K, the Company entered into several derivative positions in conjunction with our 2003 and 2004 acquisitions. These positions were entered into to preserve our strong financial position in a period of cyclically high oil and gas prices and were designated as cash flow hedges of anticipated production.
      Apache has historically only hedged long-term oil and gas prices related to a portion of its expected production associated with acquisitions. As such, the Company’s use of hedging activity remains at a correspondingly low level. In 2005, financial derivative hedges represented approximately nine percent of the total worldwide natural gas production and six percent of the total worldwide crude oil production. Heading into 2006, hedges in place are entirely related to U.S. production and will represent approximately seven percent of worldwide production for natural gas and crude oil.
      On December 31, 2005, the Company had open natural gas derivative positions with a fair value of $(260) million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $64 million, while a 10 percent decrease in prices would increase the fair value by approximately $63 million. The Company also had open crude oil derivative positions with a fair value of $(148) million. A 10 percent change in oil prices would change the fair value by plus or minus $37 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2005. See Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K for notional volumes and terms associated with the Company’s derivative contracts.
      Apache conducts its risk management activities for its commodities under the controls and governance of its risk management policy. The Risk Management Committee, comprising the Chief Financial Officer, Controller, Treasurer and other key members of Apache’s management, approve and oversee these controls, which have been implemented by designated members of the treasury department. The treasury and accounting departments also provide separate checks and reviews on the results of hedging activities. Controls for our commodity risk management activities include limits on credit, limits on volume, segregation of duties, delegation of authority and a number of other policy and procedural controls.
Governmental Risk
      Apache’s U.S. and international operations have been, and at times in the future may be, affected by political developments and by federal, state and local laws and regulations impacting production levels, taxes, environmental requirements and other assessments including a potential Windfall Profits Tax.
      The Company anticipates that announced changes to the taxation scheme in the North Sea will impact that region’s results. Primarily, the corporate tax rate in the North Sea is expected to increase 10 percent to an effective rate of 50 percent. Once the announcement is ratified, the new rate change will be effective as of January 1, 2006.
Weather and Climate Risk
      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

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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.
      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.
Foreign Currency Risk
      The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts and gas production is sold under fixed-price Australian dollar contracts. Over half the costs incurred for Australian operations are paid in Australian dollars. In Canada, the majority of oil and gas production is sold under Canadian dollar contracts. The majority of the costs incurred are paid in Canadian dollars. The North Sea production is sold under U.S. dollar contracts and the majority of costs incurred are paid in British pounds. In contrast, all oil and gas production in Egypt is sold for U.S. dollars and the majority of the costs incurred are denominated in U.S. dollars. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars and British pounds are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date.
      A 10 percent strengthening of the Australian and Canadian dollars and the British pound as of December 31, 2005 would result in a foreign currency net loss of approximately $128 million. This is primarily driven from foreign currency effects on the Company’s deferred tax liability positions in Canada and Australia. The Company began hedging a portion of its foreign exchange risk associated with lease operating expenditures in 2004. The Company’s treasury department administers this hedging program. The Company did not have any open hedging positions associated with lease operating expenditures as of December 31, 2005. For information on open derivative contracts, please see Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K.
Interest Rate Risk
      As of December 31, 2005, the Company had no interest rate risk exposure since the Company did not have any floating-rate debt.
Forward-Looking Statements and Risk
      Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, capital expenditure projections, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions and other uncertainties, all of which are difficult to predict.
      There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although Apache makes use of futures contracts, swaps, options and fixed-price physical contracts to mitigate risk, fluctuations in oil and gas prices, or a prolonged continuation of low prices may substantially adversely affect the Company’s financial position, results of operations and cash flows.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
      The financial statements and supplementary financial information required to be filed under this item are presented on pages F-1 through F-64 of this Form 10-K, and are incorporated herein by reference.
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
      The financial statements for the fiscal years ended December 31, 2005, 2004 and 2003, included in this report, have been audited by Ernst & Young LLP, independent public auditors, as stated in their audit report appearing herein.
ITEM 9A.  CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
      G. Steven Farris, the Company’s President, Chief Executive Officer and Chief Operating Officer, and Roger B. Plank, the Company’s Executive Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2005, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls were effective, providing effective means to insure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported in a timely manner. We also made no significant changes in internal controls over financial reporting during the quarter ending December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
      We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.
Management’s Report on Internal Control Over Financial Reporting
      The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Report of Management on Internal Control Over Financial Reporting, included on Page F-1 in Item 15 of this report.
      The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated by reference to Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting, included on Page F-3 in Item 15 of this report.
Changes in Internal Control Over Financial Reporting
      There was no change in our internal controls over financial reporting during the period covered by this Annual Report on Form 10-K that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B.  OTHER INFORMATION
      None.
PART III
ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
      The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the

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proxy statement relating to the Company’s 2006 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference.
Code of Business Conduct
      Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), which also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Investor Relations page of the Company’s website at http://www.apachecorp.com. Any stockholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s Corporate Secretary. Changes in and waivers to the Code of Conduct for the Company’s Directors, Chief Executive Officer and certain senior financial officers will be posted on the Company’s website within five business days and maintained for at least 12 months.
ITEM 11.  EXECUTIVE COMPENSATION
      The information set forth under the captions “Summary Compensation Table,” “Option/ SAR Exercises and Year-End Value Table,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements” and “Director Compensation” in the Proxy Statement is incorporated herein by reference.
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
      The information set forth under the captions “Securities Ownership and Principal Holders” and “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
      The information set forth under the caption “Certain Business Relationships and Transactions” in the Proxy Statement is incorporated herein by reference.
ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES
      The information set forth under the caption “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.

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PART IV
ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
      (a) Documents included in this report:
        1. Financial Statements
         
    F-1  
    F-2  
    F-3  
    F-4  
    F-5  
    F-6  
    F-7  
    F-8  
        2. Financial Statement Schedules
     Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.
        3. Exhibits
             
Exhibit        
No.       Description
         
  2 .1     Agreement and Plan of Merger among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996).
  2 .2     Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  2 .3     Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  3 .1     Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  3 .2     Bylaws of Registrant, as amended February 5, 2004 (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  4 .1     Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
  4 .2     Form of Certificate for Registrant’s 5.68% Cumulative Preferred Stock, Series B (incorporated by reference to Exhibit 4.2 to Amendment No. 2 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 001-4300).

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Exhibit        
No.       Description
         
  4 .3     Form of Certificate for Registrant’s Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 001-4300).
  4 .4     Rights Agreement, dated January 31, 1996, between Registrant and Norwest Bank Minnesota, N.A., rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).
  4 .5     Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of December 31, 1996, between Apache Corporation, a Delaware corporation, and Wells Fargo Bank, N.A. (successor to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).
  10 .1     Form of Credit Agreement, dated as of May 12, 2005, among Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, J.P. Morgan Securities Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners, Bank of America, N.A. and Citibank, N.A., as U.S. Co-Syndication Agents, and Calyon New York Branch and Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
  10 .2     Form of Credit Agreement, dated as of May 12, 2005, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, RBC Capital Markets and BMO Nesbitt Burns, as Co-Lead Arrangers and Joint Bookrunners, Royal Bank of Canada, as Canadian Administrative Agent, Bank of Montreal and Union Bank of California, N.A., Canada Branch, as Canadian Co-Syndication Agents, and The Toronto- Dominion Bank and BNP Paribas (Canada), as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
  10 .3     Form of Credit Agreement, dated as of May 12, 2005, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as Co-Lead Arrangers and Joint Bookrunners, Citisecurities Limited, as Australian Administrative Agent, Deutsche Bank AG, Sydney Branch, and JPMorgan Chase Bank, as Australian Co-Syndication Agents, and Bank of America, N.A., Sydney Branch, and UBS AG, Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
  10 .4     Form of Five-Year Credit Agreement, dated May 28, 2004, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank N.A. and Bank of America, N.A., as Co-Syndication Agents, and Barclays Bank PLC and UBS Loan Finance LLC. as Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).

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Exhibit        
No.       Description
         
  10 .5     Form of First Amendment to Combined Credit Agreements, dated May 28, 2004, among Registrant, Apache Energy Limited, Apache Canada Ltd., the Lenders named therein, JP Morgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, and Citibank, N.A., as Global Documentation Agent (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).
  10 .6     Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt, dated April 6, 1981 (incorporated by reference to Exhibit 19(g) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1984, SEC File No. 1-547).
  10 .7     Amendment, dated July 10, 1989, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt incorporated by reference to Exhibit 10(d)(4) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
  10 .8     Farmout Agreement, dated September 13, 1985 and relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10.1 to Phoenix’s Registration Statement on Form S-1, Registration No. 33-1069, filed October 23, 1985).
  10 .9     Amendment, dated March 30, 1989, to Farmout Agreement relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10(d)(5) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
  10 .10     Amendment, dated May 21, 1995, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Repsol Exploration Egypt S.A., Phoenix Resources Company of Egypt and Samsung Corporation (incorporated by reference to Exhibit 10.12 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1997, SEC File No. 001-4300).
  10 .11     Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area in Western Desert of Egypt, between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Phoenix Resources Company of Qarun and Apache Oil Egypt, Inc., dated May 17, 1993 (incorporated by reference to Exhibit 10(b) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1993, SEC File No. 1-547).
  10 .12     Agreement for Amending the Gas Pricing Provisions under the Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area, effective June 16, 1994 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .13     Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10 .14     Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10 .15     Apache Corporation 401(k) Savings Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 001-4300).

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Exhibit        
No.       Description
         
  †10 .16     Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 001-4300).
  *†10 .17     Amendment to Apache Corporation 401(k) Savings Plan, dated December 16, 2005.
  †10 .18     Apache Corporation Money Purchase Retirement Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 001-4300).
  †10 .19     Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 001-4300).
  †10 .20     Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10 .21     Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant’s Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000).
  †10 .22     Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 001-4300).
  †10 .23     Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004 (incorporated by reference to Exhibit 10.24 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  †10 .24     Apache Corporation 1990 Stock Incentive Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
  †10 .25     Apache Corporation 1995 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .26     Apache Corporation 2000 Share Appreciation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .27     Apache Corporation 1996 Performance Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
  †10 .28     Apache Corporation 1998 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).

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Exhibit        
No.       Description
         
  †10 .29     Apache Corporation 2000 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .30     Apache Corporation 2003 Stock Appreciation Rights Plan, dated and effective May 1, 2003 (incorporated by reference to Exhibit 10.31 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  †10 .31     Apache Corporation 2005 Stock Option Plan, dated February 3, 2005 (incorporated by reference to Appendix B to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
  †10 .32     Apache Corporation 2005 Share Appreciation Plan, dated February 3, 2005 (incorporated by reference to Appendix C to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
  †10 .33     1990 Employee Stock Option Plan of The Phoenix Resource Companies, Inc., as amended through September 29, 1995, effective April 9, 1990 (incorporated by reference to Exhibit 10.33 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .34     Apache Corporation Income Continuance Plan, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.30 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, SEC File No. 001-4300).
  †10 .35     Apache Corporation Deferred Delivery Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  *†10 .36     Apache Corporation Executive Restricted Stock Plan, as amended and restated December 14, 2005, effective January 1, 2005.
  †10 .37     Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .38     Apache Corporation Outside Directors’ Retirement Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.8 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .39     Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 5, 2004 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  †10 .40     Amended and Restated Employment Agreement, dated December 5, 1990, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .41     First Amendment, dated April 4, 1996, to Restated Employment Agreement between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .42     Amended and Restated Employment Agreement, dated December 20, 1990, between Registrant and John A. Kocur (incorporated by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1990, SEC File No. 001-4300).
  †10 .43     Employment Agreement, dated June 6, 1988, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1989, SEC File No. 001-4300).

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Exhibit        
No.       Description
         
  †10 .44     Amended and Restated Conditional Stock Grant Agreement, dated September 15, 2005, effective January 1, 2005, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.06 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  10 .45     Amended and Restated Gas Purchase Agreement, effective July 1, 1998, by and among Registrant and MW Petroleum Corporation, as seller, and Producers Energy Marketing, LLC, as buyer (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated June 18, 1998, filed June 23, 1998, SEC File No. 001-4300).
  10 .46     Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  *12 .1     Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.
  14 .1     Code of Business Conduct (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  *21 .1     Subsidiaries of Registrant
  *23 .1     Consent of Ernst & Young LLP
  *23 .2     Consent of Ryder Scott Company L.P., Petroleum Consultants
  *24 .1     Power of Attorney (included as a part of the signature pages to this report)
  *31 .1     Certification of Chief Executive Officer
  *31 .2     Certification of Chief Financial Officer
  *32 .1     Certification of Chief Executive Officer and Chief Financial Officer
 
Filed herewith.
†  Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.
     NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.
      (b) Reports filed on Form 8-K
     The following current reports on Form 8-K were filed by the Company during the fiscal quarter ended December 31, 2005:
 
     ITEM 8.01 — Other Events — dated and filed October 13, 2005
 
     On October 13, 2005, Apache announced that it agreed to sell its interest in the deepwater section of Egypt’s West Mediterranean concession to Amerada Hess and that Apache agreed to purchase interests in eight fields located in the Permian Basin of West Texas and New Mexico from Amerada Hess.

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SIGNATURES
      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  APACHE CORPORATION
 
  /s/ G. STEVEN FARRIS
 
 
  G. Steven Farris
  President, Chief Executive Officer and
  Chief Operating Officer
Dated: March 10, 2006
POWER OF ATTORNEY
      The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, P. Anthony Lannie, Thomas L. Mitchell, and Jeffrey B. King, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.
      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
             
Name   Title   Date
         
 
/s/ G. STEVEN FARRIS

G. Steven Farris
  Director, President, Chief Executive Officer and Chief Operating Officer (Principal Executive Officer)   March 10, 2006
 
/s/ ROGER B. PLANK

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

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

Raymond Plank
  Chairman of the Board   March 10, 2006
 
/s/ FREDERICK M. BOHEN

Frederick M. Bohen
  Director   March 10, 2006
 
/s/ RANDOLPH M. FERLIC

Randolph M. Ferlic
  Director   March 10, 2006
 
/s/ EUGENE C. FIEDOREK

Eugene C. Fiedorek
  Director   March 10, 2006
 
/s/ A. D. FRAZIER, JR.

A. D. Frazier, Jr.
  Director   March 10, 2006


Table of Contents

             
Name   Title   Date
         
 
/s/ PATRICIA ALBJERG GRAHAM

Patricia Albjerg Graham
  Director   March 10, 2006
 
/s/ JOHN A. KOCUR

John A. Kocur
  Director   March 10, 2006
 
/s/ GEORGE D. LAWRENCE

George D. Lawrence
  Director   March 10, 2006
 
/s/ F. H. MERELLI

F. H. Merelli
  Director   March 10, 2006
 
/s/ RODMAN D. PATTON

Rodman D. Patton
  Director   March 10, 2006
 
/s/ CHARLES J. PITMAN

Charles J. Pitman
  Director   March 10, 2006
 
/s/ JAY A. PRECOURT

Jay A. Precourt
  Director   March 10, 2006


Table of Contents

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
      Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
      Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (“Exchange Act”). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s Board of Directors, applicable to all Company Directors and all officers and employees of our Company and subsidiaries.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
      Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2005.
      The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s Board of Directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Apache Corporation and subsidiaries, management’s assessment of the effectiveness of the Company’s internal control over financial reporting and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.
  G. Steven Farris
  President, Chief Executive Officer
  and Chief Operating Officer
 
  Roger B. Plank
  Executive Vice President and Chief Financial Officer
 
  Thomas L. Mitchell
  Vice President and Controller
  (Chief Accounting Officer)
Houston, Texas
March 10, 2006

F-1


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Apache Corporation:
      We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Corporation and subsidiaries as of December 31, 2005 and 2004 and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
      As described in Note 8 to the consolidated financial statements, during 2004, the Company adopted the modified prospective provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123(revised), “Share-Based Payment.” In addition, as described in Notes 1 and 4, effective January 1, 2003, the Company adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations” and the prospective provisions of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.”
      We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2006 expressed an unqualified opinion thereon.
  ERNST & YOUNG LLP
Houston, Texas
March 10, 2006

F-2


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Apache Corporation:
      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apache Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
      In our opinion, management’s assessment that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Apache Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 and our report dated March 10, 2006 expressed an unqualified opinion thereon.
  ERNST & YOUNG LLP
Houston, Texas
March 10, 2006

F-3


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
                             
    For the Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands, except per common share data)
REVENUES AND OTHER:
                       
 
Oil and gas production revenues
  $ 7,457,291     $ 5,308,017     $ 4,198,920  
 
Other
    126,953       24,560       (8,621 )
                   
      7,584,244       5,332,577       4,190,299  
                   
OPERATING EXPENSES:
                       
 
Depreciation, depletion and amortization
    1,415,682       1,222,152       1,073,286  
 
Asset retirement obligation accretion
    53,720       46,060       37,763  
 
International impairments
                12,813  
 
Lease operating costs
    1,040,475       864,378       699,663  
 
Gathering and transportation costs
    100,260       82,261       60,460  
 
Severance and other taxes
    453,258       93,748       121,793  
 
General and administrative
    198,272       173,194       138,524  
 
China litigation provision
          71,216        
 
Financing costs:
                       
   
Interest expense
    175,419       168,090       169,090  
   
Amortization of deferred loan costs
    3,748       2,471       2,163  
   
Capitalized interest
    (56,988 )     (50,748 )     (52,891 )
   
Interest income
    (5,856 )     (3,328 )     (3,290 )
                   
      3,377,990       2,669,494       2,259,374  
                   
PREFERRED INTERESTS OF SUBSIDIARIES
                8,668  
                   
INCOME BEFORE INCOME TAXES
    4,206,254       2,663,083       1,922,257  
 
Provision for income taxes
    1,582,524       993,012       827,004  
                   
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE
    2,623,730       1,670,071       1,095,253  
 
Cumulative effect of change in accounting principle, net of income tax
          (1,317 )     26,632  
                   
NET INCOME
    2,623,730       1,668,754       1,121,885  
 
Preferred stock dividends
    5,680       5,680       5,680  
                   
INCOME ATTRIBUTABLE TO COMMON STOCK
  $ 2,618,050     $ 1,663,074     $ 1,116,205  
                   
BASIC NET INCOME PER COMMON SHARE:
                       
 
Before change in accounting principle
  $ 7.96     $ 5.10     $ 3.38  
 
Cumulative effect of change in accounting principle
                .08  
                   
    $ 7.96     $ 5.10     $ 3.46  
                   
DILUTED NET INCOME PER COMMON SHARE:
                       
 
Before change in accounting principle
  $ 7.84     $ 5.04     $ 3.35  
 
Cumulative effect of change in accounting principle
          (.01 )     .08  
                   
    $ 7.84     $ 5.03     $ 3.43  
                   
The accompanying notes to consolidated financial statements are an integral part of this statement.

F-4


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
                               
    For the Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
 
Net income
  $ 2,623,730     $ 1,668,754     $ 1,121,885  
 
Adjustments to reconcile net income to net cash provided by operating activities:
                       
   
Depreciation, depletion and amortization
    1,415,682       1,222,152       1,073,286  
   
Provision for deferred income taxes
    598,927       444,906       546,357  
   
Asset retirement obligation accretion
    53,720       46,060       37,763  
   
Amortization of deferred loan costs
    3,748       2,471       2,163  
   
International impairments
                12,813  
   
Cumulative effect of change in accounting principle, net of income tax
          1,317       (26,632 )
   
Other
    48,526       39,694       32,923  
 
Changes in operating assets and liabilities, net of effects of acquisitions:
                       
   
(Increase) decrease in receivables
    (504,038 )     (296,383 )     (94,295 )
   
(Increase) decrease in inventories
    11,295       (659 )     (4,216 )
   
(Increase) decrease in drilling advances and other
    (144,154 )     (35,761 )     (19,881 )
   
(Increase) decrease in deferred charges and other
    (26,454 )     (35,328 )     (29,520 )
   
Increase (decrease) in accounts payable
    97,447       182,454       68,176  
   
Increase (decrease) in accrued expenses
    214,491       28,431       11,227  
   
Increase (decrease) in advances from gas purchasers
    (22,108 )     (18,331 )     (16,246 )
   
Increase (decrease) in deferred credits and noncurrent liabilities
    (38,542 )     (18,258 )     (9,903 )
                   
     
NET CASH PROVIDED BY OPERATING ACTIVITIES
    4,332,270       3,231,519       2,705,900  
                   
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
 
Additions to property and equipment
    (3,715,856 )     (2,456,488 )     (1,616,936 )
 
Acquisition of ExxonMobil properties
          (348,173 )      
 
Acquisition of Anadarko properties
          (531,963 )      
 
Acquisition of BP properties
                (1,140,156 )
 
Acquisition of Shell properties
                (203,033 )
 
Proceeds from sales of oil and gas properties
    79,663       4,042       58,944  
 
Other
    (95,649 )     (78,431 )     (57,576 )
                   
     
NET CASH USED IN INVESTING ACTIVITIES
    (3,731,842 )     (3,411,013 )     (2,958,757 )
                   
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
 
Long-term borrowings
    153,368       544,824       1,780,870  
 
Payments on long-term debt
    (549,530 )     (283,400 )     (1,613,362 )
 
Dividends paid
    (117,395 )     (90,369 )     (72,832 )
 
Common stock activity
    18,864       21,595       583,837  
 
Treasury stock activity, net
    6,620       12,472       4,378  
 
Cost of debt and equity transactions
    (861 )     (2,303 )     (5,417 )
 
Repurchase of preferred interests of subsidiaries
                (443,000 )
 
Other
    6,273       54,265        
                   
     
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    (482,661 )     257,084       234,474  
                   
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    117,767       77,590       (18,383 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    111,093       33,503       51,886  
                   
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 228,860     $ 111,093     $ 33,503  
                   
The accompanying notes to consolidated financial statements are an integral part of this statement.

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APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
                     
    December 31,
     
    2005   2004
         
    (In thousands)
ASSETS
CURRENT ASSETS:
               
 
Cash and cash equivalents
  $ 228,860     $ 111,093  
 
Receivables, net of allowance
    1,444,545       939,736  
 
Inventories
    209,670       157,293  
 
Drilling advances
    146,047       82,889  
 
Prepaid assets and other
    132,955       57,771  
             
      2,162,077       1,348,782  
             
PROPERTY AND EQUIPMENT:
               
 
Oil and gas, on the basis of full cost accounting:
               
   
Proved properties
    23,836,789       19,933,041  
   
Unproved properties and properties under development, not being amortized
    795,706       777,690  
 
Gas gathering, transmission and processing facilities
    1,359,477       966,605  
 
Other
    312,970       284,069  
             
      26,304,942       21,961,405  
 
Less: Accumulated depreciation, depletion and amortization
    (9,513,602 )     (8,101,046 )
             
      16,791,340       13,860,359  
             
OTHER ASSETS:
               
 
Goodwill, net
    189,252       189,252  
 
Deferred charges and other
    129,127       104,087  
             
    $ 19,271,796     $ 15,502,480  
             
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
               
 
Accounts payable
  $ 714,598     $ 542,074  
 
Accrued operating expense
    66,609       80,741  
 
Accrued exploration and development
    460,203       341,063  
 
Accrued compensation and benefits
    125,022       83,636  
 
Accrued interest
    32,564       32,575  
 
Accrued income taxes
    120,153       78,042  
 
Current debt
    274        
 
Asset retirement obligation
    93,557        
 
Derivative instruments
    256,115       21,273  
 
Other
    317,469       103,487  
             
      2,186,564       1,282,891  
             
LONG-TERM DEBT
    2,191,954       2,588,390  
             
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
               
 
Income taxes
    2,580,629       2,146,637  
 
Advances from gas purchasers
    68,768       90,876  
 
Asset retirement obligation
    1,362,358       932,004  
 
Derivative instruments
    152,430       31,417  
 
Other
    187,878       225,844  
             
      4,352,063       3,426,778  
             
COMMITMENTS AND CONTINGENCIES (Note 10)
               
SHAREHOLDERS’ EQUITY:
               
 
Preferred stock, no par value, 5,000,000 shares authorized — Series B, 5.68% Cumulative Preferred Stock, 100,000 shares issued and outstanding
    98,387       98,387  
 
Common stock, $0.625 par, 430,000,000 shares authorized, 336,997,053 and 334,912,505 shares issued, respectively
    210,623       209,320  
 
Paid-in capital
    4,170,714       4,106,182  
 
Retained earnings
    6,516,863       4,017,339  
 
Treasury stock, at cost, 6,875,823 and 7,455,002 shares, respectively
    (89,764 )     (97,325 )
 
Accumulated other comprehensive loss
    (365,608 )     (129,482 )
             
      10,541,215       8,204,421  
             
    $ 19,271,796     $ 15,502,480  
             
The accompanying notes to consolidated financial statements are an integral part of this statement.

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
                                                                     
                            Accumulated    
        Series B                   Other   Total
    Comprehensive   Preferred   Common   Paid-In   Retained   Treasury   Comprehensive   Shareholders’
    Income   Stock   Stock   Capital   Earnings   Stock   Income (Loss)   Equity
                                 
    (In thousands)
BALANCE AT DECEMBER 31, 2002
          $ 98,387     $ 194,331     $ 3,427,450     $ 1,427,607     $ (110,559 )   $ (112,936 )   $ 4,924,280  
 
Comprehensive income (loss):
                                                               
   
Net income
  $ 1,121,885                         1,121,885                   1,121,885  
   
Commodity hedges
    (39,007 )                                   (39,007 )     (39,007 )
                                                 
 
Comprehensive income
  $ 1,082,878                                                          
                                                 
 
Cash dividends:
                                                               
   
Preferred
                              (5,680 )                 (5,680 )
   
Common ($.22 per share)
                              (72,200 )                 (72,200 )
 
Five percent common stock dividend
                  581       25,333       (25,914 )                  
 
Common shares issued
                  12,906       579,107                         592,013  
 
Treasury shares issued, net
                        4,109             5,390             9,499  
 
Other
                        2,008                         2,008  
                                                 
BALANCE AT DECEMBER 31, 2003
            98,387       207,818       4,038,007       2,445,698       (105,169 )     (151,943 )     6,532,798  
 
Comprehensive income (loss):
                                                               
   
Net income
  $ 1,668,754                         1,668,754                   1,668,754  
   
Commodity hedges
    22,461                                     22,461       22,461  
                                                 
 
Comprehensive income
  $ 1,691,215                                                          
                                                 
 
Cash dividends:
                                                               
   
Preferred
                              (5,680 )                 (5,680 )
   
Common ($.28 per share)
                              (91,433 )                 (91,433 )
 
Five percent common stock dividend
                                                 
 
Common shares issued
                  1,502       56,660                         58,162  
 
Treasury shares issued, net
                        11,144             7,844             18,988  
 
Other
                        371                         371  
                                                 
BALANCE AT DECEMBER 31, 2004
            98,387       209,320       4,106,182       4,017,339       (97,325 )     (129,482 )     8,204,421  
 
Comprehensive income (loss):
                                                               
   
Net income
  $ 2,623,730                         2,623,730                   2,623,730  
   
Commodity hedges
    (236,126 )                                   (236,126 )     (236,126 )
                                                 
 
Comprehensive income
  $ 2,387,604                                                          
                                                 
 
Cash dividends:
                                                               
   
Preferred
                              (5,680 )                 (5,680 )
   
Common ($.36 per share)
                              (118,526 )                 (118,526 )
 
Common shares issued
                  1,303       57,386                         58,689  
 
Treasury shares issued, net
                        7,003             7,561             14,564  
 
Other
                        143                         143  
                                                 
BALANCE AT DECEMBER 31, 2005
          $ 98,387     $ 210,623     $ 4,170,714     $ 6,516,863     $ (89,764 )   $ (365,608 )   $ 10,541,215  
                                                 
The accompanying notes to consolidated financial statements are an integral part of this statement.

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
      Nature of Operations — Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. The Company’s North American exploration and production activities are divided into two U.S. operating regions (Central and Gulf Coast) and a Canadian region. Approximately 69 percent of the Company’s proved reserves are located in North America. Outside of North America, Apache has exploration and production interests in Egypt, offshore Western Australia, offshore the United Kingdom in the North Sea (North Sea), offshore The People’s Republic of China (China) and in Argentina. In 2003, we ceased operations in Poland.
      The Company’s future financial condition and results of operations will depend upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. The vast majority of the Company’s production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.
      All share and per share information in these financial statements and notes thereto has been restated to reflect the two-for-one stock split in 2003. See Note 8, Capital Stock, for further discussion.
      Principles of Consolidation — The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company consolidates all investments in which the Company, either through direct or indirect ownership, has more than a 50 percent voting interest. In addition, Apache consolidates all variable interest entities where it is the primary beneficiary. The Company’s interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.
      Cash Equivalents — The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
      Allowance for Doubtful Accounts — The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. Many of Apache’s receivables are from joint interest owners on properties which Apache operates. Thus, Apache may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s crude oil and natural gas receivables are collected within two months. However, beginning in 2001, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC). Deteriorating economic conditions in Egypt lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. During 2005, we experienced wide variability in the timing of cash receipts, but our past due balance improved at year-end. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and we have no indication that we will not be able to collect our receivable.
      The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2005 and 2004, the Company had an allowance for doubtful accounts of $22 million.
      Marketable Securities — The Company accounts for investments in debt and equity securities in accordance with Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” Investments in debt securities classified as “held to maturity” are recorded at amortized cost. Investments in debt and equity securities classified as “available for sale” are recorded at fair value with unrealized gains and losses recognized in other comprehensive income, net of

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
income taxes. The Company utilizes the average-cost method in computing realized gains and losses, which are included in Revenues and Other in the consolidated statements of operations.
      Inventories — Inventories consist principally of tubular goods and production equipment, stated at the lower of weighted-average cost or market, and oil produced but not sold, stated at the lower of cost (a combination of production costs and depreciation, depletion and amortization (DD&A) expense) or market.
      Property and Equipment — The Company uses the full-cost method of accounting for its investment in oil and gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Historically, total capitalized internal costs in any given year have not been material to total oil and gas costs capitalized in such year. Apache capitalized $141 million, $107 million and $65 million of these internal costs in 2005, 2004 and 2003, respectively. Costs associated with production and general corporate activities, however, are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. The Company also includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance (see Note 4, Asset Retirement Obligation). Unless a significant portion of the Company’s proved reserve quantities in a particular country are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized.
      Apache computes the DD&A of oil and gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved properties are excluded from the amortizable base until evaluated. The cost of exploratory dry wells is transferred to proved properties and thus subject to amortization immediately upon determination that a well is dry in those countries where proved reserves exist. In countries where the Company has not booked proved reserves, all costs associated with a prospect or play are considered quarterly for impairment upon full evaluation of such prospect or play. This evaluation considers among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. If geological and geophysical (G&G) costs cannot be associated with specific properties, they are included in the amortization base as incurred.
      In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If capitalized costs exceed this limit, the excess is charged as additional DD&A expense. The Company calculates future net cash flows by applying end-of-the-period prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Also, included in the estimated future net cash flows are Canadian provincial tax credits expected to be realized beyond the date at which the legislation, under its provisions, could be repealed. To date, the Canadian provincial governments have not indicated an intention to repeal this legislation. See Note 14, Supplemental Oil and Gas Disclosures (Unaudited) “Future Net Cash Flows” for a discussion on calculation of estimated future net cash flows.
      In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 to provide guidance on how asset retirement obligations should impact the calculation of the ceiling test limitation on the amount of properties that can be capitalized. The guidance states that because asset retirement obligation costs are reflected in the property balance, the future net cash flow calculation should omit the expected abandonment costs to provide for a comparable basis. Apache previously included abandonment costs in its future net cash flow calculation, but adjusted the capitalized amounts by the accrued abandonment obligation. The Company’s adoption of SAB No. 106 did not have a material impact on financial results.

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.
      Unproved properties are assessed quarterly for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to proved properties. For international operations where a reserve base has not yet been established, the impairment is charged to earnings. Apache began impairing its unproved property costs in Poland in 2001, impairing $20 million ($12 million after tax) in 2002 and the remaining $13 million ($8 million after tax) in 2003.
      Buildings, equipment and gas gathering, transmission and processing facilities are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to 20 years. Accumulated depreciation for these assets totaled $467 million and $380 million at December 31, 2005 and 2004, respectively.
      Goodwill — Goodwill totaled $189 million at December 31, 2005 and 2004, representing the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in the Fletcher Challenge Energy (Fletcher) and Repsol YPF (Repsol) 2001 acquisitions. Approximately $103 million and $86 million of goodwill remain in Canada and Egypt, respectively. Apache deemed the geographic areas to be the reporting unit. Goodwill of each reporting unit is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that would reduce the fair value of the reporting unit below its carrying amount. No impairment of goodwill was recognized during 2005, 2004 and 2003.
      Accounts Payable — Included in accounts payable at December 31, 2005 and 2004, are liabilities of approximately $125 million and $116 million, respectively, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts.
      Revenue Recognition — Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.
      Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to Apache will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Company’s recorded liability is reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures.
      The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, usually up to 40 percent, is available to the contractor partners to recover all operating and capital costs. The balance of the production is split among the contractor partners and EGPC on a contractually defined basis.
      Apache began marketing its U.S. natural gas production in July 2003. As the Company’s production fluctuates because of operational issues, it is occasionally necessary for the Company to purchase gas (“third party gas”) to fulfill its sales obligations and commitments. Both the costs and sales proceeds of this third-party gas are reported on a net basis in oil and gas production revenues. The costs of third-party gas netted

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
against the related sales proceeds totaled $158 million, $107 million and $41 million, for 2005, 2004 and 2003, respectively.
      Derivative Instruments and Hedging Activities — Apache periodically enters into derivative contracts to manage its exposure to foreign currency risk and commodity price risk. These derivative contracts, which are generally placed with major financial institutions that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.
      Apache accounts for its derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 establishes accounting and reporting standards requiring that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). SFAS No. 133 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from the Company’s oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. Realized gains and losses on foreign currency cash flow hedges are generally recognized in lease operating expense when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period income as “other.” If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting under SFAS No. 133 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported under Revenues and Other in the statement of consolidated operations.
      Income Taxes — We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).
      Earnings from Apache’s international operations are permanently reinvested; therefore, the Company does not recognize U.S. deferred taxes on the unremitted earnings of its international subsidiaries. If it becomes apparent that some or all of the unremitted earnings will be remitted, the Company would then reflect taxes on those earnings.
      Foreign Currency Translation — The U.S. dollar has been determined to be the functional currency for each of Apache’s international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment, and financing arrangements in each country.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Company accounts for foreign currency gains and losses in accordance with SFAS No. 52 “Foreign Currency Translation.” Foreign currency translation gains and losses related to deferred taxes are recorded as a component of its provision for income taxes, while all other foreign currency gains and losses are reflected in Revenues and Other. The Company recorded additional deferred tax expense of $13 million, $58 million and $172 million in 2005, 2004 and 2003, respectively (see Note 6, Income Taxes). Other foreign currency gains and losses in Revenues and Other netted to a gain of $11 million in 2005, and losses of $5 million and $2 million in 2004 and 2003, respectively.
      Prior to October 1, 2002, the Company’s Canadian subsidiaries’ functional currency was the Canadian dollar. Translation adjustments resulting from translating the Canadian subsidiaries’ financial statements into U.S. dollar equivalents were reported separately and accumulated in other comprehensive income. Currency translation adjustment held in other comprehensive income on the balance sheet will remain there indefinitely unless there is a substantially complete liquidation of the Company’s Canadian operations.
      Insurance Coverage — The Company carries property damage insurance of $250 million per insurable event subject to a $7.5 million deductible per event. The policy is prorated down if total claims received by the insurer for a single event exceed $1 billion. As of December 31, 2005, the Company was advised by its insurance carrier that total claims for Hurricane Katrina would exceed the $1 billion limit, reducing the Company’s ultimate recoveries by approximately 50 percent, or $125 million. The Company was also advised that as of December 31, 2005, total estimated claims for Hurricane Rita would exceed the $1 billion limit, reducing the Company’s claims for Rita by approximately 20 percent. Based on current assessments by OIL, the Company expects to recover from OIL between $225 million and $250 million for both storms combined. The Company also carries another $100 million of casualty insurance under a separate commercial policy. The Company expects to recover the full $100 million on the commercial policy.
      The Company also carries business interruption insurance to cover deferred and lost oil and natural gas production revenues. The business interruption insurance begins 60 days after the occurrence of an insurable event, subject to a daily limit of $750,000 per event and an aggregate limit of $150 million. Coverage is based on current market prices and began October 28, 2005 for shut-in production caused by Hurricane Katrina and November 22, 2005 for Hurricane Rita. The Company accrued claims in 2005 totaling $79 million, with the remainder of the aggregate $150 million limit available for 2006. Proceeds received from the Business Interruption Insurance are reflected in “Other” under “Revenues and Other” on the “Statement of Consolidated Operations” and are included in cash flows from operating activities.
      Net Income Per Common Share — The Company’s basic earnings per share (EPS) amounts have been computed based on the average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury stock method, that could occur if options were exercised and if restricted stock were fully vested.
      Diluted EPS also includes the impact of unvested Share Appreciation Plans. For awards in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury stock method. For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in the diluted EPS is based on the number of shares, if any, using the treasury stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan.
      Stock-Based Compensation — On December 31, 2005, the Company had several stock-based employee compensation plans, which include the Stock Option Plans, the Performance Plan, the Share Appreciation Plans and restricted stock. These plans are defined and described more fully in Note 8, Capital Stock. The Company accounts for these plans under the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended and revised. Stock compensation awards granted are valued on the date of grant and are expensed using a straight-line basis over the required service period.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      During the fourth quarter of 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123-R, a revision to SFAS No. 123, which requires all companies to expense stock-based compensation. The rule is effective for the first fiscal year that begins after June 15, 2005. Apache early adopted this statement in 2004 electing to transition under the “Modified Retrospective Approach” as allowed under SFAS No. 123-R. Under this approach, the Company is required to expense all options and stock-based compensation that vested in the year of adoption based on the fair value of the stock compensation determined at the date of grant. Stock vesting in years prior to 2004 was expensed in accordance with the rules applied by the Company during such period. Had the Company not early adopted SFAS No. 123-R, net income would have been lower by $89 million ($56 million after tax), or $.17 per share on both a basic and diluted per share basis. Normally, net income would be negatively impacted by adopting SFAS No. 123-R. However, the Company’s Share Appreciation Plan, which certain awards were triggered in 2004, has a fair-market-value-based expense recorded under the provisions of SFAS No. 123-R that is substantially less than the intrinsic-value base cost of approximately $175 million that would have been recorded under the old APB No. 25 accounting.
      In addition to the expensing provisions discussed above, SFAS No. 123-R requires the Company to begin estimating expected future forfeitures under each stock compensation plan and to start valuing the Company’s liability-based compensation plan (Stock Appreciation Rights) under a fair value approach instead of the previously applied intrinsic valuation. The effects of changing the forfeiture estimates on existing stock plans and the valuation methodology for the Company’s liability plans resulted in Apache recording a Cumulative Effect of Change in Accounting Principle of $2.1 million ($1.3 million after tax). SFAS No. 123-R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow rather than as an operating cash flow as historically reported. The Company classified $27 million and $32 million as financing cash inflows in 2005 and 2004, respectively, that would have been classified as operating cash inflows had the Company not adopted the Statement.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      For 2003, the Company applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock Based Compensation”, as amended by SFAS No. 148 prospectively to all awards granted, modified, or settled after January 1, 2003. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on income attributable to common stock and earnings per share for the year 2003 had the fair-value based provisions of SFAS No. 123-R been applied to all stock-based compensation.
             
    For the Year
    Ended
    December 31,
    2003
     
    (In thousands)
Income attributable to Common Stock, as reported
  $ 1,116,205  
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects
    2,644  
Deduct: Total stock-based employee compensation expense determined under fair-value based method for all stock-based awards (see Note 8), net of related tax effects
    (15,311 )
       
Pro forma Income Attributable to Common Stock
  $ 1,103,538  
       
Net Income per Common Share:
       
 
Basic:
       
   
As reported
  $ 3.46  
   
Pro forma
    3.42  
 
Diluted:
       
   
As reported
  $ 3.43  
   
Pro forma
    3.39  
      The stock appreciation rights, described in Note 8, Capital Stock, are not included in the table above because it is a cash-based liability plan already reflected in net income attributable to common stock. Similar to cash-based salaries and benefits, stock-based compensation directly attributable to acquisition, exploration and development activities are capitalized.
      Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the U.S., requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Apache evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. See Note 14, Supplemental Oil and Gas Disclosure (Unaudited).
      Treasury Stock — The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      Impact of Recently Issued Accounting Standards — On December 21, 2004, the FASB issued Staff Position 109-1 (FSP No. 109-1), Application of FASB Statement No. 109 (SFAS No. 109) “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the Act). FSP No. 109-1 clarifies guidance that applies to the new tax deduction for qualified domestic production activities. When fully phased-in, the deduction will be up to nine percent of the lesser of “qualified production activities income” or taxable income. FSP No. 109-1 clarifies that the deduction should be accounted for as a special deduction under SFAS No. 109 and will reduce tax expense in the period or periods that the amounts are deductible on the tax return because the deduction is contingent on performing activities identified in the Act. As a result, companies qualifying for the special deduction will not have a one-time adjustment to deferred tax assets and liabilities in the period the Act is enacted. Tax benefits resulting from the new deduction are effective for the Company’s fiscal year ending December 31, 2005. The adoption of FSP No. 109-1 did not have a material impact on the Company’s financial statements.
      In March 2005, the FASB issued FASB Interpretation Number 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations”. The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005 and application of the interpretation did not change how abandonment obligations are currently calculated by the Company.
      In June 2005, the FASB ratified the consensus in Emerging Issue Task Force (EITF) Issue Number 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights”. EITF Issue Number 04-5 states that the general partner in a limited partnership is presumed to control the partnership and must consolidate the entity on its financial statements. The presumption of control and consolidation requirement may be overcome if the limited partners have substantive participating rights or have the ability to effectively liquidate the partnership. Application of this statement did not impact the Company’s consolidated financial statements.
      In September 2005, the EITF reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” concluding that purchases and sales of inventory with the same party in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. Apache presents such purchase and sale activities related to its marketing activities on a net basis in its Statement of Consolidated Operations. The consensus reached on EITF Issue No. 04-13 did not have any impact on the Company’s consolidated financial statements.
      Reclassifications — Certain other prior period amounts have been reclassified to conform with current year presentations.
2.  ACQUISITIONS AND DIVESTITURES
Subsequent Acquisitions
      Amerada Hess
      On January 5, 2006 the Company completed its purchase of Amerada Hess’s interest in eight fields located in the Permian Basin of West Texas and New Mexico for $269 million. Apache estimates that these fields had proved reserves of 27 million barrels of liquid hydrocarbons and 27 billion cubic feet of natural gas as of year-end 2005. The Company had previously announced on October 13, 2005 that it had agreed to purchase Amerada Hess’s interest for $404 million. The number of properties involved and price were reduced as a result of third parties exercising their preferential rights.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      On January 6, 2006 the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. Apache first announced this transaction on October 13, 2005. Apache did not have any oil and gas reserves recorded for these properties at year-end 2005.
Pioneer Natural Resources
      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.
2005 Acquisitions
      During 2005, Apache completed numerous minor acquisitions totaling $39 million. These acquisitions added approximately 7.8 MMboe to the Company’s proved reserves.
      On May 5, 2005, Apache signed a farm-in agreement with Exxon Mobil Corporation (ExxonMobil) covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in the 2004 farm-in agreement with ExxonMobil.
2004 Acquisitions
ExxonMobil
      During the third quarter of 2004, Apache entered into separate arrangements with Exxon Mobil Corporation and its affiliates (ExxonMobil) that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and the Gulf of Mexico-Outer Continental Shelf. Apache’s participation included cash payments of approximately $347 million, subject to normal post closing adjustments. The following details these transactions:
      ExxonMobil — Western Canada In August 2004, Apache signed a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta. Under the agreement, Apache has the right to earn acreage sections by drilling an initial well on each such section. By drilling at least 250 wells during the initial two year earning period under the agreement, Apache will receive a one-year extension in which to earn additional sections. As to any sections earned by Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. Under certain circumstances, ExxonMobil has the right to convert its retained 35 percent working interest into a 12.5 percent overriding royalty. In addition, during the term of this agreement, Apache is required to carry ExxonMobil’s retained working interest with respect to certain drilling, capping, completion, equipping and tie-in costs associated with wells drilled on leasehold acreage.
      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.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The partnership is subject to the provisions of FASB Interpretation 46 “variable interest entities” (FIN 46). Apache has concluded that it is not the primary beneficiary of the partnership as defined in that interpretation and will proportionately consolidate its partnership portion of the oil and gas properties. Apache’s maximum exposure to loss as a result of its involvement with the partnership was $55 million at December 31, 2005. Under the partnership agreement, the Company’s subsidiaries are also subject to environmental and legal claims that could arise in the ordinary course of business. Apache will operate the oil and gas properties under contract for the partnership.
      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.
Anadarko Petroleum
      On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko Petroleum Corporation’s (Anadarko) Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields with approximately 70 percent of the production.
      Prior to Apache’s purchase from Anadarko, Morgan Stanley Capital Group, Inc. (Morgan Stanley) paid Anadarko $646 million to acquire an overriding royalty interest in these properties. Anadarko’s sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP), the obligations of which Apache assumed along with its purchase. Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas production (20 MMboe) over four years beginning in October 2004. The VPP represents a non-operating interest that is free of costs incurred for operations and production. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP, but Morgan Stanley may look only to the acquired properties for delivery of the scheduled volumes. The VPP is scheduled to terminate on August 31, 2008, but may be extended if all scheduled VPP volumes have not been delivered to Morgan Stanley and the properties are still producing. The VPP includes restrictions on the Company’s ability to sell the properties subject to the VPP or resign as operator of VPP properties it currently operates. Upon termination of the VPP, all rights, titles and interests revert back to Apache. The Company does not record the reserves and production volumes attributable to the VPP.
      The $537 million purchase price agreed to in the definitive agreement was subsequently adjusted for the exercise of preferential rights by third parties and other normal post-closing adjustments. After adjusting for these items, Apache paid $532 million for the properties and recorded estimated proved reserves of 60 million barrels of oil equivalent (boe), of which 50 percent was natural gas. In addition, an $84 million liability for the future cost to produce and deliver the VPP volumes was recorded by the Company. This liability will be settled through a reduction of lease operating expenses as the volumes are produced and delivered to Morgan Stanley. Apache also recorded abandonment obligations for the properties of approximately $134 million and other obligations assumed from Anadarko in the amount of $27 million. Apache allocated $122 million of the

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
purchase price to unproved property. The purchase price was funded by borrowings under the Company’s lines of credit and commercial paper program.
      In 2004, the Company also completed other acquisitions for $73 million. These acquisitions added approximately 11 MMboe to the Company’s proved reserves.
2003 Acquisitions
      On January 13, 2003, Apache announced that it had entered into agreements to purchase producing properties in the North Sea and Gulf of Mexico from subsidiaries of BP p.l.c. (BP) for $1.3 billion, with $670 million allocated to the Gulf of Mexico properties and $630 million allocated to properties in the North Sea. The properties included estimated proved reserves of 233.2 million barrels of oil equivalent (MMboe), 147.6 MMboe located in the North Sea with the balance in the Gulf of Mexico. Both purchase agreements were effective as of January 1, 2003. The exercise of preferential rights by third parties reduced the purchase price by $73 million and estimated reserves by 9.6 MMboe.
      On July 3, 2003, Apache announced that it had completed the acquisition of producing properties on the outer Continental Shelf of the Gulf of Mexico from Shell Exploration and Production Company (Shell) for $200 million, subject to normal post-closing adjustments, including preferential rights. The acquisition included interests in 26 fields and interest in two onshore gas plants, and was effective July 1, 2003. Apache became operator of 15 of the fields with 91 percent of the production. At the time of the acquisition, Apache recorded estimated proved recoverable reserves of 124.6 billion cubic feet (Bcf) of natural gas and 6.6 million barrels of oil. Apache may be required to issue a letter of credit to BP to cover the present value of related asset retirement obligations if the rating of the Company’s senior unsecured debt is lowered by both Moody’s and Standard and Poor’s from its current ratings of A3 and A-, respectively. Should this occur, the letter of credit amount would be 127 million British pounds.
      Prior to Apache’s transaction with Shell, Morgan Stanley paid Shell $300 million to acquire an overriding royalty interest in a portion of the reserves to be produced and delivered under a VPP agreement. Under the terms of the VPP obligation which Apache assumed, Morgan Stanley is to receive a total of 11.4 MMboe of production from the properties over the period from August 2003 through October 2007. Morgan Stanley may receive up to 90 percent of production associated with Apache’s interest, but may look only to the properties for delivery of the scheduled volumes. The VPP may be extended beyond October 2007 if all scheduled VPP volumes have not been delivered to Morgan Stanley and the acquired properties are still producing. The VPP represents a non-operating interest that is free of all costs related to operations and production. As a result of this VPP obligation, Apache assumed and recorded a $60 million liability for the future cost to produce and deliver volumes subject to the VPP. This liability is being settled through a reduction of lease operating expenses as the volumes are produced and delivered to Morgan Stanley. Apache does not record the reserves or production attributable to the VPP volumes. Apache’s purchase price was funded by borrowings under the Company’s lines of credit and commercial paper program.
      In 2003, the Company also completed other acquisitions for $126 million. These acquisitions added approximately 28 MMboe to the Company’s proved reserves.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Acquisition Pro Forma
      The following unaudited pro forma information shows the effect on the Company’s consolidated results of operations as if the acquisition from BP occurred on January 1, 2003. The pro forma information includes numerous assumptions, and is not necessarily indicative of future results of operations:
                   
    For the Year Ended
    December 31, 2003
     
    As Reported   Pro Forma
(Unaudited)        
    (In thousands, except per
    common share data)
Revenues and other
  $ 4,190,229     $ 4,428,261  
Net income
    1,121,885       1,195,082  
Preferred stock dividends
    5,680       5,680  
Income attributable to common stock
    1,116,205       1,189,402  
Net income per common share:
               
 
Basic
  $ 3.46     $ 3.68  
 
Diluted
    3.43       3.64  
Average common shares outstanding(1)
    322,498       323,583  
(1)  Pro forma shares assume the issuance of 19.8 million common shares as of January 1, 2003.
 
      Each transaction described above has been accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Apache since the date of acquisition.
Divestitures
      During 2005, Apache also sold marginal properties containing 11.8 MMboe of proved reserves, for $80 million. Apache used the sales proceeds to reduce bank debt.
      During 2004, Apache sold marginal properties containing .5 MMboe of proved reserves, for $4 million. Apache used the sales proceeds to reduce bank debt.
      During 2003, Apache sold marginal properties containing 6.9 MMboe of proved reserves, for $59 million. Apache used the sales proceeds to reduce bank debt.
3.  HEDGING AND DERIVATIVE INSTRUMENTS
      Apache uses a variety of strategies to manage its exposure to fluctuations in crude oil and natural gas commodity prices. As established by the Company’s hedging policy, Apache primarily enters into cash flow hedges in connection with selected acquisitions to protect against commodity price volatility. The success of these acquisitions is significantly influenced by Apache’s ability to achieve targeted production at forecasted prices. These hedges effectively reduce price risk on a portion of the production from the acquisitions.
      Apache entered into, and designated as cash flow hedges, various fixed-price swaps, option collars and puts in conjunction with the Anadarko and ExxonMobil property acquisitions. These positions were entered into in accordance with the Company’s hedging policy and involved counterparties which were rated A+ or

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
better. As of December 31, 2005, the outstanding positions of our natural gas and crude oil cash flow hedges were as follows:
                             
        Total   Weighted   Fair Value
        Volumes   Average   Asset/
Production Period   Instrument Type   (MMBtu/Bbl)   Floor/Ceiling   (Liability)
                 
                (In thousands)
2006
  Gas Collars     32,850,000       $5.50/ 6.66     $ (133,936 )
    Gas Fixed-Price Swap     4,404,000       5.87       (21,232 )
    Oil Collars     4,307,000       32.07/ 40.66       (95,583 )
    Oil Fixed-Price Swap     224,000       38.50       (5,365 )
    Oil Put Option     1,533,000       28.00       16  
2007
  Gas Collars     24,570,000       5.25/ 6.20       (96,917 )
    Gas Fixed-Price Swap     1,761,000       5.57       (7,997 )
    Oil Collars     1,911,000       33.00/ 39.25       (45,533 )
    Oil Fixed-Price Swap     78,000       36.89       (1,982 )
      The natural gas and crude oil positions shown in the above table are based on the NYMEX index and have been valued using actively quoted prices and quotes obtained from the counterparties to the derivative agreements. The above prices represent a weighted average of several contracts entered into and are on a per MMBtu or per barrel basis for gas and oil derivatives, respectively.
      Apache entered into a separate crude oil physical sales contract with BP in February 2003, which ended December 31, 2004. Under the terms of the agreement, Apache physically delivered 22.5 million barrels of crude oil at an average fixed Brent index price of $23.38 per barrel. The contract was designated as a normal purchase and sale under SFAS No. 133 and, therefore, the Company accounted for the contract under the accrual method.
      Apache hedged a portion of its 2005 foreign currency exchange risk associated with its forecasted Canadian, Australian and North Sea lease operating expenditures by entering into forward purchase contracts. The Company purchased a total of $144 million Canadian dollars at an average exchange rate of .840, $22 million Australian dollars at an average exchange rate of .763 and 42 million British pounds at an average exchange rate of 1.853. The forward contracts matured from January through December 2005 and caused the Company to recognize $3 million of increased lease operating expense during the year.
      A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders’ equity related to Apache’s commodity and foreign currency derivative activities is presented in the table below:
                 
    Gross   After Tax
         
    (In thousands)
Unrealized loss on derivatives at December 31, 2004
  $ (33,113 )   $ (20,732 )
Net losses realized into earnings
    135,996       87,644  
Net change in derivative fair value
    (501,112 )     (323,770 )
             
Unrealized loss on derivatives at December 31, 2005
  $ (398,229 )   $ (256,858 )
             
      Differences between the fair values and the unrealized loss on derivatives before income taxes recognized in accumulated other comprehensive income (loss) are primarily related to premiums, recognition of unrealized gains and losses on certain derivatives that did not qualify for hedge accounting and hedge ineffectiveness. Based on applicable market prices as of year-end 2005, the Company recorded an unrealized loss in other comprehensive income (loss) of $398 million ($257 million after tax), representing oil and gas derivative hedges. Any loss will be realized in future earnings contemporaneously with the related sales of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
natural gas and crude oil production applicable to specific hedges. Of the $398 million unrealized loss on derivatives at December 31, 2005, approximately $247 million ($160 million after tax) applies to the next 12 months. However, these amounts are likely to vary materially as a result of changes in market conditions. The contracts designated as hedges qualified and continue to qualify for hedge accounting in accordance with SFAS No. 133, as amended.
4.  ASSET RETIREMENT OBLIGATION
      In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company’s credit-adjusted risk-free interest rate.
      The Company adopted SFAS No. 143 on January 1, 2003, and recorded an increase to net oil and gas properties of $410 million and associated liabilities of $369 million. These amounts reflect the ARO of the Company had the provisions of SFAS No. 143 been applied since inception and resulted in a non-cash cumulative effect increase to earnings of $27 million ($41 million pre-tax).
      Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
      The following table is a reconciliation of the asset retirement obligation liability:
                 
    2005   2004
         
    (In thousands)
Asset retirement obligation at beginning of period
  $ 932,004     $ 739,775  
Liabilities incurred
    87,794       199,505  
Liabilities settled
    (84,445 )     (47,784 )
Accretion expense
    53,720       46,060  
Revisions in estimated liabilities
    466,842       (5,552 )
             
Asset retirement obligation at December 31, 
  $ 1,455,915     $ 932,004  
             
      In accordance with SFAS No. 143, the Company records an abandonment liability associated with its oil and gas wells, facilities and platforms when those assets are placed in service, which for 2005 and 2004 is reflected above in liabilities incurred. Liabilities settled relate to individual properties plugged and abandoned or sold during the period. Revisions to the estimated liability normally result from annual reassessments of the expected cash outflows and assumptions inherent in the ARO calculation. However, during the third quarter of 2005, nine of the Company’s offshore platforms in the Gulf of Mexico were toppled, two platforms were severely damaged and approximately 12 non-operated structures were also destroyed as a result of Hurricanes Katrina and Rita. Upon completing our assessment of hurricane related costs during the fourth quarter, the Company increased the discounted ARO liability on the affected properties to $492 million. The revision reflects increased costs and acceleration in expected timing to abandon these platforms. Approximately $94 million has been classified as a current liability.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
5.  DEBT
Long-Term Debt
                   
    December 31,
     
    2005   2004
         
    (In thousands)
Apache:
               
 
Money market lines of credit
  $     $ 4,000  
 
Commercial paper
          392,000  
 
6.25-percent debentures due 2012, net of discount
    398,006       397,758  
 
7-percent notes due 2018, net of discount
    148,639       148,570  
 
7.625-percent notes due 2019, net of discount
    149,222       149,190  
 
7.7-percent notes due 2026, net of discount
    99,678       99,671  
 
7.95-percent notes due 2026, net of discount
    178,683       178,659  
 
7.375-percent debentures due 2047, net of discount
    148,028       148,021  
 
7.625-percent debentures due 2096, net of discount
    149,175       149,175  
             
      1,271,431       1,667,044  
             
Subsidiary and other obligations:
               
 
Fletcher notes
    4,526       5,356  
 
Apache Finance Australia 6.5-percent notes due 2007, net of discount
    169,678       169,530  
 
Apache Finance Australia 7-percent notes due 2009, net of discount
    99,733       99,662  
 
Apache Finance Canada 4.375-percent notes due 2015, net of discount
    349,732       349,709  
 
Apache Finance Canada 7.75-percent notes due 2029, net of discount
    297,128       297,089  
             
      920,797       921,346  
             
Total debt
    2,192,228       2,588,390  
Less: current maturities
    (274 )      
             
Long-term debt
  $ 2,191,954     $ 2,588,390  
             
      On May 12, 2005, the Company entered into a new $450 million revolving bank credit facility for the U.S., a $150 million revolving bank credit facility for Australia and a $150 million revolving bank credit facility for Canada. These new facilities replaced the Company’s existing credit facilities in the same amounts which were scheduled to mature in June 2007. These new facilities are scheduled to mature on May 12, 2010. There were no changes to the Company’s $750 million U.S. credit facility which matures in May 2009.
      As detailed above, the Company currently has $1.5 billion of syndicated bank credit facilities. The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics liens. The Company may incur liens on assets located in the U.S., Canada and Australia of up to five percent of the Company’s consolidated assets, which approximated $964 million as of December 31, 2005. There are no restrictions on incurring liens in countries other than the U.S., Canada and Australia. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group.
      There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes (MAC clauses). The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S., Canadian and Australian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2005. The Company’s debt-to-capitalization ratio as of December 31, 2005 was 17 percent.
      At the Company’s option, the interest rate for the facilities is based on (i) the greater of (a) The JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent or (ii) the London Interbank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $750 million and the $450 million credit facilities (U.S. credit facilities) also allow the Company to borrow under competitive auctions.
      At December 31, 2005, the margin over LIBOR for committed loans was .27 percent on the $750 million facility and .23 percent on the other three facilities. If the total amount of the loans borrowed under the $750 million facility equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of .08 percent on the total amount of the $750 million facility and .07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating. The U.S. credit facilities are used to support Apache’s commercial paper program. The available borrowing capacity under the credit facilities at December 31, 2005 was $1.5 billion.
      The Company has certain uncommitted money market lines of credit which are used from time to time for working capital purposes, of which no balance was outstanding as of December 31, 2005.
      The Company has a $1.2 billion commercial paper program which enables Apache to borrow funds for up to 270 days at competitive interest rates. There was no commercial paper outstanding as of December 31, 2005. The commercial paper balance at December 31, 2004 was classified as long-term debt in the accompanying consolidated balance sheet as the Company had the ability and intent to refinance such amount on a long-term basis through either the rollover of commercial paper or available borrowing capacity under the U.S. credit facilities. The weighted-average interest rate for commercial paper was 3.03 percent in 2005 and 1.79 percent in 2004.
      On May 15, 2003, Apache Finance Canada Corporation (Apache Finance Canada) issued $350 million of 4.375 percent, 12-year, senior unsecured notes in a private placement. On March 4, 2004, the Company completed an exchange offer with the holders of the notes, issuing publicly traded, registered notes of the same principal amount and with the same interest rates, payment terms and maturity. The notes are irrevocably and unconditionally guaranteed by Apache and are redeemable, as a whole or in part, at Apache Finance Canada’s option, subject to a make-whole premium. Interest is payable semi-annually on May 15 and November 15 of each year commencing on November 15, 2003. The proceeds of the original note offering were used to reduce bank debt and outstanding commercial paper and for general corporate purposes.
      The Company does not have the right to redeem any of its notes or debentures (other than the Apache Corporation 6.25-percent notes due April 15, 2012, the Apache Finance Australia 6.5-percent notes due 2007 and the Apache Finance Canada 4.375-percent notes due 2015) prior to maturity. Under certain conditions, the Company has the right to advance maturity on the 7.7-percent notes, 7.95-percent notes, 7.375-percent debentures and 7.625-percent debentures.
      The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache and, in the case of Apache Finance Australia, by Apache North America, Inc., an indirect wholly-owned subsidiary of the Company. Under certain conditions related to changes in relevant tax laws, Apache Finance Australia and Apache Finance Canada have the right to redeem the notes prior to maturity. The Apache Finance Australia 6.5-percent notes and the Apache Finance Canada 4.375-percent notes may be redeemed at the Company’s option subject to a make-whole premium (see Note 16. Supplemental Guarantor Information).

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The $12 million of discounts on the Company’s debt as of December 31, 2005, is being amortized over the life of the debt issuances as additional interest expense.
      As of December 31, 2005 and 2004, the Company had approximately $18 million and $21 million, respectively, of unamortized deferred loan costs associated with its various debt obligations. These costs are included in deferred charges and other in the accompanying consolidated balance sheet and are being amortized to expense over the life of the related debt.
      The indentures for the notes described above place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens and its ability to enter into certain sale and leaseback transactions. Upon certain change in control, all of these debt instruments would be subject to mandatory repurchase, at the option of the holders.
Aggregate Maturities of Debt
         
    (In thousands)
2006
  $ 274  
2007
    172,678  
2008
    353  
2009
    99,733  
2010
     
Thereafter
    1,919,190  
       
    $ 2,192,228  
       
      The Company made cash payments for interest, net of amounts capitalized, of $107 million for the years ended December 31, 2005 and 2004, and $96 million for the year ended December 31, 2003.
6.  INCOME TAXES
      Income before income taxes is composed of the following:
                           
    For the Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
United States
  $ 1,502,467     $ 1,120,906     $ 918,432  
Foreign
    2,703,787       1,542,177       1,003,825  
                   
 
Total
  $ 4,206,254     $ 2,663,083     $ 1,922,257  
                   
      The total provision for income taxes consists of the following:
                           
    For the Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
Current taxes:
                       
 
Federal
  $ 291,604     $ 145,164     $ 37,472  
 
State
    (2,424 )     4,330       2,296  
 
Foreign
    694,417       398,612       240,879  
Deferred taxes
    598,927       444,906       546,357  
                   
 
Total
  $ 1,582,524     $ 993,012     $ 827,004  
                   

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      A reconciliation of the U.S. federal statutory income tax amounts to the effective amounts is shown below:
                         
    For the Year Ended December 31,
     
    2005   2004   2003
             
    (In thousands)
Statutory income tax
  $ 1,472,189     $ 932,079     $ 672,790  
State income tax, less federal benefit
    12,579       28,023       22,961  
Taxes related to foreign operations
    147,059       86,263       49,657  
Realized tax basis in investment
    (9,282 )     (16,923 )     (23,234 )
Canadian tax rate reduction
    (28,611 )     (31,350 )     (71,340 )
Current and deferred taxes related to currency fluctuations
    13,332       58,049       171,930  
Domestic benefit from tax law change
    (9,853 )            
Australian consolidation benefit from tax law change
    (9,649 )     (50,713 )      
Benefit of previously unrecognized Canadian losses
          (18,226 )      
All other, net
    (5,240 )     5,810       4,240  
                   
    $ 1,582,524     $ 993,012     $ 827,004  
                   
      The net deferred tax liability is comprised of the following:
                     
    December 31,
     
    2005   2004
         
    (In thousands)
Deferred tax assets:
               
 
Deferred income
  $ (5,968 )   $ (1,473 )
 
State net operating loss carryforwards
    (13,439 )     (9,500 )
 
Foreign net operating loss carryforwards
    (6,154 )     (224,137 )
 
Accrued expenses and liabilities
    (5,773 )     (5,465 )
 
Other
    (9,492 )     (830 )
             
   
Total deferred tax assets
    (40,826 )     (241,405 )
 
Valuation allowance
           
             
   
Net deferred tax assets
    (40,826 )     (241,405 )
             
Deferred tax liabilities:
               
 
Depreciation, depletion and amortization
    2,621,455       2,388,042  
             
   
Total deferred tax liabilities
    2,621,455       2,388,042  
             
Net deferred income tax liability
  $ 2,580,629     $ 2,146,637  
             
      The Company has not recorded deferred income taxes on the undistributed earnings of its foreign subsidiaries as management intends to permanently reinvest such earnings. As of December 31, 2005, the undistributed earnings of the foreign subsidiaries amounted to approximately $7.4 billion. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits. Presently, limited foreign tax credits are available to reduce the U.S. taxes on such amounts if repatriated.
      At December 31, 2005, the Company had state net operating loss carryforwards of $267 million and foreign net operating loss carryforwards of $18 million for Canada. The state net operating losses will expire over the next 20 years, if they are not otherwise utilized. The foreign net operating loss for Canada has a seven-year carryover period.

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APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      The Company is currently under audit by the Internal Revenue Service (IRS) for the 2002 and 2003 income tax years. We are in the process of responding to normal requests for information regarding the federal income tax returns for these two years. The Company believes that it has adequately provided for income taxes.
      The Company made payment