10-K 1 h65809e10vk.htm FORM 10-K e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM 10-K
 
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
    For the fiscal year ended December 31, 2008
    OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number 1-4300
 
 
APACHE CORPORATION
(Exact name of registrant as specified in its charter)
 
     
Delaware
(State or other jurisdiction of incorporation or organization)
  41-0747868
(I.R.S. Employer Identification No.)
 
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)
 
Registrant’s telephone number, including area code (713) 296-6000
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
    Name of Each Exchange
Title of Each Class
 
On Which Registered
 
Common Stock, $0.625 par value
  New York Stock Exchange,
    Chicago Stock Exchange and
    NASDAQ National Market
Preferred Stock Purchase Rights
  New York Stock Exchange and
    Chicago Stock Exchange
Apache Finance Canada Corporation
  New York Stock Exchange
7.75% Notes Due 2029
   
Irrevocably and Unconditionally
   
Guaranteed by Apache Corporation
   
 
Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.625 par value
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ  No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):  Yes o  No þ
 
         
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2008
  $ 46,488,719,719  
Number of shares of registrant’s common stock outstanding as of January 31, 2009
    334,753,638  
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of registrant’s proxy statement relating to registrant’s 2009 annual meeting of stockholders have been incorporated by reference in parts II and III hereof.
 


TABLE OF CONTENTS

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


Table of Contents

 
PART I
 
ITEMS 1 AND 2.   BUSINESS AND PROPERTIES
 
General
 
Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. In North America, our exploration and production interests are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin and the Western Sedimentary basin of Canada. Outside of North America, we have exploration and production interests onshore Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea), and onshore Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego. Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since 2004. On May 23, 2008, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of our Board of Directors, other documents related to Apache’s corporate governance (including our Code of Business Conduct and Governance Principles), and documents Apache files with the Securities and Exchange Commission (SEC), including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. Included in our annual and quarterly reports are the certifications of our principal executive officer and our principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. You may also request printed copies of our committee charters or other governance documents free of charge by writing to our corporate secretary at the address on the cover of this report. Our reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov. From time to time, we also post announcements, updates and investor information on our website in addition to copies of all recent press releases.
 
We hold interests in many of our United States (U.S.), Canadian, and other international properties through subsidiaries, including Apache Canada Ltd., DEK Energy Company (DEKALB), Apache Energy Limited (AEL), Apache North America, Inc., and Apache Overseas, Inc. Properties which we refer in this document may be held by those subsidiaries. We treat all operations as one line of business. References to “Apache” or the “Company” include Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.
 
Growth Strategy
 
Apache’s mission is to grow a profitable upstream oil and gas company for the long-term benefit of our shareholders. Our strategy includes building a balanced portfolio of assets, maintaining financial flexibility, and maximizing earnings and cash flows by controlling costs.
 
We have a portfolio of core areas that provide long-term growth opportunities through organic drilling supplemented by strategic acquisitions. Two decades ago, recognizing that the United States was a mature oil and gas province, we launched an international exploration component to our portfolio approach. Our international locations provide additional diversity of geologic and geographic risk as well as exposure to larger reserve targets, which fuel production and reserve growth. We have exploration and production operations in six countries, comprising seven regions: the Gulf Coast and Central regions in the United States, Canada, Egypt, the North Sea, Australia and Argentina. We have exploration interests in Chile located adjacent to our Argentine operations in Tierra del Fuego. We have achieved a critical mass in each of our producing regions that support sustainable, lower-risk, repeatable drilling opportunities. This enables us to pursue higher-risk, higher-reward exploration primarily in our international regions, particularly our growth areas of Australia, Canada and Egypt. Our acreage positions, which include 39 million gross acres across the globe, also bring ample growth opportunities.


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In 2008, we drilled or participated in 1,418 gross wells with an overall 93 percent success rate; 90 percent were developmental and 10 percent were exploratory. We carefully spread our risk among our regions. For instance, no single region contributed more than 23 percent of our production or reserves in 2008. Our multiple geological locations also provide us a mixture in reserve life, which translates into balance in the timing of returns on our investments. Reserve life (estimated reserves divided by annual production) in our regions ranges from as short as seven years to as long as 27 years.
 
In addition, our goal is to balance our mix of hydrocarbons, which provides some measure of protection against price deterioration in a given product while retaining upside potential through a significant increase in either commodity price. In 2008, crude oil and liquids provided 50 percent of our production and 68 percent of our revenue. We were well-positioned to realize the benefit of higher oil prices, which significantly outpaced natural gas price increases for much of the year, despite falling 70 percent from their June 2008 peak. Our year-end estimated proved reserves were balanced at 55 percent natural gas and 45 percent crude oil and liquids.
 
Preserving financial flexibility and a strong balance sheet are also key to our overall business philosophy. We ended 2008 with a debt-to-capitalization ratio of 23 percent, after current year capital investments of $6.3 billion, excluding asset retirement costs. We also had over $1.5 billion of cash and short-term investments. In tightening credit markets, we believe Apache’s single-A debt ratings provide a competitive advantage in accessing capital. Our 2008 return on capital employed and return on equity of four percent and five percent, respectively, was negatively impacted by a non-cash write-down (discussed in Item 7 of this Form 10-K).
 
Another critical component of our overall strategy is maximization of earnings and cash flow. Both are significantly impacted by commodity prices, which fluctuate and are primarily influenced by factors beyond our control, including worldwide supply and demand, political stability and governmental actions and regulations. For example, demand for energy, once thought to be insatiable, waned, driving prices down. Prices began the year strong and soared to unprecedented levels in mid-2008, only to fall rapidly by year-end, as the financial markets and ultimately the world’s economies stalled.
 
We also strive to control costs of both adding and producing reserves. Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems underscore high cash flows and motivate appropriate risk taking to reach or exceed targeted hurdle rates of return. Results are measured monthly, reviewed with management quarterly and utilized to determine annual performance awards. We monitor capital allocations, at least quarterly, through a disciplined and focused process of analyzing current economic conditions in each of our regions, internally generated drilling prospects, opportunities for tactical acquisitions or, occasionally, new core areas which could enhance our portfolio. We also periodically evaluate our properties to determine whether sales of certain assets could provide opportunities to redeploy our capital resources to rebalance our portfolio and enhance prospective returns.
 
The global economic slowdown and decline in oil and gas prices create a difficult operating environment for 2009. In preparation, we have substantially reduced our capital budget for 2009 in an effort to keep our expenditures in line with our cash flow. In 2009, we plan to invest $3.5 to $4.0 billion on capital expenditures, which is 50 percent less than in 2008. Our plan includes investments for drilling and recompleting wells, development projects, waterflood projects, equipment upgrades, production enhancement projects and seismic acquisition. Also included is $300 million for gathering, transmission and processing (GTP) assets and $500 million for plugging and abandonment work, of which $250 million is for damage caused by Hurricanes Katrina, Rita and Ike. As is our custom, we will review and revise our capital expenditure estimates throughout the year based on changing industry conditions and results-to-date. Additionally, we plan to step up our search for opportunities to acquire oil and gas properties where we believe we can add value and earn adequate rates of return.
 
During our 54 years in business and throughout the cycles of our industry, these strategies have underpinned our ability to deliver long-term production growth, increase proved reserves at a reasonable economic cost and achieve competitive investment rates of return for the benefit of our shareholders. We increased reserves 22 out of 23 years and increased production 28 out of the past 30 years, a testament to our longevity. While the business environment in 2009 is likely to be challenging, we believe we are in a strong financial position and are well-positioned to take advantage of what could be some of the most attractive acquisition opportunities in years.


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Region Overviews
 
We currently have exploration and production interests in six countries, divided into seven operating regions: the United States (Gulf Coast and Central regions), Canada, Egypt, Australia, offshore the United Kingdom in the North Sea and Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego, which we acquired in the second quarter of 2008.
 
The following table sets out a brief comparative summary of certain key 2008 data for each of our operating areas. Additional data and discussion is provided in Item 7 of this Form 10-K.
 
                                                         
                            Percentage
    2008
    2008 Gross
 
          Percentage
          12/31/08
    of Total
    Gross
    New
 
          of Total
    2008
    Estimated
    Estimated
    New
    Productive
 
    2008
    2008
    Production
    Proved
    Proved
    Wells
    Wells
 
    Production     Production     Revenue     Reserves     Reserves     Drilled     Drilled  
    (In MMboe)           (In millions)     (In MMboe)                    
 
Region/Country:
                                                       
Gulf Coast
    43.1       22 %     3,076       334.8       14 %     116       90  
Central
    33.4       17       2,007       602.8       25       415       404  
                                                         
Total U.S. 
    76.5       39       5,083       937.6       39       531       494  
Canada
    28.6       15       1,651       523.0       22       484       471  
                                                         
Total North America
    105.1       54       6,734       1,460.6       61       1,015       965  
                                                         
Egypt
    40.5       21       2,739       342.9       14       260       236  
Australia
    10.5       5       372       285.5       12       46       34  
North Sea
    22.0       11       2,103       188.8       8       14       12  
Argentina
    17.5       9       380       122.8       5       83       72  
                                                         
Total International
    90.5       46       5,594       940.0       39       403       354  
                                                         
Total
    195.6       100 %     12,328       2,400.6       100 %     1,418       1,319  
                                                         
 
United States
 
In the U.S., the Gulf Coast region historically generates high returns on invested capital and cash flow significantly in excess of its exploration and development spending. Occasional acquisitions have played an important role, as steep decline rates mean offshore reserves are generally shorter-lived and difficult to replace on a cost-effective basis through drilling alone. The Central region brings the balance of long-lived reserves and consistent drilling results to the portfolio. Apache’s future growth in the U.S. is more likely to be achieved through a combination of drilling and acquisitions than through drilling activity alone.
 
Gulf Coast Region  The region comprises our interests in and along the Gulf of Mexico, in the areas on and offshore Louisiana and Texas. In waters less than 1,200 feet deep in the Gulf of Mexico, Apache is the largest producer and, since 2004, has been the largest held-by-production acreage holder. In 2008, the region contributed approximately 22 percent of our production and approximately 25 percent of our revenues and, at year-end, held approximately 14 percent of our estimated proved reserves.
 
The region had a productive year even though a considerable amount of effort was expended on evacuations and repair related to Hurricanes Gustav and Ike. We drilled 116 wells, 90 of which were completed as producers, and performed 358 workover and recompletions. In June 2008, we had a key discovery at the Geauxpher prospect located on Garden Banks Block 462 in deepwater Gulf of Mexico. Apache generated the prospect and has a 40 percent working interest. Mariner Energy, Inc. is the designated operator of the block with a 60 percent working interest. A delineation well was drilled in December 2008, extending the productive reservoir limits. We project the initial discovery to be online in the second quarter of 2009. Additional potential on the block is expected to be tested by further drilling. At Ewing Banks 826, we completed four wells during the first half of 2008 and increased


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production to 6,315 b/d from 700 b/d at the beginning of the year. We own a 100 percent working interest in the field. In addition, significant progress was achieved toward wrapping up remaining abandonments associated with Hurricanes Katrina and Rita in 2005 and repairing damage and restoring shut-in production attributable to Hurricanes Gustav and Ike in 2008.
 
Central Region  The Central region includes assets in East Texas, the Permian basin of West Texas and New Mexico and the Anadarko basin of western Oklahoma and the Texas Panhandle, where the Company got its start over 50 years ago. At year-end 2008, the Central region accounted for approximately 25 percent of our estimated proved reserves, the largest concentration in the Company. During 2008, we participated in drilling 415 wells in the Central region, 404 of which were completed as producers. Apache also performed 1,210 workovers and recompletions in the region during the year.
 
Marketing  In general, most of our U.S. gas is sold at either monthly or daily market prices. Our natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, integrated major oil and gas companies and marketers. Approximately two percent of our 2008 U.S. natural gas production was sold under physical long-term fixed-price contracts, all of which expired in 2008. See Item 7A, “Quantitative and Qualitative Disclosures about Market Risk Commodity Risk” in this Form 10-K.
 
Apache primarily markets its U.S. crude oil to integrated major oil companies, purchasers, transporters and refiners. The objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at market prevailing prices.
 
We manage our credit risk by selling our oil and gas to diverse counterparties and monitoring our exposure on a daily basis.
 
Canada
 
In our Canadian region, we have 4.9 million net acres across the provinces of British Columbia, Alberta and Saskatchewan, which provide a significant inventory of both low-risk development drilling opportunities in and around a number of Apache fields and higher-risk, higher-reward exploration opportunities. In 2008, we drilled 484 wells in Canada, with 471 completed as producers. Three percent of the wells drilled during the year were exploration wells, half of which were productive. We performed 531 workover and recompletion projects. The region comprises approximately 22 percent of our estimated proved reserves, the second largest concentration in the Company.
 
In 2009, we will continue our pursuit of the emerging shale-gas play in northeast British Columbia, where we have over 217,000 highly prospective net acres. Apache completed seven horizontal wells at the Ootla shale-gas play in the Horn River Basin during 2008. The last completed well utilized a 10-stage fracture stimulation. Apache plans to continue to develop the optimum strategy for Ootla well completions in 2009. In addition, we plan to drill exploratory wells to test other emerging plays in both Alberta and northeast British Columbia during 2009.
 
We will also continue to target shallow gas, including coal bed methane (CBM), in the Provost, North Grant Land and Nevis areas. As a result of these efforts, we believe Apache has emerged as one of Canada’s largest producers of CBM. We are also utilizing horizontal well technology to develop waterflood and enhanced oil recovery projects in the Midale field located in southeast Saskatchewan, and the Zama and House Mountain fields located in Alberta. Intermediate depth gas development drilling continues in the Kaybob, West 5 and South Grant Land areas of central and southern Alberta.
 
Marketing  Our Canadian natural gas marketing activities focus on sales to LDCs, utilities, end-users, integrated major oil companies, supply aggregators and marketers. Our composite client portfolio is diverse with the intent of reducing the concentration of credit risk in our portfolio. Improved North American natural gas pipeline connectivity over the years has led to a closer correlation between Canadian and U.S. natural gas prices. To diversify our market exposure and optimize pricing differences in the U.S. and Canada, we transport natural gas via our firm transportation contracts to California, the Chicago area, and eastern Canada. We sell the majority of our Canadian


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production on a monthly basis, either into the first- of-the-month market or the daily market. In 2008, approximately two percent of our gas sales were subject to long-term fixed-price contracts with the latest expiration in 2011.
 
Our Canadian crude oil is primarily sold to refiners, integrated major oil companies and marketers. To increase the market value of our condensate and heavier crudes, our condensate is generally either used or sold for blending purposes. We sell our oil and natural gas liquids (NGLs) on crude oil postings, which are market-reflective prices that depend on worldwide crude oil prices and are adjusted for transportation and quality. In order to reach more purchasers and diversify our market, we transport crude oil on 12 pipelines to the major trading hubs within Alberta and Saskatchewan.
 
Egypt
 
Egypt holds our largest acreage position with more than 11 million gross acres, following relinquishments in January 2009, in 23 separate concessions (19 producing concessions) that provide a sizable resource in the Cretaceous Upper Bahariya formations and outstanding exploration potential in deeper intervals from Lower Cretaceous to Jurassic. In addition to being the largest acreage holder in Egypt, we believe that Apache is the largest producer of liquid hydrocarbons and natural gas in the Western Desert and the third largest in all of Egypt. In 2008, our Egypt region contributed 22 percent of Apache’s production revenue, 21 percent of total production, and 14 percent of total estimated proved reserves. The Company reports all estimated proved reserves held under production sharing agreements utilizing the economic interest method, which excludes the host country’s share of reserves. In 2008, Apache had an active drilling program in Egypt, completing 236 of 260 wells, a 91 percent success rate, and conducted 701 workovers and recompletions. Historically, our growth in Egypt has been driven by drilling; we are the most active driller in Egypt.
 
In the Khalda concession two additional Salam gas processing trains, three and four, and an associated Apache pipeline compression project on the Western Desert Northern Gas Pipeline are forecasted to add additional net production of 100 MMcf/d and 5,000 b/d when fully operational in the second quarter of 2009. The third processing train commenced operations on December 4, 2008. Commissioning with first gas from the fourth processing train is projected to commence during the first quarter of 2009.
 
In Egypt, our operations are conducted pursuant to production sharing contracts under which the contractor partner pays all operating and capital expenditure costs for exploration and development. A percentage of the production, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs. In general, the balance of the production is allocated between the contractor partners and Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Development leases within concessions generally have a 25-year life with extensions possible for additional commercial discoveries or on a negotiated basis.
 
Marketing  Our gas production is sold to EGPC under an industry-pricing formula, a sliding scale based on Dated-Brent crude oil with a minimum of $1.50 per MMbtu and a maximum of $2.65 per MMbtu, which corresponds to a Dated-Brent price of $21.00 per barrel. Generally, the industry-pricing formula applies to all new gas discovered and produced. In exchange for extension of the Khalda Concession lease in July 2004, Apache agreed to accept the industry-pricing formula on a majority of gas sold but retained the previous gas-price formula (without a price cap) until 2013 for up to 100 MMcf/d gross.
 
Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is sold directly to EGPC or other third parties. Oil sales are made either directly into the Egyptian oil pipeline grid, exported or sold at one of two terminals on the northern coast of Egypt or sold to non-governmental third parties including the Middle East Oil Refinery located in northern Egypt. Oil production that is presently sold to EGPC is sold on a spot basis at the monthly EGPC quoted price (indexed to Brent). In 2008, we sold 34 cargoes (approximately 10.1 million barrels) of Western Desert crude oil from the El Hamra terminal located on the northern coast of Egypt into the export market. These export cargoes were sold to EGPC at market prices above our domestic sales. Additionally, Apache sold Qarun quality oil (approximately 7.6 million barrels) at the Sidi Kerir terminal, also located on the northern coast of Egypt. This Qarun oil was sold at prevailing market prices into the domestic market to non-governmental purchasers (three million barrels) or exported to buyers in the Mediterranean markets (11


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cargoes for approximately 4.6 million barrels). We expect sales to the export market from both the Khalda and Qarun areas in the Western Desert to continue in 2009.
 
Australia
 
Overview — In Australia, our exploration activity is focused in the offshore Carnarvon, Gippsland and Browse basins, where Apache holds 5.2 million net acres in 34 exploration permits, 11 production licenses and five retention leases.
 
Production operations are concentrated in the Carnarvon and Exmouth basins, the location of Apache’s 11 production licenses, all of which are Apache operated. In 2008, the region generated $372 million of production revenues from the sale of 10.5 MMboe, approximately five percent of our total production. Australia held 12 percent of our year-end estimated proved reserves. During the year, the region participated in drilling 46 wells, which generated 25 productive oil wells and nine productive gas wells.
 
Our growth strategy includes development in the Carnarvon basin and in areas adjacent to this core area. As of the end of 2008, our Van Gogh and Pyrenees projects in the Exmouth basin were under active development. We had also initiated a development project related to our 2008 Halyard discovery (discussed below) and began appraising our large Julimar discovery (also discussed below). We completed planned development drilling at our Reindeer field.
 
Van Gogh is Apache-operated, while Pyrenees is operated by BHP Billiton. Van Gogh development drilling and sub-sea production equipment installation is well underway, with first oil production slated for mid-2009 through a floating production storage and offloading tanker. Additional development drilling is planned in 2009 prior to the start of production. Pyrenees development drilling is expected to commence in 2009 with first oil production expected in the first half of 2010. Production from each field is estimated at 20,000 b/d net to Apache.
 
In April 2008, we drilled the Halyard-1 well, which tested 68 MMcf/d of gas and was completed as a producer. The Halyard field is expected to be tied-in to the nearby East Spar gas facilities once a market for the gas is under contract. Apache holds a 55 percent interest in the field. Additional appraisal in 2009 is necessary on the Julimar gas discovery before proceeding with a development plan. Based on current geological mapping, we believe that Julimar could be a multi-Tcf discovery. Apache owns a 65 percent interest in and operates the Julimar-Brunello complex.
 
During the fourth quarter of 2008, Apache completed a three-well development drilling campaign at the Reindeer field. On January 6, 2009, we secured a 154 Bcf, 7-year gas sales contract that allowed us to reinstate our Reindeer development, which was suspended at the end of 2008 program because of a delay in gas sales contract negotiations. Negotiations were delayed by the onset of the global economic crisis and the resulting drop in metal prices. The gas will be supplied through a new 65-mile offshore pipeline and a new onshore gas processing facility at Devil Creek. This sales contract is discussed in more detail below under “Subsequent Events.” Construction of pipeline and processing infrastructure is scheduled to commence in 2009 with first production anticipated in 2011. Apache owns a 55-percent interest in the field.
 
We are currently evaluating the results of wells drilled in 2008 and seismic information to assess the future potential in the Gippsland basin. All six wells drilled in 2008 were either dry or non-commercial.
 
Varanus Island — On June 3, 2008, subsidiaries of the Company reported a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia, which shut-in production from the John Brookes field and Harriet Joint Venture. When fully operational, the Island’s operations process approximately 195 MMcf/d and 5,400 b/d, net to Apache subsidiaries. On August 5, 2008, partial production was reestablished from the John Brookes field and by year-end was at greater than 80 percent pre-incident levels. The Harriet Joint Venture gas facilities are located adjacent to the pipeline explosion and required more significant repairs to restore operation. A portion of the gas production from the Harriet Joint Venture was restored in December 2008 and is projected to be fully restored in the first half of 2009. Harriet Joint Venture oil production is projected to be fully restored in the first quarter of 2009. The John Brookes field accounted for approximately 60 percent and 25 percent of the island’s pre-incident natural gas and oil production, respectively. Production from the Harriet Joint Venture accounted for the remaining 40 percent and 75 percent of the island’s pre-incident natural gas and oil production,


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respectively. Company subsidiaries operate the facilities and own a 68.5 percent interest in the Harriet Joint Venture and a 55 percent interest in the John Brookes field. Company subsidiaries maintain replacement cost insurance, subject to a deductible of approximately $7 million, with adequate limits to cover fully their share of the estimated cost of restoring the Varanus Island facilities.
 
During 2009, our Australian region plans to focus on its major field development projects and, to a lesser extent, its exploration and appraisal activities.
 
Marketing  As of December 31, 2008, Apache had a total of 18 active gas contracts in Australia with expiration dates ranging from March 2010 to July 2030. Generally, natural gas is sold in Western Australia under long-term, fixed-price contracts, many of which contain price escalation clauses based on the Australian consumer price index.
 
We continue to export all of our crude oil production into international markets at prices indexed to Asian benchmark crude oil prices, which typically track at or above New York Mercantile Exchange (NYMEX) oil prices.
 
North Sea
 
Apache entered the North Sea in 2003 upon acquiring an approximate 97 percent working interest in the Forties field (Forties). Our drilling program and continued improvements in plant efficiencies led to an 11 percent increase in 2008 production. We expect to increase our North Sea production in 2009 relative to 2008. We also have several targeted facilities projects planned for 2009 to further improve the efficiency of our operations in the North Sea.
 
In 2008, the North Sea region produced 21.9 MMboe, approximately 11 percent of our total production, generating slightly more than $2.1 billion of revenue and accounting for approximately eight percent of our year-end estimated proved reserves. In 2008, we invested $459 million in the North Sea on drilling and recompleting wells and facility enhancement programs. We drilled 14 wells in the North Sea during 2008, 12 of which were producers. We completed and commissioned a number of key projects in the North Sea region during 2008, including replacing the key import header on the Charlie platform that services the field export system, high-pressure gas-lift compression projects on the Alpha and Delta platforms, a large produced water reinjection system on the Charlie platform and replacement of the infield pipeline between the Bravo and Charlie platforms. Investments in facility upgrades and integrity-related projects over the past five years have continually increased the efficiency of our operations.
 
Drilling successes and improved platform operating efficiencies led to fourth-quarter 2008 production of 61,740 b/d. During 2008, production averaged 59,494 b/d. The 2008 annual maintenance shut down on the Charlie platform impacted the field by 1,330 b/d, which was an improvement compared to 2,270 b/d impact in 2007. The new import header on the Charlie platform enabled the platform to be shut in for planned maintenance activities without impacting production export operations from the other field platforms.
 
Marketing  In 2008, we entered into two new term contracts for the physical sale of Forties crude at prevailing market prices. These term sales are composed of base-market indices, adjusted for the quality difference between the Forties crude and Brent, with a premium to reflect the higher market value for term arrangements. In addition to the term sales, Apache sold 11 spot cargoes of approximately 600,000 barrels each and received value at or above the prevailing market prices.
 
Argentina
 
Argentina became our latest core area following two significant acquisitions in 2006 that substantially increased our presence in the country. In the second quarter of 2006, we completed our purchase of Pioneer’s operations in Argentina for $675 million, with estimated proved reserves of 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas. In the third quarter of 2006, we acquired additional interests in (and now operate) seven concessions in Tierra del Fuego (TdF) from Pan American for $429 million. With the addition of Mendoza CCyB Block 17B in 2008, our oil and gas assets are located in the Neuquén, Austral and Cuyo basins of Argentina. While Argentina presents unique challenges with evolving governmental regulations, we are optimistic about our ability to find additional hydrocarbons with the drill bit and to grow our reserves and production over the long-term.


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In 2008, our Argentina region continued its broad drilling and recompletion programs. The region drilled 83 wells, 72 of which were productive. We produced 17.5 MMboe in 2008, which accounted for nine percent of Apache’s total production. Argentina holds approximately five percent of our total estimated proved reserves.
 
In December 2008, the Mendoza Province granted Apache an exploration permit for CCyB Block 17B in the Cuyo basin, increasing our Argentine acreage by 34 percent. The block is adjacent to and along a trend of existing producing fields.
 
We also completed a nearly 2,500 square kilometer three-dimensional (3-D) seismic mega shoot in Tierra del Fuego. which aided in the identification of prospects and increased Apache’s ability to drill productive wells. In the Austral Basin of Tierra del Fuego, Apache made discoveries on operated blocks in which we own a 70 percent working interest, including the San Sebastian area, where Apache successfully drilled three kilometers from the shore to test a new separate oil structure in the San Sebastian field. Apache also discovered a new field, Sección Veintinueve, and a field extension to the Sara Norte field. Apache believes that the new 3-D seismic survey will continue to generate an inventory of drilling prospects.
 
On the mainland, we continued our drilling and recompletion campaigns in our established gas areas in the Neuquén basin. We drilled 11 new wells in our Estacion Fernandez Oro field, 10 new wells in our Guanaco field including a new deeper gas pool and 9 new wells in our Ranquil Co field, with a success rate of 100 percent. Apache plans to continue drilling in each of these fields in 2009. We also drilled a successful exploratory well on our Collon Cura exploration lease, fulfilling our license obligations.
 
Marketing  In 2008, 52 percent of our natural gas portfolio was regulated based upon certain market segments. We realized an average price of $.92 per Mcf on sales to regulated market segments in 2008. The remaining free market volumes were sold either on a monthly or daily basis or under term contracts, some of which extend through 2009. The average price received for free market volumes during the fourth quarter 2008 was $2.28 per Mcf, versus a fourth-quarter 2007 price of $2.32, a decrease of two percent primarily because of lower spot price sales in Tierra del Fuego.
 
Taxes on exported oil effectively limits prices buyers are willing to pay for domestic sales. Domestic oil prices are currently based on $42 per barrel, plus quality adjustments, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, the price cap applies, but Apache retains the value-added tax collected from buyers, effectively increasing realized prices by 21 percent. In 2008, we received an average price of $49.46 per barrel for crude oil.
 
Chile
 
In November 2007, Apache was awarded exploration rights on two blocks comprising one million net acres in Tierra del Fuego, following a bid round. This acreage is adjacent to our 552,000 net acres on the Argentine side of the island of Tierra del Fuego, and the additional acreage represents a natural extension of our expanding exploration and production operations. In 2008, Apache finalized the contracts with the Chilean government in July and shot a 3-D seismic survey. In 2009, we plan to process and interpret this seismic data in order to validate prospects and identify initial drilling locations.
 
Major Customers
 
In 2008, purchases by Shell accounted for 17 percent of the company’s oil and gas production revenues.
 
Subsequent Events
 
Australian Gas Sales Contract  On January 6, 2009, Apache signed a contract to supply natural gas from its Reindeer field to CITIC Pacific’s Sino Iron project in Western Australia. Apache and its joint venture partner agreed to supply 154 billion cubic feet of gas over seven years, beginning in the second half of 2011. Apache owns a 55-percent interest in the field.


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The gas will be supplied through a new, 65-mile offshore pipeline and a new onshore sales gas processing facility at Devil Creek, about 28 miles southwest of Dampier, with capacity to process 210 MMcf/d. Apache plans to sell additional production from the Reindeer field to other domestic customers in Western Australia.
 
The contract price for the first three years is a fixed price adjusted periodically for changes in the Australian consumer price index. Beginning in the fourth year, the price is indexed to international oil prices. At an oil price of $50 per barrel, Apache’s net share of the revenue over the seven years of the contract would be approximately $700 million.
 
The gas sales agreement will not take effect unless Apache and its joint venture partner sign contracts for engineering and procurement of the gas plant and pipeline by mid-March 2009 (or a later date if agreed by all parties).
 
Management Changes  On January 15, 2009, Raymond Plank retired as Chairman of the Board, a director, and an employee of Apache. Mr. Plank founded Apache in 1954 and had served as an officer of the Company since 1954 (President and/or Chief Executive Officer from 1954 to 2002 and Chairman of the Board since 1979). He had been a director of the Company since 1954. G. Steven Farris, Apache’s president, chief executive officer and chief operating officer since 2002, succeeded Mr. Plank as chairman.
 
Also on January 15, 2009, Apache and Mr. Plank entered into an amendment and restatement of his employment agreement dated December 5, 1990, pursuant to which he agreed to provide consulting services to the Company for the remainder of his life.
 
On February 12, 2009, Mr. Farris formed an office of the chief executive with three key executives reporting to him. Messrs. Roger B. Plank, John A. Crum and Rodney J. Eichler were appointed to new positions effective as of February 12, 2009. Mr. Roger Plank now serves as president, Mr. Crum serves as co-chief operating officer and president — North America, and Mr. Eichler serves as co-chief operating officer and president — International. Although Messrs. Roger Plank, Crum and Eichler have separate functional responsibilities, they have joint and equal roles in the daily decision-making and direction of Apache. Mr. Farris continues to serve as chairman and chief executive officer of Apache and has resigned from his positions of president and chief operating officer of Apache effective February 12, 2009. Mr. Farris continues to serve as Apache’s principal executive officer and, in his new role as president, Mr. Roger Plank continues to serve as Apache’s principal financial officer.
 
Canadian Gas Pipeline Contract  On February 10, 2009, Apache’s wholly-owned subsidiary, Apache Canada Ltd entered into an agreement with TransCanada Pipelines Limited (TCPL) pursuant to which TCPL will construct and install a gas pipeline from northeastern British Columbia to the existing NOVA pipeline system located in the Ekwan area of Alberta. Apache Canada intends to ship gas produced from the Ootla basin on the new pipeline.
 
The construction, operation and transportation rates of the new pipeline are subject to regulatory approval. We expect to receive authority to construct the pipeline, and construction is expected to be complete on or before April 1, 2011. Upon completion of the pipeline, Apache Canada will have a ship-or-pay commitment to ship 100 MMBtu/d for either a four-year period or a ten-year period, depending on the rate structure determined and approved by the regulatory agency. Apache Canada has the right to terminate the agreement before October 1, 2009. If Apache Canada elects to terminate the agreement or TCPL terminates for reasons set forth in the agreement, Apache Canada must reimburse TCPL for certain costs and expenses up to CDN $90 million plus certain taxes.
 
Drilling Statistics
 
Worldwide, in 2008, we participated in drilling 1,418 gross wells, with 1,319 (93 percent) completed as producers. We also performed more than 2,800 workovers and recompletions during the year. Historically, our drilling activities in the U.S. have generally concentrated on exploitation and extension of existing, producing fields rather than exploration. As a general matter, our operations outside of the U.S. focus on a mix of exploration and exploitation wells. In addition to our completed wells, at year-end several wells had not yet reached completion: 91 in the U.S. (56.3 net); 10 in Canada (9.7 net); 36 in Egypt (33.5 net); 2 in Australia (1.6 net); 2 in the North Sea (1.9 net); and 9 in Argentina (8.7 net).


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The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:
 
                                                                         
    Net Exploratory     Net Development     Total Net Wells  
    Productive     Dry     Total     Productive     Dry     Total     Productive     Dry     Total  
 
2008
                                                                       
United States
    4.5       6.6       11.1       334.8       25.3       360.1       339.3       31.9       371.2  
Canada
    3.9       5.0       8.9       328.0       10.1       338.1       331.9       15.1       347.0  
Egypt
    18.7       11.5       30.2       193.2       5.8       199.0       211.9       17.3       229.2  
Australia
    6.4       9.0       15.4       12.5             12.5       18.9       9.0       27.9  
North Sea
                      11.7             11.7       11.7             11.7  
Argentina
    7.5       2.0       9.5       54.4       6.2       60.6       61.9       8.2       70.1  
                                                                         
Total
    41.0       34.1       75.1       934.6       47.4       982.0       975.6       81.5       1,057.1  
                                                                         
2007
                                                                       
United States
    3.0       3.1       6.1       264.9       16.5       281.4       267.9       19.6       287.5  
Canada
    9.5       15.5       25.0       206.0       35.4       241.4       215.5       50.9       266.4  
Egypt
    10.7       13.0       23.7       144.3       14.8       159.1       155.0       27.8       182.8  
Australia
    3.8       7.2       11.0       2.7             2.7       6.5       7.2       13.7  
North Sea
          2.5       2.5       4.9       6.8       11.7       4.9       9.3       14.2  
Argentina
    2.0             2.0       80.8       2.0       82.8       82.8       2.0       84.8  
                                                                         
Total
    29.0       41.3       70.3       703.6       75.5       779.1       732.6       116.8       849.4  
                                                                         
2006
                                                                       
United States
    2.9       2.7       5.6       266.4       15.3       281.7       269.3       18.0       287.3  
Canada
    34.3       6.4       40.7       577.3       114.8       692.1       611.6       121.2       732.8  
Egypt
    11.8       8.9       20.7       122.7       10.4       133.1       134.5       19.4       153.9  
Australia
    1.2       9.3       10.5       1.0       1.3       2.3       2.2       10.6       12.8  
North Sea
          1.0       1.0       3.9             3.9       3.9       1.0       4.9  
Argentina
    9.3       5.3       14.6       60.8       2.0       62.8       70.1       7.3       77.4  
Other International
                      1.5             1.5       1.5             1.5  
                                                                         
Total
    59.5       33.6       93.1       1,033.6       143.8       1,177.4       1,093.1       177.5       1,270.6  
                                                                         
 
Productive Oil and Gas Wells
 
The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2008, is set forth below:
 
                                                 
    Gas     Oil     Total  
    Gross     Net     Gross     Net     Gross     Net  
 
Gulf Coast
    835       675       885       640       1,720       1,315  
Central
    3,415       1,765       7,650       5,215       11,065       6,980  
Canada
    8,200       7,260       2,250       990       10,450       8,250  
Egypt
    42       42       618       589       660       631  
Australia
    10       6       37       22       47       28  
North Sea
                65       63       65       63  
Argentina
    395       363       580       503       975       866  
                                                 
Total
    12,897       10,111       12,085       8,022       24,982       18,133  
                                                 


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


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Gross and Net Undeveloped and Developed Acreage
 
The following table sets out our gross and net acreage position in each country where we have operations:
 
                                 
    Undeveloped Acreage     Developed Acreage  
    Gross Acres     Net Acres     Gross Acres     Net Acres  
 
United States
    2,158,979       1,365,722       2,904,849       1,797,004  
Canada
    3,138,067       2,225,462       3,325,289       2,652,939  
Egypt
    13,969,530       8,488,721       1,316,195       1,211,734  
Australia
    6,877,670       4,857,730       572,170       352,830  
North Sea
    319,929       241,450       41,019       39,952  
Argentina
    3,070,000       2,791,000       259,000       194,000  
Chile
    1,203,137       1,034,436              
                                 
Total Company
    30,737,312       21,004,521       8,418,522       6,248,459  
                                 
 
As of December 31, 2008, we had 4,933,430, 3,270,055 and 8,474,094 net acres scheduled to expire by December 31, 2009, 2010 and 2011, respectively, if production is not established or we take no other action to extend the terms. Approximately two million net acres (four million gross acres) of the 2009 expiration total expired in Egypt in January 2009. We plan to continue the terms of many of these licenses and concession areas through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.
 
Estimated Proved Reserves and Future Net Cash Flows
 
As of December 31, 2008, Apache had total estimated proved reserves of 1,081 MMbbls of crude oil, condensate and NGLs and 7.9 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 2.4 billion barrels of oil equivalent or 14.4 Tcf of natural gas. As a result of prices in effect at the end of 2008, we experienced significant negative revisions to our reserves, causing 2008 to be the first year in the last 23 in which reserves did not grow.
 
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company reports all estimated proved reserves held under production sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. Reserve estimates are considered proved if economical productivity is supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program in the reservoir provides support for the engineering analysis on which the project or program is based. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
 
Apache emphasizes that its reported reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed throughout the year and revised either upward or downward, as warranted by additional performance data.
 
Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of Apache’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues and ultimate recoverable reserves. Reserves are reviewed internally with senior management and presented to Apache’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable.


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The estimate of reserves disclosed in this Annual Report on Form 10-K are prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, we engage Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. We selected the properties for review by Ryder Scott. These properties represented all material fields, approximately 90 percent of international properties and over 80 percent of each country’s reserve value for new wells drilled during the year. During 2008, 2007 and 2006, Ryder Scott’s review covered 82, 77 and 75 percent of the Company’s worldwide estimated reserves value, respectively.
 
Ryder Scott opined that the overall proved reserves for the reviewed properties as estimated by the Company are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles and conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. Ryder Scott has informed the Company that the tests and procedures used during its reserves audit conform to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information approved by the Society of Petroleum Engineers. Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information defines a reserves audit as the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed, (2) the adequacy and quality of the data relied upon, (3) the depth and thoroughness of the reserves estimation process, (4) the classification of reserves appropriate to the relevant definitions used, and (5) the reasonableness of the estimated reserve quantities. A reserve audit is not the same as a financial audit and is less rigorous in nature than an independent reserve report where the independent reserve engineer determines the reserves on his or her own.
 
The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2008, 2007 and 2006, changes in estimated proved reserves during the last three years and estimates of future net cash flows and discounted future net cash flows from estimated proved reserves are contained in Note 13 — Supplemental Oil and Gas Disclosures of Item 15 in this Form 10-K. These estimated future net cash flows are based on prices on the last day of the year and are calculated in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities.” Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10.
 
In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting” (Modernization). The Modernization disclosure requirements will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies will also be allowed to disclose probable and possible reserves in SEC filed documents. In addition, companies will be required to report the independence and qualifications of its reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements become effective for Apache’s Annual Report on Form 10-K for the year ended December 31, 2009.
 
Employees
 
On December 31, 2008, we had 3,639 employees.
 
Offices
 
Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2008, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2013. For information regarding the Company’s obligations under its office leases, see the table in Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity and Note 9 — Commitments and Contingencies of Item 15 in this Form 10-K.


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Title to Interests
 
As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, and other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.
 
ITEM 1A.   RISK FACTORS
 
Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future.
 
Our profitability and the carrying value of our properties is highly dependent on the prices of crude oil, natural gas and natural gas liquids, which have historically been very volatile
 
Our estimated proved reserves, revenues, profitability, operating cash flows and future rate of growth are highly dependent on the prices of crude oil, natural gas and NGLs, which are affected by numerous factors beyond our control. These prices have historically been very volatile and are likely to remain volatile in the future. A significant and extended downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow and could result in a reduction in the carrying value of our oil and gas properties and the amounts of our estimated proved oil and gas reserves. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices adversely affects our financial position.
 
Under the full-cost method of accounting as allowed by the SEC, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. The Company recorded a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of the ceiling test limitations. If oil and gas prices deteriorate from the Company’s year-end realized prices, it is likely that additional write-downs will occur in 2009.
 
A downgrade in our credit rating could negatively impact our cost of and ability to access capital
 
We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels could also be considered by the rating agencies. Apache’s senior unsecured long-term debt is currently rated A3 by Moody’s, A- by Standard & Poor’s and A by Fitch. Apache’s short-term debt rating for its commercial paper program is currently P-2 by Moody’s, A-2 by Standard & Poor’s and F1 by Fitch. The outlook is stable from Moody’s and Standard & Poor’s and negative from Fitch. A ratings downgrade could adversely impact our ability to access debt markets in


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the future, increase the cost of future debt and potentially require the Company to post letters of credit in certain circumstances.
 
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition
 
Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy.
 
These factors, combined with volatile oil, natural gas and NGLs prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish, which could impact the price at which we can sell our oil, natural gas and NGLs, affect our vendors, suppliers and customers ability to continue operations, and ultimately, adversely impact our results of operations, liquidity and financial condition.
 
Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks
 
To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:
 
  •  our production falls short of the hedged volumes;
 
  •  there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
 
  •  the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or
 
  •  a sudden unexpected event materially impacts oil and natural gas prices.
 
The credit risk of financial institutions could adversely affect us
 
We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Continued deterioration in the credit markets may continue to impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to these financial institutions in the form of derivative transactions in connection with our hedges. We also maintain insurance policies with insurance companies to protect us against certain risks inherent in our business. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.
 
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage
 
A sizeable portion of our acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to


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change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
 
Our ability to sell natural gas and/or receive market prices for our gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions
 
A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.
 
Acquisitions or discoveries of additional reserves are needed to avoid a material decline in reserves and production
 
The production rate from oil and gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery reserves, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.
 
We may not realize an adequate return on wells that we drill
 
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
 
  •  unexpected drilling conditions;
 
  •  pressure or irregularities in formations;
 
  •  equipment failures or accidents;
 
  •  fires, explosions, blowouts and surface cratering;
 
  •  marine risks such as capsizing, collisions and hurricanes;
 
  •  other adverse weather conditions; and
 
  •  increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.
 
Future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
 
We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves
 
Although we perform a review of properties that we acquire that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual


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property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and associated costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.
 
Our North American operations are subject to governmental risks that may impact our operations
 
Our North American operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection laws and regulations. New political developments, laws and regulations may adversely impact our results on operations.
 
International operations have uncertain political, economic and other risks
 
Our operations outside North America are based primarily in Egypt, Australia, the United Kingdom and Argentina. On a barrel equivalent basis, approximately 46 percent of our 2008 production was outside North America and approximately 39 percent of our estimated proved oil and gas reserves on December 31, 2008 were located outside North America. As a result, a significant portion of our production and resources are subject to increased political and economic risks and other factors including, but not limited to:
 
  •  general strikes and civil unrest;
 
  •  the risk of war, acts of terrorism, expropriation, forced renegotiation or modification of existing contracts;
 
  •  import and export regulations;
 
  •  taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
 
  •  price control;
 
  •  transportation regulations and tariffs;
 
  •  constrained natural gas markets dependent on demand in a single or limited geographical area;
 
  •  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;
 
  •  laws and policies of the United States affecting foreign trade, including trade sanctions;
 
  •  the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;
 
  •  the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and
 
  •  difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
 
Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world in which we operate have a history of political and economic instability. This instability could result in new


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governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our assets. This could adversely affect our interests and our future profitability.
 
The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.
 
Material differences between the estimated and actual timing of critical events may affect the completion and commencement of production from development projects
 
We are involved in several large development projects whose completion may be delayed beyond our anticipated completion dates. Our projects may be delayed by project approvals from joint venture partners; timely issuances of permits and licenses by governmental agencies; weather conditions; manufacturing and delivery schedules of critical equipment; and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect our large development projects and our ability to participate in large scale development projects in the future.
 
Our operations are sensitive to currency rate fluctuations
 
Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar with the Canadian dollar, the Australian dollar and the British Pound. Our financial statements, presented in U.S. dollars, are affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operation, particularly through the weakening of the U.S. dollar relative to other currencies.
 
Weather and climate may have a significant adverse impact on our revenues and productivity
 
Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico or cyclones offshore Australia, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather, and not all such effects can be predicted, eliminated or insured against.
 
We may incur significant costs related to environmental matters
 
As an owner or lessee and operator of oil and gas properties, we are subject to various federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse affect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.
 
We face strong industry competition that may have a significant negative impact on our result of operations
 
Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties and


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reserves, equipment and labor required to explore, develop and operate those properties and marketing of oil and natural gas production. Crude oil and natural gas prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geo-physicists, engineers and other specialists. These competitive pressures may have a significant negative impact on our results of operations.
 
Our insurance policies do not cover all risks
 
Exploration for and production of oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.
 
ITEM 1B.   UNRESOLVED SEC STAFF COMMENTS
 
As of December 31, 2008, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.
 
ITEM 3.   LEGAL PROCEEDINGS
 
See the information set forth in Note 9 — Commitments and Contingencies of Item 15 of this Form 10-K which is incorporated herein by reference.
 
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
No matters were submitted to a vote of our security holders during the most recently ended fiscal quarter.


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PART II
 
ITEM 5.   MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
During 2008, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock Exchanges and the NASDAQ National Market under the symbol “APA.” The table below provides certain information regarding our common stock for 2008 and 2007. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per-share prices and quarterly dividends shown below have been rounded to the indicated decimal place.
 
                                                                 
    2008     2007  
    Price Range     Dividends Per Share     Price Range     Dividends Per Share  
    High     Low     Declared     Paid     High     Low     Declared     Paid  
 
First Quarter
  $ 122.34     $ 84.52     $ .25     $ .15     $ 73.44     $ 63.01     $ .15     $ .15  
Second Quarter
    149.23       117.65       .15       .25       87.82       70.53       .15       .15  
Third Quarter
    145.00       94.82       .15       .15       91.25       73.41       .15       .15  
Fourth Quarter
    103.17       57.11       .15       .15       109.32       87.44       .15       .15  
 
The closing price of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 30, 2009 (last trading day of the month), was $75.00 per share. As of January 31, 2009, there were 334,753,638 shares of our common stock outstanding held by approximately 6,000 stockholders of record and approximately 448,000 beneficial owners.
 
We have paid cash dividends on our common stock for 44 consecutive years through December 31, 2008. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements and other relevant factors.
 
In 1995, under our stockholder rights plan, each of our common stockholders received a dividend of one preferred stock purchase right (a “right”) for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and a two-for-one stock split) that the stockholder owned. These rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the rights were reset to one right per share of common stock, and the expiration was extended to January 31, 2016. Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights, which trade automatically with our shares of common stock. For a description of the rights, please refer to Note 7 — Capital Stock of Item 15 in this Form 10-K.
 
Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2009 annual meeting of stockholders, which is incorporated herein by reference.


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The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2003 through December 31, 2008.
 
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Apache Corporation, S&P 500 Index
and the Dow Jones US Exploration & Production Index
 
PERFORMANCE GRAPH
 
* $100 invested on 12/31/03 in stock including reinvestment of dividends.
Fiscal year ending December 31.
 
                                                             
      2003     2004     2005     2006     2007     2008
Apache Corporation
    $ 100.00       $ 125.41       $ 170.91       $ 166.97       $ 272.02       $ 189.80  
S & P’s Composite 500 Stock Index
      100.00         110.88         116.33         134.70         142.10         89.53  
DJ US Expl & Prod Index
      100.00         141.87         234.54         247.14         355.06         212.61  
                                                             


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ITEM 6.   SELECTED FINANCIAL DATA
 
The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2008, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements of Item 15 in this Form 10-K. As discussed in more detail under Item 15, the 2008 numbers in the following table reflect a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties as of December 31, 2008, as a result of ceiling test limitations.
 
                                         
    As of or for the Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (In thousands, except per share amounts)  
 
Income Statement Data
                                       
Total revenues
  $ 12,389,750     $ 9,999,752     $ 8,309,131     $ 7,584,244     $ 5,332,577  
Income (loss) attributable to common stock
    706,274       2,806,678       2,546,771       2,618,050       1,663,074  
Net income (loss) per common share:
                                       
Basic
    2.11       8.45       7.72       7.96       5.10  
Diluted
    2.09       8.39       7.64       7.84       5.03  
Cash dividends declared per common share
    .70       .60       .50       .36       .28  
Balance Sheet Data
                                       
Total assets
  $ 29,186,485     $ 28,634,651     $ 24,308,175     $ 19,271,796     $ 15,502,480  
Long-term debt
    4,808,975       4,011,605       2,019,831       2,191,954       2,588,390  
Shareholders’ equity
    16,508,721       15,377,979       13,191,053       10,541,215       8,204,421  
Common shares outstanding
    334,710       332,927       330,737       330,121       327,458  
 
For a discussion of significant acquisitions and divestitures, see Note 2 — Significant Acquisitions and Divestitures of Item 15 in this Form 10-K.


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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. In North America, our exploration and production operations are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin and the Western Sedimentary basin of Canada. Outside of North America, we have exploration and production operations onshore Egypt, offshore Western Australia, offshore the United Kingdom (U.K.) in the North Sea (North Sea), and onshore Argentina. We also have exploration interests on the Chilean side of the island of Tierra del Fuego.
 
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in Item 8 of this Form 10-K, and the Risk Factors information, which are set forth in Item 1A of this Form 10-K.
 
Overview
 
Apache’s 2008 results were significantly impacted by several events:
 
  •  A drop in demand related to the slowing global economy caused fourth-quarter oil and gas prices to drop sharply.
 
  •  Two major uncontrollable events curtailed our production:
 
  •  hurricanes in the Gulf of Mexico, and
 
  •  an explosion on a pipeline that transports all of our gas production in Australia.
 
  •  A non-cash write-down of the carrying value of our U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties, necessitated by low commodity prices in effect at year-end (discussed below).
 
Crude Oil and Natural Gas Prices
 
The oil and gas industry as a whole experienced a year of extremes during 2008. Crude oil and natural gas prices climbed precipitously in the first half of the year, only to pull back in the third quarter before collapsing in the fourth quarter. Apache monthly average realized prices during the summer reached $118.38 per barrel and $9.12 per thousand cubic feet (Mcf). Our December average realized prices were $36.45 per barrel and $4.75 per Mcf. February 2009 indices indicate that prices are trending below December’s averages as the global economy and demand continue to weaken.
 
Crude Oil and Natural Gas Production
 
Apache’s 2008 consolidated production declined five percent from 2007 on a barrel of oil equivalent (boe) basis. Our production would have increased over 2007 levels had it not been for the impact of the following:
 
  •  U.S. production was affected by wells shut-in because of, and damage caused by, Hurricanes Gustav and Ike. While we plan to restore nearly all of the production during the second quarter of 2009, the timing in many instances is pipeline dependent and, therefore, beyond our control. See Operating Highlights in this Item 7.
 
  •  In June 2008, a pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia disrupted gas and oil sales, reducing 2008 production. We plan to have all of the volumes restored in the first half of 2009. See Operating Highlights in this Item 7.
 
Earnings and Cash Flow
 
From an earnings perspective, we had our historical best and worst quarters ever, just one quarter apart. The fourth-quarter price collapse and associated $3.6 billion non-cash after-tax write-down nearly eliminated 2008 nine-month earnings that totaled $3.7 billion dollars or $10.84 per common diluted share. The write-down reduced earnings for the year to $706 million, or $2.09 per share.


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Record commodity prices in the first half of 2008 drove record cash provided by operating activities of $7.1 billion and record oil and gas revenues of $12.4 billion, both of which were unaffected by the write-down. They were, however, affected by falling commodity prices, most notably in the fourth quarter of 2008. Key financial indicators for each quarter and the year of 2008 are noted below:
 
                                         
    2008 Key Financial Indicators, by Quarter  
    First
    Second
    Third
    Fourth
       
    Quarter     Quarter     Quarter     Quarter     Full Year  
    (In thousands, except realized price)  
 
Oil and Gas Revenues
  $ 3,177,949     $ 3,904,118     $ 3,368,882     $ 1,876,890     $ 12,327,839  
                                         
Average Realized Oil Price
  $ 89.25     $ 110.32     $ 101.04     $ 50.69     $ 87.80  
Average Realized Gas Price
  $ 6.42     $ 8.09     $ 7.43     $ 4.76     $ 6.70  
Income Attributable to Common Stock
  $ 1,020,093     $ 1,443,809     $ 1,189,405     $ *(2,947,033 )   $ *706,274  
                                         
Cash from operating activities
  $ 1,808,404     $ 1,929,509     $ 2,290,655     $ 1,036,776     $ 7,065,344  
                                         
 
 
* Includes a $3.6 billion (after-tax) non-cash write-down in the carrying value of oil and gas properties.
 
Operating and Drilling Costs
 
Costs were a challenge for Apache and our industry in 2008 and are expected to remain so in 2009. Drilling, service and acquisition costs, which have increased steadily since the industry’s last downturn in 2001, reached unprecedented levels in 2008. Also, in the U.S., activity to repair damage caused by Gulf of Mexico hurricanes over the last few years has contributed to increased demand and costs. Even though we have seen a sharp drop in commodity prices, costs have fallen less rapidly pressuring operating margins. We believe costs will ultimately adjust to the current oil and gas price environment, but until they do, our operating margins and drilling costs will continue to be pressured.
 
Financial Position and 2009
 
We believe we are well positioned to take advantage of opportunities that will invariably present themselves in the current business environment. We enter 2009 with a debt-to-capitalization ratio of 23 percent, after consideration of the non-cash write-down. We had over $1.5 billion in cash and short-term investments and $2.3 billion availability on our lines of credit at the close of the year. In a tightening credit market, we believe Apache’s single-A debt ratings will provide a competitive advantage in accessing capital. Our 2008 return on capital employed and return on equity were four percent and five percent, respectively, after taking into effect the $5.3 million non-cash write-down.
 
In 2009, we are projecting production growth driven by multi-year projects coming on-line during the year (discussed below in Operational Highlights). We plan to hold our capital expenditures, currently planned at 50 percent below 2008 spending levels, in line with our operating cash flows. We will continue to monitor capital spending closely based on actual and projected cash flow estimates and intend to scale back spending further should commodity prices remain at current levels or fall further.
 
For an in-depth discussion of Apache’s long-term growth strategy, please refer to Part 1, Items 1 and 2. Business and Properties of this Form 10-K.
 
Full-Cost Accounting and 2008 Write-down in Net Oil and Gas Property Assets
 
The Company follows the full-cost method of accounting as allowed by the Securities and Exchange Commission (SEC). Under the full-cost method of accounting, a ceiling test must be performed each quarter, for each country. The test establishes a limit (ceiling), on the carrying value of proved oil and gas properties. This carrying value (net book value and the related deferred income taxes) may not exceed the ceiling. The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, excluding future


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expected cash outflows associated with settling asset retirement obligations accrued on the balance sheet. The estimate of after-tax future net cash flows is discounted at 10 percent per annum and calculated using both commodity prices and costs in effect at the end of the period, held flat for the life of the properties, except where future oil and gas sales are covered by physical contract terms or by derivative instruments that qualify, and are accounted for, as cash flow hedges. If capitalized costs (carrying value) exceed this limit, the excess is charged to expense and reflected as additional Depletion, Depreciation and Amortization (DD&A) during the period.
 
In December 2008, the SEC released the final rule for “Modernization of Oil and Gas Reporting,” which will permit reporting of oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new rule becomes effective for the quarter ended December 31, 2009. See Note 1— Summary of Significant Accounting Policies in this Form 10-K.
 
Despite record realized prices and record revenues for 2008, the low oil and gas prices in effect at the end of the year resulted in an aggregate $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of Company’s U.S., U.K. North Sea, Canadian and Argentine proved oil and gas properties. If oil and gas prices fall below year-end levels, additional write-downs of oil and gas properties may occur. See Note 1 — Summary of Significant Accounting Policies in this Form 10-K.
 
Operating Highlights
 
We made considerable operational progress during the year, which we believe adds to our platform for long-term profitable growth in spite of hurricanes in the Gulf of Mexico and a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia. Key operational highlights include:
 
U.S. Gulf Coast
 
Gulf Coast focused on an active drilling program and restoring production impacted by the 2005 and 2008 hurricanes. In addition to drilling wells, the region also performed 358 workover and recompletion operations during 2008. Significant events affecting Gulf Coast operations include:
 
Development Projects
 
  •  At Ewing Banks 826, we completed four wells during the first half of 2008 and increased production to 6,315 b/d, up from 700 b/d at the beginning of the year. We own a 100 percent working interest in the field.
 
Exploration Projects
 
  •  In June 2008, we had a key discovery at the Geauxpher prospect located on Garden Banks Block 462 in deepwater Gulf of Mexico. Apache generated the prospect and has a 40-percent working interest. Mariner Energy, Inc. is the designated operator of the block with a 60-percent working interest. A delineation well was drilled in December 2008, extending the productive reservoir limits. We forecast the initial discovery to be online in the second quarter of 2009. Additional potential on the block is expected to be tested by further drilling.
 
Hurricanes
 
  •  During the third quarter of 2008, Hurricanes Gustav and Ike damaged onshore and offshore production and transportation facilities in our Gulf Coast region. Although most of our offshore operated platforms escaped with minor damage, we did lose four Apache-operated and two non-operated platforms. Our ability to transport and process our crude oil and natural gas production was also impacted by damages to third-party pipelines and processing facilities. The impact of the hurricanes on 2008 operations and results follows:
 
Production — Wells shut-in as a result of the hurricanes reduced 2008 production by an estimated 54.6 MMcf/d and 6,941 b/d. A substantial part of Apache’s net production shut-in by the storm was restored by the end of 2008, with only 7,700 b/d and 83 MMcf/d remaining offline. While we plan to restore nearly all of the production by mid-year 2009, the timing in many instances is beyond our control since we


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are awaiting repairs to third-party pipelines and facilities. All but approximately 1,100 boe per day of production will ultimately be restored.
 
Financial Results — The impact of the hurricanes on our 2008 financial results was an estimated $410 million of lower crude oil and natural gas revenues. We also incurred approximately $75 million of expenditures for repair, redevelopment and abandonment of properties damaged by the hurricanes. The Company anticipates an additional $170 to $190 million of costs, most of which are likely to occur in 2009. A majority of these costs will be recovered through insurance, as discussed below.
 
Insurance Coverage — The Company carries property damage insurance through Oil Insurance Limited (OIL) for windstorm damage in the Gulf of Mexico of $250 million after reaching a $100 million deductible per event. The deductible will be scaled down based on the Company’s working interest in the damaged properties and is anticipated to be $80 million. The $250 million in coverage will be prorated downward if total claims received by OIL for Hurricane Ike exceed their aggregate limit per event of $750 million. In December 2008, OIL indicated that losses for Hurricane Ike will likely exceed the aggregate limit by an amount that would cause insurance payments to be 80 percent of amounts claimed; however, the final percentage will not be known until all claims have been submitted to OIL. In addition, Apache has $150 million of property damage and business interruption insurance through the London market subject to a $350 million deductible that can be met with property damage and qualifying business interruption losses.
 
Egypt
 
In Egypt, we had a steady stream of significant discoveries during the year across basins and plays, completing 236 of 260 wells for a 91-percent success rate. The region also conducted 701 workovers and recompletions and made significant progress on the completion of several major growth projects that will underpin future production growth. Notable successes during the year include:
 
Development Projects
 
  •  In the Khalda concession, two additional Salam gas processing trains, trains three and four, and an associated Apache pipeline compression project on the Western Desert Northern Gas Pipeline are forecasted to add additional net production of 100 MMcf/d and 5,000 b/d when fully operational in the second quarter of 2009. The third processing train commenced operation on December 4, 2008. Commissioning with first gas from the fourth processing train is projected to commence during the first quarter of 2009.
 
  •  We drilled 203 waterflood wells across several concessions during 2008, increasing gross oil production from these waterflood projects 55 percent or 27,000 b/d when compared to 2007 production levels. Also, we believe that several discoveries (discussed below) in a new area called the Heba Ridge, which is adjacent to the Asala Ridge waterflood area in the East Bahariya concession, will add significantly to our inventory of waterflood projects in the concession.
 
Exploration Discoveries
 
  •  During 2008, Apache announced that the Hydra-1X exploration well in Egypt’s Western Desert test-flowed 76.6 MMcf/d and 2,813 b/d from the Deep Jurassic and overlying AEB-6 formations. The Hydra 4X well appraised this discovery. Apache has a 100-percent contractor interest in the Shushan “C” concession and is in the process of negotiating a Gas Sales Agreement with the Egyptian General Petroleum Corporation (EGPC) and, when completed, will file to establish a development lease.
 
  •  On July 30, 2008, Apache announced that the Heqet-2 well in the Greater Khalda area in Egypt’s Western Desert tested 2,100 b/d from the Jurassic Safa formation at a depth of 14,700 feet. We also announced that the Umbarka-174 well tested 4,300 b/d in the main AEB field in the north central portion of the Greater Khalda area. Both wells are currently producing, and development of these fields continues. In October 2008, we announced the WKAL-C-1X discovery on the West Kalabsha concession. The well tested 4,746 b/d and 4.4 MMcf/d in the Jurassic Safa formation. The WKAL-C-1X discovery represents the westernmost oil ever


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  discovered in Egypt, confirming our exploration model for this area of the Faghur Basin. Apache has a 100 percent contractor interest in both the Khalda and West Kalabsha concessions.
 
  •  During 2008, several new oil fields were discovered in the Bahariya formation in the East Bahariya concession. The EBAH-C-1X oil discovery identified a new area called the Heba Ridge. The initial discovery and three additional development wells were drilled in the EBAH-C field during 2008 and all were producing at year-end. A total of 40 wells are planned to fully develop the EBAH-C field. Three additional exploration discoveries in the East Bahariya concession found Bahariya oil pay in separate fields. The initial wells are expected to commence production during early 2009. Each of these discoveries will add significantly to our inventory of water-flood projects in the concession.
 
  •  Also in 2008, the Phiops-1X exploration well on the Kalabsha development lease in the Khalda area encountered a potential 374 foot oil column with 173 feet of logged pay in a secondary objective, the Cretaceous Alam El Bueib formation. The well will be tested in early 2009 and is expected to provide a significant oil reserve addition.
 
  •  In early 2009, we formally announced three new December 2008 field discoveries in Egypt’s Western Desert that tested an aggregate 80 MMcf/d and 5,909 b/d. The Sultan-3X located on the Khalda Offset Concession test-flowed 5,021 b/d and 11 MMcf/d from three commingled intervals in the Safa formation. The two other discoveries, the Adam-1X and the Maggie-1X, discovered new gas-condensate fields on the Matruh development lease north of the Sultan discovery. Apache has a 100-percent contractor interest in both of the concessions. We anticipate completion of Sultan-3X as an oil well prior to the end of first-quarter 2009, and completion of Adam-1X and Maggie-1X by year-end 2009.
 
Australia
 
In Australia, we had two notable discoveries, the Halyard-1 and Brulimar-1 as well as continued appraisal success at Julimar and Bambra. We also progressed on several major long lead-time development growth projects, including the Van Gogh and Pyrenees developments. In the Julimar-Brunello area on Australia’s Northwest Shelf, we drilled three successful appraisal wells that will allow us to pursue a development strategy after completing our assessment of commercial options. Also, our subsidiaries made considerable progress in restoring operations at the Varanus Island gas processing and transportation hub, which sustained damage from a gas pipeline explosion in June 2008. Lastly, on January 6, 2009, we secured a 154 Bcf, seven-year gas sales contract that enabled us to reinstate our Reindeer development program. These discoveries and developments are discussed in more detail below.
 
Development and Appraisal Projects
 
  •  We have several large development projects underway in Australia. The Van Gogh and Pyrenees developments remain on schedule to deliver first production in 2009 and 2010, respectively, each with projected net rates of 20,000 b/d. Our Reindeer development program was reinstated following signing of a gas-supply contract (discussed below) and is scheduled to deliver approximately 60 MMcf/d net to Apache in late 2011. Construction of pipeline and processing infrastructure is scheduled to commence in 2009.
 
  •  On January 6, 2009, the Company announced that it had signed a contract to supply natural gas from the Reindeer field to CITIC Pacific’s Sino Iron project in Western Australia. The terms call for Apache and its joint venture partner to supply 154 billion cubic feet of gas over seven years beginning in the second half of 2011. Apache owns a 55 percent interest in the field. The gas will be supplied through a new 65-mile offshore pipeline and a new onshore sales gas processing facility at Devil Creek.
 
  •  Appraisal of the Julimar-Brunello area on Australia’s Northwest Shelf progressed with three appraisal wells. In January 2008, we announced the Brulimar-1 discovery, which encountered 113 feet of net pay in the Upper Triassic Mungaroo sandstone. In April, we announced the Julimar Southeast-1 discovery, which logged 195 feet of net pay across five intervals of the Triassic Mungaroo sandstone. In May, we announced the Julimar Northwest-1 discovery, which logged 43 feet of net pay in the J-17 Triassic Mungaroo sandstone. We have now drilled seven discoveries in the complex. We plan to complete our appraisal program by mid-


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  year and pursue a development strategy in the second half of 2009 after completing our assessment of commercial options. The Julimar development will not require funding until we determine which market is best suited for the asset. Apache is evaluating LNG options as well as domestic-market options for Julimar gas. Apache owns a 65 percent interest in and operates the Julimar-Brunello complex.
 
Exploration Discoveries
 
  •  In April, we announced the Halyard-1 discovery on Australia’s WA-13-L block, which test-flowed 68 MMcf/d. We are currently in the development design phase that includes consideration of a sub-sea gathering line from Halyard to an existing pipeline at our East Spar field, 10 miles to the southeast, from which the gas can be transported to Varanus Island for processing. Using our existing infrastructure would accelerate development of the field and first sales. Apache obtained governmental approval for the Halyard Field development during the third quarter of 2008, and we are working toward first production in 2010. Apache has a 55 percent interest in and operates the block.
 
  •  We are currently evaluating the results of wells drilled in 2008 and seismic information to assess the future potential in the Gippsland basin. All six wells drilled in 2008 were either dry or non-commercial.
 
Varanus Island
 
  •  On June 3, 2008, subsidiaries of the Company reported a gas pipeline explosion at the Varanus Island gas processing and transportation hub offshore Western Australia, which shut-in production at the John Brookes field and Harriet Joint Venture. When fully operational, the Island’s operations process approximately 195 MMcf/d and 5,400 b/d, net to Apache subsidiaries. On August 5, 2008, partial production was reestablished from the John Brookes field, and by year-end was at greater than 80 percent pre-incident levels. The Harriet Joint Venture gas facilities are located adjacent to the pipeline explosion and required more significant repairs to restore operation. A portion of our gas production from the Harriet Joint Venture was restored in December 2008 and is projected to be fully restored in the first half of 2009. Harriet Joint Venture oil production is projected to be fully restored in the first quarter of 2009. The John Brookes field accounted for approximately 60 percent and 25 percent of the island’s pre-incident natural gas and oil production, respectively. Production from the Harriet Joint Venture accounted for the remaining 40 percent and 75 percent of the island’s pre-incident natural gas and oil production, respectively. Company subsidiaries operate the facilities and own a 68.5 percent interest in the Harriet Joint Venture and a 55 percent interest in the John Brookes field. Company subsidiaries maintain replacement cost insurance, subject to a deductible of approximately $7 million, with adequate limits to cover fully their share of the estimated cost of restoring the Varanus Island facilities.
 
Canada
 
During 2008, the Canadian region had an active development drilling program and commenced pursuit of an emerging shale-gas play in northeast British Columbia. Notable activities during the year include:
 
Exploration Projects
 
  •  During 2008, the Company completed a total of seven horizontal wells in the Ootla shale-gas play, located in northeast British Columbia. December gross production averaged 2.5 MMcf/d. Current plans for the Ootla development in 2009 include drilling 31 gross horizontal wells and construction of compression and gathering infrastructure required to take the additional production to existing processing facilities. Based on information obtained from these wells, Apache expects to achieve significant improvements in both production rate and reserves per well. Apache has a 50 percent interest and operates approximately one-half of its 400,000 gross acreage position in the play.


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Development Projects
 
  •  Apache continues to target shallow gas, including coal bed methane (CBM), in areas such as Nevis, North Grant Lands and Provost. Intermediate-depth drilling continued in the Kaybob, West 5 and South Grant Land areas of central and southern Alberta.
 
North Sea
 
Throughout 2008, the North Sea region invested in drilling and recompleting wells and facility enhancement programs. Key activities include:
 
Development Projects
 
  •  During 2008, we completed 12 new development wells in the Forties field, which flowed at a combined rate of 18,900 b/d.
 
  •  Investments in facility upgrades and integrity-related projects over the past five years have significantly reduced platform downtime. Coupled with production from new wells, these improved platform operating efficiencies enabled the region’s fourth-quarter 2008 production to reach an average 61,740 b/d. Annual production averaged 59,494 b/d, an 11 percent increase from 2007.
 
Argentina
 
During 2008, the Argentina region pursued active drilling and recompletion programs. In total, the region drilled 83 wells, 72 of which were productive. Significant activities include:
 
Development Projects
 
  •  Apache drilled 30 new wells in the Neuquén basin, with a success rate of 100 percent, and continued to exploit two new plays with an aggressive drilling and recompletion campaign.
 
Exploration Projects
 
  •  In 2008, Apache completed a nearly 2,500 square kilometer 3-D seismic mega shoot in Tierra del Fuego. Twenty-nine wells were drilled in Tierra del Fuego, resulting in a number of new exploration discoveries and field extensions. Notable successes included the completion of the first phase appraisal campaign in the 2008 Sección Baños block and the successful appraisal of La Sara Norte. We also made exploration discoveries at Las Flechas, Sección Veintinueve, Camino Real and Perla.
 
  •  In the Cuyo basin, Apache was awarded the 4,710 square kilometer CC&B-17 B block adjacent to and along a trend of existing producing fields, which increased our Argentine acreage portfolio by 34 percent.
 
Chile
 
  •  During the third quarter of 2008, we commenced a seismic program on the two exploration blocks acquired in 2008.


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Results of Operations
 
Revenues
 
                                 
    Crude Oil     Natural Gas     NGL’s     Total  
          (In thousands)        
 
2006 Revenues
  $ 4,911,861     $ 3,001,246     $ 161,146     $ 8,074,253  
Volume increase (decrease)
    616,179       404,311       16,214       1,036,704  
Price increase (decrease)
    827,725       34,111       21,680       883,516  
Impact of hedges increase (decrease)
    (96,640 )     64,149             (32,491 )
                                 
Increase (decrease) in 2007
  $ 1,347,264     $ 502,571     $ 37,894     $ 1,887,729  
2007 Revenues
  $ 6,259,125     $ 3,503,817     $ 199,040     $ 9,961,982  
Contribution to total revenues
    63 %     35 %     2 %     100 %
Volume increase (decrease)
    174,718       (426,055 )     (33,183 )     (284,520 )
Price increase (decrease)
    2,174,202       894,818       40,025       3,109,045  
Impact of hedges increase (decrease)
    (450,802 )     (7,866 )           (458,668 )
                                 
Increase (decrease) in 2008
  $ 1,898,118     $ 460,897     $ 6,842     $ 2,365,857  
2008 Revenues
  $ 8,157,243     $ 3,964,714     $ 205,882     $ 12,327,839  
Contribution to total revenues
    66 %     32 %     2 %     100 %
 
Oil and Natural Gas Prices
 
Crude Oil Prices — A substantial portion of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Apache’s oil realizations climbed precipitously in the first half of the year reaching a record $118.38 per barrel in June, before collapsing in the fourth quarter. Our realized oil price in December averaged nearly 70 percent lower than June’s peak, as demand for energy dropped following the onset of the global financial crisis. Apache manages a portion of its exposure to fluctuations in crude oil prices, primarily in North America, using financial instruments. In 2008, the 19 percent of our oil production that was subject to financial derivative hedges reduced revenues by $451 million, which comprised a $472 million loss in the first nine months and a $21 million gain in the fourth quarter of 2008. Refer to Note 3 — Hedging and Derivative Instruments for the year-end status of our derivatives.
 
While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a worldwide market. With the exception of Argentina, price movements for all types and grades of crude oil generally move in the same direction. In Argentina, we are currently selling our oil in the domestic market. The Argentine government previously imposed a sliding-scale tax on oil exports, which effectively limits prices buyers are wiling to pay. Domestic oil prices are currently based on a $42 per barrel price, subject to quality adjustments, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar price formulas exist, but producers retain value-added tax collected from buyers, effectively increasing price realizations by 21 percent.
 
Natural Gas Prices — Natural gas, which has a limited global transportation system, is subject to price variances stemming from local supply and demand conditions. The majority of our gas sales contracts are indexed to prevailing local market prices. Apache uses a variety of strategies to manage its exposure to fluctuations in natural gas prices, primarily in North America, including fixed-price contracts and derivatives. In 2008, the 20 percent of our gas production that was subject to financial derivative hedges reduced revenues by $8 million, which comprised a $29 million loss for the first nine months and a gain of $21 million in the fourth quarter of 2008. Refer to Note 3 — Hedging and Derivative Instruments for the year-end status of our derivatives.
 
Apache primarily sells natural gas into four markets:
 
1) North America, which has a common market and where most of our gas is sold on a monthly or daily basis at either monthly or daily market prices.


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2) Egypt, where the majority of our gas is sold to Egyptian General Petroleum Corporation (EGPC) under an industry pricing formula indexed to Dated-Brent crude oil with a maximum gas price of $2.65 per MMbtu. On up to 100 MMcf/d gross, there is no price cap for our gas under a legacy contract which expires in 2013.
 
3) Australia, which has a local market with mostly long-term fixed-price contracts that are periodically adjusted for changes in Australia’s consumer price index. Subsequent to year-end, however, Apache signed a contract on 85 bcf (net) that is indexed to oil prices following an initial period of fixed prices.
 
4) Argentina, where we receive low government-regulated pricing on a substantial portion of our production. The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors and industry category. During the year, we realized an average price of $.92 per Mcf on government regulated sales. The majority of the remaining volumes were sold at market-driven prices, which exceeded $2.00 per Mcf at year-end. Our average price for 2008 was $1.61 per Mcf.
 
For specific more information on marketing arrangements by country, please refer to Item 1 and 2, “Business and Properties” of this Form 10-K.
 
Production and Pricing
 
                                         
    For the Year Ended December 31,  
          Increase
          Increase
       
    2008     (Decrease)     2007     (Decrease)     2006  
 
Oil Volume — Barrels per day:
                                       
United States
    89,797       (1.06 )%     90,759       35.80 %     66,832  
Canada
    17,154       (8.54 )%     18,756       (9.46 )%     20,715  
Egypt
    66,753       9.91 %     60,735       7.36 %     56,570  
Australia
    8,249       (40.13 )%     13,778       15.86 %     11,892  
North Sea
    59,494       10.93 %     53,632       (8.39 )%     58,544  
Argentina
    12,409       8.47 %     11,440       66.84 %     6,857  
China
          NM             NM       3,167  
                                         
Total(1)
    253,856       1.91 %     249,100       10.92 %     224,577  
                                         
Average Oil price — Per barrel:
                                       
United States
  $ 83.70       25.90 %   $ 66.48       22.61 %   $ 54.22  
Canada
    93.53       36.96 %     68.29       14.01 %     59.90  
Egypt
    91.37       26.01 %     72.51       14.01 %     63.60  
Australia
    91.78       15.03 %     79.79       16.91 %     68.25  
North Sea
    95.76       35.01 %     70.93       12.52 %     63.04  
Argentina
    49.46       7.55 %     45.99       7.48 %     42.79  
China
          NM             NM       62.73  
Total(2)
    87.80       27.54 %     68.84       14.89 %     59.92  
Natural Gas Volume — Mcf per day:
                                       
United States
    679,876       (11.66 )%     769,596       15.39 %     666,965  
Canada
    352,731       (9.14 )%     388,211       (3.99 )%     404,325  
Egypt
    263,711       9.52 %     240,777       10.65 %     217,601  
Australia
    123,003       (36.90 )%     194,928       4.73 %     186,119  
North Sea
    2,637       36.42 %     1,933       (6.21 )%     2,061  
Argentina
    195,651       (2.61 )%     200,903       79.39 %     111,994  
                                         
Total(3)
    1,617,609       (9.95 )%     1,796,348       13.04 %     1,589,065  
                                         
Average Natural Gas price — Per Mcf:
                                       


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    For the Year Ended December 31,  
          Increase
          Increase
       
    2008     (Decrease)     2007     (Decrease)     2006  
 
United States
  $ 8.86       25.85 %   $ 7.04       7.65 %   $ 6.54  
Canada
    7.94       26.03 %     6.30       3.45 %     6.09  
Egypt
    5.25       14.13 %     4.60       4.07 %     4.42  
Australia
    2.10       11.11 %     1.89       14.55 %     1.65  
North Sea
    18.78       24.95 %     15.03       41.26 %     10.64  
Argentina
    1.61       37.61 %     1.17       20.62 %     .97  
Total(4)
    6.70       25.47 %     5.34       3.29 %     5.17  
Natural Gas Liquids (NGL) Volume — Barrels per day:
                                       
United States
    5,986       (22.28 )%     7,702       (3.54 )%     7,985  
Canada
    2,076       (7.57 )%     2,246       2.70 %     2,187  
Argentina
    2,887       3.11 %     2,800       82.17 %     1,537  
                                         
Total
    10,949       (14.11 )%     12,748       8.87 %     11,709  
                                         
Average NGL Price — Per barrel:
                                       
United States
  $ 58.62       29.58 %   $ 45.24       17.38 %   $ 38.54  
Canada
    49.33       21.65 %     40.55       14.55 %     35.40  
Argentina
    37.83       0.13 %     37.78       3.11 %     36.64  
Total
    51.38       20.10 %     42.78       13.47 %     37.70  
 
 
(1) Approximately 19 percent of 2008 oil production was subject to financial derivative hedges, compared to 17 percent in 2007 and nine percent in 2006.
 
(2) Reflects per-barrel reductions of $4.85 in 2008, $1.06 in 2007 and $1.37 in 2006 from financial derivative hedging activities.
 
(3) Approximately 20 percent of 2008 gas production was subject to financial derivative hedges, compared to 17 percent in 2007 and eight percent in 2006.
 
(4) Reflects per-Mcf reduction of $.01 in 2008, increase of $.10 in 2007 and reduction of $.05 in 2006 from financial derivative hedging activities.
 
NM — Not Meaningful
 
Year 2008 Compared to Year 2007
 
Crude Oil Revenues
 
Apache’s 2008 consolidated crude oil revenues increased $1.9 billion on a 28 percent increase in average realized price and a two percent increase in daily production.
 
U.S. oil revenues were up $549 million, driven by a 26 percent increase in realized crude oil prices, more than offsetting one percent lower production. Prices in the U.S. averaged $83.70 per barrel in 2008, up 26 percent from 2007. Gulf Coast region oil was 2,700 b/d lower, reflecting the impact of hurricanes, which reduced the region’s 2008 production by 6,941 b/d. Central region production was up five percent resulting primarily from production increases on the Permian basin properties acquired at the end of March 2007 and new drilling and recompletion activity in 2008.
 
Egypt’s crude oil revenues increased $625 million on a 26 percent increase in realized price and a 10 percent increase in production. Price realizations averaged $91.37 per barrel, up from $72.51 per barrel in the prior year. Increases in oil production came from wells at El Diyur, Umbarka and East Bahariya, as well as higher cost recovery

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volumes related to accelerated capital spending on the Salam gas plant expansion. These increases more than offset lower condensate volumes at Khalda because of scheduled Obayed and Salam plant shutdowns.
 
North Sea oil revenues increased $697 million, a 50 percent increase over last year. Revenue gains were driven by a 35 percent increase in realized price and an 11 percent increase in production. Oil price realizations averaged $95.76, up $24.83 per barrel. Production was higher on a successful drilling and workover program and a reduction in platform downtime.
 
Canada’s oil revenues increased $120 million. Realized prices were up 37 percent and averaged $93.53 per barrel. Daily production declined nine percent on natural decline in various fields and divested properties, which more than offset drilling and recompletion activity.
 
Argentina’s crude oil revenues increased $33 million, with both production and realized prices up eight percent. Higher production was related to successful drilling, workover and recompletion activities, particularly in Tierra del Fuego. Realized prices increased on favorable quality adjustments received for oil which remains subject to price restrictions, as well as increased production from Tierra del Fuego, a tax favored area where producers retain the 21 percent value-added tax collected from buyers.
 
Australia’s 2008 oil revenues fell $124 million from 2007 on a 40 percent decline in production, which more than offset a 15 percent increase in realized prices. Nearly half of the production decline resulted from wells shut-in following a pipeline explosion on June 3, 2008 at the Varanus Island gas processing and transportation hub. The remaining decrease is related to a natural decline. Partial production from our John Brookes field, and the associated condensate yields, was brought back on-line in August, and by year-end the field was at 80 percent pre-incident levels. Harriet field oil production was mostly restored by year-end and should be fully restored in early 2009. Condensate yields associated with Harriet gas production, which recommenced in December 2008, are expected to be fully restored in the first half of 2009 when repairs to the Harriet Joint Venture facility are completed.
 
Natural Gas Revenues
 
Apache’s 2008 consolidated natural gas revenues increased $461 million, driven by a 25 percent increase in realized natural gas prices. Worldwide daily production was down 10 percent from 2007.
 
U.S. natural gas revenues increased $227 million on higher prices as production declined 12 percent. Natural gas prices averaged $8.86, up $1.82 per Mcf. Central region gas production was up three percent on drilling and recompletion activities and incremental volumes from Permian basin properties acquired at the end of March 2007. Gulf Coast daily production was 21 percent lower on downtime, natural decline and a delay in Apache’s drilling program related to the hurricanes.
 
Canada’s natural gas revenues rose $134 million on a 26 percent increase in realized natural gas prices. Gas price realizations climbed $1.64 to $7.94 per Mcf. Natural gas production decreased nine percent because of natural decline in various areas and property divestitures in early 2008.
 
Egyptian gas revenues were up $103 million over 2007 on a 14 percent increase in price realizations and a 10 percent rise in production. Production rose on successful recompletions at our Matruh concession, new wells brought online at the Northeast Abu Gharadig concession and higher cost recovery volumes associated with an increase in capital spending related to the Salam gas plant expansion.
 
Argentina’s natural gas revenues increased $30 million on a 38 percent increase in realized price, offset by a three percent decline in daily production. Gas production was negatively impacted by gas re-injections at Tierra del Fuego resulting from gas export and pipeline restrictions. Realized gas prices increased given the more favorable sales mix attained during the year. Relative to last year, we were able to deliver more volumes under higher priced industry contracts. We also benefited from a year over year increase in residential gas prices.
 
Australia’s natural gas revenues fell $40 million on a 37 percent drop in production. Volumes were impacted by production shut-in after an explosion on the pipeline that transports all of our gas production in Australia and resulting fire that damaged our processing facilities, as previously discussed. Following the incident, both the John Brookes and Harriet fields were shut-in for approximately two months. John Brookes was the first field to come back online, with volumes partially restored in August and ramping up in subsequent months. Harriet production


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came back online in December at reduced rates. At year-end, John Brookes produced 80 percent of pre-incident levels, while Harriet saw approximately one-third of its pre-incident volumes restored. Repairs are expected to be completed late in the first half of 2009.
 
Year 2007 Compared to Year 2006
 
Crude Oil Revenues
 
Apache’s 2007 consolidated crude oil revenues totaled $6.3 billion, $1.3 billion above 2006, with nearly equal contributions from an 11 percent rise in production and a 15 percent increase in our realized oil price. On the whole, production increased an average 24,523 b/d, driven by the U.S. which was up 23,927 b/d. Crude oil price realizations averaged $68.84 per barrel for the year, $83.00 in the fourth quarter alone.
 
U.S. oil revenues were up $879 million to $2.2 billion with $580 million, or two-thirds of the increase, attributable to a 36 percent increase in production. A 23 percent increase in realized prices added the remaining $299 million. Gulf Coast production climbed 48 percent to 53,842 b/d, mainly on production restored from hurricane-damaged properties, a full year of production from Gulf of Mexico properties acquired in June 2006 and successful drilling and recompletion activities. Central region production grew 21 percent to 36,917 b/d, with the addition of Permian basin properties acquired from Anadarko Petroleum Corporation (Anadarko) in March 2007 and successful drilling and recompletion activities.
 
In Egypt, crude oil revenues rose $294 million, to $1.6 billion, with increased production generating an additional $110 million of revenues. The balance of the increase in revenues, $184 million, came from a 14 percent increase in realized prices, which were up $8.91 to $72.51 per barrel. Daily production averaged 60,735 b/d, up seven percent. Production gains were associated with development drilling in the Khalda and Matruh concessions as well as the East Bahariya, Umbarka, El Diyur and North El Diyur concessions.
 
Australia’s crude oil revenues of $401 million increased 35 percent, or $105 million. Production was 16 percent higher generating $55 million of the increase. Production growth resulted from an additional interest acquired in the Legendre field, completion of West Cycad wells and increased liquids from the Bambra, Wonnich Deep, Doric and Lee gas wells. Australia’s price realizations rose 17 percent to $79.79 per barrel, the highest in the Company, generating an additional $50 million of revenue.
 
Argentina’s oil revenues increased $85 million to $192 million, with over 90 percent of the increase associated with 67 percent higher production. The year 2007 benefited from a full year of production from acquisitions made in 2006, as well as successful drilling, workover and recompletion activity during the year. Higher volumes added $77 million to revenues, with price increases adding $8 million. Argentina’s realized oil prices averaged $45.99 per barrel, up seven percent from the prior year.
 
North Sea oil revenues increased $41 million to $1.4 billion. Oil prices averaged $70.93 per barrel, up 13 percent, adding $168 million in revenues. Production averaged 53,632 b/d, down eight percent, reducing revenues by $127 million. Production increases on three of our platforms were more than offset by declines from wells at the Alpha and Echo platforms while drilling operations were suspended for facility upgrades.
 
Canada’s oil revenues increased $15 million to $467 million, with a 14 percent price increase mostly offset by a nine percent decline in production. Prices averaged $68.29 per barrel, up from $59.90 in 2006. Production dropped in 2007 primarily because of natural decline resulting from a 38 percent reduction in exploration and development capital invested in Canada compared to 2006.
 
China had no crude oil revenues in 2007 compared to $73 million in the prior year, a result of our August 2006 asset divestiture and exit from China.
 
Natural Gas Revenues
 
Apache’s natural gas revenues increased 17 percent, or $503 million, to $3.5 billion. Higher production contributed $405 million of the additional revenues. Gas production averaged 1,796 MMcf/d, up 13 percent from 2006. Natural gas prices increased $.17 to an average $5.34 per Mcf, generating an additional $98 million in revenue.


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U.S. natural gas revenues grew by $385 million to nearly $2 billion. U.S. production rose 15 percent, boosting revenues $264 million. Gulf Coast production increased 16 percent, boosted by final production restoration on hurricane-damaged properties, a full year of production from Gulf of Mexico properties acquired in June 2006 and successful drilling and recompletion activities. Central region production climbed 14 percent on successful drilling and recompletion activities and the addition of Permian basin properties acquired in March 2007. Higher natural gas prices, which averaged $7.04 per Mcf compared to $6.54 in 2006, added $121 million to revenues.
 
Gas revenues in Egypt were up $53 million, to $404 million, on an 11 percent increase in production and a four percent increase in price realizations. Production gains of 23 MMcf/d boosted the region’s average output to 241 MMcf/d, generating an additional $39 million in revenues. Production gains resulted from higher throughput and less downtime at the Obaiyed plant compared to 2006 and new wells in the North East Abu Gharadig (NEAG) concession. Higher prices added another $14 million.
 
Australia’s natural gas revenues increased $22 million to $134 million on higher price realizations and production gains. Price realizations improved 15 percent, adding $16 million to revenues. A five percent demand-driven rise in production generated another $6 million of revenues.
 
Argentina’s natural gas revenues more than doubled to $86 million, bolstered by a full year of production from 2006 property acquisitions, successful drilling and recompletion activities and a 21 percent increase in price realizations. Production grew 89 MMcf/d, or 79 percent, generating $38 million of new revenues. The price gain added another $8 million.
 
Canada’s natural gas revenues decreased $6 million to $892 million on a four percent decline in production. Production, which averaged 388 MMcf/d, was impacted by natural decline, which more than offset increases from drilling and recompletion activities. Our exploration and development capital investment in Canada was 38 percent lower than 2006. Lower production reduced revenues by $37 million. Natural gas prices rose $.21, to $6.30 per Mcf, increasing revenues $31 million.
 
Costs
 
The table below compares our costs on an absolute dollar and boe basis. Our discussion may reference expenses either on a boe basis or on an absolute dollar basis, or both, depending on their relevance.
 
                                                 
    Year Ended December 31,     Year Ended December 31,  
    2008     2007     2006     2008     2007     2006  
    (In millions)     (Per boe)  
 
Depreciation, depletion and amortization:
                                               
Oil and gas property and equipment Recurring
  $ 2,358     $ 2,208     $ 1,699     $ 12.06     $ 10.78     $ 9.29  
Additional
    5,334                   27.27              
Other assets
    158       140       118       .81       .68       .64  
Asset retirement obligation accretion
    101       96       89       .52       .47       .48  
Lease operating expenses
    1,909       1,653       1,323       9.76       8.07       7.23  
Gathering and transportation
    157       137       120       .80       .67       .66  
Taxes other than income
    985       598       598       5.03       2.92       3.27  
General and administrative expenses
    289       275       211       1.48       1.34       1.16  
Financing costs, net
    166       220       142       .85       1.07       .78  
                                                 
Total
  $ 11,457     $ 5,327     $ 4,300     $ 58.58     $ 26.00     $ 23.51  
                                                 


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Year 2008 Compared to Year 2007
 
Depreciation, Depletion and Amortization
 
The following table details the changes in recurring depreciation, depletion and amortization (DD&A) of oil and gas properties between 2008 and 2007:
 
         
    Recurring DD&A  
    (In millions)  
 
2007
  $ 2,208  
Volume change
    (127 )
Rate change
    277  
         
2008
  $ 2,358  
         
 
Recurring full-cost depletion expense increased $150 million, $277 million on rate partially offset by $127 million on lower volumes. Our full-cost depletion rate increased $1.28 to $12.06 per boe on drilling and finding costs that exceeded our historical cost basis. The higher industry-wide costs, which also impact estimates of future development costs, have been driven by increased demand for drilling services, a consequence of higher oil and gas prices.
 
In addition, we recorded a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of our December 31, 2008 proved property balances in the U.S., U.K. North Sea, Canada and Argentina proved oil and gas properties. Under the full-cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing future oil and gas production at the unescalated oil and gas prices and costs in effect at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded, even if prices declined for only a short period of time. Write-downs required by these rules do not impact cash flow from operating activities. If oil and gas prices deteriorate from the Company’s year-end levels, additional write-downs may occur.
 
Lease Operating Expenses
 
Lease operating expenses (LOE) include several components: direct operating costs, repair and maintenance, and workover costs.
 
Direct operating costs generally trend with commodity price levels and are impacted by the type of commodity produced and the location of properties (i.e. offshore, onshore, remote locations, etc). Rising commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Other items such as labor, boats, helicopters and materials and supplies are indirectly impacted as high prices increase industry activity and demand and thus, costs. Oil, which contributed nearly half of our production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are higher on offshore properties and in areas with remote plants and facilities. All production in Australia and the North Sea and nearly 90 percent from the U.S. Gulf Coast region comes from offshore properties. Workovers accelerate production; hence, activity generally increases with higher commodity prices. Fluctuations in exchange rates impact the Company’s LOE, with a weakening U.S. dollar adding to per-unit costs and a strengthening U.S. dollar lowering per unit costs in our international regions.
 
LOE increased 15 percent on an absolute dollar basis. On a per-unit basis LOE was up 21 percent, or $1.69 per boe. The following discussion focuses on per-unit costs which we believe to be the most meaningful measure for analyzing LOE.
 
  •  Higher operating costs in all regions, including increased power costs in the U.S. and Egypt along with increased labor costs in the North Sea and Argentina, drove the rate up $.33.
 
  •  Increased workover activity, primarily in the U.S. and Egypt, resulted in an increase of $.29.


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  •  Hurricane repairs in the U.S. contributed $.07 to increased cost.
 
  •  Repairs related to the pipeline explosion at Varanus Island in Australia added $.03.
 
  •  Non-recurring repairs and maintenance in Egypt, Australia, the North Sea and Argentina increased $.07.
 
  •  Overall production declines resulted in an increase of $.45, with the impact from a combined 12 percent production decline in the U.S., Canada and Australia partially offset by increased production in Egypt, the North Sea and Argentina. The main contributors were decreased production in Australia, $.30, and production shut-in because of the hurricanes, $.29.
 
Gathering and Transportation
 
We generally sell oil and natural gas under two common types of agreements, both of which include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a lower relative price to reflect transportation costs to be incurred by the purchaser. In this case, we record sales at the netback price received from the purchaser. Alternatively, we sell oil or natural gas at a specific delivery point, pay our own transportation to a third-party carrier and receive a price with no transportation deduction. In this case we record the separate transportation cost as gathering and transportation costs.
 
In both the U.S. and Canada, we sell oil and natural gas under both types of arrangements. In the North Sea, we pay transportation to a third-party carrier. In Australia, oil and natural gas are sold under netback arrangements. In Egypt, our oil and natural gas production is primarily sold to EGPC under netback arrangements; however, we also export crude oil under both types of arrangements. In Argentina, we sell oil and natural gas under both types of arrangements.
 
The following table presents gathering and transportation costs we paid directly to third-party carriers for each of the periods presented:
 
                 
    For the Year Ended
 
    December 31,  
    2008     2007  
    (In millions)  
 
U.S. 
  $ 39     $ 38  
Canada
    64       54  
North Sea
    28       27  
Egypt
    21       15  
Argentina
    5       3  
                 
Total Gathering and Transportation
  $ 157     $ 137  
                 
Total Gathering and Transportation per boe
  $ .80     $ .67  
                 
 
These costs are primarily related to the portion of natural gas in our U.S. and Canadian operation sold under arrangements where we pay transportation directly to third parties North Sea crude oil sales and our Egyptian crude oil exports not sold under netback arrangements. The $20 million increase was driven primarily by higher transportation tariffs in Canada and an increase in Egyptian export volumes.
 
Taxes other than Income
 
Taxes other than income primarily comprises United Kingdom (U.K.) Petroleum Revenue Tax (PRT), severance taxes on properties onshore and in state or provincial waters in the U.S. and Australia and ad valorem taxes on properties in the U.S. and Canada. Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties field in the U.K. North Sea. We are subject to a variety of other taxes including U.S. franchise taxes, Australian Petroleum Resources Rent tax and various Canadian taxes including: Freehold


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Mineral tax, Saskatchewan Capital tax and Saskatchewan Resources Surtax. We also pay taxes on invoices and bank transactions in Argentina. The table below presents a comparison of these expenses:
 
                 
    For the Year Ended
 
    December 31,  
    2008     2007  
    (In millions)  
 
U.K. PRT
  $ 695     $ 346  
Severance taxes
    168       142  
Ad valorem taxes
    71       56  
Other taxes
    51       54  
                 
Total Taxes other than Income
  $ 985     $ 598  
                 
Total Taxes other than Income per boe
  $ 5.03     $ 2.92  
                 
 
U.K. PRT was $349 million more than 2007 on a 98 percent increase in net profits, driven by higher oil revenues. The increase in severance taxes resulted from higher taxable revenues in the U.S., consistent with the higher realized oil and natural gas prices in the first nine months of the year. The $15 million increase in ad valorem taxes resulted from higher taxable valuations associated with increases in oil and natural gas prices at the time the taxes were assessed and a full year of taxes on the Permian Basin properties acquired in the first quarter of 2007.
 
General and Administrative Expenses
 
General and administrative expenses (G&A) were $14 million higher. On a boe basis, G&A averaged $1.48, up $.14 per boe on a combination of increased costs and lower volumes, each of which added $.07 to the rate. The cost increase was driven by higher legal fees, especially in our international operations, increased incentive compensation expenses and miscellaneous higher costs in several departments, partially offset by a decrease in stock-based compensation expenses related to cash settled stock appreciation rights.
 
Financing Costs, Net
 
The major components of financing costs, net, include interest expense and capitalized interest. Net financing costs for 2008 decreased $54 million or $.22 per boe, on lower average outstanding debt balances. Interest expense was down $28 million on lower average debt. Capitalized interest was up primarily because of higher expenditures associated with long-term construction projects that are under development.
 
Provision for Income Taxes
 
There were no significant changes in statutory tax rates in the major jurisdictions in which the Company operates during 2008. In 2007 we saw a significant reduction to deferred income taxes resulting from Canadian tax rate reductions.
 
The provision for income taxes decreased $1.6 billion from 2007 to $220 million, as income before taxes decreased 80 percent as a result of the $5.3 billion in additional DD&A recorded in conjunction with the ceiling test write-down. The effective income tax rate for the year was 23.6 percent compared to 39.8 percent in 2007. The 2008 effective rate was impacted by the magnitude of the taxes related to the write-down, non-cash benefits related to the effect of the strengthening U.S. dollar on our foreign deferred tax liabilities and other net tax settlements. Excluding these items, the 2008 effective rate would have been comparable to the 2007 effective rate. The 2007 effective rate was impacted by a non-cash charge related to the effect of the weakening U.S. dollar on our foreign deferred tax liabilities. Partially offsetting this charge was an out of period benefit from Canadian federal tax rate reductions enacted in the second and fourth quarters of 2007.


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Year 2007 Compared to Year 2006
 
Depreciation, Depletion and Amortization
 
The following table details the changes in depreciation, depletion and amortization (DD&A) of oil and gas properties between 2007 and 2006:
 
         
    DD&A  
    (In millions)  
 
2006
  $ 1,699  
Volume change
    210  
Rate change
    299  
         
2007
  $ 2,208  
         
 
Full-cost DD&A expense totaled $2.2 billion, $509 million more than 2006. Production growth drove $210 million of the increase; the remainder is a consequence of higher costs. DD&A per boe averaged $10.78, $1.49 higher than 2006 as the costs to acquire, find and develop reserves continued to exceed our historical cost basis. Increasing costs also impact our estimates for future development of known reserves and estimates to abandon properties, both of which impact our full-cost depletion rate.
 
DD&A on other assets increased $22 million to $140 million with facilities coming online, in Canada, Egypt and the U.S. A full year of DD&A on assets acquired during 2006 in Argentina also contributed to the year-over-year increase.
 
Lease Operating Expenses
 
Lease operating expenses (LOE) increased 25 percent on an absolute dollar basis. On a per-unit basis LOE was up 12 percent, or $.84 per boe. Almost two-thirds of the increase was from additional workover activity ($.16), a weakening U.S. dollar ($.16), hurricane repair activity ($.15) and incentive-based compensation ($.07). The remaining increase is the result of the inflationary impact of higher commodity prices on all other operating costs, as described above.
 
The U.S. contributed $.47 to the $.84 per boe increase. Driving factors in the increase were additional hurricane repairs ($.15), more workover activity ($.13), acquired Permian basin oil properties which carry a higher rate than our historical average ($.05), incremental incentive-based compensation with Apache’s rising stock price ($.04) and the inflationary impact higher commodity prices have on operating costs ($.05). Over two-thirds of the increase in workover activity occurred on properties acquired in March 2007 in the Permian basin of West Texas.
 
Canada added $.30 per boe to the consolidated rate, $.09 of which was attributed to a decline in relative production. A weakening U.S. dollar negatively impacted the rate an additional $.09. The balance of the increase related to higher levels of workover activity ($.03), lease rentals ($.02), company labor ($.02) and generally higher costs.
 
The North Sea increased the consolidated rate $.09 per boe: the net impact of a $.10 per boe increase on a decline in production volumes and a reduction of $.01 on lower costs. The benefit of decreases in diesel fuel consumption ($.08) and lower turnaround expenses more than offset increases from the impact of the weakening U.S. dollar ($.05), higher standby and supply boat costs ($.01) and higher contract labor ($.01). We are seeing the benefits of several years of facility upgrades to reduce the operating costs, including completion of our power generation ring.
 
Australia increased the consolidated rate $.09 per boe over 2006. The increase was primarily a result of our acquisition of an additional interest in Legendre, an oil field which carries a higher cost per barrel than our existing blended Australian rate ($.06), and appreciation of the Australian dollar relative to the U.S. dollar ($.02).
 
Two Argentine acquisitions, in April and September 2006, lowered the 2007 consolidated rate $.13 per boe. The LOE rate on these properties was lower than our existing consolidated rate.


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Egypt had no impact on the consolidated rate. Our 2006 exit from China increased the 2007 consolidated rate $.04 per boe.
 
Gathering and transportation
 
Gathering and transportation costs totaled $137 million, up $17 million. The following table presents gathering and transportation costs paid by Apache to third-party carriers for each of the periods presented.
 
                 
    For the Year Ended
 
    December 31,  
    2007     2006  
    (In millions)  
 
U.S. 
  $ 38     $ 32  
Canada
    54       50  
North Sea
    27       26  
Egypt
    15       11  
Argentina
    3       1  
                 
Total Gathering and Transportation
  $ 137     $ 120  
                 
Total Gathering and Transportation per boe
  $ .67     $ .66  
                 
 
These costs are primarily related to the portion of natural gas in our U.S. and Canadian operation sold under arrangements where we pay transportation directly to third parties, and North Sea crude oil sales and our Egyptian crude oil exports not sold under netback arrangements. The $17 million increase was driven primarily by U.S. production growth, an increase in Egyptian crude exports not sold under netback arrangements and a full year of transportation costs paid to third parties in Argentina.
 
Taxes other than Income
 
Taxes other than income totaled $598 million for 2007 and 2006.
 
The table below presents a comparison of these expenses:
 
                 
    For the Year Ended
 
    December 31,  
    2007     2006  
    (In millions)  
 
U.K. PRT
  $ 346     $ 394  
Severance taxes
    142       122  
Ad Valorem taxes
    56       44  
Other taxes
    54       38  
                 
Taxes other than Income
  $ 598     $ 598  
                 
Taxes other than Income per boe
  $ 2.92     $ 3.27  
                 
 
On a per-unit basis taxes other than income decreased $.35, or 12 percent, reflecting the 12 percent increase in equivalent production. The increase in severance taxes was driven by higher production and prices on U.S. and Australian properties burdened by such taxes. U.K. PRT was 12 percent below 2006, largely driven by lower comparable revenues on less production and slightly higher deductible costs. Deductible costs include capital expenditures, LOE, general and administrative expenses (G&A) and transportation tariffs. Ad valorem taxes increased $12 million. Oil and liquids were 47 percent of our production in both 2007 and 2006. A significant portion of our ad valorem taxes are reserve based and increase when prices rise. Other taxes increased with a full year of taxes on invoice and bank transactions in Argentina.


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General and Administrative Expenses
 
General and administrative expenses (G&A) were $64 million, or $.18 per boe, higher than 2006. Incentive-based compensation added $.12 per boe to the rate, a consequence of a strong stock price appreciation during the year, while insurance costs added $.11 per boe, a consequence of industry-wide premium increases after the 2005 hurricanes. These increases were partially offset by a decrease in rate stemming from higher production.
 
Financing Costs, Net
 
The major components of financing costs, net, include interest expense and capitalized interest. Net financing costs for 2007 increased $78 million or $.29 per boe, on higher average outstanding debt balances, which offset a slightly lower average interest rate.
 
Provision for Income Taxes
 
The 2007 provision for income taxes was $1.9 billion, $403 million above 2006 on both higher taxable income and a higher effective tax rate. Apache’s 2007 effective tax rate was 39.8 percent compared to 36.3 percent in 2006. The 2007 effective rate was impacted by a non-cash charge related to the effect of the weakening U.S. dollar on our foreign deferred tax liabilities. Partially offsetting this charge was an out of period benefit from Canadian federal tax rate reductions enacted in the second and fourth quarters of 2007. The 2006 effective tax rate was impacted by a charge related to retroactive application of a 10 percent increase in the oil and gas company supplemental tax enacted by the U.K., a benefit from a Canadian federal provincial tax rate reduction enacted in the second quarter of 2006 and a gain recognized on the sale of China. Foreign currency fluctuations had a negligible impact on the 2006 rate.
 
Acquisitions and Divestitures
 
2008 Activity
 
There was no major acquisition activity during 2008; however, the Company completed several divestiture transactions. On January 29, 2008, the Company completed the sale of its interest in Ship Shoal blocks 349 and 359 on the outer continental shelf of the Gulf of Mexico to W&T Offshore, Inc. for $116 million. On January 31, 2008, the Company completed the sale of non-strategic oil and gas properties in the Permian Basin of West Texas to Vanguard Permian, LLC for $78 million. On April 2, 2008, the Company completed the sale of non-strategic Canadian properties to Central Global Resources for $112 million. These divestitures are subject to normal post-closing adjustments.
 
2007 Activity
 
U.S. Gulf Coast Farm-in  On September 6, 2007, Apache entered into an Exploration Agreement with various EnerVest Partnerships (“EVP”) for an initial term of four years whereby Apache committed to spend $30 million in qualified expenditures to explore, drill, produce and market hydrocarbons from specified undeveloped formations across 400,000 net acres in Central and East Texas. As of December 31, 2008, Apache has fulfilled the $30 million commitment.
 
U.S. Permian Basin  On March 29, 2007, the Company closed its acquisition of controlling interest in 28 oil and gas fields in the Permian basin of West Texas from Anadarko for $1 billion. Apache estimates that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of year-end 2006. The Company funded the acquisition with debt. Apache and Anadarko entered into a joint-venture arrangement to effect the transaction. The Company entered into cash flow hedges for a portion of the crude oil and the natural gas production.
 
2006 Activity
 
U.S. Permian Basin  On January 5, 2007, the Company purchased Amerada Hess’s interest in eight fields located in the Permian basin of West Texas and New Mexico. The original purchase price was reduced from $404 million to $269 million because other interest owners exercised their preferential rights to purchase a number of the properties. The settlement price at closing of $239 million was adjusted for revenues and expenditures


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occurring between the effective date and the closing date of the acquisition. The acquired fields had estimated proved reserves of 27 MMbbls of liquid hydrocarbons and 27 Bcf of natural gas as of year-end 2005.
 
Argentina  On April 25, 2006, the Company acquired the operations of Pioneer Natural Resources (Pioneer) in Argentina for $675 million. The settlement price at closing, of $703 million, was adjusted for revenues and expenditures occurring between the effective date and closing date of the acquisition. The properties are located in the Neuquén, San Jorge and Austral basins of Argentina and had estimated net proved reserves of approximately 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas as of December 31, 2005. Eight gas processing plants (five operated and three non-operated), 112 miles of operated pipelines in the Neuquén basin and 2,200 square miles of three-dimensional (3-D) seismic data were also included in the transaction. Apache financed the purchase with cash on hand and commercial paper.
 
The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):
 
         
Proved property
  $ 501,938  
Unproved property
    189,500  
Gas Plants
    51,200  
Working capital acquired, net
    11,256  
Asset retirement obligation
    (13,635 )
Deferred income tax liability
    (37,630 )
         
Cash consideration
  $ 702,629  
         
 
On September 19, 2006, Apache acquired additional interests in (and now operates) seven concessions in the Tierra del Fuego Province from Pan American Fueguina S.R.L. (Pan American) for total consideration of $429 million. The settlement price at closing of $396 million was adjusted for normal closing items, including revenues and expenses between the effective date and the closing date of the acquisition. Apache financed the purchase with cash on hand and commercial paper.
 
The total cash consideration allocated below includes working capital balances purchased, asset retirement obligations assumed and an obligation to deliver specific gas volumes in the future. The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):
 
         
Proved property
  $ 289,916  
Unproved property
    132,000  
Gas plants
    12,722  
Working capital acquired, net
    8,929  
Asset retirement obligation
    (1,511 )
Assumed obligation
    (46,000 )
         
Cash consideration
  $ 396,056  
         
 
U.S. Gulf Coast  In June 2006, the Company acquired the remaining producing properties of BP plc (BP) on the Outer Continental Shelf of the Gulf of Mexico. The original purchase price was reduced from $1.3 billion for 18 producing fields to $845 million because other interest owners exercised their preferential rights to purchase five of the 18 fields. The purchase price consisted of $747 million of proved property, $42 million of unproved property and $56 million of facilities. The settlement price on the date of closing of $821 million was adjusted primarily for revenues and expenditures occurring between the April 1, 2006 effective date and the closing date of the acquisition. The acquired properties include 13 producing fields (nine of which are operated) with estimated proved reserves of 19.5 MMbbls of liquid hydrocarbons and 148 Bcf of natural gas. Apache financed the purchase with cash on hand and commercial paper.


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Divestitures  On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. Apache did not have any proved reserves booked for these properties.
 
On August 8, 2006, the Company completed the sale of its 24.5 percent interest in the Zhao Dong block, offshore the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking Apache’s exit from China. The effective date of the transaction was July 1, 2006. The Company recorded a gain of $174 million in the third quarter of 2006.
 
Capital Resources and Liquidity
 
Sources and Uses of Cash
 
The following table presents the sources and uses of our cash and cash equivalents for each of the three years ended December 31. The table presents capital expenditures on a cash basis; therefore, the amounts differ from the amounts of capital expenditures, elsewhere in this document, which include accruals.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In millions)  
 
Sources of Cash and Cash Equivalents:
                       
Net cash provided by operating activities
  $ 7,065     $ 5,677     $ 4,313  
Sales of property and equipment
    308       67       678  
Net commercial paper and bank loan borrowings
                1,630  
Project financing draw-downs
    100              
Fixed-rate debt borrowings
    796       2,002        
Common stock issuances
    36       44       39  
Other
    39       26       36  
                         
      8,344       7,816       6,696  
                         
Uses of Cash and Cash Equivalents
                       
Capital expenditures
    5,823       4,802       4,140  
Purchase of short-term investments
    792              
Acquisitions
    150       1,005       2,164  
Net commercial paper and bank loan repayments
    200       1,425        
Payments on debt
          170        
Repurchase of common stock
                174  
Dividends
    239       205       154  
Other
    84       224       152  
                         
      7,288       7,831       6,784  
                         
Increase (decrease) in cash and cash equivalents
  $ 1,056     $ (15 )   $ (88 )
                         
 
Net Cash Provided by Operating Activities  Net cash provided by operating activities (“operating cash flows”) is our primary source of capital and liquidity. Factors affecting changes in operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A and deferred income tax expense. Factors affecting our operating cash flows are discussed in the “Results of Operations” section of this report. Operating cash flows in 2008 increased from 2007.
 
Fixed-Rate Debt Issuances  On October 1, 2008, the Company issued $400 million principal amount, $398 million net of discount, of senior unsecured 6.0-percent notes maturing September 15, 2013, and $400 million principal amount, $398 million net of discount, of senior unsecured 6.9-percent notes maturing September 15, 2018. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The


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proceeds are presently invested in U.S. Treasury Bills and will be used for general corporate purposes or, possibly, future acquisitions.
 
Project Financing Draw-downs  On December 5, 2008, one of the Company’s Australian subsidiaries entered into a secured revolving syndicated credit facility for the Van Gogh and Pyrenees oil developments. The facility provides for total commitments of $350 million with availability determined by a borrowing base formula. The borrowing base was set at $350 million and will be redetermined at completion and semi-annually thereafter. The facility is secured by certain assets associated with the Van Gogh and Pyrenees oil developments, including the shares of stock of the Company’s subsidiary holding the assets. The Company has agreed to guarantee the credit facility until completion occurs pursuant to terms of the facility, which is expected in 2010. The commitments under the facility will be reduced by scheduled increments every six months beginning June 30, 2010, with final maturity on March 31, 2014. Interest is based on LIBOR, which may be subject to change under certain market disruption conditions, plus a margin of 1.00 percent pre-completion and 1.75 percent post-completion. The pre-completion margin increases to 1.125 percent in the event the Company’s ratings are downgraded to BBB+ or below by at least two major rating agencies. As of December 31, 2008 there was $100 million outstanding under the facility.
 
Capital Expenditures  We fund exploration and development activities primarily through net cash provided by operating activities and budget capital expenditures based on projected operating cash flows. Our operating cash flows, both in the short- and long-term, is impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire or find high-margin reserves at competitive prices. For these reasons, management primarily relies on annual operating cash flow forecasts. Annual operating cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to these adjusted operating cash flow forecasts and market trends in drilling and acquisitions costs. Longer-term operating cash flows and capital spending projections are rarely used by management to operate the business.
 
Historically, we have used a combination of our operating cash flow, borrowings under the our lines of credit and commercial paper program and, from time to time, issues of public debt or common stock to fund significant acquisitions.
 
The following table details capital expenditures for each country in which we do business.
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Exploration and Development:
                       
United States
  $ 2,183,473     $ 1,630,776     $ 1,532,959  
Canada
    705,066       650,676       1,056,614  
Egypt
    852,802       605,115       454,892  
Australia
    879,680       516,054       179,892  
North Sea
    459,239       537,868       329,498  
Argentina
    317,490       287,047       115,570  
Chile
    27,457              
China
                12,288  
                         
      5,425,207       4,227,536       3,681,713  
Acquisitions — Oil and gas properties
    149,838       1,024,956       2,428,432  
Asset Retirement Costs
    513,891       439,368       390,612  
Capitalized Interest
    94,164       75,748       61,301  
Gathering, Transmission and Processing Facilities
    659,248       473,481       248,589  
                         
Total capital expenditures
  $ 6,842,348     $ 6,241,089     $ 6,810,647  
                         
 
Exploration and Development (E&D) — Increases in our 2008 operating cash flows, year-over-year, enabled us to invest larger amounts on E&D capital projects. We invested $5.4 billion on drilling, recompletions and


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platform and production support facilities in 2008, up 28 percent from 2007. Our 2007 E&D capital expenditures were $546 million above 2006.
 
Acquisitions — We completed $150 million of acquisitions in 2008 compared to $1 billion in 2007. Acquisition capital expenditures occur as attractive opportunities arise and, therefore, vary from year to year.
 
Asset Retirement Costs — In 2008, we recorded $514 million of additional asset retirement costs. The increase is primarily related to revisions of our cost estimates. Rising estimates for service costs and the high level of abandonment activities in the Gulf Coast region have accelerated some obligations. Continued worldwide drilling programs, acquisition activity and damage from Hurricane Ike also contributed to the increased abandonment costs.
 
Gathering, Transmission and Processing Facilities (GTP) — We invested $659 million in GTP facilities in 2008 compared to $473 million in 2007. In Egypt, we invested $571 million in gas processing facilities to alleviate capacity constraints, which are restricting production. We also invested $55 million in Australia on GTP projects currently in process. In Canada, we invested $29 million in processing plants.
 
2009 Outlook — In light of a collapse in commodity prices and uncertainties surrounding the worldwide financial crisis, we seek to keep capital spending in line with 2009 operating cash flows in order to preserve our strong balance sheet and financial flexibility. We will closely monitor commodity prices, service cost levels and predicted operating cash and will adjust our exploration and development budgets accordingly. While certain long-lead development projects are committed in 2009, the majority of our drilling and development projects are discretionary and subject to deferral or cancellation as conditions warrant. Because we revise our exploration and development capital budgets frequently throughout the year, projecting future expenditures is difficult at best. Our 2009 preliminary plan includes exploration and development capital of approximately $3.5 to $4.0 billion, including GTP. We generally do not project estimates for acquisitions because their occurrence and timing is unpredictable. Any acquisitions would be funded from operating cash flow, credit facilities, issuing new equity, or a combination thereof.
 
Repurchases of Common Stock  On April 19, 2006, the Company announced that its Board of Directors authorized the purchase of up to 15 million shares of the Company’s common stock, representing a market value of approximately $1 billion on the date of announcement. The Company may buy shares from time to time on the open market, in privately negotiated transactions, or a combination of both. The timing and amounts of any purchases will be at the discretion of Apache’s management. The Company initiated the purchase program on May 1, 2006, after the Company’s first-quarter 2006 earnings information was disseminated in the market. During 2006, the Company purchased 2,500,000 shares at an average price of $69.74 per share. No stock purchases were made in 2007 or 2008, and we currently have no plans to purchase any shares in 2009.
 
Dividends  The Company has paid cash dividends on its common stock for 44 consecutive years through 2008. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other relevant factors. Common dividends paid during 2008 rose 17 percent to $234 million, reflecting the special cash dividend of 10 cents per common share paid on March 18, 2008 and an increase in common shares outstanding. Common dividends paid during 2007 rose 34 percent to $199 million, reflecting the increase in common shares outstanding and an increase in the common stock dividend rate. The Company increased its quarterly cash dividend 50 percent, to 15 cents per share from 10 cents per share, effective with the November 2006 dividend payment.
 
During 2008 and 2007, Apache paid a total of $6 million in dividends each year on its Series B Preferred Stock issued in August 1998. See Note 7 — Capital Stock of Item 15 in this Form 10-K.


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Liquidity
 
                         
    At December 31,  
Millions of Dollars Except as Indicated
  2008     2007     2006  
 
Cash
  $ 1,181     $ 126     $ 141  
Short-term investments
    792              
Restricted cash
    14              
Total debt
    4,922       4,227       3,822  
Shareholders’ equity
    16,509       15,378       13,192  
Available committed borrowing capacity
    2,550       2,115       690  
Floating-rate debt/total debt
    2 %     5 %     43 %
Percent of total debt to capitalization
    23 %     22 %     22 %
 
Thus far, our liquidity and financial position have not been affected by recent events in the credit markets. We believe that losses from non-performance are unlikely to occur; however, we are not able to predict sudden changes in the creditworthiness of the financial institutions with which we do business. The banks with lending commitments to the Company have credit ratings of at least single-A (or equivalent) which in some cases is based on government support. There is no assurance that the financial condition of these banks will not deteriorate or that the government guarantee will be maintained. We closely monitor the ratings of the 27 banks in our bank group. Having a large bank group allows the Company to mitigate the impact of any bank’s failure to honor its lending commitment.
 
Cash and Cash Equivalents  We had $1.2 billion in cash and cash equivalents at December 31, 2008, compared with $126 million at December 31, 2007. The majority of this cash is in our foreign subsidiaries ($146 million was in U.S.) and is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities, with maturities of three months or less at the time of purchase. We intend to use cash from our international subsidiaries to fund international projects.
 
Short-term Investments  The Company occasionally invests in highly-liquid, short-term investments in order to maximize our income on available cash balances. As needed, we may reduce such short-term investment balances to further supplement our operating cash flows. At December 31, 2008, we had $792 million invested in obligations of the U.S. Government with original maturities greater than three months but less than a year.
 
Restricted Cash  The Company classifies cash balances as restricted cash when it is restricted as to withdrawal or usage. As of December 31, 2008, the Company had approximately $14 million of property divestiture proceeds classified as restricted cash and held in escrow available for use in a like-kind exchange under Section 1031 of the U.S. federal income tax code. The Company expected to use these funds to purchase noncurrent assets. Accordingly, the restricted cash was classified as long-term at year-end. Subsequent to year-end, the time limits pursuant to Section 1031 expired and the funds were transferred to cash.
 
Debt  At year-end 2008, outstanding debt, which consisted of notes, debentures and uncommitted bank lines, totaled $4.9 billion. Current debt includes $100 million of Apache Finance Pty Limited 7.0-percent notes due March 2009 and $13 million borrowed under uncommitted overdraft lines in Argentina. We have no debt maturing in 2010 or 2011, $439 million maturing in 2012, $942 million maturing in 2013 and the remaining $3.4 billion maturing intermittently in years 2014 through 2096.
 
Debt-to-Capitalization Ratio  The Company’s debt-to-capitalization ratio as of December 31, 2008 was 23 percent.
 
Available Credit Facilities  The Company had available borrowing capacity under our total credit facilities of approximately $2.6 billion at December 31, 2008; $2.3 billion of unsecured revolving syndicated bank credit facilities and $250 million under one of the Company’s Australian subsidiaries secured revolving syndicated credit facility for the Van Gogh and Pyrenees oil developments, entered into in December 2008. The Company was in compliance with the terms of all credit facilities as of December 31, 2008.


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The $2.3 billion of unsecured revolving syndicated bank credit facilities mature in May 2013. Since there were no outstanding borrowings or commercial paper at year-end, the full $2.3 billion of unsecured credit facilities were available to the Company. These facilities consist of a $1.5 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia and a $150 million facility in Canada. The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to five percent of the Company’s consolidated assets, which approximated $1.5 billion as of December 31, 2008. There are no restrictions on incurring liens in countries other than U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group. Furthermore, our non-cash write-down of oil and gas properties in 2008 does not impact the availability of credit lines or result in non-compliance with any covenants.
 
There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes (MAC clauses). The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2008.
 
At the Company’s option, the interest rate for the facilities is based on (i) the greater of (a) the JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent or (ii) the London Inter-bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $1.5 billion and the $450 million credit facilities (U.S. credit facilities) also allow the company to borrow under competitive auctions.
 
At December 31, 2008, the margin over LIBOR for committed loans was .19 percent on the $1.5 billion facility and .23 percent on the other three facilities. If the total amount of the loans borrowed under the $1.5 billion facility equals or exceeds 50 percent of the total facility commitments, then an additional .05 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of .06 percent on the total amount of the $1.5 billion facility and .07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating. The U.S. credit facilities are used to support Apache’s commercial paper program.
 
On December 5, 2008, one of the Company’s Australian subsidiaries entered into a secured revolving syndicated credit facility for the Van Gogh and Pyrenees oil developments. The facility provides for total commitments of $350 million with availability determined by a borrowing base formula. The borrowing base was set at $350 million and will be redetermined at project completion and semi-annually thereafter. The facility is secured by certain assets associated with the Van Gogh and Pyrenees oil developments, including the shares of stock of the Company’s subsidiary holding the assets. The Company has agreed to guarantee the credit facility until completion occurs pursuant to terms of the facility, which is expected in 2010. The commitments under the facility will be reduced by scheduled increments every six months beginning June 30, 2010, with final maturity on March 31, 2014. Interest is based on LIBOR, which may be subject to change under certain market disruption conditions, plus a margin of 1.00 percent pre-completion and 1.75 percent post-completion. The pre-completion margin increases to 1.125 percent in the event the Company’s ratings are downgraded to BBB+ or below by at least two major rating agencies. As of December 31, 2008, there is $100 million outstanding under the facility.
 
Commercial Paper Program  The Company has available a $1.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. As of December 31, 2008, Apache had no commercial paper outstanding. Our weighted-average interest rate for commercial paper was 5.65 percent and 3.85 percent for 2008 and 2007, respectively. If the Company is unable to issue commercial paper


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following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100 percent backstop.
 
Credit Ratings  We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels could also be considered by the rating agencies. Apache’s senior unsecured long term debt is currently rated A3 by Moody’s, A- by Standard & Poor’s and A by Fitch. Apache’s short-term debt rating for its commercial paper program is currently P-2 by Moody’s, A-2 by Standard & Poor’s and F1 by Fitch. The outlook is stable from Moody’s and Standard & Poor’s and negative from Fitch. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and potentially require the Company to post letters of credit in certain circumstances. We cannot predict, nor can we assure, that we will not receive a ratings downgrade in the future.
 
Pricing Trends.  For 2008, the Company’s average realized prices were substantially higher than the previous year’s prices. In fact, prices continued a general upward trend until July of this year, at which time prices began to decline significantly. Crude oil trades in global market; consequently, prices for all types and grades of crude oil generally move in the same direction. Natural gas has a limited global transportation system and, therefore, is subject to local supply and demand conditions. Approximately two-thirds of our natural gas is sold in the North American market, which tracks New York Mercantile Exchange (NYMEX) prices, while the remaining is sold under fixed-price contracts in regulated markets. Following is a table of the published monthly average NYMEX prices in 2008:
 
                                                 
    December     November     October     September     August     July  
 
Crude Oil
  $ 42.04     $ 57.44     $ 76.77     $ 104.41     $ 116.73     $ 134.42  
Natural Gas
  $ 5.79     $ 6.70     $ 6.73     $ 7.50     $ 8.30     $ 11.20  
 
While we are presently in a strong financial position, continued lower prices would negatively impact our future oil and gas production revenues, earnings and liquidity. Commodity prices are volatile and future prices cannot be accurately predicted. Apache’s investment decisions are based on longer-term commodity prices. For these reasons, we have historically based our capital expenditure budget on projected cash flows, modifying initial budgets in the event of significant changes in commodity prices. Given the recent commodity price levels, our initial 2009 budgeted expenditures is substantially less than projected 2008 levels. We also believe that certain service costs will be reduced, but historically there has been a lag between a precipitous drop in commodity prices and the underlying service costs necessary to find, develop and produce oil and natural gas.
 
Contractual Obligations
 
We are subject to various financial obligations and commitments in the normal course of operations. These contractual obligations represent known future cash payments that we are required to make and relate primarily to long-term debt, operating leases, pipeline transportation commitments and international commitments. The Company expects to fund these contractual obligations with cash generated from operating activities.


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The following table summarizes the Company’s contractual obligations as of December 31, 2008. See Notes 5 — Debt and 9 — Commitments and Contingencies of Item 15 in this form 10-K for further information regarding these obligations.
 
                                                 
    Note
                            2015 &
 
Contractual Obligations
  Reference     Total     2009     2010-2012     2013-2014     Beyond  
                (In thousands)              
 
Debt
    Note 5     $ 4,921,573     $ 112,598     $ 438,852     $ 957,065     $ 3,413,058  
Interest payments
    Note 5       5,112,221       299,485       875,455       471,595       3,465,686  
Drilling rig commitments
    Note 9       889,874       516,180       372,594       1,100        
Purchase obligations
    Note 9       371,279       370,720       559              
E&D commitments
    Note 9       197,512       92,459       99,670       5,383        
Firm transportation agreements
    Note 9       223,153       26,541       81,234       55,496       59,882  
Office and related equipment
    Note 9       122,599       21,354       60,758       18,962       21,525  
Oil and gas operations equipment
    Note 9       472,980       77,122       125,676       59,304       210,878  
Other
            3,840       3,840                    
                                                 
Total Contractual Obligations(a)(b)(c)(d)
          $ 12,315,031     $ 1,520,299     $ 2,054,798     $ 1,568,905     $ 7,171,029  
                                                 
 
 
(a) This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1.9 billion. See Note 4 — Asset Retirement Obligation of Item 15 in this Form 10-K for further discussion.
 
(b) This table does not include the Company’s $212 million asset for outstanding derivative instruments valued as of December 31, 2008. See Note 3 — Hedging and Derivative Instruments of Item 15 in this Form 10K for further discussion.
 
(c) This table does not include the Company’s pension or postretirement benefit obligations. See Note 9 — Commitments and Contingencies of Item 15 in this Form 10-K for further discussion.
 
(d) This table does not include the Company’s FIN 48 obligations. See Note 6 — Income Taxes of Item 15 in this Form 10-K for further discussion.
 
Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations, including approximately $27 million for environmental remediation and approximately $25 million for various legal liabilities. See Note 9 — Commitments and Contingencies of Item 15 in this Form 10-K for a detailed discussion of the Company’s environmental and legal contingencies.
 
The Company also accrued approximately $74 million as of December 31, 2008, for an insurance contingency because of our involvement with Oil Insurance Limited (OIL). Apache is a member of this insurance pool, which insures specific property, pollution liability and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay termination fees were we to elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential termination fee is calculated annually based on past losses, and the liability reflecting this potential charge has been accrued as required.
 
Subsequent Event  On February 10, 2009, Apache’s wholly-owned subsidiary, Apache Canada Ltd. entered into an agreement with TransCanada Pipelines Limited (TCPL) pursuant to which TCPL will construct and install a gas pipeline from northeastern British Columbia to the existing NOVA pipeline system located in the Ekwan area of Alberta. Apache Canada intends to ship gas produced from the Ootla basin on the new pipeline.
 
The construction, operation and transportation rates of the new pipeline are subject to regulatory approval. Authority to construct the pipeline is expected, and construction is anticipated to be complete on or before April 1, 2011. Upon completion of the pipeline, Apache Canada will have a ship-or-pay commitment of 100 MMBtu of gas


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for either a four-year period or a ten-year period depending on the rate structure determined and approved by the regulatory agency. Apache Canada has the right to terminate the agreement before October 1, 2009. If Apache Canada elects to terminate the agreement or TCPL terminates for reasons set forth in the agreement, Apache Canada must reimburse TCPL for certain costs and expenses up to approximately CDN $90 million plus certain taxes.
 
Off-Balance Sheet Arrangements
 
Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions.
 
Critical Accounting Policies and Estimates
 
Apache prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Apache identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of Apache’s financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of Apache’s most critical accounting policies:
 
Reserve Estimates  Our estimate of proved reserves is based on the quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. As such, our reserve engineers review and revise the Company’s reserve estimates at least annually.
 
Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.
 
Asset Retirement Obligation (ARO)  The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future, and contracts and regulation often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
 
ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
 
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal,


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regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.
 
Income Taxes  Our oil and gas exploration and production operations are currently located in six countries. As a result, we are subject to taxation on our income in numerous jurisdictions. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).
 
The Company regularly assesses and, if required, establishes accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. Tax reserves have been established and include any related interest, despite the belief by the Company that certain tax positions have been fully documented in the Company’s tax returns. These reserves are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law and any new legislation. The Company believes that the reserves established are adequate in relation to the potential for any additional tax assessments.
 
ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates, foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
 
Commodity Risk
 
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile due to unpredictable events such as economical growth or retraction, weather and climate. Crude oil prices in 2008 began the year strong and increased rapidly to unprecedented levels in the summer, before decreasing to below first quarter 2008 prices by the end of the year. West Texas Intermediate (WTI), an industry benchmark crude oil, peaked above $147 per barrel in July before falling to nearly $40 at year-end as a result of decreased demand for energy as world economies slowed. Natural gas prices, especially in the U.S. where we have fewer long-term supply contracts, followed a similar path.
 
We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. Apache may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from the Company’s price risk management activities are recognized in oil and gas production revenues when the associated production occurs. Apache does not generally hold or issue derivative instruments for trading purposes.
 
Apache historically only hedged long-term oil and gas prices related to a portion of its expected production associated with acquisitions; however, in 2007 and 2008, the Company’s Board of Directors authorized management to hedge a portion of production generated from the Company’s drilling program. Approximately 20 percent of our 2008 natural gas production and 19 percent of our crude oil production were subjected to financial derivative hedges.


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On December 31, 2008, the Company had open natural gas derivative hedges in an asset position with a fair value of $47 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $15 million, while a 10 percent decrease in prices would increase the fair value by approximately $18 million. The Company also had open oil derivatives in an asset position with a fair value of $165 million. A 10 percent increase in oil prices would decrease the asset by approximately $117 million, while a 10 percent decrease in prices would increase the asset by approximately $118 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2008. See Note 3 — Hedging and Derivative Instruments of Item 15 in this Form 10-K for notional volumes and terms associated with the Company’s derivative contracts.
 
Apache conducts its risk management activities for its commodities under the controls and governance of its risk management policy. The Risk Management Committee, comprising the President (principal financial officer), General Counsel, Treasurer and other key members of Apache’s management, approve and oversee these controls, which have been implemented by designated members of the treasury department. The treasury and accounting departments also provide separate checks and reviews on the results of hedging activities. Controls for our commodity risk management activities include limits on credit, limits on volume, segregation of duties, delegation of authority and a number of other policy and procedural controls.
 
Interest Rate Risk
 
On December 31, 2008, the Company’s debt with fixed interest rates represented approximately 98 percent of total debt. As a result, the interest expense on approximately two percent of Apache’s debt will fluctuate based on short-term interest rates. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $707,000.
 
Foreign Currency Risk
 
The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts, and the majority of the gas production is sold under fixed-price Australian dollar contracts. Approximately half the costs incurred for Australian operations are paid in U.S. dollars. In Canada, the majority of oil and gas production is sold under Canadian dollar contracts. The majority of the costs incurred are paid in Canadian dollars. The North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars but converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, Egyptian pounds and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.
 
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when we re-measure our foreign tax liabilities, as a component of the Company’s provision for income tax expense on the Statement of Consolidated Operations.
 
Forward-Looking Statements and Risk
 
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2008 and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are


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reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
 
  •  the market prices of oil, natural gas, NGLs and other products or services;
 
  •  our commodity hedging arrangements;
 
  •  the supply and demand for oil, natural gas, NGLs and other products or services;
 
  •  production and reserve levels;
 
  •  drilling risks;
 
  •  economic and competitive conditions;
 
  •  the availability of capital resources;
 
  •  capital expenditure and other contractual obligations;
 
  •  currency exchange rates;
 
  •  weather conditions;
 
  •  inflation rates;
 
  •  the availability of goods and services;
 
  •  legislative or regulatory changes;
 
  •  terrorism;
 
  •  occurrence of property acquisitions or divestitures;
 
  •  the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks; and
 
  •  other factors disclosed under Items 1 and 2 — “Business and Properties — Estimated Proved Reserves and Future Net Cash Flows,” Item 1A — “Risk Factors,” Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A — “Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this Form 10-K.
 
All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.


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ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The financial statements and supplementary financial information required to be filed under this item are presented on pages F-1 through F-55 of this Form 10-K and are incorporated herein by reference.
 
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
The financial statements for the fiscal years ended December 31, 2008, 2007 and 2006, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein.
 
ITEM 9A.   CONTROLS AND PROCEDURES
 
Disclosure Controls and Procedures
 
G. Steven Farris, the Company’s Chairman and Chief Executive Officer, in his capacity as principal executive officer, and Roger B. Plank, the Company’s President, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2008, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in internal controls over financial reporting during the quarter ending December 31, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.
 
Management’s Report on Internal Control Over Financial Reporting
 
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to “Report of Management on Internal Control Over Financial Reporting,” included on Page F-1 in Item 15 of this Form 10-K.
 
The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated by reference to the “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting,” included on Page F-3 in Item 15 of this Form 10-K.
 
Changes in Internal Control Over Financial Reporting
 
There was no change in our internal controls over financial reporting during the quarter ending December 31, 2008, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
 
ITEM 9B.   OTHER INFORMATION
 
None.


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PART III
 
ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
 
The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2009 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference.
 
Code of Business Conduct
 
Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), which also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Management and Governance page of the Company’s website at www.apachecorp.com. Any stockholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within five business days and maintained for at least 12 months.
 
ITEM 11.   EXECUTIVE COMPENSATION
 
The information set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Non-Qualified Deferred Compensation Table,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements” and “Director Compensation Table” in the Proxy Statement is incorporated herein by reference.
 
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
The information set forth under the captions “Securities Ownership and Principal Holders” and “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.
 
ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
The information set forth under the captions “Certain Business Relationships and Transactions” and “Director Independence” in the Proxy Statement is incorporated herein by reference.
 
ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
The information set forth under the caption “Independent Registered Public Accountants” in the Proxy Statement is incorporated herein by reference.
 
PART IV
 
ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
 
  (a)   Documents included in this report:


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1. Financial Statements
 
     
Report of management
  F-1
Report of independent registered public accounting firm
  F-2
Report of independent registered public accounting firm
  F-3
Statement of consolidated operations for each of the three years in the period ended December 31, 2008
  F-4
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2008
  F-5
Consolidated balance sheet as of December 31, 2008 and 2007
  F-6
Statement of consolidated shareholders’ equity for each of the three years in the period ended December 31, 2008
  F-7
Notes to consolidated financial statements
  F-8
 
 
2. Financial Statement Schedules
 
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.
 
3. Exhibits
 
             
Exhibit
       
No.
     
Description
 
  2 .1     Agreement and Plan of Merger among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996).
  2 .2     Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  2 .3     Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  3 .1     Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  3 .2     Bylaws of Registrant, as amended December 14, 2006 (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2006, SEC File No. 001-4300).
  4 .1     Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
  4 .2     Form of Certificate for Registrant’s 5.68% Cumulative Preferred Stock, Series B (incorporated by reference to Exhibit 4.2 to Amendment No. 2 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 001-4300).
  4 .3     Rights Agreement, dated January 31, 1996, between Registrant and Norwest Bank Minnesota, N.A., rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).


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

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

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

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

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Exhibit
       
No.
     
Description
 
  14 .1     Code of Business Conduct (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  *21 .1     Subsidiaries of Registrant
  *23 .1     Consent of Ernst & Young LLP
  *23 .2     Consent of Ryder Scott Company L.P., Petroleum Consultants
  *24 .1     Power of Attorney (included as a part of the signature pages to this report)
  *31 .1     Certification of Principal Executive Officer
  *31 .2     Certification of Principal Financial Officer
  *32 .1     Certification of Principal Executive Officer and Principal Financial Officer
 
 
Filed herewith.
 
†  Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.
 
NOTE:  Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.
 
(b) See (a) 3. above.
 
(c) See (a) 2. above.

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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, hereunto duly authorized.
 
APACHE CORPORATION
 
   
/s/  G. STEVEN FARRIS
G. Steven Farris
Chairman of the Board and Chief Executive Officer
 
Dated: February 27, 2009
 
POWER OF ATTORNEY
 
The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, P. Anthony Lannie and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Name
 
Title
 
Date
 
         
/s/  G. STEVEN FARRIS

G. Steven Farris
  Chairman of the Board and Chief Executive Officer
(principal executive officer)
  February 27, 2009
         
/s/  ROGER B. PLANK

Roger B. Plank
  President
(principal financial officer)
  February 27, 2009
         
/s/  REBECCA A. HOYT

Rebecca A. Hoyt
  Vice President and Controller
(principal accounting officer)
  February 27, 2009
         
/s/  FREDERICK M. BOHEN

Frederick M. Bohen
  Director   February 27, 2009
         
/s/  RANDOLPH M. FERLIC

Randolph M. Ferlic
  Director   February 27, 2009
         
/s/  EUGENE C. FIEDOREK

Eugene C. Fiedorek
  Director   February 27, 2009
         
/s/  A. D. FRAZIER, JR.

A. D. Frazier, Jr.
  Director   February 27, 2009
         
/s/  PATRICIA ALBJERG GRAHAM

Patricia Albjerg Graham
  Director   February 27, 2009


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Name
 
Title
 
Date
 
         
/s/  JOHN A. KOCUR

John A. Kocur
  Director   February 27, 2009
         
/s/  GEORGE D. LAWRENCE

George D. Lawrence
  Director   February 27, 2009
         
/s/  F. H. MERELLI

F. H. Merelli
  Director   February 27, 2009
         
/s/  RODMAN D. PATTON

Rodman D. Patton
  Director   February 27, 2009
         
/s/  CHARLES J. PITMAN

Charles J. Pitman
  Director   February 27, 2009


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REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
 
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934 (Exchange Act). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program on internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
 
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2008. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2008.
 
The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Apache Corporation and subsidiaries, and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.
 
G. Steven Farris
Chairman of the Board and Chief Executive Officer
(principal executive officer)
 
Roger B. Plank
President
(principal financial officer)
 
Rebecca A. Hoyt
Vice President and Controller
(principal accounting officer)
 
Houston, Texas
February 27, 2009


F-1


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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Corporation and subsidiaries at December 31, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
 
As described in Note 1 to the consolidated financial statements, in 2007 the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apache Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009, expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Houston, Texas
February 27, 2009


F-2


Table of Contents

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Shareholders of Apache Corporation:
 
We have audited Apache Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apache Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Apache Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008, and our report dated February 27, 2009, expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Houston, Texas
February 27, 2009


F-3


Table of Contents

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


F-4


Table of Contents

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


F-5


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEET
 
                 
    December 31,  
    2008     2007  
    (In thousands)  
 
ASSETS
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 1,181,450       125,823  
Short-term investments
    791,999        
Receivables, net of allowance
    1,356,979       1,936,977  
Inventories
    498,567       461,211  
Drilling Advances
    93,377       112,840  
Derivative instruments
    154,280       20,889  
Prepaid taxes
    303,203       21,077  
Prepaid assets and other
    71,119       73,434  
                 
      4,450,974       2,752,251  
                 
PROPERTY AND EQUIPMENT:
               
Oil and gas, on the basis of full cost accounting:
               
Proved properties
    40,639,281       34,645,710  
Unproved properties and properties under development, not being amortized
    1,300,347       1,439,726  
Gathering, transmission and processing facilities
    2,883,789       2,206,453  
Other
    452,989       416,149  
                 
      45,276,406       38,708,038  
Less: Accumulated depreciation, depletion and amortization
    (21,317,889 )     (13,476,445 )
                 
      23,958,517       25,231,593  
                 
OTHER ASSETS:
               
Restricted cash
    13,880        
Goodwill, net
    189,252       189,252  
Deferred charges and other
    573,862       461,555  
                 
    $ 29,186,485     $ 28,634,651  
                 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
               
Accounts payable
  $ 570,138     $ 617,937  
Accrued operating expense
    168,531       112,453  
Accrued exploration and development
    964,859       600,165  
Accrued compensation and benefits
    111,907       172,542  
Accrued interest
    91,456       78,187  
Accrued income taxes
    48,028       73,184  
Current debt
    112,598       215,074  
Asset retirement obligations
    339,155       309,777  
Derivative instruments
          286,226  
Other
    208,556       199,471  
                 
      2,615,228       2,665,016  
                 
LONG-TERM DEBT
    4,808,975       4,011,605  
                 
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
               
Income taxes
    3,166,657       3,924,983  
Asset retirement obligation
    1,555,529       1,556,909  
Derivative instruments
    7,713       381,791  
Other
    523,662       716,368  
                 
      5,253,561       6,580,051  
                 
COMMITMENTS AND CONTINGENCIES (Note 9) SHAREHOLDERS’ EQUITY:
               
Preferred stock, no par value, 5,000,000 shares authorized Series B, 5.68% Cumulative, $100 million aggregate liquidation value, 100,000 shares issued and outstanding
    98,387       98,387  
Common stock, $0.625 par, 430,000,000 shares authorized, 342,754,114 and 341,322,088 shares issued, respectively
    214,221       213,326  
Paid-in capital
    4,472,826       4,367,149  
Retained earnings
    11,929,827       11,457,592  
Treasury stock, at cost, 8,044,050 and 8,394,945 shares, respectively
    (228,304 )     (238,264 )
Accumulated other comprehensive loss
    21,764       (520,211 )
                 
      16,508,721