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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 ü No .

Indicate by check mark if the 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 the 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 .

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2003 was $11.1 billion.

The number of shares outstanding of the Company’s common stock as of January 30, 2004 is shown below:

Anadarko Petroleum Corporation is among the largest independent oil and gas exploration and production companies in the world, with 2.5 billion barrels of oil equivalent (BOE) of proved reserves as of December 31, 2003. The Company’s major areas of operations are located in the United States, primarily in Texas, Louisiana, the mid-continent region and the western states, Alaska and in the shallow and deep waters of the Gulf of Mexico, as well as in Canada and Algeria. Anadarko also has significant production in Venezuela and Qatar and is executing strategic exploration programs in several other countries. The Company actively markets natural gas, oil and natural gas liquids (NGLs) and owns and operates gas gathering systems in its core producing areas. In addition, the Company engages in the hard minerals business through non-operated joint ventures and royalty arrangements in several coal, trona (natural soda ash) and industrial mineral mines located on lands within and adjacent to its Land Grant holdings. The Land Grant is an 8 million acre strip running through portions of Colorado, Wyoming and Utah where the Company owns most of its fee mineral rights. Anadarko is committed to minimizing the environmental impact of exploration and production activities in its worldwide operations through programs such as carbon dioxide (CO₂) sequestration and the reduction of surface area used for production facilities.

Available Information The Company files Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, registration statements and other items with the Securities and Exchange Commission (SEC). Anadarko provides access free of charge to all of these SEC filings, as soon as reasonably practicable after filing, on its internet site located at www.anadarko.com. The Company will also make available to any stockholder, without charge, copies of its Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filings, please contact: Anadarko Petroleum Corporation, Public Affairs Department, P.O. Box 1330, Houston, Texas 77251-1330 or call (832) 636-1316.

In addition, the public may read and copy any materials Anadarko files with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like Anadarko, that file electronically with the SEC.

As of December 31, 2003, Anadarko had proved reserves of 7.7 trillion cubic feet (Tcf) of natural gas and 1.2 billion barrels of crude oil, condensate and NGLs. Combined, these proved reserves are equivalent to 2.5 billion barrels of oil or 15.1 Tcf of gas. The Company’s reserves have grown 22% over the past three years due primarily to: the acquisitions of Berkley Petroleum Corp. (Berkley) and Gulfstream Resources Canada Limited in 2001 and Howell Corporation (Howell) in 2002; substantial crude oil and natural gas reserves discovered in the Gulf of Mexico, Canada and onshore in the United States; crude oil reserves added in Algeria and Alaska; and, through acquisitions of producing properties. As of December 31, 2003, Anadarko had proved developed reserves of 5.9 Tcf of natural gas and 746 million barrels (MMBbls) of crude oil, condensate and NGLs. Proved developed reserves comprise 69% of total proved reserves.

Proved reserve estimates are made by the Company’s engineers. In 2003, Anadarko bolstered its internal control of these estimates by using a corporate review team comprised of five technical experts: four members from within Anadarko who are independent of the operating groups responsible for the reserve estimates, and one member from Netherland, Sewell & Associates, Inc. (NSA), an independent worldwide reserves consultant. The procedures and methods used by Anadarko in preparing its estimates of proved reserves and future revenues, as of

December 31, 2003, were reviewed by the team. Through participation on the team, NSA reviewed more than 70% of the Company’s 2003 reserve additions, as well as specific major properties representing about half of Anadarko’s total worldwide reserves. NSA determined that the general methods and procedures used by Anadarko in the reserve estimation process were reasonable and prepared in accordance with SEC Regulation S-X Rule 4-10(a) and generally accepted petroleum engineering and evaluation principles. A copy of the NSA report is attached as Exhibit 99.1 of this Form 10-K.

To improve investor confidence and provide transparency regarding the Company’s reserves, the Company has initiated an effort to annually report the status of its proved undeveloped reserves (PUDs). The Company annually reviews all PUDs, with a particular focus on those PUDs that have been booked for three or more years, to ensure that there is an appropriate plan for development. Generally, onshore United States PUDs are converted to proved developed reserves within two years. Certain projects, such as improved oil recovery, arctic development, deepwater development and many international programs, may take longer, sometimes beyond five years. Nearly 75% of the Company’s PUDs booked prior to 1999 are in Algeria and are being developed according to a government approved plan. The remaining PUDs booked prior to 1999 are primarily associated with ongoing programs in the onshore United States for improved recovery and arctic development.

The following graph shows the change in PUDs for each year by comparing the vintage distribution of December 31, 2003 PUDs to the vintage distribution of December 31, 2002 PUDs. It illustrates the Company’s effectiveness in converting PUDs to developed reserves.

The Company’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2003, 2002 and 2001 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities — Unaudited (Supplemental Information) in the Anadarko Petroleum Corporation 2003 Consolidated Financial Statements (Consolidated Financial Statements) under Item 8 of this Form 10-K. The Company files annual estimates of certain proved oil and gas reserves with the U.S. Department of Energy (DOE), which are within 5% of the amounts included in the above estimates. See Critical Accounting Policies and Estimates under Item 7 of this Form 10-K.

The following table shows the Company’s annual sales volumes. Volumes for natural gas are in billion cubic feet (Bcf) at a pressure base of 14.73 pounds per square inch and volumes for oil, condensate and NGLs are in MMBbls. Total volumes are in MMBOE. For this computation, six thousand cubic feet (Mcf) of gas is the energy equivalent of one barrel of oil, condensate or NGLs.

The following table shows the Company’s annual average sales prices and average production costs. The average sales prices include gains and losses for derivative contracts the Company utilizes to manage price risk related to the Company’s sales volumes. Production costs are costs incurred to operate and maintain the Company’s wells and related equipment and include cost of labor, well service and repair, location maintenance, power and fuel, transportation, cost of product, property taxes, production and severance taxes and production related administrative and general costs. Certain amounts for prior years have been reclassified to conform to the current presentation. Additional information on volumes, prices and markets is contained in Financial Results and Marketing Strategies under Item 7 of this Form 10-K. Additional detail of production costs is contained in the Supplemental Information under Item 8 of this Form 10-K. Information on major customers is contained in Note 13 of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Anadarko’s active areas in the United States include the Lower 48 states, Alaska and the Gulf of Mexico. Reserves in the United States comprised 68% of Anadarko’s total proved reserves at year-end 2003. During 2003, drilling results included 430 gas wells, 219 oil wells and 37 dry holes. The accompanying maps illustrate by state Anadarko’s undeveloped and developed lease and fee acreage, number of net producing wells and other data relevant to its domestic onshore and offshore oil and gas operations.

Overview About 56% of the Company’s proved reserves are located onshore in the Lower 48 states, with operations primarily in Texas, Louisiana, the mid-continent region and western states. In 2003, average production from the Company’s properties in this area was 1,169 million cubic feet per day (MMcf/d) of gas and 102 thousand barrels per day (MBbls/d) of crude oil, condensate and NGLs, or 57% of the Company’s total production volumes. Anadarko has 2,570,000 gross (1,921,000 net) undeveloped lease acres, 2,964,000 gross (1,980,000 net) developed lease acres and 9,527,000 gross (8,478,000 net) fee acres in the Lower 48 states. In 2004, capital spending in the Lower 48 states is expected to range from $1.2 billion to $1.4 billion.

Bossier Play During 2003, Anadarko continued drilling in the Bossier play and had a total of 20 rigs drilling (11 in east Texas and nine in north Louisiana) at year-end. The Company drilled 142 wells in 2003 with a success rate of 98%. Bossier net volumes for 2003 totaled 122 Bcf, or roughly 19% of the Company’s total gas production, making it Anadarko’s largest onshore gas area. During 2003, exploration leasing activity continued in the Bossier play. At year-end 2003, Anadarko had a total of 478,000 net acres in the area. During 2004, the Company expects to operate about 22 rigs (13 in east Texas and nine in north Louisiana) to drill 205 wells, including six exploration wells, in the Bossier play.

In the east Texas Bossier, the Company has 573 gross operated producing wells and a total of 354,000 net acres as of the end of 2003. During 2003, Anadarko drilled 93 wells, with a 97% success rate. The Company’s net gas production from the east Texas Bossier averaged 211 MMcf/d of gas, a slight increase compared to 2002. During 2003, the Dowdy Ranch field continued to be the focus of activity in east Texas. Production from the field was 106 MMcf/d of gas at the end of 2003, an increase of 47%, compared to the beginning of the year.

In the north Louisiana Bossier, the Vernon field was producing 141 MMcf/d of gas (net) from 123 wells at the end of 2003. This represents an increase of about 100% from year-end 2002. Anadarko’s drilling program in the Vernon field remains focused on extending the boundaries and developing the field areas with the highest production rates, recoverable reserves and economic returns. A total of 49 wells were drilled in the Vernon area in 2003, with a 100% success rate. At year-end 2003, Anadarko’s position in the play totaled 124,000 net acres.

Carthage Anadarko is conducting a successful development program in the Carthage area of east Texas. The Company drilled 44 wells in the area with a success rate of 100% during 2003 and had four rigs performing infill drilling at the end of the year. The Company also had four rigs performing workovers and recompletions throughout the Carthage area at the end of 2003. Anadarko’s net production from the Carthage area averaged 110 MMcf/d of gas and 3 MBbls/d of liquids during 2003. The Company plans to drill 56 wells in the Carthage area in 2004.

Woodbine The Company is operating a deep gas exploration program in the Woodbine play of east Texas (100% working interest (WI)). In 2003, Anadarko drilled two exploration wells. One well encountered mechanical problems and was temporarily abandoned pending further evaluation. The second well is expected to be tested in the first quarter of 2004. In addition, the Company is participating in a 197 square mile 3-D seismic survey in the area. During 2004, the Company plans to continue activity within the play, which may include offset drilling, acquiring additional 3-D seismic and leasing.

South Louisiana During 2003, net volumes from south Louisiana were 5 MMBOE. The majority of the Company’s production in south Louisiana is from the Kent Bayou field. In 2004, the Company expects production to decrease to less than 1 MMBOE due to higher water production.

Overview Anadarko’s horizontal drilling program continues to be the focus in central Texas where it holds approximately 1,001,000 net acres. During 2003, Anadarko drilled 62 wells, with a success rate of 95%, to exploit the multiple pay zones in the Giddings and Brookeland fields. The Company also has an exploration program in the James Lime formation in central Texas. During 2003, net volumes averaged approximately 126 MMcf/d of gas, 14 MBbls/d of oil and 5 MBbls/d of NGLs. In 2003, Anadarko operated over 1,550 wells in this area. In 2004, Anadarko expects to drill 75 wells, including three exploratory wells, as part of a seven-rig program.

Giddings The Company continued its cost-efficient horizontal reentry program in the Giddings field. The cost to reenter a well is about 40% less than the cost of a new well. During 2003, 28 wells were reentered and completed. Additionally, Anadarko continued its water-fracturing program, successfully stimulating 105 wells in 2003.

Brookeland Anadarko’s development program included the drilling and completion of nine wells in 2003 in the Brookeland field, where the Company has approximately 178,000 net acres. During 2003, Anadarko successfully applied a reentry program, similar to the Giddings field, to the area with five wells reentered and completed. During 2004, the Company plans to continue the reentry program to access infill drilling areas.

James Lime In late 2003, Anadarko drilled one successful exploratory well in the James Lime formation, in Madison County, Texas. During 2004, Anadarko plans to evaluate the 2003 discovery well, possibly drill two prospects and continue leasing activity.

During 2003, Anadarko drilled 126 wells with a 98% success rate in the Permian basin. In addition, the Company performed 172 workovers and recompletions. Net production for 2003 averaged 91 MMcf/d of gas and 13 MBbls/d of oil, condensate and NGLs. Anadarko controls 308,000 net acres in the Permian basin and operates 4,960 wells. During 2004, the Company plans to drill 240 development wells and five exploration wells in the Permian basin.

In the Ozona field, located in southwest Texas, development continued with the Company drilling and completing 42 wells and recompleting 45 wells during 2003. In 2003, net production averaged 60 MMcf/d of gas. Anadarko operates 1,844 wells in the Ozona field and plans to drill 48 wells and recomplete 30 wells in 2004. The Company also had activity in its emerging Haley tight gas play in the deep Delaware basin of west Texas. During 2003, two development wells were drilled with a 100% success rate and one exploration well was drilled and is currently awaiting completion. In addition, the Company recompleted two wells and continues to monitor the results. During 2004, Anadarko plans to drill two exploration wells and have an active development program in the deep Delaware basin. Additionally, three exploration wells are planned in the Val Verde basin.

Hugoton Embayment Anadarko’s drilling activities in the Hugoton Embayment, located in southwest Kansas and the Oklahoma and Texas panhandles, are focused on the deeper oil and gas zones below the shallow gas producing formations. Anadarko controls 875,000 net acres in this area and operates 2,300 wells. The deep drilling program in Kansas and the Oklahoma panhandle utilizes 3-D seismic technology to locate oil and gas bearing zones. During 2003, the Company installed a waterflood project in Kansas.

The Company’s net production from the Hugoton Embayment area during 2003 averaged 133 MMcf/d of gas and 17 MBbls/d of oil, condensate and NGLs. In 2003, the Company drilled 36 deep wells with a 53% success rate. Anadarko also recompleted 16 wells and carried out workover operations on 137 wells in the area. In 2004, the Company plans to drill about 48 wells and install an additional waterflood project.

Central Oklahoma During 2003, net production from central Oklahoma was 22 MMcf/d of gas and 8 MBbls/d of crude oil and NGLs. The majority of Anadarko’s focus in 2003 was developing an oil play in the Rush Creek field. In 2003, Anadarko drilled and completed 37 wells in the field, with an 84% success rate, resulting in a net production increase of 2 thousand barrels of oil equivalent per day (MBOE/d). The Company plans to drill about 33 wells in central Oklahoma focused on developing the deeper gas producing zones of the Golden Trend interval in 2004.

Page 9 - Onshore US map Net Net Net Net Undeveloped Developed Fee Producing Acres Acres Acres Wells Onshore: United States Alabama 223 2,677 11,473 9 Alaska* 1,659,315 5,006 7,978 11 Arkansas 658 1,103 344,660 3 California 6,153 318 3,135 -- Colorado 8,572 20,885 2,893,025 216 Florida -- -- 5,342 -- Georgia -- --2,838 -- Idaho -- --846 -- Illinois -- -- 1,954 -- Indiana 913 -- 9,912 -- Iowa -- -- 198 -- Kansas* 355,435 363,737 29,834 1,763 Louisiana* 130,718 156,954 13,131 224 Mississippi 7,349 1,953 63,880 6 Missouri -- -- 552 --Montana 135,449 3,095 8 105 Nebraska 4,643 926 28,198 1 New Mexico 2,643 13,117 417 4 Nevada ---- 433 --North Dakota 20 1,862 -- 3 Oklahoma* 73,977 196,066 31,109 1,288 Oregon -- -- 741 --South Carolina -- -- 2,734 -- Tennessee -- -- 902 -- Texas* 654,071 1,093,275 176,104 6,810 Utah* 7,565 23,651 690,322 167 Washington ---- 2,524 --West Virginia 330 -- -- -- Wyoming* 531,849 100,157 4,163,906 3,200 Office Locations: United States Anchorage, Alaska The Woodlands, Texas * Drilling activities were conducted in these areas in 2003.

Overview Anadarko continues to increase its activity level and production in the western states area, with significant exploration and development activity in conventional, tight gas, enhanced oil recovery and coalbed methane (CBM) plays. The western states area primarily includes the Company’s oil and gas properties in the Land Grant area of Wyoming, Colorado and Utah. Economics on the Land Grant acreage are greatly enhanced by Anadarko’s fee mineral ownership position. For example, in a typical non-operated well that is outside of the Land Grant, Anadarko may have a 25% WI with a 20% net revenue interest. However, on the Land Grant, because of the Company’s fee mineral ownership, Anadarko may have a 25% WI with a 33.75% net revenue interest. Anadarko’s operations on the Land Grant are concentrated in the Green River basin and the Overthrust area.

The Company currently has approximately 8,440,000 net acres, principally attributable to its Land Grant ownership. Anadarko and its partners drilled 231 wells in the area in 2003 with an overall success rate of 99%. Anadarko’s 2003 net production from the western states area averaged 294 MMcf/d of gas, 13 MBbls/d of oil and 16 MBbls/d of NGLs. The Company’s 2004 plans include drilling 274 development wells and at least one exploratory well.

Conventional During 2003, Anadarko’s net production from its conventional properties, located primarily in Wyoming, averaged 219 MMcf/d of gas, 4 MBbls/d of oil and 16 MBbls/d of NGLs. In the Green River basin of Wyoming, Anadarko focused on conventional drilling projects in the Wamsutter, Brady and Moxa Arch areas. In 2003, the Company drilled or participated in 114 wells in the Green River basin, with an overall success rate of 99%. Of these, 30 are Company-operated development wells (95% average WI) and 84 are non-operated wells (21% average WI). In 2004, the Company plans to drill 115 additional wells in the area.

In 2003, three wells were drilled with a 100% success rate in the Table Rock area. In addition, Anadarko and its partner purchased and upgraded the Table Rock gas sweetening plant. Anadarko operates this facility that now has a capacity of 60 MMcf/d of gas. The Company’s net production from the area was 12 MMcf/d of gas in 2003. The Company plans to drill nine wells and continue exploitation of this field in 2004.

During 2003, exploration efforts continued in the Green River and Hanna basins assisted by new interpretations of 2-D and 3-D seismic data. Anadarko continues to process and interpret this seismic data to identify new plays and prospects in the under-explored basins of southern Wyoming. At the end of 2003, the Company was drilling its first Hanna exploration well based on this new seismic data. The Company holds a working interest ownership in 134,000 net acres in this area. In 2004, the Company plans to acquire new 3-D seismic data and drill one additional exploration well.

Enhanced Oil Recovery In late 2002, Anadarko acquired 64 MMBOE of proved reserves, primarily in the Salt Creek and Elk Basin fields of Wyoming, with the Howell acquisition. In a separate transaction, Anadarko acquired the rights to purchase significant quantities of CO₂ and the exclusive rights to market the CO₂ in the Powder River basin. During 2003, the Company completed a pilot CO₂ flood project that confirmed the viability of the enhanced oil recovery process and commenced construction of the first phase of the project. The Company also constructed a 125-mile pipeline that will transport CO₂ to the Salt Creek field and potentially could serve other enhanced oil recovery projects in Wyoming as well. The Company expects to invest an additional $150 million over the next three years for the further development of this project. These projects are expected to result in an increase in net production from the Salt Creek field (98% WI) from year-end 2003 net oil production of 4 MBOE/d to peak production of about 30 MBOE/d by 2009.

During 2003, Anadarko began injection of CO₂ in the Monell field located in south-central Wyoming following completion of a 33-mile CO₂ pipeline. During 2004, the remainder of the facilities needed to serve Monell’s first phase will be completed, another 21 wells will be drilled and the CO₂ flood area will be expanded. This project is expected to result in an increase in net production from the Monell field to about 10 MBOE/d by 2010.

Anadarko is committed to protecting the environment and is working with the DOE and the scientific community to study the long-term storage of CO₂ in its enhanced oil recovery projects. CO₂ is produced along with natural gas in fields elsewhere in Wyoming and the CO₂ has historically been vented to the atmosphere. Reinjecting this CO₂ in the Company’s projects will reduce the amount of greenhouse gases introduced into the atmosphere.

Coalbed Methane CBM has become a core gas play for Anadarko. The Company now operates three full-scale CBM properties (County Line, Helper and Drunkard’s Wash), as well as active pilot programs. The Company also continues to evaluate new CBM exploration opportunities on the Land Grant. Production from the Company’s CBM properties continued to increase during 2003. At year-end 2003, net production averaged 66 MMcf/d of gas compared to 61 MMcf/d of gas in 2002 and 34 MMcf/d of gas in 2001. In 2003, the Company drilled or participated in 68 wells, with an overall success rate of 97%. In 2004, the Company plans to continue to explore for and develop CBM reserves and drill about 130 wells.

During 2003, the Company finished completion operations on 13 pilot wells at Copper Ridge in Wyoming (50% WI). Additionally, along the Land Grant, Anadarko has entered into a 50/50 joint venture to develop 126,000 gross acres for CBM in the Atlantic Rim project area. Anadarko began operating 36 wells and drilled nine additional wells throughout the year within the joint venture. The Company plans to continue to monitor the wells performance in anticipation of development drilling in 2004.

Overview Anadarko’s activity in Alaska is concentrated primarily on the North Slope. The Company had interests in 3,176,000 gross (1,659,000 net) undeveloped lease acres, 24,000 gross (5,000 net) developed lease acres and 16,000 gross (8,000 net) fee acres in Alaska at year-end 2003. About 3% of the Company’s proved reserves at year-end 2003 were in Alaska. The Company has budgeted about $60 million in capital spending in Alaska for 2004, which includes drilling three to four exploration wells and about 12 development wells.

Development The Alpine field (22% WI) on Alaska’s North Slope produced an average of 98 MBbls/d of oil (gross) in 2003. A facility expansion to increase produced water handling in the field and eliminate minor oil train bottlenecks, scheduled to be completed in 2004, is expected to increase production capacity to 110 MBbls/d. During 2003 at Colville Delta 2, development drilling continued with 17 wells (five production and 12 injection wells) drilled and completed. As of year-end 2003, 82 wells (38 production wells and 44 injection or service wells) had been completed. When fully developed, the Alpine field is expected to have 94 horizontal wells from two drill sites.

The Alpine field serves as an excellent example of Anadarko’s commitment to minimizing the impact of exploration and production operations in environmentally sensitive and logistically challenging areas. The production facilities for the Alpine field are situated on about 100 acres, less than one-half of one percent of the subsurface reservoir area being developed. In addition, Alpine is a zero discharge facility; the waste generated is reused, recycled or disposed of properly.

Progress continued on an Environmental Impact Statement that was initiated under the direction of the Bureau of Land Management as a step towards approval of the development of reserves at the Spark, Lookout, Nanuq, Fiord and West Alpine fields (all 22% WI properties). Initial preparation of the permit packages for these fields has also begun. These fields are anticipated to be developed and produced through the Alpine production facility, filling in the natural production decline of Alpine.

Exploration During the 2002-2003 winter exploration season, the Company participated in the drilling of two exploration wells, one located in the National Petroleum Reserve-Alaska (NPR-A) and one in the Colville River Unit. The results of these wells are held confidential pending upcoming lease sales. During 2003, the Company participated in the acquisition of proprietary 3-D seismic around the Alpine field to evaluate additional potential satellite opportunities. The Company also acquired 2-D seismic in the Foothills.

The Company is completing a one-well drilling program to study the feasibility of producing methane hydrates from the arctic tundra. This program will utilize Anadarko’s self-contained, elevated drilling platform called the Arctic Platform Drilling System, which is designed to be lightweight, modular and mobile. This system is intended to be utilized in logistically challenging areas with minimal surface impact, potentially extending traditional drilling seasons.

Overview At year-end 2003, about 9% of the Company’s proved reserves were located offshore in the Gulf of Mexico. Net production volumes in 2003 from these properties averaged 209 MMcf/d of gas and 19 MBbls/d of oil, condensate and NGLs. At year-end 2003, Anadarko owned an average 69% interest in 417 blocks representing 620,000 gross (325,000 net) acres in developed properties and 1,462,000 gross (1,118,000 net) acres in undeveloped properties in the Gulf of Mexico. Anadarko also holds options to earn working interests covering an additional 112 blocks. During 2003, Anadarko drilled 19 wells in the Gulf of Mexico, which resulted in seven gas wells, six oil wells and six dry holes. In the Gulf of Mexico, Anadarko has budgeted about $600 million for capital spending in 2004, which includes drilling about 30 wells.

Acquisition During 2003, Anadarko acquired shelf properties from Amerada Hess with proved reserves of 23 MMBOE for $225 million. The properties added 2.2 MMBOE to Anadarko’s 2003 net production volumes. Anadarko drilled its first well associated with these properties in late 2003. The South Timbalier 166 E-4 well (60% WI) encountered 214 feet of net pay and tested at a rate of 19 MMcf/d of gas. In early 2004, a five-well drilling program began in the South Timbalier 172 field. During 2004, the Company plans to reprocess seismic data on 75 blocks to prioritize deep shelf opportunities identified at these properties. A total of eight wells are expected to be drilled, including development wells and deeper field exploration wells. In addition, a number of recompletions and facilities upgrades are planned.

Conventional Shallow water projects in the Gulf of Mexico continue as the Company exploits the potential around several of its larger and more mature fields. During 2003, nine successful wells were drilled with an 82% success rate. Anadarko has interests in a total of 142 blocks on the shelf.

The Company continued to have success with its redevelopment program at South Marsh Island 269/280/281 (30-50% WI). During 2003, Anadarko drilled and completed three wells and performed three recompletions, bringing net production to 5 MBOE/d at year-end 2003. At the Ship Shoal 207 complex (48% WI), three wells were completed and five wells were recompleted to various zones. This program increased year-end 2003 net field production to 10 MBOE/d. At Eugene Island 380 (100% WI), a shallow well was drilled and completed during 2003 and at year-end was flowing at a rate of 10 MMcf/d of gas. In 2004, the Company is planning to drill 19 development wells and one exploratory well in the shallow waters of the Gulf of Mexico.

Subsalt During 2003, Anadarko continued to delineate the Tarantula (100% WI) subsalt discovery made during 2001, which is located on South Timbalier 308. During 2003, one successful well was drilled and the Company authorized construction of a production platform with a capacity of 100 MMcf/d of gas and 30 MBbls/d of oil. Production is expected to commence in early 2005.

Central Gulf of Mexico Marco Polo (100% WI), Anadarko’s first deepwater development project, is located on Green Canyon Block 608 approximately 180 miles offshore Louisiana in the Gulf of Mexico. Anadarko made the Marco Polo discovery in 2000. During 2003, the final two development wells were drilled. The development program produced better than expected results due to thicker pay and higher quality sands. A third party owns the platform and production facilities for the Marco Polo discovery, as well as other nearby fields. Production capacity of the facility will be 120 MBbls/d of oil and 300 MMcf/d of gas, which is greater than expected production from Marco Polo. Anadarko will have firm capacity of 50 MBbls/d of oil and 150 MMcf/d of gas. The platform hull and topsides are installed and the pipelines are currently being connected to the platform. Upon reaching mechanical completion, Anadarko will become the operator of the facility. Production is expected to commence in mid-2004.

During 2003, Anadarko and its partners announced a third successful deepwater subsalt appraisal well at K2 on Green Canyon Block 562 (52% WI) in the Gulf of Mexico, approximately six miles northwest of Marco Polo. The K2 No. 3 well encountered a total of 208 feet of oil pay. In 1999, the K2 No. 1 well and sidetrack were drilled on the same block, about 4,000 feet away. The wells encountered one zone with average net pay of 60 feet. In 2002, the K2 No. 2 well found a total of 339 feet of pay. This field is planned as a subsea tieback to the Marco Polo platform and is expected to commence production in 2005.

The Company also announced a discovery during 2003 on Green Canyon Block 518. The Green Canyon 518 No. 1 well (100% WI) encountered a total of 128 feet of net oil pay in the same pay zone present at the K2 discovery. The Company believes the well extends the boundaries of the K2 field northward. The field is currently planned as a subsea tieback to the Marco Polo platform and first production is expected in 2005. The Company is currently drilling another well on Green Canyon Block 518 to further delineate the field.

In 2004, drilling will continue in Green Canyon Block 518 to explore the northern and western limits of the field, and three development sidetracks will be drilled in Green Canyon Block 562 to prepare for first production in 2005. In addition, the Company plans to drill the Genghis Khan exploration prospect (100% WI), which is located approximately three miles southeast of Marco Polo.

Eastern Gulf of Mexico During 2003, in the eastern Gulf of Mexico, Anadarko made a natural gas discovery at its Jubilee prospect, the first well in Anadarko’s eastern Gulf exploration program. The Atwater Valley 349 No. 1 well encountered 83 feet of net pay. Anadarko made a second natural gas discovery at the deepwater Atlas prospect on Lloyd Ridge Block 50. Anadarko holds a 100% WI in Atlas and Jubilee. The Company made a third eastern Gulf of Mexico discovery on its Spiderman prospect (45% WI). The discovery well encountered more than 140 feet of net pay. The well is located on DeSoto Canyon Block 621, about 180 miles southeast of New Orleans. In early 2004, a fourth natural gas discovery was made with the Atlas NW exploration prospect on Lloyd Ridge Block 5 (100% WI). Delineation of these discoveries continues.

A regional development plan for several discoveries in the eastern Gulf of Mexico, including Anadarko’s Jubilee, Atlas, Atlas NW and Spiderman, is currently under consideration. In December 2003, Anadarko and several parties executed an agreement to commence the Front End Engineering and Design (FEED) work for the design of a potential deepwater platform for the Atwater Valley area of the eastern Gulf of Mexico. Under the terms of the agreement, the parties agreed to commence the FEED work necessary to evaluate several floating platform concepts and to substantiate the cost estimates associated with a natural gas hub platform and processing facility.

South Auger Participation Agreement Anadarko has a Participation Agreement with BP to explore 95 deepwater blocks in the Garden Banks and Keathley Canyon areas of the western Gulf of Mexico. The 95 blocks, held 100% by BP, are within a larger 640-block area of mutual interest where the two companies have licensed and are reprocessing 3-D seismic data. These blocks are in water depths ranging from 3,000 to 6,000 feet. The agreement gives Anadarko the option to earn a 33% to 66% WI in the blocks. Anadarko will fund 100% of the licensing and reprocessing costs and pay a disproportionately larger share of the first four wells drilled. Anadarko plans to begin drilling the first exploration well by early 2005.

Jupiter Agreement During 2003, Anadarko finalized a Participation Agreement with ExxonMobil covering 32 jointly owned blocks in the Alaminos Canyon and Garden Banks areas. Initial plans include drilling an exploration well in early 2005.

Anadarko holds a total of 152 lease blocks in its deepwater program and has identified approximately 25 prospects. An additional 110 blocks could be earned within its option program. The Company plans to drill about five deepwater exploratory wells in 2004.

The Company processes gas at various third-party plants under agreements generally structured to provide for the extraction and sale of NGLs in efficient plants with flexible commitments. The Company has agreements with five plants in the western states area, 15 plants in the mid-continent area and 11 plants in the gulf coast area. Anadarko also processes gas and has interests in three Company-operated plants and three non-operated plants in the western states. Anadarko’s strategy to aggregate gas through Company-owned and third-party gathering systems allows Anadarko to secure processing arrangements in each of the regions where the Company has significant production.

Overview Anadarko has operations in Alberta, British Columbia, Saskatchewan and in the Northwest Territories. The Company has proved reserves in Canada of 314 MMBOE, which is about 12% of the Company’s total proved reserves. In 2003, net production from the Company’s properties in Canada averaged 383 MMcf/d of gas and 19 MBbls/d of crude oil, condensate and NGLs, or 16% of the Company’s total production volumes. During 2003, Anadarko participated in a total of 344 wells with a 95% success rate, including 276 gas wells, 51 oil wells and 17 dry holes. Anadarko has 9,124,000 gross (3,310,000 net) undeveloped lease acres, 1,834,000 gross (1,037,000 net) developed lease acres and 606,000 gross (606,000 net) fee acres in Canada. The Company’s 2004 capital budget for Canada ranges from $375 million to $425 million and the Company expects to drill about 175 development and 40 exploration wells. The accompanying map illustrates the Company’s developed and undeveloped lease and fee acreage, number of productive wells and other data relevant to its properties in Canada.

Alberta During 2003, the Company announced a significant natural gas discovery well in the Saddle Hills area of Alberta. The discovery well (100% WI) flowed at a rate of 16 MMcf/d of gas. A total of seven gas wells were completed in the area during 2003.

In the Wild River area of west central Alberta, 26 wells were drilled and completed from various zones during 2003. In addition, Anadarko expanded the capacity of the Wild River gas plant (100% WI) in 2003 by 35 MMcf/d to 79 MMcf/d of gas. In the Dawson area of northwest Alberta, five oil wells and one gas well were drilled and completed in 2003. In the Foothills area of Alberta, the Voyager 3-21 (83% WI) was put on production at 3 MMcf/d of gas.

British Columbia In 2003, Anadarko had continued success in the Slave Point program at Adsett in northeast British Columbia. Three exploration and two development wells were drilled in 2003 with a success rate of 71%. The Company also acquired 263 square miles of 3-D seismic in the area and is drilling to test the western extent of the Adsett field. Anadarko recently expanded infrastructure capacity from 45 MMcf/d to 50 MMcf/d of gas and plans to add an additional 5 MMcf/d of capacity in 2004.

During 2003, in the Foothills area in eastern British Columbia, a successful exploration well (23% WI) was also drilled. The well came on production in late 2003 at a rate of 7 MMcf/d of gas. One additional development well may be required to define the extent of this field. In addition, an exploratory well was drilled at West Sukunka (30% WI) and is undergoing evaluation.

Saskatchewan During 2003, the Company drilled and completed 106 shallow gas wells with an overall success rate of 92%. In the Hatton area, the Company drilled 65 operated wells and participated in another 16 non-operated wells. Net production from the Hatton area averaged 71 MMcf/d of gas in 2003.

Anadarko increased its exploratory acreage position in southwest Saskatchewan by 30,000 gross (27,000 net) acres in 2003. Two new shallow gas plays were initiated during the year in this area. A total of 16 wells were part of the Milk River exploratory program in the Freefight and Leader areas, east and north of Hatton respectively. Development of these areas will take place in late 2004 and 2005.

Northwest Territories In the southern Northwest Territories near Fort Liard, the Company drilled nine exploratory wells (100% WI) in 2003. Initial tests from the wells were encouraging and consequently the Company filed four discovery applications. Anadarko also participated in a development well in the Liard area that tested at a rate of 30 MMcf/d of gas. In 2004, Anadarko will participate in the drilling of an exploratory well (37% WI) on Block EL-384 in the Mackenzie Delta.

Page 17 - Canada map Net Net Net Net Undeveloped Developed Fee Producing Acres Acres Acres Wells Canada: Alberta* 885,576 536,346 517,206 1,075 British Columbia* 924,948 207,584 -- 255 Northwest Territories* 1,079,137 5,608 -- 3 Saskatchewan* 187,879 287,425 88,683 2,230 Scotian Shelf 231,975 -- -- --Office Locations: Canada Calgary, Alberta Edson, Alberta Fort St. John, British Columbia Grande Prairie, Alberta Medicine Hat, Alberta * Drilling activities were conducted in these areas in 2003.

Overview Anadarko is engaged in exploration, development and production activities in Algeria’s Sahara Desert. At the end of 2003, six fields discovered by the Company were on production. Anadarko has developed a good working relationship with Sonatrach, the national oil and gas enterprise of Algeria, its principal partner within Algeria. Sonatrach has owned shares of the Company’s common stock since 1986 and at year-end 2003 was the registered owner of 4.8% of Anadarko’s outstanding common stock.

The Company has proved reserves in Algeria of 361 MMBbls of crude oil, condensate and NGLs as of year-end 2003. In 2003, net sales volumes from the Company’s properties in Algeria totaled 19 MMBbls of crude oil, or 10% of the Company’s total sales volumes. In 2003, Anadarko participated in 27 wells with a success rate of 85%. In addition, the Company participated in 18 injection or service wells during the year. At the end of 2003, the Company had 3,994,000 gross (1,221,000 net) acres in Algeria. Anadarko plans to invest between $60 million and $70 million in Algeria during 2004. The accompanying map illustrates the Company’s developed and undeveloped acreage, number of productive wells and other data relevant to its properties in Algeria.

Blocks 404, 208 and 211 Production Sharing Agreement Anadarko’s interest in the production sharing agreement (PSA) is 50% before participation at the exploitation stage by Sonatrach. The Company has two joint venture partners, each with a 25% interest, also prior to participation by Sonatrach. Under the terms of the PSA, oil reserves that are discovered, developed and produced are shared by Sonatrach, Anadarko and its two joint venture partners. Anadarko and its joint venture partners fund Sonatrach’s 51% share of exploration costs and are entitled to recover these exploration costs out of production in the exploitation phase. As of year-end 2003, Anadarko and its joint venture partners had recovered about 95% of Sonatrach’s portion of exploration costs through an increased share of production (cost recovery oil). Sonatrach is responsible for 51% of development and production costs. Sonatrach, Anadarko and its joint venture partners formed a non-profit company, Groupement Berkine, to carry out the majority of their joint operating activities under the PSA. Sonatrach, Anadarko and its joint venture partners fund the expenditures incurred by Groupement Berkine according to their participating interests under the PSA. Exploration drilling under the original PSA ended in 1998. Anadarko and its partners resumed their exploration program on Blocks 404, 208 and 211 in 2002 following an amendment to the PSA. See Exploration.

Block 406b Production Sharing Agreement The Company has a separate exploration license for Block 406b in which it has a 60% interest.

Block 403c/e Production Sharing Agreement Anadarko has exploration rights over Block 403c/e. Anadarko holds a 67% interest in the exploration phase of this venture.

Block 404 — Hassi Berkine South Central Production Facility The Hassi Berkine South (HBNS) Central Production Facility has a total processing capacity of 300 MBbls/d of oil. During 2003, production from the HBNS field averaged 119 MBbls/d of oil (gross). Production from three of the satellite fields — Hassi Berkine South East (HBNSE), Berkine North East (BKNE) and Rhourde Berkine (RBK) averaged 24 MBbls/d of oil (gross) in 2003. During 2003, 11 wells were drilled in the HBNS and satellite fields, resulting in 10 productive wells and one unsuccessful well.

Groupement Berkine is also developing the Hassi Berkine (HBN) field that is located just to the north of the HBNS field. This producing field extends into Block 403, which is under a different association with Sonatrach. Unitization of the field was accomplished to facilitate development activities. A crude oil production train with the capacity to process 75 MBbls/d of oil has been installed as part of the HBNS facility. Production from the HBN field averaged 66 MBbls/d of oil (gross) in 2003. Five productive wells were drilled in the HBN field during 2003 with a 100% success rate.

Page 19 - Algeria map Algeria Undeveloped Acreage Total 3.8 million acres (1.2 million acres net) Algeria Developed Acreage (HBNS, HBN, Ourhoud, HBNSE, BKNE, RBK, QBN & BKE Fields) Total 221,435 acres (54,252 acres net) Productive Wells Total 122 (26 net) Fields discovered to date shown graphically HBN field* HBNE field* HBNS field* HBNSE field* SFSW field* RBK field QBN field BKNE field* BKNE-AAC-A field* BKE field Ourhoud field* EKT field* EMN field* EMK field* EME field* Blocks shown graphically 403c 403e 404* 406b 208* 211 Central Processing Facilities shown graphically HBNS field Ourhoud field *Drilling activities were conducted in these areas in 2003.

Block 404 — Ourhoud Central Production Facility Anadarko is also actively involved in developing the Ourhoud field, the second largest oil field in Algeria. Located in the southern portion of Block 404, the Ourhoud field extends into Block 406a and Block 405 and is unitized with the companies with interests in those blocks. The field is operated by the Ourhoud Organization, which represents the interests of the three associations involved in this development. Production from the field commenced in late 2002. Ourhoud became fully operational during the first half of 2003 with facility capacity reaching 230 MBbls/d of oil. Production from the Ourhoud field averaged 174 MBbls/d of oil (gross) in 2003. A total of 14 productive wells were drilled in the Ourhoud field in 2003.

Block 208 Anadarko also has several fields farther south on Block 208; these include the El Merk field (EMK), the El Kheit Et Tessekha field (EKT), the El Merk East field (EME) and the El Merk North field (EMN). During 2003, the Exploitation License Applications were approved for these fields by the Ministry of Energy and Mines. Anadarko will proceed with design and anticipates awarding the Engineering, Procurement and Construction contract for a third Central Production Facility by mid-2005. During 2003, a total of nine wells were drilled in the Block 208 fields with a 100% success rate.

Blocks 404, 208 and 211 Following an amendment to the original PSA with Sonatrach, Anadarko and its joint venture partners resumed their exploration drilling program on Blocks 404, 208 and 211 in 2002, outside the boundaries encompassing the previous discoveries. These are the same blocks Anadarko and partners began exploring during the original exploration phase in 1989. As a result, a large amount of data had been gathered over the years in this area prior to commencing the current phase of exploration drilling.

Under the terms of the three-phase exploration program, Anadarko and its joint venture partners will spend a minimum of $55 million by mid-2006. Anadarko and its joint venture partners will finance 100% of the exploration investment and Sonatrach will participate 51% in the development and exploitation phases of any discoveries. Where appropriate, existing facilities and infrastructure may be used to develop any discoveries.

During 2003, Anadarko and its joint venture partners drilled six exploration and appraisal wells, three of which were successful Block 404 wells. The BKNE-AAC-A, which lies within the BKNE field exploitation license area, tested at a rate of 3 MBbls/d of oil. The Sif Fatima South West (SFSW) #1 tested at a rate of 3 MBbls/d of oil. The SFSW #2, which confirmed the extension of the field, tested at a rate of 1 MBbls/d of oil.

Block 406b The license for Block 406b has a three-year initial term. A work program commitment includes seismic acquisition and one exploration well. A 735-mile proprietary 2-D seismic acquisition program has been completed on this 686,000 acre block, located in the Berkine basin to the east of Anadarko’s other license areas. During 2003, the new data was processed and interpreted to develop the prospect inventory for the permit. The first exploration well on the block will be drilled in 2004. The first exploration period expires in December 2004.

Block 403c/e The license for Block 403c/e has a three-year initial term and includes 399,000 acres in the Berkine basin. A work program commitment includes seismic acquisition and one exploration well. During 2003, 1,790 miles of existing seismic data was reprocessed in two phases and a 2-D seismic acquisition program of 65 miles was completed. A 3-D seismic program commenced in late 2003. The Company plans to drill the first exploration well in late 2004. The first exploration period expires in January 2006.

Political unrest continues in Algeria. Anadarko continually monitors the situation and has taken steps to help ensure the safety of employees and the security of its facilities in the remote regions of the Sahara Desert. Anadarko is unable to predict with certainty any effect the current situation may have on activity planned for 2004 and beyond. However, the situation has had no material effect to date on the Company’s operations in Algeria, where the Company has had activities since 1989. See Regulatory Matters and Additional Factors Affecting Business — Foreign Operations Risk under Item 7 of this Form 10-K.

Overview The Company’s other international oil and gas production and development operations are located primarily in Venezuela and Qatar. The Company also has an interest in a non-operated producing property in offshore Egypt, interests in two non-operated offshore producing properties in Australia and an operated interest in exploratory and development acreage in Oman. The Company currently has exploration acreage in Qatar, Tunisia, West Africa, the Faroe Islands, off the coast of Georgia in the Black Sea and other selected areas. In the process of evaluating the allocation of capital resources to international areas for 2004, the Company decided to narrow the list of international projects. While Management sees an important place for international projects within its portfolio, this strategy was implemented to better focus the Company’s international efforts. During 2004, the Company expects to work toward divesting the non-core assets located in Oman, Egypt and Australia.

The Company had total proved reserves in other international locations of 109 MMBbls of crude oil, condensate and NGLs and 144 Bcf of gas at year-end 2003. During 2003, net production from the Company’s other international properties was 22 MBbls/d of crude oil, condensate and NGLs, or 4% of the Company’s total production volumes. Anadarko participated in a total of 12 wells in other international locations during 2003 with a success rate of 58%. Drilling results included six oil wells, one gas well and five dry holes. Anadarko has 21,957,000 gross (8,940,000 net) undeveloped lease acres and 569,000 gross (155,000 net) developed lease acres in these international areas. In 2004, the Company plans to invest about $100 million in other international projects. See Regulatory Matters and Additional Factors Affecting Business — Foreign Operations Risk under Item 7 of this Form 10-K.

Venezuela The Company’s Venezuelan operation consists of the Oritupano-Leona contract area, a risk service contract in which the Company has a non-operated 45% participating interest. The area covers 395,000 gross (178,000 net) acres and had 274 producing wells at year-end 2003. The Company’s net oil sales volumes from the area averaged 12 MBbls/d during 2003. The development and exploitation program in 2003 included three new well completions and the conversion of 26 idle wells to producing wells. During 2004, the Company expects to continue with the development of the Oritupano-Leona contract area, focusing most of the activities on recompleting and reactivating existing wells.

Currently, there is political unrest in Venezuela. After two national strikes during 2002, production resumed in January 2003 and was fully restored by the second quarter of 2003. Anadarko is unable to predict with certainty any effect the current situation may have on activity planned for 2004 and beyond. However, the situation is not expected to have a material adverse effect on the consolidated results of operations or financial position of the Company.

Qatar Anadarko is operator and has a 92.5% interest in the Al Rayyan field, which is part of an Exploration and Production Sharing Agreement covering Blocks 12 and 13. Production from the Al Rayyan field, which is located in the northern part of Block 12, averaged 8 MBbls/d of oil (net) during 2003. During 2003, a new permanent production platform was installed, the existing wells were tied back, several workovers were conducted and two previously untested wells were brought online. Production in 2003 was less than expected because forecasted development drilling was delayed, water production from several wells was higher than anticipated and completion of the production facility was delayed primarily due to weather constraints. At year-end 2003, the field was producing 18 MBbls/d of oil (10 MBbls/d net) from 12 wells. During 2004, the Company plans to reevaluate potential infill drilling, recompletion and workover opportunities, pending the results of a full field reservoir stimulation study that is expected to be completed in early 2004.

The South Al Rayyan exploration prospect, also on offshore Block 12, was drilled and subsequently plugged and abandoned during 2003. Anadarko does not intend to further pursue exploration on Block 12. During 2003, the Company recorded a ceiling test impairment of $68 million for Qatar as a result of lower production estimates and unsuccessful exploration activity.

Tunisia The Company operates two blocks in the Ghadames basin of Tunisia. The Company has a 61% interest in the Anaguid Block, which covers 1,100,000 acres and a 100% interest in the Jenein Nord Block, which covers 384,000 acres. The acreage is on trend with the Company’s discoveries in Algeria to the west. During 2003, the CEM-1 well encountered 95 feet of pay and tested at a rate of 4 MMcf/d of gas and 500 barrels of condensate per day. A second well, the SEA-1, encountered 52 feet of net pay in the same section. Both of these Anaguid wells have been suspended pending the evaluation of commercial development plans.

West Africa Anadarko is the operator and holds a 50% interest in the Agali Block, offshore Gabon. During 2003, the Company secured an amendment to its production sharing contract that allows the obligation well to be drilled after the boundary dispute between Gabon and its northern neighbor, Equatorial Guinea, is resolved.

North Atlantic Margin In the Faroe Islands, Anadarko is the operator and sole licensee of License 007 and holds a 28% interest in the adjacent non-operated License 006. The licenses cover a total of 617,000 acres. In 2003, the Company completed its technical evaluation of these blocks and secured a two year extension on License 007 until August 2005. During 2004, Anadarko plans to seek a partner to evaluate this block. The Company has no outstanding drilling commitments in the region.

Georgia — Black Sea Anadarko has a Production Sharing Contract with the State of Georgia. The agreement gives Anadarko exploration rights to three blocks covering approximately 2,000,000 acres on the Black Sea Continental Shelf and extending 50 miles offshore. During 2003, the Company conducted geophysical and geological studies and Anadarko is currently seeking partners to share costs and reduce risk in future seismic or drilling activities.

The Company’s 2003 drilling program focused on known oil and gas provinces in the United States (Lower 48, Alaska and Gulf of Mexico), Canada and Algeria. Exploration activity consisted of 147 wells, including 36 wells in the Lower 48, one well in Alaska, seven wells offshore in the Gulf of Mexico, 92 wells in Canada, six wells in Algeria and five wells in other international locations. Development activity consisted of 922 wells, which included 622 wells in the Lower 48, eight wells in Alaska, 12 wells offshore in the Gulf of Mexico, 252 wells in Canada, 21 wells in Algeria and seven wells in other international locations.

The following table shows the results of the oil and gas wells drilled and tested:

The following table shows the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion as of December 31, 2003:

As of December 31, 2003, the Company had a working interest ownership in productive wells as follows:

The following schedule shows the number of developed lease, undeveloped lease and fee mineral acres in which Anadarko held interests at December 31, 2003:


*	Developed acreage in Algeria relates only to areas with an Exploitation License. A portion of the undeveloped acreage in Algeria will be relinquished in the future upon finalization of Exploitation License boundaries.

Marketing The Company’s marketing department actively manages the sale of Anadarko’s oil, natural gas and NGLs production. The Company markets its production to creditworthy customers at competitive prices, maximizing realized prices while managing credit exposure. The Company also purchases volumes for resale primarily from partners and producers near Anadarko’s production. These purchases allow the Company to aggregate larger volumes and attract larger, creditworthy customers, which in turn enhance the value of the Company’s production.

The Company sells natural gas under a variety of contracts and may also receive a service fee related to the level of reliability and service required by the customer. The Company has the marketing capability to move large volumes of gas into and out of the “daily” gas market to take advantage of any price volatility. The Company may also conduct limited trading activities for the purpose of generating profits from exposure to changes in market prices of natural gas, crude oil, condensate and NGLs.

Gas Gathering Anadarko owns and operates seven major gas gathering systems in the United States, where the Company has substantial gas production. The systems are: Antioch Gathering System in the Southwest Antioch field of Oklahoma; Sneed System in the West Panhandle field of Texas; Hugoton Gathering System in southwest Kansas; Dew Gathering System in east Texas; Pinnacle Gathering System in east Texas; CJV/ SEC Gathering System in the Carthage field of east Texas; and, Vernon Gathering System in the Vernon field of north Louisiana.

The Company’s minerals properties contribute to operating income through non-operated joint venture and royalty arrangements in coal, trona and industrial mineral mines across the Company’s extensive fee mineral interest in the Land Grant. The Company reinvests the cash flow from its hard minerals operations primarily into its oil and gas operations.

The Company’s low sulfur coal deposits, located primarily in southern Wyoming, compete with other western coal producers for industrial and utility boiler markets, which burn the coal to produce steam used to generate electricity. Most of the Company’s coal interests use the surface mining method of extraction. Because of the high extraction and transportation costs, additional development of the Company’s reserves is dependent on increased coal usage in local markets. In addition to fee mineral ownership of and royalty interests in coal reserves, the Company owns a 50% non-operating interest in Black Butte Coal Company. Black Butte Coal Company produces approximately three million tons of coal per year.

The world’s largest known deposit of trona, comprising 90% of the world’s trona resources, is located in the Green River basin in southwestern Wyoming. Natural soda ash, which is produced by refining trona ore, is used primarily in the production of glass, in the paper and water treatment industries and in the manufacturing of certain chemicals and detergents. The Company owns interests in lands containing approximately 50% of these reserves and has leased a portion of those lands to companies that mine and refine trona. In addition to fee mineral ownership of and royalty interest in trona reserves, the Company owns a 49% non-operating interest in the OCI Wyoming LP (OCI) soda ash refining facility near Green River, Wyoming. The OCI facility typically produces about 2 million tons of soda ash per year.

Information on operations by segment and geographic location is contained in Note 14 of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

As of December 31, 2003, the Company had about 3,500 employees. Relations between the Company and its employees are considered to be satisfactory. The Company has had no significant work stoppages or strikes pertaining to its employees.

See Regulatory Matters and Additional Factors Affecting Business under Item 7 of this Form 10-K.

As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time properties believed to be suitable for drilling operations are acquired by the Company. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. A thorough title examination has been performed with respect to substantially all leasehold producing properties owned by the Company. Anadarko believes the title to its leasehold properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which the Company has conducted exploration activities, are not so material as to detract substantially from the use of such properties.

The leasehold properties owned by the Company are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. Anadarko does not believe any of these burdens will materially interfere with its use of these properties.

Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends

Anadarko’s ratio of earnings to fixed charges was 5.83 and earnings to combined fixed charges and preferred stock dividends was 5.71 for the year ended December 31, 2003. Anadarko’s ratio of earnings to fixed charges was 3.83 and earnings to combined fixed charges and preferred stock dividends was 3.74 for the year ended December 31, 2002. As a result of the Company’s net loss in 2001, Anadarko’s earnings did not cover fixed charges by $599 million and did not cover combined fixed charges and preferred stock dividends by $610 million.

These ratios were computed by dividing earnings by either fixed charges or combined fixed charges and preferred stock dividends. For this purpose, earnings include income before income taxes and fixed charges. Fixed charges include interest and amortization of debt expenses and the estimated interest component of rentals. Preferred stock dividends are adjusted to reflect the amount of pretax earnings required for payment.

Information on Properties is contained in Item 1 of this Form 10-K and in Note 19 — Commitments of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

General The Company is a defendant in a number of lawsuits and is involved in governmental proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. The Company has also been named as a defendant in various personal injury claims, including numerous claims by employees of third-party contractors alleging exposure to asbestos, silica and benzene while working at a refinery in Corpus Christi, Texas, which a company Anadarko acquired by merger in 2000 sold in segments in 1987 and 1989. While the ultimate outcome and impact on the Company cannot be predicted with certainty, Management believes that the resolution of these proceedings will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. Discussed below are several specific proceedings.

Royalty Litigation The Company is subject to various claims from its royalty owners in the regular course of its business as an oil and gas producer, including disputes regarding measurement, costs and expenses beyond the wellhead, and basis valuations. Among such claims, the Company was named as a defendant in a case styled U.S. of America ex rel. Harold E. Wright v. AGIP Company, et al. (the “Gas Qui Tam case”) filed in September 2000 in the U.S. District Court for the Eastern District of Texas, Lufkin Division. This lawsuit generally alleges that the Company and 118 other defendants improperly measured and otherwise undervalued natural gas in connection with a payment of royalties on production from federal and Indian lands. Based on the Company’s present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, if the Company is found to have violated the Civil False Claims Act, the Company could be subject to a variety of sanctions, including treble damages and substantial monetary fines. The case was transferred to the U.S. District Court, Multi-District Litigation (MDL) Docket pending in Wyoming. All defendants jointly filed a motion to dismiss the action on jurisdictional grounds based on Mr. Wright’s failure to qualify as the original source of the information underlying his fraud claims, and the Company filed additional motions to dismiss on separate grounds. The MDL Panel remanded the case to the federal court in Lufkin, Texas without ruling on the motions for dismissal. The proceedings were delayed for procedural reasons as the case was remanded and a new judge was appointed; however, the Company now expects to obtain a hearing on its motions for dismissal in early 2004.

A group of royalty owners purporting to represent Anadarko’s gas royalty owners in Texas was granted class action certification styled Neinast, Russell, et al. v. Union Pacific Resources Company, et al. in December 1999, by the 21st Judicial District Court of Washington County, Texas, in connection with a gas royalty underpayment case against the Company. This certification did not constitute a review by the Court of the merits of the claims being asserted. The royalty owners’ pleadings did not specify the damages being claimed, although a demand for damages in the amount of $100 million was asserted. The Company appealed the class certification order. A favorable decision from the Houston Court of Appeals decertified the class. The royalty owners did not appeal this matter to the Texas Supreme Court and the decision from the Houston Court of Appeals became final in the second quarter of 2002. In the fourth quarter of 2003, the royalty owners filed a new petition alleging that the class may properly be brought so long as “sub-class” groups are broken out. The Company is vigorously contesting this new petition. The same attorneys who filed the Neinast lawsuit as a state-wide class action also filed a lawsuit, styled Hankins, Lowell F., et al. v. Union Pacific Resources Group Inc., et al., in the 112th Judicial District Court, Crockett County, Texas. The two lawsuits are substantially identical, except that the Hankins lawsuit is limited to royalty owners in Crockett and Sutton Counties. The Texas Supreme Court has reversed certification of this class; however, as with the Neinast case, the plaintiffs have indicated that they may seek certification of sub-classes and continue to prosecute the claims. The Company continues to vigorously defend itself against the claims.

A class action lawsuit styled Gilbert H. Coulter, et al. v. Anadarko Petroleum Corporation has been certified in the 26th Judicial District Court, Stevens County, Kansas. In this action, the royalty owners contend that royalty was underpaid as a result of the deduction for certain post-production costs in the calculation of royalty. The Company believes that its method of calculating royalty was proper, and thus plaintiffs’ claims are without merit. This case was certified as a class action in August 2000 and was tried in February 2002. It is uncertain at this time when the trial court will render its ruling.

Texas Osage. In addition, the plaintiff contends that the Company failed to comply with express and implied provisions of various leases between April 1993 and the present. The Company is vigorously contesting the claims and believes royalties were properly paid based upon prices received in sales made to third-party purchasers or at sales prices comparable to third-party sales. The plaintiff served expert reports in the third quarter of 2003, which calculate the plaintiff’s royalty damages in a range between $4 million and $5 million. The plaintiff also claims additional damages of approximately $2 million with regard to certain specific land and development issues. The Company disputes these claims and the trial is scheduled for June 2004.

T-Bar X Lawsuit T-Bar X Limited Company v. Anadarko Petroleum Corporation, a case filed in the 82nd Judicial District Court of Robertson County, Texas, involves a dispute regarding a confidentiality agreement that Anadarko executed in August 1999. On January 28, 2004, based upon a jury verdict, the court entered a $145 million judgment in favor of the plaintiff as follows: $40 million in actual damages; $100 million in punitive damages; and, $5 million in pre-judgment interest. The Company believes that it has strong arguments for a reversal on appeal. Anadarko and outside counsel believe that, following appeals, it is not probable that the judgment will be affirmed. If a judgment is reversed and remanded for a new trial, Anadarko will vigorously defend itself on retrial. While the ultimate outcome and impact of this claim on Anadarko cannot be predicted with certainty, Anadarko believes that the resolution of these proceedings will not have a material adverse effect on its consolidated financial position.

CITGO Litigation CITGO Petroleum Corporation’s (CITGO) claims arise out of an Asset Purchase and Contribution Agreement in 1987 whereby a company Anadarko acquired by merger in 2000 sold a refinery located in Corpus Christi, Texas to CITGO’s predecessor. After the sale of the refinery, numerous individuals living near the refinery sued CITGO (the Neighborhood Litigation) thereby implicating the Asset Purchase and Contribution Agreement indemnity provision. CITGO and Anadarko eventually entered into a settlement agreement to allocate, on an interim basis, each party’s liability for defense and liability cost in that and related litigation. That agreement provides that once the Neighborhood Litigation and certain related claims are resolved, then the parties will determine their final indemnity obligations to each other through binding arbitration. At the present time, Anadarko and CITGO have agreed to defer arbitrating the allocation of responsibility for this liability in order to focus their efforts on a global settlement. Arbitration will resume upon request of either CITGO or Anadarko. Negotiations and discussions with CITGO continue. Anadarko has offered to settle all outstanding issues for approximately $4 million and a liability for this amount has been accrued.

Kansas Ad Valorem Tax The Natural Gas Policy Act of 1978 allowed a “severance, production or similar” tax to be included as an add-on, over and above the maximum lawful price charged for natural gas. Based on the Federal Energy Regulatory Commission (FERC) ruling that the Kansas ad valorem tax was such a tax, the Company collected the Kansas ad valorem tax. FERC’s ruling regarding the ability of producers to collect the Kansas ad valorem tax was appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). Ultimately, the D.C. Circuit issued a decision on August 2, 1996 ruling that producers must refund all Kansas ad valorem taxes collected relating to production since October 1983. The Company filed a petition for writ of certiorari with the Supreme Court. That petition was denied on May 12, 1997.

During 2003, the PanEnergy Litigation related to these refunds was settled. The Company has a reserve of about $2 million for three other Kansas ad valorem tax refunds. The Company has reached agreements to settle the three remaining claims, subject to formal FERC approval, which the Company expects to receive in the first half of 2004. Upon receipt of final FERC approval, the Company expects to conclude those settlements by paying approximately $2 million. After those settlements are concluded, all claims for refunds related to Kansas ad valorem taxes will be fully resolved.

Other The Company is subject to other legal proceedings, claims and liabilities which arise in the ordinary course of its business. In the opinion of the Company, the liability with respect to these actions will not have a material effect on the Company.

There were no matters submitted to a vote of security holders during the fourth quarter of 2003.

In December 2003, Mr. Hackett was named President and Chief Executive Officer. Prior to joining Anadarko, he served as President and Chief Operating Officer of Devon Energy Corporation since its acquisition of Ocean Energy, Inc. in April 2003. Mr. Hackett served as President and Chief Executive Officer of Ocean Energy, Inc. from March 1999 to April 2003 and as Chairman of the Board from January 2000 to April 2003. He served as Chief Executive Officer and President of Seagull Energy Corporation from September 1998 until March 1999 and as Chairman of the Board from January 1999 to March 1999.

Mr. Meyer was named Vice President, International and Alaska Operations in 2002 and was named Vice President, Algeria in 2001. Prior to this position, he served as President and General Manager, Anadarko Algeria Company, LLC and in other managerial roles for Anadarko Algeria Company, LLC and in the Operations Department. He has worked for the Company since 1981.

Mr. Pease was named Vice President, U. S. Onshore and Offshore in 2002. Prior to this position, he served as Vice President, International and Alaska Operations since September 2001, Vice President, Engineering and Technology since February 2001, Vice President, Algeria since 1998 and as President and General Manager, Anadarko Algeria Company, LLC since 1993. He has worked for the Company since 1979.

Ms. Ripley was named Vice President and General Counsel in 2003. Prior to this position, she served as Vice President, General Counsel and Secretary of Anadarko Canada Corporation since 2000. She served as Vice President, General Counsel and Secretary of Union Pacific Resources Inc. since 1998 and as Senior Counsel for Norcen Energy Resources Limited since 1997.

Officers of Anadarko are elected at an organizational meeting of the Board of Directors following the annual meeting of stockholders, which is expected to occur on May 6, 2004, and hold office until their successors are duly elected and shall have qualified. There are no family relationships between any directors or executive officers of Anadarko.

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

Information on the market price and cash dividends declared per share of common stock is included in the Stockholder Information in the Anadarko Petroleum Corporation 2003 Annual Report (Annual Report) which is incorporated herein by reference.

The amount of future common stock dividends will depend on earnings, financial condition, capital requirements and other factors, and will be determined by the Directors on a quarterly basis. For additional information, see Dividends under Item 7 of this Form 10-K.

Equity Compensation Plan Table The following table sets forth information with respect to the equity compensation plans available to directors, officers and employees of the Company as of December 31, 2003:

Unregistered Securities In March 2001, Anadarko issued $650 million of Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) due 2021 to qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S. The initial purchaser of the ZYP-CODES was Lehman Brothers Inc. Debt offering expenses related to issuing these securities were $6 million. The ZYP-CODES were subsequently registered on a Form S-3 effective July 2001.

In April 2001, Anadarko Finance Company, a wholly-owned finance subsidiary of Anadarko, issued $1.3 billion in notes to qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S. The initial purchaser was Credit Suisse First Boston Corporation. This issuance was made up of $400 million of 6 3/4% Notes due 2011 and $900 million of 7 1/2% Notes due 2031. In May 2001, Anadarko Finance Company issued an additional $550 million of 6 3/4% Notes due 2011, bringing the 6 3/4% Notes to an aggregate total of $950 million. Discounts related to issuing these securities were $11 million. The notes were subsequently registered on a Form S-4 effective July 2001.

See Five Year Financial Highlights in the Annual Report, which is incorporated herein by reference.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Anadarko Petroleum Corporation’s primary line of business is the exploration, development, production and marketing of natural gas, crude oil, condensate and NGLs. The Company’s major areas of operations are located in the United States, Canada and Algeria. The Company is also active in Venezuela, Qatar and several other countries. The Company’s focus is on adding high-margin oil and natural gas reserves at competitive finding and development costs and continuing to develop more efficient and effective ways of producing oil and gas. The primary factors that affect the Company’s results of operations include, among other things, commodity prices for natural gas, crude oil and NGLs, production volumes, the Company’s ability to find additional oil and gas reserves, as well as the cost of finding reserves and changes in the levels of costs and expenses required for continuing operations. Unless the context otherwise requires, the terms “Anadarko” or “Company” refer to Anadarko and its subsidiaries.

Net Income Anadarko’s net income available to common stockholders for 2003 totaled nearly $1.3 billion, or $5.09 per share (diluted), compared to net income available to common stockholders for 2002 of $825 million, or $3.21 per share (diluted). The increase in net income in 2003 is due primarily to significantly higher commodity prices, partially offset by higher costs and expenses. Anadarko had a net loss available to common stockholders in 2001 of $188 million or $0.75 per share (diluted). The net loss for 2001 included noncash charges of $2.5 billion ($1.6 billion after taxes) for impairments of the carrying value of oil and gas properties primarily in the United States, Canada and Argentina as a result of low natural gas and oil prices at the end of the third quarter of 2001. See Critical Accounting Policies and Estimates.

In 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of a liability for an asset retirement obligation to be recorded in the period incurred and a corresponding increase in the carrying amount of the related long-lived asset. The related cumulative adjustment to net income was an increase of $47 million after income taxes, or $0.18 per share (diluted). The application of SFAS No. 143 did not have a material impact on the Company’s depreciation, depletion and amortization (DD&A) expense, net income or earnings per share in 2003. There was no impact on the Company’s cash flow as a result of adopting SFAS No. 143.

Anadarko’s total revenues for 2003 increased $1.3 billion or 33% compared to 2002 due primarily to significantly higher commodity prices, partially offset by slightly lower sales volumes. Total revenues for 2002 were down $873 million or 19% compared to 2001 due primarily to a significant decrease in natural gas prices and decreases in natural gas volumes, partially offset by higher crude oil prices and volumes.

Unrealized gains and losses on derivative instruments that do not meet the conditions to qualify for hedge accounting are recognized in gas sales and oil sales and are reflected in the average sales prices. In 2003, these amounts for prior periods were reclassified from other (income) expense to gas sales and oil sales. The amount of the reclassification was not significant and had no effect on net income or per share amounts.

The impact of hedges and marketing activities resulted in lower realized prices of $0.27 per Mcf of gas and $1.42 per barrel of oil for 2003 compared to market prices, decreasing revenues $267 million. For 2002, the impact of hedges and marketing activities resulted in higher realized prices of $0.14 per Mcf of gas and lower realized prices of $0.32 per barrel of oil compared to market prices, resulting in a net increase to revenues of $62 million. For 2001, the impact of hedges and marketing activities resulted in higher realized prices of $0.26 per Mcf of gas and $0.64 per barrel of oil compared to market prices, increasing revenues $227 million.

During 2003, Anadarko sold 192 MMBOE, a decrease of 5 MMBOE or 3% compared to sales of 197 MMBOE in 2002. The decrease for 2003 was primarily due to lower volumes of 5 MMBOE from operations in Canada, related primarily to the divestiture of heavy oil properties in late 2002 and 5 MMBOE from operations in Algeria due primarily to the substantial completion of cost recovery, whereby Anadarko was reimbursed for previous exploration spending with additional barrels of oil production. These decreases were partially offset by higher volumes of 5 MMBOE from operations in the United States, primarily due to higher oil production in the western states as a result of the acquisition of Howell in late 2002. The Company’s sales volumes were down 2 MMBOE or 1% in 2002 compared to sales of 199 MMBOE in 2001. The decrease for 2002 was primarily due to lower volumes of 14 MMBOE due to operations in the United States, primarily offshore and in Texas and Louisiana, and 4 MMBOE related to the disposition of operations in Guatemala and Argentina in 2001. The decrease in volumes in the United States was primarily a result of natural production declines and a decrease in development drilling in late 2001 and early 2002 in response to lower commodity prices. These lower volumes were offset by an increase of 16 MMBOE in Algeria due to the expansion of production facilities.

Anadarko’s natural gas sales volumes for 2003 were essentially flat compared to 2002. An increase in natural gas sales volumes in Texas, Louisiana and Canada due to successful exploration and development activities was offset by a decrease in the Gulf of Mexico, as a result of temporary operational issues and natural production declines. The Company’s natural gas sales volumes in 2002 were down 53 Bcf or 8% compared to 2001. The decrease in 2002 was due primarily to lower volumes of 66 Bcf from operations within the United States, primarily offshore and in Texas, partially offset by higher volumes of 14 Bcf from operations in Canada primarily due to the Berkley acquisition in 2001. Production of natural gas is generally not directly affected by seasonal swings in demand. However, the Company may decide during periods of low commodity prices to decrease development activity, which can result in lower production volumes.

The Company’s average realized natural gas price in 2003 increased 55% compared to 2002. Strong demand in North America due to colder weather and declining gas supply resulted in significantly higher gas prices. These higher prices were partially offset by commodity price hedges on 49% of natural gas sales volumes during 2003 that reduced the Company’s exposure to low prices and limited participation in higher prices. The Company’s average realized natural gas price in 2002 decreased 33% compared to 2001. The decrease in prices during 2002 was attributed to a severe decline in natural gas demand as a result of high prices in early 2001, followed by a national economic downturn and mild summer weather in 2001. As of December 31, 2003, the Company has hedged about 34% of its anticipated natural gas wellhead sales volumes for 2004. See Derivative Instruments under Item 7a of this Form 10-K.

Anadarko’s crude oil and condensate sales volumes for 2003 decreased 8 MMBbls or 11% compared to 2002 due to lower volumes of 6 MMBbls in Canada and 5 MMBbls in Algeria, partially offset by higher volumes of 3 MMBbls in the United States. The lower Canada volumes are due largely to the sale of the Company’s heavy oil assets in late 2002. The lower Algeria volumes are due primarily to the substantial completion of cost recovery, whereby Anadarko was reimbursed for previous exploration spending with additional barrels of oil production. The higher volumes in the United States are primarily in the western states as a result of the Howell acquisition in late 2002.

Crude oil and condensate sales volumes for 2002 increased 7 MMBbls or 10% compared to 2001. The increase was due primarily to higher volumes of 16 MMBbls from operations in Algeria primarily due to the expansion of production facilities and 2 MMBbls due to the acquisition of producing properties in Qatar in 2001. These higher volumes were partially offset by lower volumes of 4 MMBbls due to the sale of producing properties in Guatemala and Argentina in 2001, 3 MMBbls related to operations in the United States, primarily offshore, and 3 MMBbls in Venezuela primarily due to higher oil prices. Production of oil usually is not affected by seasonal swings in demand or in market prices.

Anadarko’s average realized crude oil price in 2003 increased 18% compared to 2002. The higher crude oil prices during 2003 are attributed primarily to political unrest in the Middle East, the oil workers’ strike in Venezuela, low oil inventory levels and increased demand. These higher prices were partially offset by commodity price hedges on 38% of crude oil and condensate sales volumes during 2003 that reduced the Company’s exposure to low prices and limited participation in higher prices. The Company’s average realized crude oil price in 2002 increased 9% compared to 2001. The higher crude oil prices in 2002 were due primarily to continued uncertainty of the situation in the Middle East, the oil workers’ strike in Venezuela and a colder than normal winter late in 2002 that increased oil demand in the United States. As of December 31, 2003, the Company had hedged about 37% of its anticipated oil and condensate volumes for 2004.

The Company’s 2003 NGLs sales volumes increased 2 MMBbls or 13% compared to 2002 primarily due to additional natural gas volumes processed in central Texas. NGLs sales volumes in 2002 were essentially flat compared to 2001.

During 2003, average NGLs prices increased 43% compared to 2002. The higher NGLs prices are attributed primarily to high natural gas prices in the United States during 2003. Natural gas prices generally serve as a minimum or “floor” for NGLs prices because NGLs production is highly dependent on the economics of processing the natural gas to extract NGLs. The 2002 average NGLs prices decreased 11% compared to 2001. High levels of NGLs inventories in the United States during the first half of 2002, coupled with lower demand for NGLs by the petrochemical industry, caused NGLs prices to decline.

During 2003, Anadarko’s costs and expenses increased $479 million or 20% compared to 2002 due to the following factors:


	—	Operating expenses increased $81 million (11%) due to increases of $53 million in direct operating expenses and $28 million in cost of product and transportation expenses. The increase in direct operating expenses is due primarily to the acquisition of producing properties in the western states in late 2002 and the Gulf of Mexico in 2003, an increase in electricity, fuel and other lease expenses attributed to the effect of increased commodity prices and the impact of an increase in the Canadian exchange rate. These increases were partially offset by the effect of the sale of heavy oil properties in Canada in late 2002. The increase in cost of product and transportation expenses was due primarily to an increase in volumes of NGLs processed and higher transportation rates.
	—	Administrative and general (A&G) expense increased $38 million (12%). A&G expense in 2003 included $24 million in benefits expenses and $8 million in salaries expenses related to executive transitions during 2003. Excluding executive transition expenses, A&G expense increased $17 million for the first six months of 2003 and decreased $11 million in the last half of 2003 as a result of the cost reduction plan implemented in July 2003.
	—	DD&A expense increased $176 million (16%). DD&A increases include about $180 million primarily due to higher costs associated with finding and developing oil and gas reserves (including the transfer of excluded costs to the DD&A pool), $20 million due to asset retirement obligation accretion expense related to SFAS No. 143 and $8 million related to higher DD&A on general properties. These increases were partially offset by a $32 million decrease due to lower production volumes.
	—	Other taxes increased $80 million (37%) due primarily to significantly higher commodity prices.
	—	Impairments of oil and gas properties in 2003 are due to a $68 million ceiling test impairment for Qatar as a result of lower future production estimates and unsuccessful exploration activities as well as $35 million related to unsuccessful exploration activities in Australia ($19 million), Gabon ($7 million), Tunisia ($7 million), Angola ($1 million) and Kazakhstan ($1 million).
	—	Restructuring costs of $40 million related to one-time charges for employee termination benefits, primarily severance payments, and other costs associated with the Company’s cost reduction plan.

During 2002, Anadarko’s costs and expenses decreased $2.6 billion or 52% compared to 2001 due to the following factors:


	—	Operating expenses decreased $22 million (3%) due to a decrease in cost of product and transportation expenses related primarily to a decrease in costs associated with processing NGLs, partially offset by an increase in direct operating expenses primarily related to the acquisition of producing properties in Qatar in the second half of 2001.
	—	A&G expense increased $22 million (8%). An increase of $58 million due primarily to increases in benefits and salaries expenses associated with the Company’s workforce was partially offset by a $31 million decrease in merger related expenses and a $5 million decrease related to an adjustment to provisions for uncollectible accounts.
	—	DD&A expense decreased $33 million (3%). About $180 million of the decrease is related to the DD&A rate reduction as a result of ceiling test impairments in the third quarter of 2001 and $13 million of the decrease is due to slightly lower production volumes. These decreases were partially offset by an increase of approximately $135 million due to increases in the DD&A rate resulting from higher costs associated with finding and developing oil and gas reserves (including the transfer of excluded costs to the DD&A pool) and an increase of $25 million related to DD&A on general properties.
	—	Other taxes decreased $33 million (13%). The decrease is primarily due to a $40 million decrease in production taxes as a result of lower commodity prices and slightly lower production volumes in 2002, partially offset by higher ad valorem taxes.
	—	Impairments of oil and gas properties in 2002 related primarily to unsuccessful exploration activities in Congo ($16 million), Oman ($10 million), Australia ($7 million) and Tunisia ($5 million). Impairments in 2001 were primarily due to low oil and gas prices at the end of the third quarter of 2001, which resulted in ceiling test impairments for the United States ($1.7 billion), Canada ($808 million) and Argentina ($15 million).
	—	Amortization of goodwill was discontinued in 2002 in accordance with SFAS No. 142.

Interest Expense Anadarko’s gross interest expense has increased over the past three years due primarily to higher levels of borrowings for capital expenditures, including corporate and producing property acquisitions. Gross interest expense in 2003 increased 4% compared to 2002 primarily due to the expensing of debt issuance costs related to the Company redeeming the Zero Coupon Convertible Debentures due 2020 in 2003 and slightly higher interest rates caused by the redemption of the Zero Yield Puttable Contingent Debt Securities in 2002, which were put to the Company and replaced with higher rate debt. Gross interest expense in 2002 increased 19% compared to 2001 primarily due to higher average debt outstanding in 2002 primarily because of acquisitions in 2001 and slightly higher interest rates. See Capital Resources and Liquidity.

Other (Income) Expense During 2003, foreign exchange gains increased $20 million compared to 2002 due primarily to the impact of the strengthening Canadian dollar on the Company’s outstanding Canadian debt that is denominated in the United States dollar. Gains from the firm transportation keep-whole contract valuation decreased $26 million during 2003 primarily due to the effect of lower market values for firm transportation subject to the keep-whole agreement. During 2002, foreign exchange losses decreased $28 million compared to 2001 primarily due to the restructuring of Canadian debt and strengthening of the Canadian dollar. Gains from the firm transportation keep-whole contract valuation decreased $56 million during 2002 primarily due to the effect of lower market values for firm transportation subject to the keep-whole agreement. See Derivative Instruments and Foreign Currency Risk under Item 7a of this Form 10-K.

For 2003, income taxes increased $353 million compared to 2002. The increase was primarily due to the increase in earnings before income taxes, partially offset by a decrease in Canadian taxes due to a Canadian federal income tax rate reduction from 28% to 21% over a five year period beginning in 2003. Income taxes for 2002 increased $590 million compared to 2001. Income taxes for 2001 included a benefit of approximately $962 million related to the impairment of the carrying value of oil and gas properties in the United States, Canada and Argentina as a result of low natural gas and crude oil prices at the end of the third quarter of 2001. Excluding the effect of the impairment and related tax benefit in 2001, income taxes for 2002 decreased primarily due to the decrease in earnings before income taxes.

Anadarko focuses on growth and profitability. Reserve replacement is the key to growth and future profitability depends on the cost of finding oil and gas reserves, among other factors. Reserve growth can be achieved through successful exploration and development drilling, improved recovery or acquisition of producing properties.

Reserve Replacement Anadarko continues to be successful in replacing reserves. For the 22nd consecutive year, Anadarko more than replaced annual production volumes with proved reserves of natural gas, crude oil, condensate and NGLs. The following table shows the Company’s reserve replacement through all means, including extensions and discoveries, revisions, improved recovery and purchases or sales of proved reserves, as a percentage of production volumes. Reserve replacement percentages excluding acquisitions and divestitures represent reserve replacement achieved through drilling and development.

The Company’s worldwide reserve replacement excluding acquisitions and divestitures increased to 176% in 2003. This increase was primarily due to successful drilling in the U.S. and Canada. The decrease in 2002 compared to 2001 was partially due to a downward revision of 36 MMBOE in Venezuela due to increased prices. See Critical Accounting Policies and Estimates.

Anadarko’s U.S. reserve replacement percentage excluding acquisitions and divestitures increased to 204% in 2003. The increase in 2003 was due primarily to successful drilling in east Texas and Louisiana and successful enhanced oil recovery projects in the western states. The Company’s U.S. reserve replacement for the five-year period 1999-2003 was 168% excluding acquisitions and divestitures. By comparison, the most recent published U.S. industry average (1998-2002) was 111% (Source: DOE). Anadarko’s U.S. reserve replacement performance for the same period of 1998-2002 was 179% of production, excluding acquisitions and divestitures. Industry data for 2003 is not yet available.

Cost of Finding Cost of finding represents the cost of proved reserves added through all means, including additions related to extensions and discoveries, revisions, improved recovery and purchases of proved reserves. The following table shows the Company’s cost of finding proved reserves of natural gas, crude oil, condensate and NGLs, stated on a BOE basis. Cost of finding excludes asset retirement costs and includes actual asset retirement expenditures.

Worldwide finding costs in 2003 decreased 34% compared to 2002. Worldwide finding costs in 2002 were higher than 2003 and 2001 due primarily to downward revisions of Venezuelan reserves primarily related to higher prices (see Critical Accounting Policies and Estimates) and large investments made in leases in the eastern Gulf of Mexico that had not yet been drilled.

Cost of finding results in any one year can be misleading due to the long lead times associated with exploration and development. A better measure of cost of finding performance is over a five-year period. For the five-year period 1999-2003, Anadarko’s worldwide finding cost was $7.65 per BOE and its U.S. finding cost was $8.10 per BOE. For the previous five-year period 1998-2002, Anadarko’s worldwide finding cost was $7.24 per BOE and its U.S. finding cost was $7.78 per BOE. Excluding acquisitions, Anadarko’s worldwide and U.S. finding costs for the five-year period 1999-2003 were $8.10 per BOE and $8.04 per BOE, respectively. For the previous five-year period 1998-2002, the Company’s worldwide and U.S. finding costs excluding acquisitions were $7.23 per BOE and $7.44 per BOE, respectively.

Proved Reserves At the end of 2003, Anadarko’s proved reserves were 2.5 billion BOE compared to 2.3 billion BOE at year-end 2002 and 2001. Anadarko’s proved reserves have grown 22% over the past three years, primarily as a result of corporate acquisitions, successful exploration projects in the Gulf of Mexico and successful development programs in major domestic fields in core areas onshore and offshore and in Algeria.

The Company’s proved natural gas reserves at year-end 2003 were 7.7 Tcf compared to 7.2 Tcf at year-end 2002 and 7.0 Tcf at year-end 2001. Anadarko’s proved gas reserves have increased 27% since year-end 2000, as a result of corporate acquisitions, continued development activity onshore in the U.S. and producing property acquisitions. Anadarko’s proved crude oil, condensate and NGLs reserves at year-end 2003 were 1.2 billion barrels compared to 1.1 billion barrels at year-end 2002 and 2001. Proved crude oil reserves have risen 17% over the last three years primarily due to corporate acquisitions, successful exploration projects in the Gulf of Mexico and successful development programs in major domestic fields in core areas onshore and offshore and in Algeria. Crude oil, condensate and NGLs comprise 49% of the Company’s proved reserves at year-end 2003, 2002 and 2001.

At December 31, 2003, the present value (discounted at 10%) of future net revenues from Anadarko’s proved reserves was $27.8 billion, before income taxes, and $18.8 billion, after income taxes, (stated in accordance with the regulations of the SEC and the Financial Accounting Standards Board (FASB)). This present value was calculated based on prices at year-end held flat for the life of the reserves, adjusted for any contractual provisions. The after income taxes increase of $4.7 billion or 33% in 2003 compared to 2002 is primarily due to additions of proved reserves related to successful drilling and development and higher natural gas prices at year-end 2003. See Supplemental Information under Item 8 of this Form 10-K.

The present value of future net revenues does not purport to be an estimate of the fair market value of Anadarko’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas.

Recent Developments The SEC obtained information from oil and gas companies operating offshore (including Anadarko) to assess the criteria being used by industry to determine proved reserves related to new field discoveries offshore. The SEC regulations allow companies to recognize proved reserves if economic producibility is supported by either an actual production test (flow test) or conclusive formation testing. In the absence of a production test, compelling technical data must exist to recognize proved reserves related to the initial discovery of a field. In deepwater environments where production tests are extremely expensive, the industry has increasingly depended on advanced technical testing to support economic producibility.

Anadarko has recorded proved reserves related to the initial discovery of four offshore fields based on conclusive formation tests rather than actual production tests. As of December 31, 2003, these proved reserves amounted to 143 MMBOE or less than 6% of Anadarko’s total worldwide proved reserves. A significant portion of these reserves are located at Marco Polo, a deepwater field at Green Canyon Block 608 scheduled for first production in mid-2004. The Company is currently developing three other fields (K2, K2 North and Tarantula) and expects production from these fields to commence in 2005. When production commences, the issue of economic producibility is resolved. Anadarko believes these reserves are properly classified.

Anadarko is unable to predict the likely outcome of the SEC’s staff review of this industry practice. The issue is not expected to have a material impact on the Company’s proved reserves or financial results; however, if the issue is not favorably resolved, Anadarko may be required to revise its proved reserve estimates, which would affect Anadarko’s finding costs per barrel, reserve replacement ratios and DD&A expense, until flow tests are conducted or production commences.

Drilling Activity During 2003, Anadarko participated in a total of 1,069 gross wells, including 707 gas wells, 299 oil wells and 63 dry holes. This compares to 949 gross wells (686 gas wells, 217 oil wells and 46 dry holes) in 2002 and 1,420 gross wells (970 gas wells, 375 oil wells and 75 dry holes) in 2001. The increase in activity during 2003 reflects the Company’s increase in spending for development drilling in response to higher commodity prices in 2003. The decrease in activity during 2002 reflects the Company’s reduced spending for development drilling in response to lower commodity prices in late 2001 and early 2002.

Acquisitions and Divestitures The Company’s strategy includes an asset acquisition and divestiture program. In 2003, Anadarko acquired approximately 54 MMBOE of proved reserves, located primarily in the United States. In 2002, Anadarko acquired approximately 87 MMBOE of proved reserves, including 74 MMBOE located in the United States primarily from the Howell acquisition (64 MMBOE) and 13 MMBOE located in Qatar. In 2001, the Company acquired approximately 157 MMBOE of proved reserves, located in: Canada, primarily from the Berkley acquisition (99 MMBOE); Qatar and Oman from the Gulfstream Resources Canada Limited acquisition (57 MMBOE); and the United States (1 MMBOE). Excluding corporate acquisitions, during 2001-2003, Anadarko acquired through purchases and trades 78 MMBOE of proved reserves for $326 million. During the same time period, the Company sold properties, either as a strategic exit from a certain area or asset rationalization in existing core areas, of 113 MMBOE with proceeds totaling $516 million. In 2004, the Company will continue to consider dispositions of certain producing properties in non-core areas.

Overview The Company’s sales of natural gas, crude oil, condensate and NGLs are generally made at the market prices of those products at the time of sale. Therefore, even though the Company sells significant volumes to major purchasers, the Company believes other purchasers would be willing to buy the Company’s natural gas, crude oil, condensate and NGLs at comparable market prices. The Company’s marketing department actively manages sales of its oil and gas. The Company markets its production to customers at competitive prices, maximizing realized prices while managing credit exposure. The market knowledge gained through the marketing effort is valuable to the corporate decision making process.

The Company may also engage in trading activities for the purpose of generating profits from exposure to changes in market prices of gas, oil, condensate and NGLs. However, the Company does not engage in market-making practices nor does it trade in any non-energy-related commodities. The Company’s trading risk position, typically, is a net short position that is offset by the Company’s natural long position as a producer. Essentially all of the Company’s trading transactions have a term of less than one year and most are less than three months. See Derivative Instruments under Item 7a of this Form 10-K.

Since 2002, all segments of the energy market have experienced increased scrutiny of their financial condition, liquidity and credit. This has been reflected in rating agency credit downgrades of many merchant energy trading companies. In 2003, Anadarko has not experienced any material financial losses associated with credit deterioration of third-party gas purchasers; however, in certain situations the Company has declined to transact with some counterparties and changed its sales terms to require some counterparties to pay in advance or post letters of credit for purchases.

Natural Gas Natural gas continues to supply a significant portion of North America’s energy needs and the Company believes the importance of natural gas in meeting this energy need will continue. The tightening of the natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.

Anadarko markets its equity natural gas production to maximize the commodity value and reduce the inherent risks of the physical commodity markets. Anadarko Energy Services Company (AES), a wholly owned subsidiary of Anadarko, is a marketing company offering supply assurance, competitive pricing, risk management services and other services tailored to its customers’ needs. The Company also purchases natural gas physical volumes for resale primarily from partners and producers near Anadarko’s production. These purchases allow the Company to aggregate larger volumes of gas and attract larger, creditworthy customers, which in turn enhances the value of the Company’s production. The Company sells natural gas under a variety of contracts and may also receive a service fee related to the level of reliability and service required by the customer. The Company has the marketing capability to move large volumes of gas into and out of the “daily” gas market to take advantage of any price volatility. Included in this strategy is the use of leased natural gas storage facilities and various derivative instruments.

In 2003, 2002 and 2001, approximately 35%, 39% and 31%, respectively, of the Company’s gas production was sold under long-term contracts to Duke Energy (Duke). These sales represent 22%, 18% and 27%, respectively, of total revenues in 2003, 2002 and 2001. Most of these contracts have expired or will expire at the end of the first quarter of 2004. The Company expects to integrate the marketing of the natural gas previously sold to Duke into its current marketing operations and sell it to various purchasers under short-term agreements at market prices. Volumes sold to Duke under the long-term contracts were at market prices.

A company Anadarko acquired in 2000 was a party to several long-term firm gas transportation agreements that supported its gas marketing program within the gathering, processing and marketing (GPM) business segment, which was sold in 1999 to Duke. Most of these agreements were transferred to Duke in the GPM disposition. One agreement was retained, but is managed and operated by Duke. Anadarko is not responsible for the operations of the contracts and does not utilize the associated transportation assets to transport the Company’s natural gas. As part of the GPM disposition, Anadarko pays Duke if transportation market values fall below the fixed contract transportation rates, while Duke pays Anadarko if the transportation market values exceed the contract transportation rates (keep-whole agreement). This keep-whole agreement will be in effect until the earlier of each contract’s expiration date or February 2009. The Company may periodically use derivative instruments to reduce its exposure under the Duke keep-whole agreement to potential decreases in future transportation market values. While derivatives are intended to reduce the Company’s exposure to declines in the market value of firm transportation, they also limit the potential to benefit from increases in the market value of firm transportation.

The fair value of the short-term portion of the firm transportation keep-whole agreement is calculated based on quoted natural gas basis prices. Basis is the difference in value between gas at various delivery points and the New York Mercantile Exchange (NYMEX) gas futures contract price. Management believes that natural gas basis price quotes beyond the next twelve months are not reliable indicators of fair value due to decreasing liquidity. Accordingly, the fair value of the long-term portion is estimated based on historical natural gas basis prices, discounted at 10% per year. Management also periodically evaluates the supply and demand factors (such as expected drilling activity, anticipated pipeline construction projects, expected changes in demand at pipeline delivery points, etc.) that may impact the future market value of the firm transportation capacity to determine if the estimated fair value should be adjusted.

Crude Oil, Condensate and NGLs Anadarko’s crude oil, condensate and NGLs revenues are derived from production in the U.S., Canada, Algeria and other international areas. Most of the Company’s U.S. crude oil and NGLs production is sold under 30-day “evergreen” contracts with prices based on marketing indices and adjusted for location, quality and transportation. Most of the Company’s Canadian oil production is sold on a term basis of one year or greater. Oil from Algeria and other international areas is sold by tanker as Saharan Blend to customers primarily in the Mediterranean area. Saharan Blend is a high quality crude that provides refiners with large quantities of premium products like high quality jet and diesel fuel. The Company also purchases and sells third-party produced crude oil, condensate and NGLs in the Company’s domestic and international market areas. Included in this strategy is the use of various derivative instruments.

Gas Gathering Systems and Processing Anadarko’s investment in gas gathering operations allows the Company to better manage its gas production, improve ultimate recovery of reserves, enhance the value of gas production and expand marketing opportunities. The Company has invested about $175 million to build or acquire gas gathering systems over the last five years. The vast majority of the gas flowing through these systems is from Anadarko operated wells.

General Anadarko’s cash flow from operating activities in 2003 was $3.0 billion compared to $2.2 billion in 2002 and $3.3 billion in 2001. The increase in 2003 cash flow is attributed primarily to the significant increase in commodity prices. The decrease in 2002 cash flow compared to 2001 is attributed to significantly lower natural gas prices. Fluctuations in commodity prices have been the primary reason for the Company’s short-term changes in cash flow from operating activities. Sales volume changes can also impact cash flow in the short-term, but have not been as volatile as commodity prices in the past. Anadarko holds derivative instruments to help manage commodity price risk. Anadarko’s long-term cash flow from operating activities is dependent on commodity prices, reserve replacement and the level of costs and expenses required for continued operations. The Company’s goals include continuing to find high-margin oil and gas reserves at competitive prices, managing commodity price risk and keeping operating costs at efficient levels.

In July 2003, Anadarko implemented a cost reduction plan that eliminated more than $100 million of overhead costs from the Company’s annual cost structure, which included cuts in personnel and corporate expenses. This cost reduction plan lowered costs and expenses by $60 million and capitalized overhead costs by $40 million. Restructuring costs associated with this plan are approximately $41 million and charged to income as specific liabilities are incurred. Restructuring costs of $40 million were expensed during 2003. These relate to one-time employee termination benefits ($29 million), contract termination costs ($3 million) and other costs ($8 million). The remaining restructuring costs are expected to be paid and expensed in 2004. For additional information on restructuring costs see Note 15 — Restructuring Costs of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.

Debt At year-end 2003, Anadarko’s total debt was $5.1 billion compared to total debt of $5.5 billion at year-end 2002, a decrease of about $400 million. This compares to $5.1 billion at year-end 2001. The decrease in debt during 2003 was related primarily to repaying debt that was incurred as a result of the Howell acquisition in late 2002 and repaying Notes that matured in 2003.

In March 2001, Anadarko issued $650 million of Zero Yield Puttable Contingent Debt Securities (ZYP-CODES) due 2021. In March 2002, ZYP-CODES in the amount of $620 million were put to the Company for repayment and were paid in cash. Holders of the remaining ZYP-CODES have the right to require Anadarko to purchase all or a portion of their ZYP-CODES in March 2004, 2006, 2011 or 2016, at $1,000 per ZYP-CODES.

In April 2002, Anadarko filed a shelf registration statement with the SEC that permits the issuance of up to $1 billion in debt securities, preferred stock, preferred securities, depositary shares, common stock, warrants, purchase contracts and purchase units. Net proceeds, terms and pricing of the offerings of securities issued under the shelf registration statement will be determined at the time of the offerings. After giving effect to the securities issuances described below, the Company may issue, subject to market conditions, up to $350 million in additional securities under this registration statement.

Capital Expenditures The Company funded its capital investment programs in 2003, 2002 and 2001 primarily through cash flow, plus increases in long-term debt and proceeds from property sales. The following table shows the Company’s capital expenditures by category.


*	Excludes corporate acquisitions. Excludes asset retirement costs and includes actual asset retirement expenditures, which is consistent with prior years.

Anadarko’s total capital spending in 2003 was $2.8 billion, a 17% increase compared to 2002. The increase from 2002 represents a $487 million increase in development spending and a $30 million increase in other spending, partially offset by a $113 million decrease in exploration spending. The increase in development spending and the decrease in exploration spending reflect the Company’s decision to direct capital to the areas that have shown the best performance and rate of return, primarily the Lower 48 states, during periods of higher prices.

Anadarko’s total capital spending in 2002 was $2.4 billion, a 28% decrease compared to 2001. The decrease from 2001 represents a $562 million decrease in development spending, a $215 million decrease in exploration spending and a $151 million decrease in other spending. The decrease in spending for development activities reflects the Company’s decision to focus on increasing its inventory of drilling prospects by identifying new reserves through exploration, rather than growing production through development during the down cycle in energy prices in early 2002.

Dividends In 2003, Anadarko paid $109 million in dividends to its common stockholders (10 cents per share in the first, second and third quarters and 14 cents per share in the fourth quarter). In 2002, Anadarko paid $80 million in dividends to its common stockholders (7.5 cents per share in the first, second and third quarters and 10 cents per share in the fourth quarter). The dividend amount in 2001 was $57 million (5 cents per share in the first, second and third quarters and 7.5 cents per share in the fourth quarter). Anadarko has paid a dividend to its common stockholders continuously since becoming an independent company in 1986.

The Company’s credit agreement allows for a maximum capitalization ratio of 60% debt, exclusive of the effect of any noncash writedowns. As of December 31, 2003, Anadarko’s capitalization ratio was 37% debt. While there is no specific restriction on paying dividends, under the maximum debt capitalization ratio retained earnings were not restricted as to the payment of dividends at December 31, 2003. The amount of future common stock dividends will depend on earnings, financial conditions, capital requirements and other factors, and will be determined by the Board of Directors on a quarterly basis.

Outlook The Company’s 2004 capital expenditure budget has been set between $2.6 billion and $2.9 billion. Anadarko has allocated $2.3 billion to $2.6 billion for worldwide exploration and development. Approximately 80% will be designated for development and about 20% for exploration. The primary focus of the 2004 budget is to direct capital to the areas that have shown the best performance and rate of return. Anadarko made a number of significant discoveries in 2003 and a top priority in 2004 will be to delineate and develop those discoveries. In addition, the Company plans to carry out a focused exploration program in North America, North Africa and the Middle East. Anadarko’s overall plan includes about $300 million for capitalized interest and overhead. In conjunction with the cost reduction plan, the Company evaluated the allocation of capital resources to international exploration for 2004. While Management sees an important place for international projects within its portfolio, Anadarko has narrowed the list of international projects in order to better focus its efforts. As a result, the Company expects to work toward divesting its non-core assets in Egypt, Australia and Oman during 2004.

flow from operations using prices below January 2004 NYMEX levels. The Company intends to adjust capital expenditures to reflect changes in its cash flow from operations. If higher prices are realized, the Company may expand the drilling program, make targeted acquisitions or further reduce net debt. If commodity prices significantly decrease, the Company may curtail capital spending projects, as well as delay or defer drilling wells in certain areas because of lower cash flows.

The Company has had a stock buyback program to purchase up to $1 billion in shares of Anadarko common stock since 2001. The repurchase program does not obligate Anadarko to acquire any specific number of shares and may be discontinued at any time. The Company did not purchase any shares under this program in 2003. To date, the Company has repurchased $166 million of its common stock under this program. No stock purchases have been budgeted for 2004.

Both exchange and over-the-counter traded financial derivative instruments are subject to margin deposit requirements. Margin deposits are required of the Company whenever its unrealized losses with a counterparty exceed predetermined credit limits. Given the Company’s sizable hedge position and price volatility, the Company may be required from time to time to advance cash to its counterparties in order to satisfy these margin deposit requirements. During 2003, the Company’s margin deposit requirements have ranged from zero to $125 million. The Company did not have any margin deposits outstanding at December 31, 2003.

Anadarko believes that operating cash flow and existing or available credit facilities will be adequate to meet its capital and operating requirements for 2004. The Company funds its day-to-day operating expenses and capital expenditures from operating cash flows, supplemented as needed by short-term borrowings under commercial paper, money market loans or credit facility borrowings. To facilitate such borrowings, the Company has in place a $750 million committed credit facility, which is supplemented by various noncommitted credit lines that may be offered by certain banks from time to time at then-quoted rates. As of December 31, 2003, Anadarko had no outstanding borrowings under its credit facility. It is the Company’s policy to limit commercial paper borrowing to levels that are fully back-stopped by unused balances from its committed credit facilities. The Company may choose to refinance certain portions of these short-term borrowings by issuing long-term debt in the public or private debt markets. To facilitate such financings, the Company may file shelf registrations in advance with the SEC.

The Company continuously monitors its debt position and coordinates its capital expenditure program with expected cash flows and projected debt repayment schedules. The Company will continue to evaluate funding alternatives, including property sales and additional borrowing, to secure other funds for additional capital expenditures. At this time, Anadarko has no plans to issue common stock other than through its Dividend Reinvestment and Stock Purchase Plan, the Executives and Directors Benefits Trust, the exercise of stock options, the issuance of restricted stock or the Company’s Employee Savings Plan and Employee Stock Ownership Plan equity funded contributions. See Regulatory Matters and Additional Factors Affecting Business for additional information.

Following is a summary of the Company’s future payments on obligations as of December 31, 2003:


Title of Class		Number of Shares Outstanding
Common Stock, par value $0.10 per share		251,656,714


Part of
Form 10-K		Documents Incorporated By Reference
	Part II	Portions of the Anadarko Petroleum Corporation 2003 Annual Report to Stockholders.
	Part III	Portions of the Proxy Statement for the Annual Meeting of Stockholders of Anadarko Petroleum Corporation to be held May 6, 2004 (to be filed with the Securities and Exchange Commission prior to April 29, 2004).


			Page
PART I
	Item 1.	Business		2
		General		2
		Oil and Gas Properties and Activities		2
		Proved Reserves and Future Net Cash Flows		2
		Sales Volumes and Prices		5
		Properties and Activities — United States		7
		Properties and Activities — Canada		16
		Properties and Activities — Algeria		18
		Properties and Activities — Other International		21
		Drilling Programs		22
		Drilling Statistics		23
		Productive Wells		24
		Properties and Leases		24
		Marketing and Gathering Properties and Activities		25
		Minerals Properties and Activities		25
		Segment and Geographic Information		25
		Employees		26
		Regulatory Matters and Additional Factors Affecting Business		26
		Title to Properties		26
		Capital Spending		26
		Ratios of Earnings to Fixed Charges and Earnings to Combined Fixed Charges and Preferred Stock Dividends		26
	Item 2.	Properties		26
	Item 3.	Legal Proceedings		27
	Item 4.	Submission of Matters to a Vote of Security Holders		29
		Executive Officers of the Registrant		29
PART II
	Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		31
	Item 6.	Selected Financial Data		31
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
	Item 7a.	Quantitative and Qualitative Disclosures About Market Risk		52
	Item 8.	Financial Statements and Supplementary Data		53
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		114
	Item 9a.	Controls and Procedures		114
PART III
	Item 10.	Directors and Executive Officers of the Registrant		114
	Item 11.	Executive Compensation		114
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		114
	Item 13.	Certain Relationships and Related Transactions		114
	Item 14.	Principal Accountant Fees and Services		114
PART IV
	Item 15.	Exhibits and Reports on Form 8-K		115


		2003		2002		2001

United States
	Natural gas (Bcf)		503		507		573
	Oil and condensate (MMBbls)		34		31		34
	Natural gas liquids (MMBbls)		16		14		14
	Total (MMBOE)		135		130		144
Canada
	Natural gas (Bcf)		140		135		121
	Oil and condensate (MMBbls)		6		12		13
	Natural gas liquids (MMBbls)		1		1		1
	Total (MMBOE)		30		35		34
Algeria
	Oil and condensate (MMBbls)		19		24		8
	Total (MMBOE)		19		24		8
Other International
	Natural gas (Bcf)		—		—		1
	Oil and condensate (MMBbls)		8		8		13
	Total (MMBOE)		8		8		13
Total
	Natural gas (Bcf)		643		642		695
	Oil and condensate (MMBbls)		67		75		68
	Natural gas liquids (MMBbls)		17		15		15
	Total (MMBOE)		192		197		199


			2003		2002		2001

United States
	Sales price
		Natural gas (per Mcf)	$	4.36	$	2.83	$	4.23
		Oil and condensate (per barrel)		26.16		22.90		23.08
		Natural gas liquids (per barrel)		21.19		14.98		16.44
	Production cost (per BOE)		$	5.49	$	4.66	$	4.66
Canada
	Sales price
		Natural gas (per Mcf)	$	4.71	$	2.91	$	4.38
		Oil and condensate (per barrel)		27.33		19.09		18.18
		Natural gas liquids (per barrel)		21.04		12.11		18.32
	Production cost (per BOE)		$	8.01	$	6.40	$	5.97
Algeria
	Sales price
		Oil and condensate (per barrel)	$	28.43	$	24.38	$	23.97
	Production cost (per BOE)		$	2.44	$	1.78	$	2.33
Other International
	Sales price
		Natural gas (per Mcf)	$	—	$	—	$	1.22
		Oil and condensate (per barrel)		23.15		19.92		14.35
	Production cost (per BOE)		$	8.90	$	8.48	$	5.71
Total
	Sales price
		Natural gas (per Mcf)	$	4.43	$	2.85	$	4.25
		Oil and condensate (per barrel)		26.55		22.44		20.56
		Natural gas liquids (per barrel)		21.18		14.80		16.55
	Production cost (per BOE)		$	5.71	$	4.79	$	4.85


Incorporated in the State of Delaware		Employer Identification No. 76-0146568


					Percentage
	PUDs		Percentage		of Total Proved
	MMBOE		of Total PUDs		Reserves
Country
United States		466		59%		18%
Algeria		179		23%		7%
Canada		72		9%		3%
Other International		69		9%		3%

Total		786		100%		31%



	Net Exploratory						Net Development

	Productive		Dry Holes		Total		Productive		Dry Holes		Total		Total

2003
United States		22.2		16.3		38.5		452.1		14.4		466.5		505.0
Canada		64.6		7.3		71.9		183.7		5.5		189.2		261.1
Algeria		1.5		1.5		3.0		4.0		0.3		4.3		7.3
Other International		1.0		2.2		3.2		3.5		1.0		4.5		7.7

Total		89.3		27.3		116.6		643.3		21.2		664.5		781.1

2002
United States		34.0		13.8		47.8		275.2		5.1		280.3		328.1
Canada		30.6		6.8		37.4		305.6		4.0		309.6		347.0
Algeria		0.5		1.0		1.5		7.3		0.7		8.0		9.5
Other International		—		3.7		3.7		3.7		0.9		4.6		8.3

Total		65.1		25.3		90.4		591.8		10.7		602.5		692.9

2001
United States		33.6		18.3		51.9		544.0		8.4		552.4		604.3
Canada		28.0		6.0		34.0		381.1		18.0		399.1		433.1
Algeria		—		—		—		3.5		0.2		3.7		3.7
Other International		—		2.7		2.7		11.4		—		11.4		14.1

Total		61.6		27.0		88.6		940.0		26.6		966.6		1,055.2



		Wells in the process
		of drilling or				Wells suspended or
		in active completion				waiting on completion

		Exploration		Development		Exploration		Development

United States
	Gross		4		84		12		5
	Net		4.0		59.0		10.4		5.0
Canada
	Gross		13		26		8		17
	Net		7.0		16.0		7.1		12.7
Algeria
	Gross		1		2		—		—
	Net		0.5		0.3		—		—
Other International
	Gross		—		—		2		—
	Net		—		—		1.2		—
Total
	Gross		18		112		22		22
	Net		11.5		75.3		18.7		17.7


		Oil Wells*		Gas Wells*

United States
	Gross		9,347		10,704
	Net		7,105.2		7,149.6
Canada
	Gross		871		3,652
	Net		622.5		2,940.9
Algeria
	Gross		122		—
	Net		25.9		—
Other International
	Gross		304		—
	Net		138.6		—
Total
	Gross		10,644		14,356
	Net		7,892.2		10,090.5



		Developed				Undeveloped
		Lease				Lease				Fee Minerals				Total

		Gross		Net		Gross		Net		Gross		Net		Gross		Net
thousands
United States
	Onshore — Lower 48		2,964		1,980		2,570		1,921		9,527		8,478		15,061		12,379
	Offshore		620		325		1,498		1,121		—		—		2,118		1,446
	Alaska		24		5		3,176		1,659		16		8		3,216		1,672

Total			3,608		2,310		7,244		4,701		9,543		8,486		20,395		15,497

Canada			1,834		1,037		9,124		3,310		606		606		11,564		4,953
Algeria*			221		54		3,773		1,167		—		—		3,994		1,221
Other International			569		155		21,957		8,940		—		—		22,526		9,095


	Age at End
Name	of 2004		Position

James T. Hackett		50	President and Chief Executive Officer
James R. Larson		54	Senior Vice President, Finance and Chief Financial Officer
Richard J. Sharples		57	Senior Vice President, Marketing and Minerals
Robert P. Daniels		45	Vice President, Canada
Diane L. Dickey		48	Vice President and Controller
James J. Emme		48	Vice President, Exploration
Morris L. Helbach		59	Vice President, Information Technology Services and Chief Information Officer
Karl F. Kurz		43	Vice President, Marketing
David R. Larson		47	Vice President, Investor Relations
Richard A. Lewis		60	Vice President, Human Resources
J. Anthony Meyer		46	Vice President, International and Alaska Operations
Mark L. Pease		48	Vice President, U. S. Onshore and Offshore
Gregory M. Pensabene		54	Vice President, Government Relations and Public Affairs
Albert L. Richey		55	Vice President and Treasurer
Charlene A. Ripley		40	Vice President and General Counsel
Suzanne Suter		58	Vice President, Corporate Secretary and Chief Governance Officer
Donald R. Willis		54	Vice President, Corporate Services


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
millions
2003	$	24	$	25	$	25	$	35
2002	$	18	$	18	$	20	$	24


		Five-Year
		Average			2003			2002			2001

Worldwide
	Reserve replacement		310	%		196	%		112	%		221	%
	Reserve replacement excluding acquisitions and divestitures		164	%		176	%		87	%		173	%
	Production (MMBOE)		150			192			196			201
United States
	Reserve replacement		290	%		232	%		185	%		161	%
	Reserve replacement excluding acquisitions and divestitures		168	%		204	%		137	%		160	%
	Production (MMBOE)		107			135			130			144


		Gas		Oil		Dry		Total

2003 Exploratory
	Gross		87		22		38		147
	Net		71.0		18.3		27.3		116.6
2003 Development
	Gross		620		277		25		922
	Net		454.3		189.0		21.2		664.5
2002 Exploratory
	Gross		58		24		32		114
	Net		45.2		19.9		25.3		90.4
2002 Development
	Gross		628		193		14		835
	Net		444.2		147.6		10.7		602.5


Gross	394	2,147
Net	328.0	1,612.4



	Obligations by Period

			2-3		4-5		Later
	1 Year		Years		Years		Years		Total
millions
Total debt*	$	—	$	462	$	1,127	$	3,613	$	5,202
Operating leases		57		120		118		103		398
Transportation and storage		41		37		37		108		223
Oil and gas activities