POGO PRODUCING CO - 10-K Annual Report

Pogo Producing Company
(Exact name of registrant as specified in its charter)

Title of each class:		Name of each exchange on which registered:
Common Stock, $1 par value		New York Stock Exchange Pacific Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

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 ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ý No o

The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $2,648,832,750 as of June 30, 2003 (based on $42.75 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange Composite Tape on such date).

63,812,824 shares of the registrant's Common Stock were outstanding as of February 13, 2004.

Portions of the Company's definitive Proxy Statement respecting the annual meeting of shareholders to be held on April 27, 2004 (to be filed not later than 120 days after December 31, 2003) are incorporated by reference in Part III of this Form 10-K.

The statements included or incorporated by reference in this Annual Report on Form 10-K for the year ended December 31, 2003 (this "Annual Report") include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included or incorporated by reference herein, other than statements of historical fact, are forward-looking statements. In some cases, you can identify the Company's forward-looking statements by the words "anticipate," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions. Such forward-looking statements include, without limitation, the statements herein and therein regarding the timing of future events regarding the operations of Pogo Producing Company (the "Company") and its subsidiaries, and the statements under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations" regarding the Company's anticipated future financial position and cash requirements. Although the Company believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company's expectations ("Cautionary Statements") are disclosed in this Annual Report and in other filings by the Company with the Securities and Exchange Commission (the "Commission"). All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and other factors set forth in or incorporated by reference in this Annual Report. These factors include:

Many of those factors are beyond the Company's ability to control or predict. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels.

All subsequent written and oral forward-looking statements attributable to the Company and persons acting on the Company's behalf are qualified in their entirety by the Cautionary Statements contained in this section and elsewhere in this Annual Report.

As used in this Annual Report, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel, "MBbls" means thousand barrels and "MMBbls" means million barrels. "BOE" means barrel of oil equivalent, "Mcfe" means thousand cubic feet of natural gas equivalent, "MMcfe" means million cubic feet of natural gas equivalent and "Bcfe" means billion cubic feet of natural gas equivalent. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids ("NGL"). References to "$" and "dollars" refer to United States dollars. All estimates of reserves contained in this Annual Report, unless otherwise noted, are reported on a "net" basis. Information regarding production, acreage and numbers of wells are set forth on a gross basis, unless otherwise noted.

The Company was incorporated in 1970 and is engaged in oil and gas exploration, development, acquisition and production activities on its properties located offshore in the Gulf of Mexico, onshore in selected areas including Texas, New Mexico, Wyoming and Louisiana, and internationally, primarily in the Gulf of Thailand and in Hungary. As of December 31, 2003, the Company had interests in 78 lease blocks offshore Louisiana and Texas, approximately 484,000 gross acres onshore in the United States, approximately 734,000 gross acres offshore in the Kingdom of Thailand, approximately 81,000 gross acres in the Danish sector of the North Sea, approximately 764,000 gross acres in Hungary. On February 4, 2004, the Company acquired interests in approximately 1,014,000 gross acres in New Zealand.

The Company organizes its exploration and production activities principally into five operating regions and a New Ventures Group. The operating regions are its Gulf of Mexico region, which is responsible for the Company's operations offshore Texas and Louisiana in the Gulf of Mexico; its Western U.S. region, which is active in the Permian Basin area in New Mexico and West Texas, in the San Juan Basin in New Mexico and in the Madden Field in Wyoming; its Gulf Coast region, which includes the Company's onshore operations principally in South Texas and Louisiana; the Asia and Pacific region, which has responsibility for the Company's operations on its Block B8/32 Concession in the Kingdom of Thailand (the "Thailand Concession") and in New Zealand; and its Europe region, which is currently active principally in Hungary and the North Sea. The Company's New Ventures Group is primarily responsible for identifying new projects and opportunities for the Company outside the United States.

Gulf of Mexico Region. Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 21% of the Company's proved reserves were located as of December 31, 2003. During 2003, approximately 23% of the Company's natural gas production and 53% of its oil and condensate production came from the Company's domestic offshore properties, contributing approximately 42% of the Company's consolidated oil and gas revenues. The Company's exploration and development efforts are primarily focused in the shallower waters of the continental shelf.

The scope of exploration and development programs relating to the Company's offshore interests is affected by prices for oil and gas, and by federal, state and local legislation, regulations and ordinances applicable to the petroleum industry. The Company's domestic offshore capital and exploration expenditures for 2003 were approximately $60,500,000, or 54% lower than the Company's domestic offshore capital and exploration expenditures of approximately $130,265,000 for 2002, and 65% lower than the Company's domestic offshore capital and exploration expenditures of approximately $170,800,000 (excluding approximately $87,700,000 of net property acquisitions principally related to the North Central

Oil Corporation acquisition) for 2001. The decrease in the Company's domestic offshore capital and exploration expenditures for 2003, compared with 2002, resulted primarily from decreased expenditures for facilities construction. During 2003, the Company invested approximately $9,495,000 on facilities construction for its Gulf of Mexico operations. The Company has currently budgeted approximately $80,000,000 for capital and exploration expenditures during 2004 in the Gulf of Mexico, of which approximately $17,000,000 is budgeted for facilities construction.

The Company maintains a significant presence in the Gulf of Mexico where it participated in drilling 10 wells during 2003, 80% of which were considered successful. At December 31, 2003, the Company held varying interests in 209 producing oil and gas wells in the Gulf of Mexico.

Leases acquired by the Company and other participants in its bidding groups are customarily committed, on a block-by-block basis, to separate operating agreements under which the appointed operator supervises exploration and development operations for the account and at the expense of the group. These agreements usually contain terms and conditions that have become relatively standardized in the industry. Major decisions regarding development and operations typically require the consent of at least a majority (in working interest) of the participants. Because the Company generally has a meaningful working interest position, the Company believes it can significantly influence (but not always control) decisions regarding development and operations on most of the leases in which it has a working interest even though it may not be the operator of a particular lease. The Company is the operator on all or a portion of 41 of the 78 offshore leases in which it had an interest as of December 31, 2003.

Platforms and related facilities are installed on an offshore lease block when, in the judgment of the lease interest owners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment. Platform costs vary depending on, among other factors, the number of well slots, water depth, currents, and sea floor conditions.

The Company has participated, either on its own or with other companies, in bidding on and acquiring interests in federal and state leases offshore in the Gulf of Mexico since 1970. As a result of such purchases and subsequent activities, as of December 31, 2003, the Company owned interests in 66 federal leases and 12 state leases offshore Louisiana and Texas. Federal leases generally have primary terms of five, eight or ten years, depending on water depth, and state leases generally have terms of three or five years, depending on location, in each case subject to extension by development and production operations.

As part of its strategy, the Company intends to continue an active lease evaluation program in the Gulf of Mexico in order to identify exploration and exploitation opportunities. The Company acquires leases through participation in federal and state lease sales, farmouts and by acquisition. For example, the Company acquired 10 offshore leases at the lease sale conducted by the Minerals Management Service of the Department of the Interior (the "MMS") on March 19, 2003. The Company also acquired one state lease through sales conducted by the State of Louisiana in 2003. The Company also maintains an asset rationalization process through which it seeks to sell or farmout blocks that the Company believes have little or no remaining upside potential, or that face significant future expenditures that would likely result in a rate of return that does not meet the Company's internal criteria. As part of this process, the Company farmed out two leases in 2003. The extent to which the Company participates in future bidding on federal or state offshore lease sales or otherwise acquires additional lease blocks will depend on the availability of funds and its estimates of hydrocarbon deposits, operating expenses and future revenues that may reasonably be expected from available lease blocks. Such estimates typically take into account, among other things, estimates of future hydrocarbon prices, federal regulations and taxation policies applicable to the petroleum industry. It is also the Company's objective to acquire producing leasehold properties in

areas where additional low-risk exploration and development drilling or improved production methods can provide attractive rates of return.

The Company's Gulf Coast region is headquartered in Houston, Texas, with field offices in Laredo and Manvel, Texas. The Company's Western U.S. region has an office in Midland, Texas and two field offices in Southeastern New Mexico. The Company conducts its onshore operations in the United States directly and through its wholly owned subsidiaries, North Central Oil Corporation ("North Central") and Arch Petroleum Inc. Domestic onshore reserves as of December 31, 2003, accounted for approximately 56% of the Company's total proved reserves, with the Gulf Coast region and the Western U.S. region contributing approximately 19% and 37%, respectively, of the Company's total proved reserves. During 2003, approximately 48% of the Company's natural gas production and 14% of its oil and condensate production was from its domestic onshore properties, contributing approximately 31% of the Company's consolidated oil and gas revenues.

Western U.S. Region. The Company's Western U.S. region has actively explored West Texas and New Mexico for more than 24 years, and during this period has participated in the discovery or development of over 29 oil and gas fields. In 2003, the Company participated in the drilling of 97 wells (97% of which were successfully completed). The Company believes that during the past decade it has been one of the most active companies drilling for oil and natural gas in southeastern New Mexico (Lea and Eddy Counties), where the Company has interests in approximately 125,000 gross acres. The Company currently plans to drill approximately 106 wells in the Permian Basin during 2004 in various known fields and exploratory prospects. Drilling objectives of these wells range in depth from 1,700 feet to 15,700 feet below the surface and target numerous formations including, among others, the San Andres, Glorieta, San Angelo, Delaware (Brushy Canyon), Clearfork, Bone Springs, Spraberry, Wolfcamp, Canyon, Strawn, Atoka, Morrow and Devonian pay zones.

The Company's Western U.S. region also actively participates in the exploration and development of the Madden Deep Unit in central Wyoming, where the Company currently is credited with varying working interests that average approximately 14% across the unit area. Recent drilling activity in the Madden Deep Unit involves two principal producing horizons, the comparatively shallow Lower Fort Union formation (where productive zones are historically found from approximately 5,500 feet to 9,500 feet below the surface) and the Madison formation (which currently produces from zones located approximately 23,500 feet to 25,000 feet below the surface). The gas produced from the Lower Fort Union formation is comparatively dry sweet gas. Gas produced from the Madison formation, however, contains significant quantities (approximately one-third by volume) of carbon dioxide and hydrogen sulfide gases. Gas from the Madison zones must be processed through the Lost Cabin Gas Plant to remove the carbon dioxide and hydrogen sulfide gases prior to sale. An expansion of the Lost Cabin Gas Plant was completed in 2002, which increased the plant's processing capacity from 132 MMcf per day to approximately 313 MMcf per day. The Company owns a working interest of approximately 15% in this plant. The wells to the Madison formation are deep and technologically challenging to drill, taking up to 12 months from commencement to completion. One Madison test (the Bighorn 9-4) was successfully completed as a producing gas well during 2003. Additionally, a 20,800' Frontier test has recently commenced and is scheduled to be completed in 2004. This exploratory well is located in an area of established production from the Lower Fort Union and Madison formations. If this test is successful, development opportunities may extend over a portion of the Madden structure, with reservoir quality being the primary risk. An active Lower Fort Union drilling program is also anticipated for 2004.

In the second quarter of 2003, Burlington Resources, Inc., operator of the Madden Deep Unit, curtailed production from the Madison formation to evaluate and repair deformations found in the flow

lines transporting production from the wellheads to the Lost Cabin Gas Plant. At the time production was curtailed, Pogo's net share of sellable gas from the Madison formation was approximately 18.9 MMcf per day. Throughout the balance of 2003, production continued to be curtailed at varying rates. Pogo's net share of gas sales from the Madison formation at the beginning of January 1, 2004, was estimated to be approximately 16.7 MMcf per day (which includes volumes attributable to interests acquired through acquisitions).

Gulf Coast Region. The Company's Gulf Coast region is actively exploring for, acquiring and developing oil and gas reserves in the coastal onshore areas of Louisiana and Texas. During 2003, the Gulf Coast region participated in drilling 53 wells, 89% of which were successfully completed.

The Company's Gulf Coast region was most active during 2003 drilling on its 66,000 gross acres of leasehold in South Texas' Webb and Zapata Counties. The Company has been developing gas reserves primarily in its Los Mogotes, Hundido, South Hundido, Hereford Ranch, Mujeres Creek and Mancho Prado Fields that produce from Asche, Charco and Lobo members of the Wilcox formation, found at depths ranging from 7,000 to 14,000 feet below the surface. In its Los Mogotes Field, where its working interest averages 72%, the Company drilled 27 wells in 2003. The Company currently has three contract drilling rigs running in South Texas and those rigs are expected to spend the majority of their time working in the Los Mogotes Field drilling 34 wells budgeted in 2004. A total of four wells were drilled in the Company's 100%-owned South Hundido Fields in 2003 and six more wells have been scheduled for drilling in 2004.

During 2003, the Company participated in drilling three Miocene wells in South Louisiana. One well operated by an industry partner is a new field discovery that is expected to see additional development in 2004. In the Upper Texas Gulf Coast, a new Woodbine formation discovery well has been drilled by the Company and is anticipated to be followed up by drilling several appraisal wells in 2004. The Company undertook several new projects in the Wilcox trend along the Central Texas coastal area and is expanding its presence in this trend. The projects include participation in two wildcat wells operated by an industry partner and the acquisition of a producing property upon which additional Company-operated development drilling has commenced.

The Company's onshore capital and exploration expenditures for 2003 were approximately $142,400,000 (excluding approximately $177,700,000 of net property acquisitions), or 7% higher than comparable expenditures for 2002, and approximately equal to comparable expenditures for 2001. The increase in the Company's onshore capital and exploration expenditures for 2003, compared to 2002, resulted primarily from expenditures related to increased exploratory and development drilling. The Company has currently budgeted approximately $182,000,000 for capital and exploration expenditures during 2004 in its domestic onshore areas.

The Company generally conducts its onshore activities through joint ventures and other interest sharing arrangements with major and independent oil companies. The Company and its subsidiaries operate many of their onshore properties using both independent contractors and field personnel that are employed by the Company or its subsidiaries.

In four transactions in 2003, the Company acquired interests in producing properties located primarily in Andrews, Schleicher and Irion Counties in West Texas, Wharton County in the Texas Gulf Coast area, and the San Juan Basin in New Mexico. In addition, in two additional transactions, the Company increased its working interest in the Madden Field from approximately 12.5% to 14%. The aggregate purchase price for these transactions was approximately $178 million and the aggregate reserves associated with these acquisitions were approximately 155 bcfe.

As it has in recent years, in 2003 the Company also successfully participated in various onshore federal and state lease sales and acquired interests in other prospective acreage. As of December 31, 2003, the Company held interests in approximately 484,000 (256,000 net) acres onshore in the United States.

The Company has conducted international exploration activities since the late 1970's in numerous oil and gas areas throughout the world. The Company currently holds licenses in the Kingdom of Thailand, Hungary, the Danish sector of the North Sea and New Zealand. In addition, the Company's international explorationists continue to evaluate other international opportunities that are consistent with its international exploration strategy and expertise.

Substantial portions of the Company's international operations are grouped under its wholly owned Dutch subsidiary, Pogo Overseas Production B.V. Two subsidiaries of Pogo Overseas Production B.V., Thaipo Limited ("Thaipo") and Pogo Hungary Ltd. ("Pogo Hungary"), maintain offices in Bangkok, Thailand and in Budapest, Hungary, respectively.

The Company's international capital and exploration expenditures were approximately $138,000,000 for 2003, or 34% higher than comparable expenditures for 2002, and 97% higher than comparable expenditures for 2001. The increase in the Company's capital and exploration expenditures for 2003 resulted primarily from expenditures for facilities costs, including construction of eight platforms for installation in the Thailand Concession, increased drilling expenses resulting from having two rigs drilling in Thailand for a substantial portion of the year and the costs of the initial phase of drilling, all or a portion of, four wells in Hungary.

The Company has currently budgeted approximately $153,000,000 for capital and exploration expenditures during 2004 in areas outside the United States, including $115,000,000 in Thailand and $37,000,000 in Europe, of which approximately $5,700,000 is designated for the Danish sector of the North Sea and the remainder is primarily designated for the Company's operations in Hungary. In addition, the Company has budgeted approximately $1,000,000 for 2004 for its international new venture operations in New Zealand and elsewhere. Of this $153,000,000, approximately $63,400,000 is budgeted for facilities upgrades and additions in the Kingdom of Thailand, including the completion and installation of five platforms on the Thailand Concession, the ordering of steel for another five platforms that are projected to be installed on the Thailand Concession in late 2005, and facilities related to the development of Pogo Hungary's Szolnok No. 2 discovery.

The Company currently owns, directly or indirectly, a 46.34% working interest in the entire Thailand Concession. The remainder of the working interest is primarily owned, directly or indirectly, by subsidiaries of ChevronTexaco Corporation, including Chevron Offshore (Thailand) Limited ("Chevron"), Palang Sophon Two Limited, and Palang Sophon Limited ("Palang"). Through its majority ownership of Palang, Chevron owns or controls, directly or indirectly, 53.66% of the working interests in the Thailand Concession and is currently the operator of the Thailand Concession. Through voting procedures in the joint operating agreement governing the Thailand Concession, and the close working relationship between Chevron's and Thaipo's exploration staffs, Thaipo exerts substantial influence over the development of the Thailand Concession. As of December 31, 2003, the Company's proved reserves located in the Kingdom of Thailand accounted for approximately 23% of the Company's total proved reserves. During 2003, approximately 29% of the Company's natural gas production and 33% of its oil and condensate production came from its operations on the Thailand Concession, contributing approximately 26% of the Company's consolidated oil and gas revenues.

Benchamas Field. A portion of the Thailand Concession comprising approximately 102,000 acres is designated as the Benchamas and Pakakrong production area or the "Benchamas Field." In January 2004, the government of Thailand designated approximately 31,000 additional acres as the North Benchamas area. This area is considered a part of, and is being developed in conjunction with, the remainder of the Benchamas Field. By the end of 2004, there are expected to be 14 production platforms installed in the Benchamas Field. Natural gas and oil from these platforms are delivered by undersea pipeline to a central processing and compression platform where the oil, condensate and natural gas is processed and separated. The natural gas is sold to PTT Public Company Limited ("PTT") and delivered into export pipelines for transportation to shore, while the crude oil and condensate produced from the field is stored on board a Floating Storage and Offloading system ("FSO") known as the "Benchamas Explorer" for sale and ultimate transfer to shore by oil tanker. (Please reference section entitled "2004 Production Outlook" for a description of temporary shut-in for the Benchamas Field.) The FSO is moored in the Benchamas Field. Its capacity is approximately 1,400,000 Bbls of crude oil and condensate. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Crude Oil and Condensate—Production." Additional drilling is currently planned for the Benchamas Field during 2004. A temporary shutdown of the Benchamas Field to upgrade the Benchamas central processing platform commenced in January and was recently completed. Operations are currently underway to establish full production from all producing wells in the field. During 2003, an additional 24 productive development wells and one successful exploration well were drilled in the Benchamas Field. For 2004, an active drilling campaign is currently planned in the field.

Tantawan Field. A portion of the Thailand Concession comprising approximately 68,000 acres is designated as the Tantawan production area or the "Tantawan Field." Oil and gas production from the Tantawan Field is gathered through pipelines from the platforms into a Floating Production Storage and Offloading system (an "FPSO") named the "Tantawan Explorer." The FPSO is a converted oil tanker with a capacity of slightly less than 1,000,000 Bbls, and is moored in the Tantawan Field, on which hydrocarbon processing, separation, dehydration, compression, metering and other production-related equipment is installed. Following processing on board the FPSO, natural gas produced from the field is delivered to PTT through an export pipeline. Oil and condensate produced from the field is stored on board the FPSO until sold and transferred to shore by oil tanker. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." During 2003, a new platform was set on the western side of the Tantawan Field. In early 2004, eight productive wells were drilled from this platform. In addition, during 2003, ten development and two exploratory wells were drilled in the field. Currently, there is production from six platforms. Current plans call for additional development and exploratory drilling within the field during 2004. During the fourth quarter of 2003, an additional 20,000 acres, comprising the adjacent Block 9A, were assigned to Thaipo and its joint venture partners. Two successful exploration wells were promptly drilled and a production area designation has been applied for. If and when Block 9A is designated a production area, it will be developed from and through existing Tantawan Field facilities, but will require the setting of at least one additional platform.

Maliwan Field. Approximately 91,000 acres of the Thailand Concession are designated as the Maliwan production area or the "Maliwan Field." The Maliwan "A" platform was installed and commenced production on October 29, 2001. An additional seven development wells were drilled from this platform in late 2003. Production from this platform is delivered to the central Benchamas Field production handling facilities for processing and sale. During 2003, two appraisal wells were also drilled in the field and current plans call for additional appraisal drilling in the Maliwan Field during 2004 in connection with finalizing a development plan for the entire field.

Jarmjuree Field. Approximately 124,000 acres of the Thailand Concession, known as the Jarmjuree Field, are designated as a production area. The first platform in this field, the North Jarmjuree "A" platform, is anticipated to be set in the second quarter of 2004. Development drilling and initial production from the Jarmjuree Field is currently expected to occur in 2004. Production from this platform is planned

to be delivered to the central Benchamas Field production handling facilities for processing and sale. Development plans for the remainder of the field are still being formulated. Additional exploration and appraisal wells could be drilled in the Jarmjuree Field and surrounding areas during 2004.

Other Portions of the Thailand Concession. Thaipo and its joint venture partners have identified other potentially promising areas on the Thailand Concession and surrounding acreage. During 2003, Thaipo and its joint venture partners drilled six exploratory wells and have currently budgeted to drill an additional six exploratory wells during 2004. Interpretation of the data provided by these wells and 3-D seismic data covering the Thailand Concession is ongoing.

Platforms are installed on the Thailand Concession in fields where, in the judgment of Thaipo and its joint venture partners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment and the area where the platform would be located has been designated a production area by the government of the Kingdom of Thailand. See "Contractual Terms Governing the Thailand Concession and Related Production." Platforms are used to accommodate both development drilling and additional exploratory drilling. A key focus of Thaipo and its joint venture partners has been to reduce the average cost of the platforms installed to improve the overall economics of the project. The gross cost of the fourteen production platforms and related facilities installed in the Tantawan, Benchamas and Maliwan Fields first averaged approximately $17,400,000 per platform. The gross cost of "second generation" platforms, including the three that were installed in 2003 and the five that are under construction, is currently expected to average approximately $15,200,000 per platform. Efforts are currently underway to design and construct even less expensive platforms as part of the next generation to be ordered in 2004. Platform costs vary, and more (or less) expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, ocean currents and sea floor conditions and the amount of facilities required to be placed on the platform.

The Thailand Concession was granted in August 1991. The initial exploratory term for the Thailand Concession expired on July 31, 2000. However, through a series of one-year extensions, Thaipo and its joint venture partners have been granted an extension of the exploratory term through July 31, 2004. A similar one-year extension will also be applied for to extend the exploratory term of the Thailand Concession through July 31, 2005. This will be the last extension that can be obtained. On July 31, 2005, all acreage for which production area status has not been applied for will revert to the government of Thailand. For those portions of the Thailand Concession that have been designated as production areas, the initial production period term is 20 years, which is also subject to extension, generally for a term of ten years. In November 2003, Thaipo and its joint venture partners requested that the government designate Block 9A as a production area. To date, the Benchamas Field (including the North Benchamas area), Tantawan Field, Maliwan Field and North Jarmjuree Field have been designated as production areas. Subject to governmental approval, other portions of the Thailand Concession may be designated production areas in the future.

Production resulting from the Thailand Concession is generally subject to a royalty ranging from 5% to 15% of oil and gas sales. Slightly different terms apply to production from Block 9A, but the difference is not expected to be material to the results of operations of the Company. Profits from production in Thailand are also subject to a Special Remuneration Benefit ("SRB"). The SRB rate, which can range from 20% to 75%, is calculated based on a complex formula using discounted revenue, meters drilled and other factors specified in the Thailand Concession license agreement. This rate is then applied toward the net proceeds derived by each joint venture partner's Thailand subsidiaries. SRB payments are then treated as a deductible expense for Thailand income tax calculations by such subsidiaries. The Company began accruing SRB liabilities in 2003 on a portion of the net proceeds it derives from the Thailand Concession and currently expects to make significant SRB payments during 2004. See "Management's Discussion and

Analysis of Financial Condition and Results of Operations—Results of Operations: Production and Other Taxes."

Thaipo and its joint venture partners have entered into a thirty-year Gas Sales Agreement with PTT (the "Gas Sales Agreement"), governing gas production from the Tantawan Field and the Benchamas Field. The terms of the Gas Sales Agreement currently include a minimum daily contract quantity ("DCQ") of 125 MMcf per day, subject to certain exceptions, and will in the future be based on a percentage of the remaining proved reserves, but in any event will not be less than 125 MMcf per day. In addition, the Gas Sales Agreement gives PTT the right to nominate in any given week 115% of DCQ or approximately 145 MMcf per day. The Gas Sales Agreement provides that PTT may take up to an additional approximate 177 billion cubic feet of gas through December 31, 2007 at production rates that, until the end of such supplemental period ("Supplemental DCQ"), equates to 85 MMcf per day or approximately 40 MMcf net to the Company. During 2003, gas production averaged approximately 224 MMcf per day (90 MMcf per day net to the Company).

Thaipo and its joint venture partners are subject to penalties if they are unable to meet the DCQ or the Supplemental DCQ under the Gas Sales Agreement. Failure to meet DCQ results in a decrease in the sales price for gas sold under the Gas Sales Agreement of up to 25% of the then-current sales price and failure to meet the Supplemental DCQ will result in a credit against the next month's supplemental production of 12% (6% from March 1, 2004 through January 1, 2006) of the then-current sales price of the gas not delivered. Thaipo currently meets the minimum DCQ and generally meets the Supplemental DCQ requirements, however, there can be no assurance that Thaipo will be able to continue to meet them in the future, in which case these penalty provisions would reduce the price received by Thaipo for its gas sold to PTT under the Gas Sales Agreement.

The sales price for the base DCQ production under the Gas Sales Agreement is subject to automatic semi-annual adjustments based upon a formula that takes into account changes in: Singapore fuel oil prices; the U.S. Bureau of Labor Statistics Oilfield Machinery and Tool Index; the Thai wholesale producer price index; and the U.S./Thai currency exchange rate. However, the Gas Sales Agreement provides for adjustment on a more frequent basis in the event that certain indices and factors on which the price is based fluctuate outside a given range. The sales price for Supplemental DCQ production is 88% of the then-current sales price for DCQ production. As of December 31, 2003, the Company was receiving a blended average price of approximately $2.59 per Mcf under the Gas Sales Agreement for DCQ and Supplemental DCQ production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations" and "Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues."

Hungary. On April 20, 1999, the Company's subsidiary, Pogo Hungary, was awarded a license to explore for oil and gas in the Szolnok and Tompa areas of central and south central Hungary. This license area currently consists of approximately 764,000 acres. The exploration term of the license is currently set to expire on April 19, 2005, with further extension possible until April 19, 2007 with government approval. Areas where commercial accumulation of hydrocarbons are identified may then be designated as "mining plots" and held through the economic productive life of such reserves. One 3-D survey covers approximately 97,000 acres, a substantial portion of the Tompa area, and the other covers approximately 42,000 acres of the Szolnok area and is referred to as the Kenderes 3-D survey. Based upon detailed evaluation of this 3-D seismic data and extensive other data acquired from government sources, a number of prospects have been preliminarily identified. During 2003, Pogo Hungary drilled two wells in the Szolnok area, including the Szolnok No. 2 well that was successfully tested and another well that has been temporarily abandoned to allow for possible future testing. Pogo Hungary also drilled three wells in the Tompa area, which have been temporarily abandoned pending possible fracture stimulation or additional testing. Pogo Hungary currently intends to drill additional exploration wells during 2004, as well as

delineation wells on the Szolnok No. 2 discovery. Pogo Hungary also currently intends to acquire additional seismic data during 2004 in the Szolnok area and to continue analyzing its existing 2-D and 3-D seismic database.

Hungary imported approximately 80% of the crude oil and approximately 77% of the natural gas that it consumed in 2002. Most of the natural gas that is imported into Hungary comes from Russia. The remaining imported natural gas is delivered from Austria through the HAG pipeline. Historically, the domestic Hungarian oil and gas industry was entirely state-owned. Due to privatization of the industry, the Hungarian retail petroleum market was liberalized in 1991. The wholesale and retail prices for natural gas remained heavily regulated and partially subsidized until late 2003. Currently, the Company believes that crude oil produced in Hungary may be sold in Hungary or exported at a price based upon world market prices. The sale of natural gas in Hungary was recently liberalized under an amendment to the Hungarian Natural Gas Act. Effective January 1, 2004, industrial consumers are eligible to purchase gas in the free market. The residential consumer market is anticipated to continue to be served by a public utility wholesale provider at regulated prices until no later than 2007 in accordance with European Economic Union regulations. Pogo Hungary also currently believes that, in addition to supplying gas to eligible consumers in the domestic market, it has the ability to swap the natural gas it produces in Hungary for natural gas at the Baumgarten hub in Austria, which can then be sold at unregulated European spot prices, or to export the gas to surrounding countries.

North Sea. On August 5, 1999, the Danish government approved the assignment to the Company of a 40% working interest in License 13/98 covering approximately 81,000 acres in the Danish sector of the North Sea. This license interest is currently held by the Company's Danish subsidiary, Pogo Denmark ApS. The work commitment for this license requires the drilling of an exploratory well prior to the expiration of the license. The initial term of the license goes through June 14, 2004, unless otherwise extended or a production license is granted. Pogo Denmark ApS and its joint venture partners have scheduled and intend to drill a well during the first half of 2004 on one of the prospects that has been identified on the block.

During 2003, Pogo North Sea Limited, a British subsidiary of the Company, together with two joint venture partners, held a license governing approximately 113,000 acres in the British sector of the North Sea. Pending final government approval, and as of December 23, 2003, the joint venture has relinquished its interest in the license area back to the Department of Trade and Industry.

New Zealand. On February 4, 2004, the Company was granted three petroleum exploration licenses (the "Licenses") over approximately 1,014,000 acres in the offshore Northern Taranaki Basin. The primary exploration term of the Licenses is for five years, subject to extension up to an additional ten years, provided that at least half of the acreage under each license has been relinquished and the permit holder has substantially complied with the terms of its permits. The Company has committed to acquire 3-D seismic data over at least 1,000 square kilometers of the Licenses within the first two years of their primary term. Based upon an analysis of this data, the Company has a contingent commitment to drill one well on each of the three Licenses by the end of 2007. Production permits of up to 40 years may be applied for if a commercial field is discovered. The Company's current plans for 2004 consist of evaluating existing data and designing a 3-D seismic acquisition program over prospective portions of the Licenses.

For financial information about geographic areas, see Note 6—Geographic Segment Information in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in eight pipelines (excluding field gathering pipelines) through which offshore hydrocarbon production is transported. As previously discussed, the Company also owns an approximate 15% interest in the Lost Cabin Gas Plant located in the Madden Field, which currently has the capacity to process 313 MMcf of natural gas per day.

The marketing of all of the Company's onshore and offshore oil and gas production is subject to the availability of pipelines and other transportation, processing and refining facilities, as well as the existence of adequate markets. As a result, even if hydrocarbons are discovered in commercial quantities, a substantial period of time could elapse before commercial production commences. If pipeline facilities in an area are insufficient, the Company may have to await the construction or expansion of pipeline capacity before production from that area can be marketed. The Company's domestic onshore and offshore properties are generally located in areas where a pipeline infrastructure or other transportation alternatives are well developed and there is adequate availability in such pipelines or other transportation alternatives to transport the Company's current and projected future production.

The Company may not be able to successfully market all of the oil and natural gas found and produced on the Thailand Concession. Currently, the only purchaser of natural gas is PTT, which maintains a monopoly over gas transmission and distribution in Thailand, including ownership of the two major natural gas pipelines (34 inches and 36 inches in diameter, respectively) that traverse the Thailand Concession. All oil and condensate production from the Tantawan Field is initially stored aboard the FPSO and then sold to various third parties, including PTT, on a tanker load by tanker load basis at prices based on then-current world oil prices, typically with reference to the Malaysian Tapis Blend crude oil benchmark price. Crude oil and condensate production from the Benchamas Field and the first platform located in the northern portion of the Maliwan Field is initially stored aboard the FSO. A portion of this production is sold under a term sales agreement with China International United Petroleum & Chemical Company Ltd. that expires in March 2004. This term sales agreement is for a total of 3,600,000 Bbls (1,668,000 Bbls net to Thaipo) at a price equal to Malaysian TAPIS less $0.40 per Bbl. Another portion of this production is sold under a term sales agreement with Pacific Petroleum and Trading Co., Ltd. that expires in August 2004. This term sales agreement is for 600,000 Bbls per month, subject to seller's availability, at an agreed price each month. The remaining production from the Benchamas Field is sold on a tanker load by tanker load basis, similar to the way Tantawan Field crude oil is currently marketed.

The prices that the Company receives for crude oil sales from its Thailand Concession are influenced by a number of factors including, among others, tanker availability, world-wide crude oil demand, size of the lifting and the perceived quality of crude oil produced. For example, crude oil produced from the Gulf of Thailand is generally perceived as having high mercury levels. The crude oil from the Benchamas Field has high wax content. Therefore, it is sought after by some refineries and is less desirable to others. These factors and others have led to significant fluctuations in the price that the Company receives for its Thai crude oil production in comparison to the Malaysian Tapis Blend benchmark price. During 2003, the price that the Company received for its crude oil production from the Thailand Concession ranged between a $0.75 per Bbl premium and a $1.25 per Bbl discount to the Malaysian Tapis Blend benchmark price. The Company and its joint venture partners continue to examine ways to improve the price received for crude oil, including the possibility of entering into further long-term contracts for a portion of its production. In addition, because much of the oil produced from the Thailand Concession is associated with natural gas, limitations on Thaipo's ability to produce natural gas could limit crude oil production as well. The crude oil purchaser is generally responsible for sending a tanker to offload the oil and condensate it has purchased.

See "International Operations; Contractual Terms Governing the Thailand Concession and Related Production."

Most of the Company's North American natural gas sales are currently made in the "spot market" for no more than one month at a time at then-currently available prices or under longer-term contracts with prices that are based on, and fluctuate with, spot market prices. Prices on the spot market fluctuate with supply and demand. Crude oil and condensate production is also generally sold one month at a time at the price that is then-currently available or under longer-term contracts with prices that also fluctuate in relationship to published market price. Other than any oil and natural gas forward sales contracts that may exist from time to time, and are referred to in "Miscellaneous; Competition and Market Conditions," and the Gas Sales Agreement with PTT for production from the Thailand Concession (see "International Operations; Contractual Terms Governing the Thailand Concession and Related Production") and the crude oil contracts discussed above, the Company has no existing contracts that require the delivery of fixed quantities of oil or natural gas, other than on a best efforts basis. In 2003, crude oil sales to one customer (China International United Petroleum & Chemical Company Ltd.) constituted more than 10% of the Company's consolidated revenues.

From time to time the Company acquires, and may acquire in the future, additional interests in oil and gas properties, either through acquisition of the properties themselves or, as in the case of the North Central acquisition, indirectly through the purchase of an equity interest in the entity owning such properties. The successful acquisition of such properties requires an assessment of several factors, including recoverable reserves, development and exploratory potential, projected future cash flows that are, in part, based upon future oil and gas prices, current and projected operating, general and administrative and other costs, and contingent liabilities associated with the properties or entities acquired, including potential environmental and other liabilities.

The accuracy of the Company's assessment of these factors is inherently uncertain. To the extent reasonably practicable under the specific circumstances of each acquisition, the Company performs a review of the properties or entities prior to an acquisition. The Company believes that its review procedures are generally consistent with current industry practices. The Company's review and assessment process will not reveal all existing or potential problems nor will it permit the Company to become sufficiently familiar with the properties or entities to fully assess their deficiencies and capabilities. Even when problems are identified, the other party may be unwilling or unable to provide effective contractual protection against all or part of the problems. Occasionally, the Company may not be entitled to contractual indemnification for certain liabilities, acquiring the properties on an "as is, where is" basis. In addition, successful acquisitions frequently require the successful integration of operations, equipment and personnel. There can be no assurance that the Company will be able to successfully integrate operations and properties that it acquires and still achieve the anticipated synergies, cost savings and efficiencies.

The Company experiences competition from other oil and gas companies in all phases of its operations, as well as competition from other energy-related industries. The Company's profitability and cash flow are highly dependent upon the prices of oil and natural gas, which historically have been seasonal, cyclical and volatile. In general, prices of oil and gas are dependent upon numerous factors beyond the control of the Company, including various weather, economic, political and regulatory conditions. In addition, the decisions of the Organization of Petroleum Exporting Countries relating to export quotas also affect the price of crude oil. A future drop in oil or gas prices could have a material adverse effect on the Company's cash flow and profitability. Sustained periods of low prices could cause the Company to shut in existing production and also have a material adverse effect on its operations and financial condition. It could also result in a reduction of funds available under the Company's bank credit

facilities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources; Credit Facility."

Because it is impossible to predict future oil and gas price movements with any certainty, the Company from time to time enters into contracts to hedge against future market price changes on a portion of its production. Such hedging transactions, historically, have never exceeded 50% of the Company's total oil and gas production on an energy equivalent basis for any given period. While intended to limit the negative effect of price declines, some forms of hedging transactions could effectively limit the Company's participation in price increases, which could be significant, for the covered period. As of December 31, 2003, the Company was not a party to any natural gas or crude oil option contracts. When the Company does engage in certain types of hedging activities, it may satisfy its obligations with its own production or by the purchase (or sale) of third-party production. The Company may also offset delivery obligations under these hedging transactions requiring physical delivery with equivalent agreements, thereby effecting a purely cash transaction.

The Company's operations are subject to risks inherent in the exploration for and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pollution and other environmental risks. Offshore oil and gas operations are subject to the additional hazards of marine and helicopter operations, such as capsizing, collision and adverse weather and sea conditions. These hazards could result in substantial losses to the Company due to injury or loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company carries insurance that it believes is in accordance with customary industry practices, but is not fully insured against all risks incident to its business.

Drilling activities are subject to numerous risks, including the risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. For example, the Company is currently experiencing some difficulty in obtaining additional drilling rigs for its Thailand operations due to the lack of suitable rigs in the region. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs.

In periods during which the industry experiences a substantial decline in oil and gas prices, many of the Company's partners, particularly the smaller ones, can experience liquidity and cash flow problems. These problems may lead to the smaller companies' attempts to delay or slow down the pace of drilling or project development in order to conserve cash, to a point that the Company believes is detrimental to the project. In most cases, the Company has the ability to influence the pace of development through joint operating agreements. Some partners may be unwilling or unable to pay their share of the costs of projects as they become due. At worst, a partner may declare bankruptcy and refuse or be unable to pay its share of the costs of a project. The Company would then be required to pay this partner's share of the project costs. In most instances, the Company believes that it is contractually protected from such an event through its ability to take over the non-paying partner's share of the project and by applicable oil and gas lien laws and bankruptcy laws. The Company believes that it would ultimately recover any sums that it is owed by non-paying partners that do not meet their share of the costs of a project in a timely fashion.

Ownership of property interests and production operations in Thailand, Hungary, the North Sea, New Zealand and in any other areas outside the United States in which the Company may choose to do business are subject to the various risks inherent in foreign operations. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risks of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies and other uncertainties arising out of foreign government sovereignty over the Company's international operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations," and "Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States. The Company seeks to manage these risks by concentrating its international exploration efforts in areas where the Company believes that the existing government is stable and favorably disposed towards United States exploration and production companies.

In the following data, "gross" refers to the total acres or wells in which the Company has an interest and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company.

The Company owns interests in developed and undeveloped oil and gas acreage in various parts of the world. These ownership interests generally take the form of "working interests" in oil and gas leases that

have varying terms. The following table shows the Company's interest in developed and undeveloped oil and gas acreage under lease as of December 31, 2003:

			Developed Acreage(a)		Undeveloped Acreage(b)
			Gross	Net	Gross	Net
Domestic Offshore
	Louisiana		142,126	52,498	137,604	101,324
	Texas		17,280	6,141	23,040	5,904

		Total Domestic Offshore	159,406	58,639	160,644	107,228

Domestic Onshore
	Louisiana		9,407	2,577	9,334	3,279
	Mississippi		1,280	26	—	—
	New Mexico		54,357	38,505	74,879	57,510
	Texas		185,262	85,950	63,523	41,909
	Wyoming		29,205	3,700	50,614	20,287
	Other		6,120	2,211	80	15

		Total Domestic Onshore	285,631	132,969	198,430	123,000

		Total Domestic	445,037	191,608	359,074	230,228

International
	Gulf of Thailand		415,824	192,698	318,444	147,572
	North Sea		—	—	81,000	32,400
	Hungary		—	—	764,315	764,315

		Total International	415,824	192,698	1,163,759	944,287

		Total Company	860,861	384,306	1,522,833	1,174,515

In addition, the Company holds a 100% interest in 1,014,000 undeveloped acres in New Zealand that were granted in February 2004, as well as certain other types of mineral interests, including fee interests (which never expire) and royalty interests (which generally terminate when the underlying mineral lease expires). The Company owns varying fee and royalty interests in approximately 1,190,600 gross acres (26,875 net acres) in various parts of the United States, principally as a result of the North Central acquisition.

The following table shows the average production (lifting) costs per unit of production during the periods indicated. For a discussion of the Company's average daily production and the average sales prices received by the Company for such production, see "Selected Financial Data Production (Sales) Data" and

"Management's Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations; Oil and Gas Revenues."

The following table shows the Company's interest in productive oil and natural gas wells as of December 31, 2003. For purposes of this table "productive wells" are defined as wells producing hydrocarbons and wells "capable of production" (e.g., natural gas wells waiting for pipeline connections or necessary governmental certification to commence deliveries and oil wells waiting to be connected to currently installed production facilities). "Net wells" for purposes of this table are defined to mean the sum of the Company's working interest net of royalties and other burdens. This table does not include exploratory or development wells which have located commercial quantities of oil or natural gas but which are not capable of commercial production without the installation of material production facilities or which, for a variety of reasons, the Company does not currently believe will be placed on production.

The following table shows the number of successful gross and net exploratory and development wells in which the Company has participated and the number of gross and net wells abandoned as dry holes during the periods indicated. An onshore well is considered successful upon the installation of permanent equipment for the production of hydrocarbons or when electric logs run to evaluate such wells indicate the presence of commercially producible hydrocarbons and the Company currently intends to complete such

wells. Successful offshore wells consist of exploratory or development wells that have been completed or are "suspended" pending completion (which has been determined to be feasible and economic) and exploratory test wells that were not intended to be completed and that encountered commercially producible hydrocarbons. A well is considered a dry hole when the Company decides to report permanent abandonment to the appropriate agency.

				2003		2002		2001
				Productive	Dry	Productive	Dry	Productive	Dry
Gross Wells:
	Offshore United States
		Exploratory		5.0	2.0	5.0	2.0	2.0	3.0
		Development		3.0	—	13.0	—	22.0	—
	Onshore North America(a)
		Exploratory		9.0	3.0	1.0	4.0	7.0	3.0
		Development		169.0	9.0	83.0	5.0	61.0	3.0
	Offshore Kingdom of Thailand
		Exploratory		5.0	1.0	6.0	—	11.0	—
		Development		40.0	1.0	51.0	2.0	18.0	—
	Europe
		Exploratory		1.0	—	—	—	—	—
		Development		—	—	—	—	—	—

			Total	232.0	16.0	159.0	13.0	121.0	9.0

Net Wells:
	Offshore United States
		Exploratory		2.3	2.0	5.0	2.0	2.0	1.7
		Development		2.2	—	8.8	—	8.3	—
	Onshore North America(a)
		Exploratory		5.9	2.0	0.8	3.2	5.0	1.3
		Development		75.9	3.5	54.7	3.4	38.0	1.6
	Offshore Kingdom of Thailand
		Exploratory		2.3	0.5	2.8	—	5.1	—
		Development		18.5	0.5	23.5	0.9	8.3	—
	Europe
		Exploratory		1.0	—	—	—	—	—
		Development		—	—	—	—	—	—

			Total	108.1	8.5	95.6	9.5	66.7	4.6

The following table sets forth information as to the Company's net proved and proved developed reserves as of December 31, 2003, 2002 and 2001, and the present value as of such dates (based on an annual discount rate of 10%) of the estimated future net revenues from the production and sale of those reserves, as set forth in reports prepared by Ryder Scott Company L.P. ("Ryder Scott") and Miller and Lents, Ltd. ("Miller and Lents"), the Company's independent petroleum engineers, in accordance with criteria prescribed by the Commission. The summary reports of Ryder Scott and Miller and Lents on the Company's reserves are set forth as exhibits to this Annual Report on Form 10-K and are incorporated herein by reference. The Ryder Scott report covers the Company's reserves except for certain domestic onshore areas acquired in the North Central acquisition.

The Company does not currently believe that the calculation of estimated future net revenues using the assumptions prescribed by Commission guidelines and generally described below is representative of the true value of future net revenues from the Company's proved reserves. The future prices received by the Company for the sales of its production may be higher or lower than the prices used in calculating the estimates of future net revenues, and the operating costs and other costs relating to such production may also increase or decrease from existing levels.

The Company believes, for the reasons set forth in succeeding paragraphs, that the present value of estimated future net revenues set forth in the Annual Report and calculated in accordance with

Commission guidelines is not necessarily indicative of the true fair value of the Company's reserves. Moreover, due to the fact that essentially all of the Company's domestic natural gas production is currently sold on the spot market, while all of the Company's Thailand natural gas production is sold pursuant to a long-term gas sales contract, the estimates of future net revenues from the Company's domestic and Thailand reserves are of limited value for comparative purposes.

Natural gas liquids comprised approximately 5% of the Company's total proved liquids reserves and approximately 5% of the Company's proved developed liquids reserves as of December 31, 2003. All hydrocarbon liquid reserves are expressed in standard 42 gallon Bbls. All gas volumes and gas sales are expressed in MMcf at the pressure and temperature bases of the area where the gas reserves are located.

In accordance with Commission guidelines, the prices used by the Company to calculate the present value of estimated future revenues are determined on a well or field-by-field basis, as applicable, as described above and were held constant over the productive life of the reserves. The initial weighted average prices used by Ryder Scott and Miller & Lents were as follows:

			As of December 31,
			2003		2002		2001
Initial Weighted Average Price (in Dollars):
	Oil, condensate and natural gas liquids (per Bbl)
		Located in North America(a)	$	31.34	$	28.72	$	18.75

		Located in the Kingdom of Thailand	$	30.27	$	32.41	$	18.94

		Located in Hungary	$	26.00	$	—	$	—

	Natural Gas (per Mcf)
		Located in North America(a)	$	5.70	$	4.70	$	2.48

		Located in the Kingdom of Thailand	$	2.51	$	2.24	$	2.31

		Located in Hungary	$	4.82	$	—	$	—

In computing future revenues from gas reserves attributable to the Company's domestic interests, prices in effect at December 31, 2003 were used, including current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with Commission guidelines, the gas prices that were used make no allowances for seasonal variations in gas prices that are likely to cause future yearly average gas prices to be different than December gas prices. For domestic gas sold under contract, the contract gas price including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price through to depletion of the reserves. In computing future revenues from liquids attributable to the Company's domestic interests, prices in effect at December 31, 2003 were used and these prices were held constant through to depletion of the properties. The future net revenues are adjusted to reflect the Company's net revenue interest in these reserves as well as any ad valorem and other severance taxes but do not include any provisions for corporate income taxes.

In computing future revenues from the Company's gas reserves attributable to the Company's interests in the Kingdom of Thailand, a blended price that took into account the current contract price under the Gas Sales Agreement for the base production (currently 145 MMcf per day) and the price for excess sales volumes (which equals 88% of the then-current price for base production) was used, without giving effect to any of the future adjustments provided for in the Gas Sales Agreement, due to their indeterminate nature as of December 31, 2003, in accordance with Commission guidelines. In computing future revenues from liquids attributable to the Company's interests in the Kingdom of Thailand, a price

was used that the Company believes approximates the price that the Company would have received for its production from the Thailand Concession based upon the world market price for Malaysian Tapis Blend benchmark crude on December 31, 2003, and this price was held constant until depletion of the Company's reserves in the Kingdom of Thailand. The future net revenues are adjusted to reflect the Company's net revenue interest in these reserves and the Company's obligations under the Thailand Concession, including the payment of SRB, but do not include any provisions for U.S. or Thai corporate income or other taxes.

In accordance with Commission guidelines for calculating future net revenues, the operating costs for the leases and wells include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. Development costs are based on authorization for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. The estimated net cost of abandonment after salvage was considered for the properties. No deduction was made for indirect costs such as general and administrative and overhead expenses, loan repayments, interest expenses and exploration and development prepayments. Accumulated gas production imbalances, if any, have been taken into account.

Production data used to arrive at the estimates set forth above includes estimated production for the last few months of 2003. The future production rates from reservoirs now on production may be more or less than estimated because of, among other reasons, mechanical breakdowns and changes in market demand or allowables set by regulatory bodies. Properties that are not currently producing may start producing earlier or later than anticipated in the estimates of future production rates.

There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those of the Company, Ryder Scott and Miller & Lents. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate, which may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Company is periodically required to file estimates of its oil and gas reserve data with various U.S. governmental regulatory authorities and agencies, including the Department of Energy, the Federal Energy Regulatory Commission ("FERC") and the Federal Trade Commission and, with respect to reserves located in Thailand, the Kingdom of Thailand's Department of Mineral Fuels and PTT, which the Company considers a quasi-governmental authority. In addition, estimates are from time to time furnished to governmental agencies in connection with specific matters pending before such agencies. The basis for reporting reserves to these agencies, in some cases, is not comparable to that furnished by Ryder Scott and Miller & Lents in accordance with Commission guidelines because of the nature of the various reports required. The major differences generally include differences in the timing of such estimates, differences in the definition of reserves, requirements to report in some instances on a gross, net or total operator basis and requirements to report in terms of smaller geographical units. Since January 1, 2003, no estimates by the Company of its total proved net oil or gas reserves were filed with or included in reports to any Federal authority or agency other than the Commission.

Federal income tax laws significantly affect the Company's operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic "intangible drilling and development costs"

and to claim depletion on a portion of its domestic oil and gas properties based on 15% of its oil and gas gross income from such properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic natural gas), even though the Company has little or no basis in such properties. Under certain circumstances, however, a portion of such intangible drilling and development costs and the percentage depletion allowed in excess of basis will be tax preference items that will be taken into account in computing the Company's alternative minimum tax.

Domestic oil and gas operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") also known as the "Superfund Law." The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Oil and gas lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee's operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may, as it has in the past, also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.

The Company has numerous applications pending before the Environmental Protection Agency (the "EPA") for National Pollution Discharge Elimination System ("NPDES") water discharge permits with respect to offshore drilling and production operations. NPDES permits are required to ensure that effluent discharges from each facility or installation comply with the applicable federal regulations.

The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company's offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The amount of financial responsibility that the Company must currently demonstrate for its offshore platforms is $70,000,000. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.

The Company's onshore operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee's operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Federal, state and local initiatives to further regulate the disposal of oil and gas wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company's operations are also subject to additional federal, state and local laws and regulations

relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.

The Company is asked to comment on the costs it incurred during the prior year on capital expenditures for environmental control facilities and the amount it anticipates incurring during the coming year. The Company believes that, in the course of conducting its oil and gas operations, many of the costs attributable to environmental control facilities would have been incurred absent environmental regulations as prudent, safe oilfield practice. During 2003, the Company incurred capital expenditures of approximately $1,987,000 for environmental control facilities, primarily relating to the cost of installing environmental equipment, the installation of pit and firewall spill liners, and routine site restoration costs. The Company has budgeted approximately $2,500,000 for expenditures involving environmental control facilities during 2004, including, among other things, anticipated site restoration costs and the installation of environmental control equipment.

Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of oil and gas including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company's properties and to limit the allowable production from the successful wells completed on the Company's properties, thereby limiting the Company's revenues.

The MMS administers the oil and gas leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers.

The FERC has embarked on wide-ranging regulatory initiatives relating to gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC's rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the gas prices received by the Company for the sale of its production, the FERC's actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated gas producers and sellers.

As of December 31, 2003, the Company and its subsidiaries had 221 full-time employees, including six in its Bangkok, Thailand office and seven in its Budapest, Hungary office. None of the Company's employees are presently represented by a union for collective bargaining purposes.

The Company files annual, quarterly and current reports, proxy statements and other information with the Commission. These filings are available free of charge through its Internet website at www.pogoproducing.com as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Commission. Additionally, the Company makes available free of charge on its Internet website:

Any shareholder who so requests may obtain a printed copy of any of these documents from the Company. Changes in or waivers to the Company's Code of Business Conduct and Ethics required to be disclosed by rules of the Commission or the New York Stock Exchange will be posted on the Company's Internet website within five business days and maintained for at least twelve months.

The information appearing in Item 1 of this Annual Report is incorporated herein by reference.

The Company is a party to various legal proceedings consisting of routine litigation incidental to its businesses, but believes that any potential liabilities resulting from these proceedings are adequately covered by insurance or are otherwise immaterial at this time. See "Business—Government Regulation; Other Laws and Regulations."

No matters were submitted to a vote of the Company's security holders during the fourth quarter of the year ended December 31, 2003.

Officers of the Company are appointed annually by the Company's Board of Directors to serve for the ensuing year or until their successors have been elected or appointed. The officers of the Company that have been designated as "executive officers" for purposes of Item 401(b) of Regulation S-K and "officers" for purposes of Section 16 of the Exchange Act, their age as of December 31, 2003, and the year each was elected to his current position are as follows:

Executive Officer	Executive Office	Age	Year Elected
Paul G. Van Wagenen	Chairman, President and Chief Executive Officer	57	1991
Stephen R. Brunner	Executive Vice President—Operations	45	2002
Stuart P. Burbach	Executive Vice President—Exploration	51	1998
Jerry A. Cooper	Executive Vice President and Regional Manager—Western United States	55	2002
John O. McCoy, Jr.	Executive Vice President and Chief Administrative Officer	52	2002
David R. Beathard	Senior Vice President—Engineering	45	2002
Gerald A. Morton	Senior Vice President and Regional Manager—Asia and Pacific and Corporate Secretary	45	2003
James P. Ulm, II	Senior Vice President and Chief Financial Officer	40	2002
Thomas E. Hart	Vice President and Chief Accounting Officer	60	1999
Michael J. Killelea	Vice President and General Counsel	41	2001

Mr. Van Wagenen, who joined the Company in 1979, has served in his current position since 1991. Prior to assuming their present positions with the Company, the business experience of each of the other executive officers for at least the last five years was as follows: Mr. Brunner, who joined the Company in 1994, served as Vice President—Operations since 1997; Mr. Burbach served as Vice President and Offshore Division Manager since rejoining the Company in 1991; Mr. Cooper, who joined the Company in 1979, served as Senior Vice President and Western Division Manager since 1998 and prior thereto served as Vice President and Western Division Manager since 1990; Mr. McCoy, who joined the Company in 1978, served as Senior Vice President and Chief Administrative Officer of the Company since 1998 and prior thereto as Vice President and Chief Administrative Officer since 1989; Mr. Beathard, who joined the Company in 1982, served as Vice President—Engineering since 1997; Mr. Morton, who joined the Company in 1993, served as Vice President and Regional Manager -Asia and Pacific since 2002 and Vice President—Law, Chief Regulatory Officer and Corporate Secretary since 2001, and prior thereto was Vice President—Law and Corporate Secretary since 1997; Mr. Ulm served as Treasurer of Newfield Exploration Company from 1995 until joining the Company as its Vice President and Chief Financial Officer in 1999; Mr. Hart joined the Company in 1977 and served as Vice President and Controller since 1988; and Mr. Killelea was Chief Counsel of the Company since he joined the Company in 2000 and prior thereto served as Chief Counsel of CMS Oil and Gas Company for more than three years.

ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters.

The following table shows the range of low and high sales prices of the Company's Common Stock (the "Common Stock") on the New York Stock Exchange composite tape where the Common Stock trades under the symbol PPP. The Common Stock is also listed on the Pacific Exchange under the same symbol.

			High
2002
	1st Quarter	$	23.00	$	31.75
	2nd Quarter	$	29.44	$	35.49
	3rd Quarter	$	25.44	$	34.71
	4th Quarter	$	31.90	$	39.28
2003
	1st Quarter	$	34.29	$	39.98
	2nd Quarter	$	38.68	$	45.41
	3rd Quarter	$	40.30	$	46.42
	4th Quarter	$	41.63	$	49.50

As of February 13, 2004, there were 2,125 holders of record of the Company's Common Stock.

In 2002, the Company paid four quarterly dividends of $0.03 per share on its Common Stock. On January 21, 2003, the Company increased its dividend 67% and during 2003 the Company paid four quarterly dividends of $0.05 per share on its Common Stock. The declaration and payment of future dividends, and the amount of such dividends, will depend upon, among other things, the Company's future earnings and financial condition, liquidity and capital requirements, the general economic and regulatory climate and other factors deemed relevant by the Company's Board of Directors.

The Company's revolving credit facility with its banks under which the Company has borrowed funds, and the Indentures relating to the Company's 10³/8% Senior Subordinated Notes due 2009 (the "2009 Notes") and 8¹/4% Senior Subordinated Notes due 2011 (the "2011 Notes") contain covenants that may restrict the ability of the Company to pay future dividends on the Company's Common Stock. The Company does not currently believe that any of these agreements will restrict the Company's ability to pay dividends on its Common Stock in the reasonably foreseeable future.

No equity securities of the Company not registered under the Securities Act of 1933 were sold by the Company during the year ended December 31, 2003.

During the year ended December 31, 2003, no equity securities of the Company registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of the Company or any "affiliated purchaser" of the Company, as defined in Rule 10b-18(a)(3) under the Securities Exchange Act.

In the following table, the Company's financial, production and other data for 2003, 2002 and 2001 reflect the Company's acquisition of North Central from and on March 14, 2001. The selected financial data should be read in conjunction with "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations" and the audited consolidated financial statements and notes thereto included under "Item 8—Financial Statements and Supplementary Data."

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Statements in the following discussion may be forward-looking and involve risks and uncertainties. The Company's financial results are most directly affected by changing prices for its production. Changing prices can influence not only current results of operations but the determination of the Company's proved reserves and available sources of financing, including the determination of the borrowing base under its bank credit facility. The Company's results depend not only on hydrocarbon prices generally, but on its ability to market its production on favorable terms in the areas in which it is produced, including foreign areas such as Thailand where the Company's operations may be subject to local constraints on demand, currency restrictions, exchange rate fluctuations, the possibility of increases in taxes or other charges and non-renewal or other adverse action relating to concessions or contracts, and other political risks. On a

longer term basis, the Company's financial condition and results of operations are affected by its ability to replace reserves as they are produced through successful exploration, development and acquisition activities. The Company's results could also be adversely affected by adverse regulatory developments and operational risks associated with oil and gas operations. Some of the other risks and uncertainties that may affect the Company's results are mentioned in the discussion that follows.

On March 14, 2001, the merger of the Company and NORIC Corporation ("NORIC") was consummated. As a result of the merger, the Company acquired all of the outstanding capital stock of North Central Oil Corporation ("North Central"), an independent domestic oil and gas exploration and production company, which was the principal asset of NORIC. The merger was accounted for using the purchase method of accounting. Commencing March 14, 2001, the results of North Central's operations are consolidated with the Company's.

The Company's objective is to cost effectively explore for, develop, acquire and produce oil and gas in select locations worldwide. In pursuit of that objective, the Company's goal for each year is to add more oil and gas reserves than it produces. 2003 marked the twelfth consecutive year of reserve replacement for the Company.

The Company pursues a balanced approach in core areas located in major oil and gas provinces in the United States and internationally. The Company follows a strict set of criteria when selecting areas of the world in which to explore. Areas selected are viewed as having proven oil and gas resources, having reasonable economic terms and possessing low political risk. Following these criteria, the Company operates internationally in several selected areas: Gulf of Thailand, Hungary, offshore New Zealand and in the Danish North Sea. The Company also seeks to maintain a balanced mixture of the gas/oil ratio of its reserves base.

Since January 2001, the Company has increased reserves and production by 81% and 108%, respectively. At the end of 2003, reserves topped 1,701 Bcfe and production for the year averaged more than 115,000 BOE per day, both exceeding previous Company records set in 2002. Oil and gas pricing and production volumes are important components of an exploration and development company's growth in net income and cash flow. In 2003, oil and gas pricing for the Company was strong, increasing 32% over 2002.

The Company made significant improvements to its balance sheet and financial leverage last year. Long-term debt (excluding debt discount) was $489 million at December 31, 2003, down from $725 million the previous year. Interest charges also were reduced from $57.5 million in 2002 to $46.4 million in 2003. The Company's debt to total capitalization ratio, an indicator of a company's financial strength, decreased to 25% from 40%. Cash and cash equivalents increased from $134 million to $179 million at year-end 2003. Company management believes being fiscally conservative is essential to position the Company for future growth.

Capital and exploration expenditures for 2003 were approximately $512 million. Exploration & development operations were allocated approximately $334 million, and approximately $178 million was spent on selective acquisitions in the Company's core areas of operations. The Company anticipates spending $415 million in 2004 (excluding property acquisitions), the largest exploration and development budget in the Company's history, and the Company will continue to pursue selective acquisitions.

The Company experienced strong drilling results during 2003. The Company drilled 248 wells during the year, with 232 wells successfully completed, a 94% success rate. During 2004, the Company anticipates drilling approximately 300 wells, another record number for the company.

2004 Production Outlook. A temporary shutdown of the Benchamas Field in the Gulf of Thailand to upgrade the Benchamas central processing platform, commenced in January 2004 and was completed in February 2004. Operations are currently underway to re-establish full production from all producing wells in the field. The shutdown is currently expected to reduce the Company's Gulf of Thailand crude oil and condensate and natural gas production for 2004 by approximately 2,500 barrels per day and 10 MMcf per day, respectively. This shutdown combined with normal production declines at the Company's Main Pass Blocks 61/62 Field, Mississippi Canyon Blocks 661/705 Field, and Ewing Banks Block 871 Field are currently expected to reduce the Company's overall equivalent hydrocarbon production by approximately 4-7% during 2004, compared to 2003, subject to changes in circumstances, acquisitions and many other factors.

The Company's oil and gas revenues for 2003 were $1,159,544,000, an increase of approximately 55% from oil and gas revenues of $750,401,000 for 2002, which were an increase of approximately 26% from oil and gas revenues of $596,077,000 for 2001. The following table reflects an analysis of variances in the Company's oil and gas revenues (expressed in thousands) between years:

			2003 Compared to 2002		2002 Compared to 2001
Increase (decrease) in oil and gas revenues resulting from variances in:
	Natural gas—
		Price	$	152,879	$	(71,612	)
		Production		28,749		43,428

				181,628		(28,184	)

	Crude oil and condensate—
		Price		72,984		9,866
		Production		146,581		160,677

				219,565		170,543

	Natural gas liquids ("NGL")			7,950		11,965

		Increase in oil and gas revenues	$	409,143	$	154,324

The increase in the Company's oil and gas revenues in 2003, compared to 2002, is related to increases in both the average price that the Company received for its hydrocarbon production volumes and an increase in the Company's natural gas and crude oil and condensate production volumes. The increase in the Company's oil and gas revenues in 2002, compared to 2001, is related to increases in the Company's hydrocarbon production volumes which were only partially offset by a decrease in the average price that the Company received for natural gas production volumes. The increase in oil and gas revenues for 2003, compared to 2002 and 2001, was also the result of an increase in the average price that the Company received for its NGL production volumes from $16.14 and $14.94 in 2001 and 2002, respectively, to $21.59 in 2003.

				2003		2002		% Change 2003 to 2002		2001		% Change 2002 to 2001
Comparison of Increases (Decreases) in:
Natural Gas
	Average prices
		North America(a)		$	5.17	$	3.15	64	%	$	4.25	(26	)%
		Kingdom of Thailand(b)		$	2.49	$	2.22	12	%	$	2.30	(3	)%
			Company-wide average price	$	4.39	$	2.89	52	%	$	3.71	(22	)%
	Average daily production volumes
		(MMcf per day):
		North America(a)			210.4		201.3	5	%		172.8	16	%
		Kingdom of Thailand			86.5		77.8	11	%		65.1	20	%

			Company-wide average daily production		296.9		279.1	6	%		237.9	17	%

Crude Oil and Condensate—
	Average prices(c)
		North America		$	29.08	$	24.95	17	%	$	24.60	1	%
		Kingdom of Thailand		$	29.14	$	24.80	18	%	$	23.38	6	%
			Company-wide average price	$	29.10	$	24.89	17	%	$	23.99	4	%
Average daily production volumes
		(Bbls per day):
		North America(c)			40,173		30,971	30	%		14,804	109	%
		Kingdom of Thailand(d)			21,948		16,389	34	%		14,786	11	%

			Company-wide average daily production		62,121		47,360	31	%		29,590	60	%

Total Liquid Hydrocarbons—
			Company-wide average daily production (Bbls per day)(d)		66,230		51,840	28	%		31,707	63	%

Thailand Prices. The Company has a long-term Gas Sales Agreement for its Kingdom of Thailand natural gas production. This agreement covered approximately 29% of the Company' 2003 natural gas production. The price that the Company receives under its Gas Sales Agreement with the Petroleum Authority of Thailand ("PTT") is based upon a formula that takes into account a number of factors including, among other items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore. The contract price is also subject to adjustments for quality. Effective October 2001, an amendment to the Gas Sales Agreement was negotiated with PTT in which PTT agreed to purchase supplemental gas volumes (currently up to 85 MMcf per day) over and above the base contractual amount (currently 145 MMcf per day). These supplemental gas volumes over and above the base contractual amounts are sold to PTT at a price equal to 88% of the then-current price calculated under the Gas Sales Agreement for the base contractual volumes. In 2003, the Gas Sales Agreement was further amended to extend the period during which supplemental gas volumes would be provided to PTT through December 31, 2007. The price for the supplemental gas volumes was not changed and remains 88% of the then-current price calculated under the Gas Sales Agreement as previously described. See "Business—International Operations; Contractual Terms Governing the Thailand Concession and Related Production."

Production. The increase in the Company's natural gas production during 2003, compared to 2002, was primarily related to increased production from the continuing success of the Company's exploration program at its Los Mogotes Field in South Texas, combined with the Company's continued development of its Gulf of Thailand concession and, to a lesser extent, an increase in the production capacity of the Lost Cabin Gas Plant located on the Company's Madden Field in Wyoming. These production gains were partially offset by natural production declines at other properties. The increase in the Company's natural gas production during 2002, compared to 2001, was primarily related to production from properties acquired in the North Central acquisition, successful development programs on the Company's Gulf of Mexico properties, including its Mississippi Canyon Blocks 661/705 Field, and increased Thailand production sold under the amendment to the Gas Sales Agreement, partially offset by natural production declines at other properties and weather-related shutdowns in the Gulf of Mexico.

Thailand Prices. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, typically as a differential to Malaysian TAPIS crude, and are denominated in U.S. dollars. As discussed further under "Costs and Expenses, Lease Operating Expenses," the Company records all crude oil held in the FPSO and the FSO at the end of an accounting period as inventory held at cost. When such crude oil is sold, usually during the following month, the cost of the crude oil and the sales revenue are recognized in the income statement.

Production. The increase in the Company's crude oil and condensate production during 2003, compared to 2002, resulted primarily from the continued success of development programs at the Company's Main Pass Blocks 61/62 Field in the Gulf of Mexico and its Gulf of Thailand concession, partially offset by natural production declines at certain other properties. The increase in the Company's crude oil and condensate production during 2002, compared to 2001, resulted primarily from the success of the Company's development program in the Benchamas Field in the Kingdom of Thailand, the commencement of production from the Company's Main Pass Blocks 61/62 Field, its Mississippi Canyon Blocks 661/705 Field and its Ewing Bank Block 871 Field and, to a lesser extent, increased crude oil and condensate production in the Kingdom of Thailand associated with the increased natural gas production permitted by the amendment to the gas sales contract. These increases were partially offset by natural production declines at certain other properties and weather-related shut downs in the Gulf of Mexico.

In accordance with generally accepted accounting principles, the Company records its oil production at the time of sale, rather than when produced. At the end of each quarter, the crude oil and condensate

stored on board the FSO and FPSO pending sale is accounted for as inventory at cost. Reported revenues are based on sales volumes. When a tanker load of oil is sold in Thailand, the entire amount is accounted for as production sold, regardless of when it was produced. As of December 31, 2003, the Company had approximately 495,000 net barrels stored on board the FPSO and FSO.

NGL Production. The Company's oil and gas revenues, and its total liquid hydrocarbon production, reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for 2003, compared with 2002, related to an increase in the average price that the Company received for its NGL production to $21.59 in 2003 from $14.94 in 2002, partially offset by a slight decline in NGL production volumes. The increase in NGL revenues from 2002, compared to 2001, primarily related to NGL removed from the Company's Mississippi Canyon Blocks 661/705 Field gas production. This increase was partially offset by a decline in the average price that the Company received for its NGL production during the comparative periods, from $16.12 in 2001 to $14.94 in 2002.

		2003		2002		% Change 2003 to 2002		2001		% Change 2002 to 2001
Comparison of Increases (Decreases) in:
Lease Operating Expenses
	North America		$	81,731,000		$	74,416,000		10	%	$	55,700,000		34	%
	Kingdom of Thailand		$	41,367,000		$	38,247,000		8	%	$	36,993,000		3	%

		Total Lease Operating Expenses		$	123,098,000		$	112,663,000		9	%	$	92,693,000		22	%

General and Administrative Expenses		$	61,291,000		$	49,490,000		24	%	$	39,162,000		26	%
Exploration Expenses		$	7,547,000		$	4,783,000		58	%	$	23,373,000		(80	)%
Dry Hole and Impairment Expenses		$	35,102,000		$	26,999,000		30	%	$	26,945,000		0	%
Depreciation, Depletion and Amortization (DD&A) Expenses		$	325,820,000		$	287,809,000		13	%	$	206,609,000		39	%
	DD&A rate		$	1.29		$	1.33		(3	)%	$	1.32		1	%
	Mcfe sold			253,422,703			215,728,000		17	%		156,780,000		38	%
Production and Other Taxes		$	35,485,000		$	20,058,000		77	%	$	22,007,000		(9	)%
Transportation and Other		$	25,924,000		$	12,879,000		101	%	$	19,447,000		(34	)%
Interest—
	Charges		$	(46,360,000	)	$	(57,450,000	)	(19	)%	$	(56,259,000	)	2	%
	Capitalized Interest Expense		$	16,531,000		$	24,033,000		(31	)%	$	33,242,000		(28	)%
Loss on debt extinguishment		$	(5,893,000	)	$	—		N/M		$	—		N/M
Minority Interest—Dividends and Costs		$	—		$	(4,140,000	)	N/M		$	(9,999,000	)	(59	)%
Income Tax Expense		$	(220,122,000	)	$	(97,780,000	)	125	%	$	(61,613,000	)	59	%

The increase in North American lease operating expenses for 2003, compared to 2002, is due to higher production from the Company's onshore properties and additional Gulf of Mexico platforms added during 2002 and the resulting increase in operating expenses as additional wells were subsequently brought on

production and, to a lesser extent, increased expenses at the Lost Cabin gas plant in the Madden Unit, which was expanded in late 2002. The increase in North American lease operating expenses for 2002, compared to 2001, is related to higher production from the Company's Gulf of Mexico properties, and to a lesser extent, increased maintenance costs during 2002. As a result of the increased production from its Gulf of Mexico properties, the Company also incurred increased rental expenses for compressors and other equipment during 2002. In addition to the above factors, the increased lease operating expenses associated with properties acquired in the acquisition of North Central (completed on March 14, 2001) also impacted the comparison of 2002 to 2001.

The increase in lease operating expenses in the Kingdom of Thailand for 2003, compared to 2002, primarily related to costs associated with operating the five additional platforms which were added to the Gulf of Thailand primarily during the second half of 2002 and the resulting increase in operating expenses as additional wells were subsequently brought on production. The Company added three new platforms during 2003 and expects to add five new platforms in 2004. The increase in lease operating expenses in the Kingdom of Thailand for 2002, compared to 2001, primarily related to an increase in insurance expenses related to the construction of platforms and processing facilities for the Benchamas field. In accordance with generally accepted accounting principles, the portion of lifting costs that is attributable to crude oil and condensate stored on the FPSO and FSO is treated as an inventoried cost until that crude oil and condensate is sold. At the time the crude oil and condensate is sold, those inventoried lifting costs are recognized as lease operating expenses. Variances in production, sales and operating costs will result in variances in the amount of lease operating expense that is currently recognized as expense and the amount recorded as product inventory to be recognized in subsequent periods. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand relates to the lease payments made in connection with the bareboat charter of the FPSO for the Tantawan field and the FSO for the Benchamas field. Collectively, these lease payments accounted for approximately $14,500,000 (net to the Company's interest) of the Company's Thailand lease operating expenses for 2003, 2002 and 2001. The Company currently expects these lease payments to remain relatively constant at approximately $14,500,000 (net to the Company's interest) for the next three years. See "Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term Commitments."

Notwithstanding the overall increase in lease operating expenses, on a per unit of production basis, the Company's total lease operating expenses have continued to decrease from an average of $0.59 per Mcfe for 2001 and $0.52 per Mcfe for 2002 to $0.49 per Mcfe for 2003.

The increase in general and administrative expenses for 2003, compared with 2002, primarily related to higher benefit expenses, increases in professional fees, costs related to the start of operations in the Company's Budapest office, increased insurance costs and expenses related to the Company's decision, effective January 1, 2003, to expense stock-based compensation. The increase in general and administrative expenses for 2002, compared with 2001, primarily related to increased expenses associated with the Company's acquisition of North Central and its employees, as well as other increases in the size of the Company's work force, normal increases in compensation and concomitant benefit expense and, to a lesser extent, increases in map purchases, office rent, insurance costs and audit fees. On a per unit of production basis, the Company's general and administrative expenses were $0.24 per Mcfe in 2003, $0.23 per Mcfe in 2002 and $0.25 per Mcfe in 2001.

Exploration expenses consist primarily of rental payments required under oil and gas leases to hold non-producing properties ("delay rentals") and exploratory geological and geophysical costs that are expensed as incurred. The increase in exploration expenses for 2003, compared to 2002, resulted primarily from increased 3-D seismic acquisition activities in the Gulf of Mexico and seismic operations in the

Company's Western division. The decrease in exploration expenses for 2002, compared to 2001, resulted primarily from a decrease in 3-D seismic acquisition activities during 2002. The 2001 expense includes the cost of conducting 3-D surveys in Hungary, the cost of acquiring substantial new speculative 3-D data sets in the Gulf of Mexico and seismic operations in Canada. The 2001 expense also includes the cost of transferring certain seismic licenses in connection with the North Central acquisition. There were no expenses comparable to these incurred in 2002.

Dry hole and impairment expenses relate to costs of unsuccessful exploratory wells drilled and impairment of oil and gas properties. During 2003 the Company drilled 6 gross unsuccessful exploratory wells (4.46 net to the Company's interest), in 2002 the Company drilled 6 unsuccessful exploratory wells (5.17 net to the Company's interest) and in 2001 the Company drilled 6 unsuccessful exploratory wells (3.06 net to the Company's interest). The Company has had overall drilling success rates of 94% in 2003, 92% in 2002 and 93% in 2001. The Company had approximately $9,511,000 of exploratory wells in progress or temporarily abandoned pending evaluation, located primarily in Hungary, at December 31, 2003.

Generally accepted accounting principles require that if the expected future cash flow of the Company's reserves on a property fall below the cost that is recorded on the Company's books, these costs must be impaired and written down to the property's fair value. Depending on market conditions, including the prices for oil and natural gas, and the results of operations, a similar test may be conducted at any time to determine whether impairments are appropriate. Depending on the results of this test, an impairment could be required on some of the Company's proved properties and this impairment could have a material negative non-cash impact on the Company's earnings and balance sheet. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. As a result of these reviews, the Company recognized impairments to oil and gas properties of approximately $10,542,000 during 2003, approximately $6,191,000 during 2002 and $9,991,000 during 2001.

The Company's provision for DD&A expense is based on its capitalized costs and is determined on a cost center by cost center basis using the units of production method. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its onshore oil and gas activities.

The increase in the Company's DD&A expense for 2003, compared to 2002, resulted primarily from an increase in the Company's natural gas and liquid hydrocarbon production, partially offset by a decrease in the Company's composite DD&A rate. The decrease in the composite DD&A rate for all of the Company's producing fields for 2003, compared to 2002, resulted primarily from an increased percentage of the Company's production coming from fields that have DD&A rates lower than the Company's recent historical composite rate (principally certain Gulf of Mexico properties and the Benchamas Field) and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates higher than the Company's recent historical composite DD&A rate.

The increase in the Company's DD&A expense for 2002, compared to 2001, resulted primarily from an increase in the Company's natural gas and liquid hydrocarbon production and, to a lesser extent, an increase in the Company's composite DD&A rate. The increase in the composite DD&A rate for all of the Company's producing fields for 2002, compared to 2001, resulted primarily from having a full year's production from fields acquired in the North Central acquisition that, because they were valued at fair market value in connection with the acquisition, contribute a DD&A rate higher than the Company's historic average. The increase was partially offset by an increased percentage of the Company's production coming from certain of the Company's fields that have DD&A rates lower than the Company's recent historical composite rate (principally the Benchamas Field and certain Gulf of Mexico properties) and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates higher than the Company's recent historical composite DD&A rate.

The increase in production and other taxes for 2003, compared to 2002, relates to the recognition during 2003 of $11,750,000 of the Special Remunitory Benefit ("SRB") obligation incurred on the Company's Kingdom of Thailand concession. No comparable SRB expenses were incurred in 2002 or 2001. SRB is a payment to the Thai government required by the Company's concession agreement after certain specified revenue, expenditure and drilling criteria have been achieved. It is currently anticipated that the Company will continue to pay SRB for the foreseeable future. The amount of SRB to be incurred in 2004 is not currently determinable, as it will be computed using a complex formula that includes various factors such as revenues, expenditures and meters drilled on the Thailand concession during the year. See "Business—International Operations; Contractual Terms Governing the Thailand Concession and Related Production." The increase is also related to increased severance taxes due to higher domestic onshore production volumes and prices. The decrease in production and other taxes for 2002, compared to 2001, primarily relates to decreased severance taxes due to lower prices received for the Company's domestic onshore production.

Transportation and other expense includes the Company's cost to move its products to market (transportation costs), accretion expense related to Company asset retirement obligation under a new accounting pronouncement adopted on January 1, 2003, natural gas purchase costs, pipeline operating costs, tubular inventory valuation write-offs and allowances, and various other operating expenses, none of which represents more than 5% of this expense category. The increase in transportation and other expense for 2003, compared to 2002, relates primarily to the inclusion of $4,972,000 of expense related to the accretion of the Company's asset retirement obligation and a $2,407,000 write down of the cost of the Company's tubular inventory stock, for which no comparable expenses were incurred in 2002. The Company incurred transportation expense of $12,980,000 in 2003 and $10,140,000 in 2002. The increase in transportation costs in 2003, compared to 2002, is due to the Company's higher hydrocarbon production volumes discussed above.

The decrease in transportation and other expense for 2002, compared to 2001, relates primarily to a decrease in the Company's pipeline operating costs and a reduction in the volume of natural gas purchased by the Company. During 2001, primarily all of the natural gas purchased and resold by the Company was transported on Pogo Onshore Pipeline Company's Saginaw pipeline, which was sold during the fourth quarter of 2001 as part of the Company's ongoing asset rationalization process. No material pipeline operating expenses were incurred by the Company subsequent to this sale. During 2002, substantially all of the natural gas purchased by the Company was the result of purchases of natural gas volumes required to replace the reduction in heating content of the gas stream after the extraction of NGLs. These purchases were made to bring the gas stream to pipeline quality standards. During 2003 and 2001, the Company used its own natural gas production to replenish this extracted gas and therefore was not required to purchase

natural gas from outside sources. The Company incurred transportation expense of $10,140,000 in 2002 and $3,457,000 in 2001. The increase in transportation costs in 2002, compared to 2001, is due to the commencement of production on certain of the Company's more significant Gulf of Mexico properties, primarily the Company's Mississippi Canyon Block 661/705 as discussed above.

Interest Charges. The decrease in the Company's interest charges for 2003, compared to 2002, resulted primarily from a decrease of approximately $236 million in the Company's outstanding debt during the year, partially offset by an increase in the average interest rate on the debt that remained outstanding. The increase in the Company's interest charges for 2002, compared to 2001, resulted primarily from an increase in the average amount of the Company's outstanding debt (largely related to the acquisition of North Central in March 2001), partially offset by a decline in the average interest rate on the outstanding debt.

Capitalized Interest. Interest costs related to financing major oil and gas projects in progress are required to be capitalized until the projects are substantially complete and ready for their intended use if projects are evaluated as successful. The decrease in capitalized interest for 2003, compared to 2002, and for 2002, compared to 2001, resulted primarily from a decrease in the amount of capital expenditures subject to interest capitalization during 2003 (approximately $192,000,000), compared to 2002 (approximately $346,000,000), and a decrease in the amount of capital expenditures subject to interest capitalization during 2002 compared to 2001 (approximately $365,000,000). These decreases were also impacted by changes in the weighted average rate on borrowings incurred by the Company (discussed above under "Results of Operations—Interest Charges") and applied to such capital expenditures to arrive at the total amount of capitalized interest. A substantial percentage of the Company's capitalized interest related to unevaluated properties acquired in the North Central acquisition and capital expenditures for the development of the Benchamas Field in the Gulf of Thailand, as well as several development projects in the Gulf of Mexico. Several of these projects were placed in service during 2003.

The loss on debt extinguishment for 2003 is related to redemption premiums paid and unamortized debt issuance costs which were expensed due to the redemption of the 2006 Notes and 2007 Notes. No comparable costs were incurred in either 2002 or 2001.

Pogo Trust I, a business trust in which the Company owned all of the issued common securities, issued $150,000,000 of Trust Preferred Securities on June 2, 1999. Pogo Trust I called the Trust Preferred Securities for redemption on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities converted their Trust Preferred Securities, representing over $149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares of the Company's common stock. In connection with the redemption, Pogo Trust I paid a total of $147,000 to former holders of the Trust Preferred Securities. Subsequent to June 3, 2002, there were no Trust Preferred Securities outstanding. The amounts recorded under Minority Interest—Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities.

Changes in the Company's income tax expense are a function of the Company's consolidated effective tax rate and its pre-tax income. The increase in the Company's tax expense for 2003, compared to 2002,

resulted primarily from increased pre-tax income derived from both the Company's U.S. and Thailand operations in 2003, partially offset by a decrease in the Company's effective tax rate during the comparative periods. The increase in the Company's tax expense for 2002, compared to 2001, resulted primarily from an increase in the Company's effective tax rate during the comparative periods and from increased pre-tax income during 2002. The Company's consolidated effective tax rate for 2003, 2002 and 2001 was 43%, 48% and 41%, respectively. The lower effective tax rates during the 2003 and 2001 periods, compared to 2002, are the result of higher pre-tax income derived from the Company's North American operations during the comparative periods, relative to its pre-tax income from its Thailand operations which are taxed at a rate higher than the U.S. statutory rate. Management currently expects that foreign income taxes will constitute a substantial portion of its overall tax burden for the foreseeable future.

The Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," ("SFAS 143"), as of January 1, 2003. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, the Company recorded an after-tax charge to recognize the cumulative effect of a change in accounting principle of $4,166,000. This charge was required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, and also to increase the carrying amount of the associated long-lived asset and its accumulated depreciation.

The Company's primary needs for cash are for exploration, development, acquisition and production of oil and gas properties, repayment of principal and interest on outstanding debt and payment of income taxes. The Company funds its exploration and development activities primarily through internally generated cash flows and budgets capital expenditures based on projected cash flows. The Company adjusts capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition results, and cash flow. The Company has historically utilized net cash provided by operating activities, available cash, debt, and equity as capital resources to obtain necessary funding for all other cash needs.

The Company's cash flow provided by operating activities for 2003 was $744,559,000. This compares to cash flow from operating activities of $466,479,000 in 2002 and $368,076,000 in 2001. The resulting increases are attributable to the reasons described under "Results of Operations" above. Cash flow from operating activities in 2003 was more than adequate to fund $524,698,000 in cash expenditures for capital and exploration projects for the year. The Company also repaid approximately $197,566,000 of cash (net of borrowings) to settle debt obligations (including the redemptions discussed below) and paid $12,520,000 of dividends on the Company's common stock during 2003. As of December 31, 2003, the Company had cash and cash equivalents of $178,754,000 (including $170,092,000 in international subsidiaries which the Company intends to reinvest in its foreign operations) and long-term debt obligations of $489,000,000 (excluding debt discount of $1,739,000) with no repayment obligations until 2006. On July 7, 2003, the Company satisfied all $115,000,000 of its outstanding 5¹/2% Convertible Subordinated Notes due 2006 for 1,008,299 shares of common stock and $73,661,000 in cash. On August 6, 2003, the Company redeemed all $100,000,000 of its 8³/4% Senior Subordinated Notes due 2007 for $102,917,000 in cash. The Company, at its option, may redeem the 10³/8% Senior Subordinated Notes due 2009, in whole or in part, at any time on or after February 15, 2004, at a redemption price of 105.188% of their principal value. The Company may elect to repurchase the 2009 Notes through market transactions, privately negotiated transactions or otherwise, depending on market conditions, liquidity requirements, contractual restrictions and other factors.

Effective October 30, 2003, the Company's lenders redetermined the borrowing base under its Credit Agreement at $800,000,000. The available borrowing capacity under the Credit Agreement is currently $515,000,000. As of February 18, 2003, the Company had an outstanding balance of $122,000,000 under its Credit Agreement See "Capital Structure—Credit Facility".

The Company's capital and exploration budget for 2004, which does not include any amounts that may be expended for acquisitions or any interest which may be capitalized resulting from projects in progress, was established by the Company's Board of Directors at $415,000,000. The Company has included 300 gross wells in its 2004 capital and exploration budget, including wells to be drilled in the United States, the Kingdom of Thailand, Hungary and Denmark. The Company currently anticipates that its available cash and cash investments, cash provided by operating activities and funds available under its Credit Agreement will be sufficient to fund the Company's ongoing operating, interest and general and administrative expenses, its authorized capital budget, and dividend payments at current levels for the foreseeable future. The declaration and amount of future dividends on the Company's common stock will depend upon, among other things, the Company's future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends and other payments under covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company's Board of Directors.

Contractual Obligations. The Company's material contractual obligations include long-term debt, operating leases, and other contracts. Material contractual obligations for which the ultimate settlement amounts are not fixed and determinable include derivative contracts that are sensitive to future changes in commodity prices and other factors. See "Item 3. Quantitative and Qualitative Disclosure about Market Risk."

A summary of the Company's known contractual obligations as of December 31, 2003 are set forth on the following table:

		Payments due by period (in millions)
		Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Long Term Debt		$	489.0	$	0.0	$	139.0	$	0.0	$	350.0
Operating Leases(a)		$	144.3	$	22.3	$	43.9	$	34.1	$	44.0
Purchase Obligations(b)		$	64.9	$	19.0	$	25.9	$	8.6	$	11.4
Asset Retirement Obligations (c)		$	236.4	$	1.7	$	7.5	$	14.7	$	212.5

	Total	$	934.6	$	43.0	$	216.3	$	57.4	$	617.9

Commitments under Joint Operating Agreements. The oil and gas industry operates in many instances through joint ventures under joint operating agreements, and the Company's operations are no exception. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a "working interest" basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. The contractual obligations set forth above represent the Company's working interest share of the contractual commitments that it has entered into as operator and, to the extent that it is aware, the contractual commitments entered into by the operator of projects that the Company does not operate.

Surety Bonds. In the ordinary course of the Company's business and operations, it is required to post surety bonds from time to time with third parties, including governmental agencies, primarily to cover self insurance, site restoration, equipment dismantlement, plugging and abandonment obligations. As of December 31, 2003, the Company had obtained surety bonds from a number of insurance and bonding institutions covering certain operations in the United States in the aggregate amount of approximately $10,000,000 that are not included in the prior table. In connection with their administration of offshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee's plugging and abandonment liabilities. The MMS reviews this information and applies certain financial tests including, but not limited to, current asset and net worth tests. The MMS determines whether each lessee is financially capable of paying the estimated costs of such plugging and abandonment liabilities. The Company must annually provide the MMS with financial information. If the Company does not satisfy the MMS requirements, it could be required to post supplemental bonds. In the past, the Company has not been required to post supplemental bonds; however, there can be no assurance that the Company will satisfy the financial tests and remain on the list of MMS lessees exempt from the supplemental bonding requirements. The Company cannot predict or quantify the amount of any such supplemental bonds or the annual premiums related thereto and therefore has not included them in the prior table, but the amount could be substantial.

Guarantees and Letters of Credit. The Company has also issued performance guarantees related to the operations of its subsidiaries in Thailand, Hungary and Denmark. If its subsidiaries do not fulfill their contractual obligations or legal obligations under the relevant local laws, the Company could be obligated to make payments to satisfy the subsidiaries' obligations. Most of these obligations relate to plugging, abandonment, site restoration and compliance with environmental laws. The Company also has guaranteed performance of its subsidiaries' obligations under the FPSO lease. However, the Company's guarantee of these obligations has not been so included. Currently, there are no material letters of credit that have been issued on the Company's behalf.

Credit Facility. The Company has a revolving credit facility (the "Credit Facility") that provides for a $515,000,000 revolving loan facility terminating on March 7, 2006. The amount that may be borrowed under the Credit Facility may not exceed a borrowing base that is determined no less than semi-annually and is calculated based upon substantially all of the Company's proved oil and gas properties. The borrowing base is currently set at $800,000,000. The next redetermination of the borrowing base is expected to occur by May 1, 2004. The borrowing base is determined by the lenders based on their own proprietary credit criteria, which appear to be strongly correlated to the quantity of the Company's proven oil and gas reserves and the lenders' expectations as to the future revenues that the Company can expect to

receive from the sale of these oil and gas reserves. A significant decline in the prices that the Company is expected to receive for its future oil and gas production could have a material negative impact on the borrowing base under the Credit Facility which, in turn, could have a material negative impact on the Company's liquidity. If at a redetermination of the borrowing base, the lenders reduce the borrowing base below the amount then outstanding under the Credit Agreement and other senior debt arrangements, the Company must repay the excess to the lenders in no more than five substantially equal monthly installments, commencing not later than 90 days after the Company is notified of the new borrowing base. The Credit Facility also permits short-term "swing line" loans and the issuance of up to $50,000,000 in letters of credit as a part of the facility. Borrowings under the Credit Facility bear interest, at the Company's option, at a base (prime) rate plus a variable margin (currently none) or LIBOR plus a variable margin (currently 1.125%). The margin varies as a function of the percentage of the borrowing base being utilized and, with respect to the LIBOR rate loans, the Company's credit rating. A commitment fee on the unborrowed amount that is currently available under the Credit Facility is also charged based upon the percentage of the borrowing base that is being utilized. As of February 18, 2004, there was $122,000,000 outstanding under the Credit Facility.

The discussion and analysis of the Company's financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements included in this Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas revenues, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, on a periodic basis and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company's financial statements:

The Company accounts for its oil and gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. In most cases, a gain or loss is recognized for sales of producing properties.

The application of the successful efforts method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of

costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs requires management's judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company enters a new exploratory area in hopes of finding oil and gas reserves. The initial exploratory wells may be unsuccessful and the associated costs will be expensed as dry hole costs. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

The Company's estimates of oil and gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company's oil and gas properties and/or the rate of depletion of such oil and gas properties. Actual production, revenues and expenditures with respect to the Company's reserves will likely vary from estimates, and such variances may be material.

The Company reviews its proved oil and gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company estimates the expected future cash flows from its proved oil and gas properties and compares these future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company has recognized significant impairment expense due to poor reservoir performance at one of its Gulf of Mexico properties in the first quarter of 2001, and has recognized other less significant impairment expenses related to other properties in subsequent periods. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require the Company to record an impairment of its oil and gas properties and there can be no assurance that such impairments will not be required in the future.

The estimated fair values of the Company's derivative instruments are recorded on the Company's consolidated balance sheet. Historically, substantially all of the Company's derivative instruments have represented cash flow hedges of the price of future oil and natural gas production. Therefore, while fair values of such hedging instruments must be estimated at the end of each reporting period, the related changes in such fair values are not included in the Company's consolidated results of operations, to the extent they are expected to offset the future cash flows from oil and natural gas production. Instead, the changes in fair value of hedging instruments are recorded directly to shareholders' equity until the hedged oil or natural gas quantities are produced.

The estimation of fair values for the Company's hedging derivatives requires substantial judgment. The Company estimates the fair values of its derivatives on a monthly basis using an option-pricing model. To utilize the option-pricing model, the Company uses various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The estimated future prices are compared to the prices fixed by the hedge agreements, and the resulting estimated future cash inflows (outflows) over the lives of the hedges are discounted using the Company's current borrowing rates under its revolving credit facility. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates. Historically, the majority of the Company's derivative instruments have been hedges of the price of crude oil and natural gas production. The Company is not involved in any derivative trading activities.

In 2001, the Company grew substantially through the acquisition of North Central. As stated earlier, this acquisition was accounted for using the purchase method of accounting, and current accounting pronouncements require that all future acquisitions be accounted for using the purchase method.

Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company's assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. As of January 1, 2002, the accounting for goodwill changed. In prior years, goodwill was amortized. Effective January 1, 2002, goodwill and other intangibles with an indefinite useful life are no longer amortized, but instead are assessed for impairment

at least annually. The Company has never recorded any goodwill in connection with its business combinations/acquisitions. However, there can be no assurance that the Company will not do so in the future.

There are various assumptions made by the Company in determining the fair values of an acquired company's assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, the Company prepares estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by the Company's engineers and outside petroleum reservoir consultants. The judgments associated with the estimation of reserves are described earlier in this section. The fair value of the estimated reserves acquired in a business combination is then calculated based on the Company's estimates of future oil, natural gas and NGL prices. The Company's estimates of future prices are based on its own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics, such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity and trends in regional pricing differentials. Future price forecasts from independent third parties are also taken into account in arriving at the Company's own pricing estimates. The Company's estimates of future prices are applied to the estimated reserve quantities acquired to arrive at estimated future net revenues. For estimated proved reserves, the future net revenues are then discounted to derive a fair value for such reserves. The Company also applies these same general principles in arriving at the fair value of unproved reserves acquired in a business combination. These unproved reserves are generally classified as either probable or possible reserves. Because of their very nature, probable and possible reserve estimates are less precise than those of proved reserves. Generally, in the Company's business combinations, the determination of the fair values of oil and gas properties requires more judgment than the estimates of fair values for other acquired assets and liabilities.

Future development costs include costs incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, FPSOs, FSOs, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. The Company reviews its assumptions and estimates of future abandonment costs on an annual basis. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of SFAS 143. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Accounting for pensions and other postretirement benefits involves several assumptions including the expected rates of return on plan assets, determination of discount rates for remeasuring plan obligations, determination of inflation rates regarding compensation levels and health care cost projections. The Company develops its demographics and utilizes the work of actuaries to assist with the measurement of employee-related obligations. The assumptions used vary from year-to-year, which will affect future results

of operations. Any differences among these assumptions and the results actually experienced will also impact future results of operations.

For financial reporting purposes, the Company generally provides taxes at the rate applicable for the appropriate tax jurisdiction. Where the Company's present intention is to reinvest the unremitted earnings in its foreign operations, the Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries. Management periodically assesses the need to utilize these unremitted earnings to finance the foreign operations of the Company. This assessment is based on cash flow projections that are the result of estimates of future production, commodity pricing and expenditures by tax jurisdiction for the Company's operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future.

Management also periodically assesses, by tax jurisdiction, the probability of recovery of recorded deferred tax assets based on its assessment of future earnings outlooks. Such estimates are inherently imprecise since many assumptions utilized in the assessments are subject to revision in the future.

Inflation. Publicly held companies are asked to comment on the effects of inflation on their business. Currently annual inflation in terms of the decrease in the general purchasing power of the dollar is running well below the general annual inflation rates experienced in the past. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the dollar due to inflation, such effect is not currently considered significant.

Southeast Asia Economic Issues. A substantial portion of the Company's oil and gas operations are conducted in Southeast Asia, and a substantial portion of its natural gas and liquid hydrocarbon production is sold there. As with most emerging market economies, the Thai economy is particularly sensitive to worldwide economic trends. The economic health of the Thai economy and its effect on the volatility of the Thai Baht against the dollar will continue to have a material impact on the Company's operations in the Kingdom of Thailand, together with the prices that the Company receives for its oil and natural gas production there. See "Results of Operations; Oil and Gas Revenues".

All of the Company's current natural gas production from the Thailand Concession is committed under a long-term Gas Sales Agreement, in each case to PTT at prices denominated in Thai Baht which are determined in accordance with a formula that is intended to ameliorate, at least in part, any decline in the purchasing power of the Thai Baht against the dollar. See "Business International Operations; Contractual Terms Governing the Thailand Concession" and "Business Miscellaneous; Sales." Although the Company currently believes that PTT will honor its commitments under the Gas Sales Agreement, a failure by PTT to honor such commitments could have a material adverse effect on the Company. During 2001, the government of Thailand partially privatized the Petroleum Authority of Thailand, forming PTT and retaining an ownership interest of approximately 70%. PTT is a publicly traded entity that currently constitutes one of the largest public companies in the Kingdom of Thailand. However, its contractual obligations are no longer backed by the full faith and credit of the Thai government.

The Company's crude oil and condensate production from the Thailand Concession is currently sold on a tanker load by tanker load basis. Prices that the Company receives for such production are based on world benchmark prices, which are denominated in dollars, and are typically paid in dollars. See "Business—International Operations; Contractual Terms Governing the Thailand Concession and Related Production" and "Business—Miscellaneous; Sales."

The Financial Accounting Standards Board ("FASB") has issued several new pronouncements, including Interpretation No. 46 (revised December 2003) ("FIN 46R"), "Consolidation of Variable Interest Entities, an interpretation of ARB 51", Statement of Financial Accounting Standards No. 149 ("SFAS 149"), "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and Statement of Financial Accounting Standards No. 150 ("SFAS 150"), "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity".

FIN 46R. The primary objectives of FIN 46R are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (these entities are referred to as "variable interest entities" or "VIEs") and how to determine if a business enterprise should consolidate the VIEs. This new model for consolidation applies to an entity for which either:

In addition, FIN 46R requires that all enterprises with a significant variable interest in a VIE make additional disclosures regarding their relationship with the VIE. The interpretation requires public entities to apply FIN 46R to all entities that are considered SPEs in practice and under the FASB literature that was applied before the issuance of FIN 46R by the end of the first reporting period that ends after December 15, 2003. Application of the accounting requirements of the interpretation to all other entities is required by the end of the first reporting period that ends after March 15, 2004. The adoption of FIN 46R had no effect on the Company's financial statements.

SFAS 149. SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003 (with limited exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have a material effect on the Company's financial statements.

SFAS 150. SFAS 150 establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equity on a Company's balance sheet. SFAS 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) because that financial instrument embodies an obligation of the issuer. Many of those instruments were previously classified as equity. SFAS 150 was effective for financial instruments entered into after May 31, 2003. The adoption of SFAS 150 had no effect on the Company's financial statements.

Other. The Company has been made aware that an issue has arisen regarding the application of provisions of SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142") to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, "Disclosures about Oil and Gas Producing Activities" ("SFAS 69"). Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.

The Emerging Issues Task Force ("EITF") has recently decided to consider this issue. If the EITF determines that SFAS 142 requires the Company to reclassify costs associated with mineral rights from

property and equipment to intangible assets, the Company currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in the Company's required disclosures under SFAS 69.

At December 31, 2003, the Company had undeveloped leaseholds of approximately $74 million that would be classified on the balance sheet as "intangible undeveloped leaseholds" and developed leaseholds of approximately $1,131 million (net of accumulated depletion) that would be classified as "intangible developed leaseholds" if the Company applied the interpretation currently being discussed.

The Company is exposed to market risk, including adverse changes in commodity prices, interest rates and foreign currency exchange rates as discussed below.

The Company produces, purchases and sells natural gas, crude oil, condensate and NGLs. As a result, the Company's financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. In the past, the Company has made limited use of a variety of derivative financial instruments only for non-trading purposes as a hedging strategy to manage commodity prices associated with oil and gas sales and to reduce the impact of commodity price fluctuations. See "Business—Competition and Market Conditions."

From time to time, the Company has entered into various financial instruments, such as interest rate swaps, to manage the impact of changes in interest rates. As of February 18, 2004, the Company has no open interest rate swap or interest rate lock agreements. Therefore, the Company's exposure to changes in interest rates primarily results from its short-term and long-term debt with both fixed and floating interest rates. The following table presents principal or notional amounts (stated in thousands) and related average interest rates by year of maturity for the Company's debt obligations and their indicated fair market value at December 31, 2003:

In addition to the U.S. dollar, the Company and certain of its subsidiaries conduct their business in Thai Baht and Hungarian Forint and are therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. The Company conducts a substantial portion of its oil and gas production and sales in Southeast Asia. Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties in the recent past, including sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." The economic situation in Thailand and the volatility of the Thai Baht against the dollar could have a material impact on the Company's Thailand operations and prices that the Company receives for its natural gas

production there. Although the Company's sales to PTT under the Gas Sales Agreement are denominated in Baht, because predominantly all of the Company's crude oil sales and its capital and most other expenditures in the Kingdom of Thailand are denominated in U.S. dollars, the U.S. dollar is the functional currency for the Company's operations in the Kingdom of Thailand. As of February 18, 2004, the Company is not a party to any foreign currency exchange agreement.

Exposure from market rate fluctuations related to activities in Hungary, where the Company's functional currency is the U.S. dollar, is not material at this time.

From time to time, the Company has used and expects to continue to use hedging transactions with respect to a portion of its oil and gas production to achieve a more predictable cash flow, as well as to reduce its exposure to price fluctuations. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counter-parties will be unable to meet the financial terms of such transactions. All of the Company's recent historical hedging transactions have been carried out in the over-the-counter market with investment grade institutions. As of February 18, 2004, the Company was not a party to any commodity price contracts with respect to any of its current or future crude oil and condensate or natural gas production.

In our opinion, the accompanying consolidated balance sheets as of December 31, 2003 and 2002, and the related consolidated statements of income, shareholders' equity and cash flows present fairly, in all material respects, the financial position of Pogo Producing Company (the "Company") and its subsidiaries at December 31, 2003 and 2002 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. The financial statements of the Company for the year ended December 31, 2001, were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated February 28, 2002.

As discussed in Note 1 to the financial statements, the Company changed its method of accounting for employee stock-based compensation, effective January 1, 2003. As discussed in Note 11 to the financial statements, the Company changed its method of accounting for asset retirement costs, effective January 1, 2003.

THE FOLLOWING REPORT IS A COPY OF THE PREVIOUSLY ISSUED REPORT FROM ARTHUR ANDERSEN LLP (ANDERSEN). ANDERSEN DID NOT PERFORM ANY PROCEDURES IN CONNECTION WITH THIS ANNUAL REPORT ON FORM 10-K. ACCORDINGLY, THIS REPORT HAS NOT BEEN REISSUED BY ANDERSEN.

We have audited the accompanying consolidated balance sheets of Pogo Producing Company (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, cash flows and shareholders' equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pogo Producing Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

As explained in Note 1 to the financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities. In addition, effective January 1, 2000, the Company changed its method of accounting for product inventory.

The accompanying notes to consolidated financial statements are an integral part hereof.

POGO PRODUCING COMPANY & SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Expressed in thousands)

POGO PRODUCING COMPANY & SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pogo Producing Company was incorporated in 1970. Pogo Producing Company and its subsidiaries (the "Company") are engaged in oil and gas exploration, development, production and acquisition activities in the United States, both offshore in the Gulf of Mexico (primarily in federal waters offshore Louisiana and Texas) and onshore principally in the states of New Mexico, Texas, Louisiana and Wyoming. The Company also conducts exploration, development and production activities internationally in the Kingdom of Thailand (offshore in the Gulf of Thailand) and exploration activities in Hungary, New Zealand and the Danish sector of the North Sea.

The preparation of these financial statements requires the use of certain estimates by management in determining the Company's assets, liabilities, revenues and expenses. Actual results could differ from such estimates. Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Proved reserves of crude oil, condensate, natural gas and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions.

The consolidated financial statements include the accounts of Pogo Producing Company and its subsidiaries and affiliates, after elimination of all significant intercompany transactions. Majority owned subsidiaries are fully consolidated. Minority owned oil and gas affiliates are pro rata consolidated in the same manner as the Company accounts for its operating or working interest in oil and gas joint ventures.

The Company follows the "sales" (takes or cash) method of accounting for oil and gas revenues. Under this method, the Company recognizes revenues on production as it is taken and delivered to its purchasers. The volumes sold may be more or less than the volumes the Company is entitled to based on its ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. At December 31, 2003, the Company had taken approximately 1,030 MMcf of natural gas less than it was entitled to based on its interest in certain properties, and approximately 798 MMcf more than its entitlement on other properties, placing the Company in a net under-delivered position of approximately 232 MMcf of natural gas based on its working interest ownership in such properties. The Company's crude oil imbalances are not significant. Such imbalances are reflected as adjustments to proved reserves and future cash flows in the unaudited supplementary oil and gas data included herein.

Crude oil and condensate from the Company's producing fields located in the Kingdom of Thailand are produced into storage vessels and are sold and recognized as revenue periodically as economic quantities are accumulated. The product inventory at December 31, 2003 consists of approximately 495,452

barrels of crude oil and condensate, net to the Company's interest, and is carried at the Company's estimated average cost of $12.01 per barrel. The product inventory at December 31, 2002 consisted of approximately 202,397 barrels of crude oil and condensate, net to the Company's interest, and is carried at its estimated average cost of $12.35 per barrel.

Tubular inventories consist primarily of goods used in the Company's operations and are stated at the lower of average cost or market value.

The Company follows the successful efforts method of accounting for its oil and gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved oil and gas properties are reviewed annually or when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Estimated fair value includes the estimated present value of all reasonably expected future production, prices, and costs. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated as successful. Other exploratory costs are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above, and is computed on a cost center by cost center basis using the units of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its onshore oil and gas activities. As described further below, the Company's method of accounting for asset retirement obligations (i.e. future abandonment costs) changed effective January 1, 2003.

The Company has an ongoing asset rationalization process. In connection with this process, the Company has from time to time disposed of certain non-core properties and other assets that it considers to be under performing, to have little or no remaining upside potential, or which face significant future expenditures that would result in an unacceptable rate of return. Refer to the captions "Gains on sales" and "Proceeds from the sale of property and tubular stock" in the Consolidated Statements of Cash Flows.

Other properties and equipment are depreciated using a straight-line method in amounts which, in the opinion of management, are adequate to allocate the cost of the properties over their estimated useful lives.

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit the Company does not expect to be realized. Note 3 contains information about the Company's income taxes, including the components of income tax provision and the composition of deferred income tax assets and liabilities.

The Company from time to time enters into commodity price hedging contracts with respect to its oil and gas production to achieve a more predictable cash flow, as well as reduce its exposure to price volatility. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").

SFAS 133, as amended, established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Based on the nature of derivative instruments used by the Company and the historical volatility of oil and gas commodity prices, the Company expects that SFAS 133 could increase volatility in the Company's earnings and other comprehensive income for future periods during which derivative instruments are outstanding.

SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings

SFAS 133 requires that as of the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of these derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. Upon adoption, the Company determined that the cumulative effect of adopting SFAS 133 should be recorded in other comprehensive income. The Company adopted SFAS 133 effective January 1, 2001 and recorded an unrealized loss of $2,438,000, net of deferred taxes of $1,313,000, in other comprehensive income (loss).

The Company's incentive plans authorize awards granted wholly or partly in common stock (including rights or options which may be exercised for or settled in common stock) to key employees and non-employee directors (collectively, "Stock Awards"). Prior to January 1, 2003, the Company accounted for Stock Awards using the intrinsic value recognition provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Under this method, the Company recognized no compensation expense for stock options granted when the exercise price of the options was equal to or greater than the quoted market price of the Company's common stock on the grant date. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock Based Compensation" ("SFAS 123"), and the prospective method transition provisions of SFAS No. 148, "Accounting for Stock Based Compensation—Transition and Disclosure—an amendment of FAS No. 123" ("SFAS 148"), for all Stock Awards granted, modified or settled after January 1, 2003. Compensation cost for stock options and other stock-based compensation is recognized on a straight-line basis over the vesting period for the applicable Stock Award. The Company granted Stock Awards covering 547,000 shares of common stock with a fair market value of $9,920,000 during the year ended December 31, 2003.

The following table illustrates the effect on the Company's net income and earnings per share if the fair value recognition provisions of SFAS 123 for employee stock-based compensation had been applied to all Stock Awards outstanding during the years ended December 31, 2003, 2002 and 2001 (in thousands of dollars, except per share amounts):

		Year Ended December 31,
		2003			2002			2001
Net income, as reported		$	290,941		$	107,031		$	87,954
Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported			1,408			756			606
Deduct: Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects			(7,017	)		(6,466	)		(5,115	)

Net income, pro forma		$	285,332		$	101,321		$	83,445

Earnings per share:
	Basic—as reported	$	4.65		$	1.85		$	1.72
	Basic—pro forma	$	4.56		$	1.75		$	1.64
	Diluted—as reported	$	4.54		$	1.77		$	1.62
	Diluted—pro forma	$	4.45		$	1.68		$	1.54

The fair value of grants was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used in 2003, 2002 and 2001, respectively: risk free interest rates of 2.30%, 4.20% and 4.85%, expected volatility of 28.4%, 33.9% and 44.41%, dividend yields of 0.61%, 0.51% and 0.49%, and an expected life of the options of three, seven and six years.

For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and, as such, are not disclosed in the Consolidated Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of Shareholders' Equity relating to shares issued as compensation, and shares issued for stock and debt of an acquired company. The shares issued for stock of an acquired company are also discussed in Note 12, "Acquisition".

The U.S. dollar is the functional currency for all areas of operations of the Company. Accordingly, monetary assets and liabilities and items of income and expense denominated in a foreign currency are remeasured to U.S. dollars at the rate of exchange in effect at the end of each month or the average for the month, and the resulting gains or losses on foreign currency transactions are included in the consolidated statements of income for the period.

Certain prior year amounts have been reclassified to conform with the current year presentation. Such reclassifications had no effect on the Company's operating income, net income or shareholders' equity.

The Financial Accounting Standards Board ("FASB") has issued several new pronouncements including Interpretation No. 46 (revised December 2003) ("FIN 46R"), "Consolidation of Variable Interest Entities, an interpretation of ARB 51", Statement of Financial Accounting Standards No. 149 ("SFAS 149"), "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" and Statement of Financial Accounting Standards No. 150 ("SFAS 150"), "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity".

Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.

The Emerging Issues Task Force ("EITF") has recently decided to consider this issue. If the EITF determines that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in the Company's required disclosures under SFAS 69.

Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. Earnings per common share and potential common share (diluted earnings per share) consider the effect of dilutive securities as set out below in thousands, except per share amounts.

		For the Year Ended December 31, 2003
		Income(a)		Shares	Per Share
Basic earnings per share		$	295,107	62,538	$	4.72
Effect of potential dilutive securities:
	Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period		—	683
	Interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $42.185 per share of the 2006 Notes (redeemed July 7, 2003)		2,106	1,391

Diluted earnings per share		$	297,213	64,612	$	4.60

Antidilutive securities:
	Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive	$	—	467	$	41.87

		For the Year Ended December 31, 2002
		Income		Shares	Per Share
Basic earnings per share		$	107,031	57,963	$	1.85
Effect of potential dilutive securities:
	Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period		—	980
	Interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $42.185 per share of the 2006 Notes		4,111	2,726
	Minority interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $23.75 per share of the Trust Preferred Securities (redeemed June 3, 2002)		2,661	2,652

Diluted earnings per share		$	113,803	64,321	$	1.77

Antidilutive securities:
	Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive	$	—	143	$	38.00

		For the Year Ended December 31, 2001
		Income		Shares	Per Share
Basic earnings per share		$	87,954	51,031	$	1.72
Effect of potential dilutive securities:
	Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period		—	749
	Interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $42.185 per share of the 2006 Notes		4,111	2,726
	Minority interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $23.75 per share of the Trust Preferred Securities		6,338	6,316

Diluted earnings per share		$	98,403	60,822	$	1.62

Antidilutive securities:
	Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive	$	—	266	$	33.75

The components of income before income taxes and cumulative effect of change in accounting principle for each of the three years in the period ended December 31, 2003, are as follows (expressed in thousands):

The components of income tax expense (benefit) for each of the three years in the period ended December 31, 2003, are as follows (expressed in thousands):

Total income tax expense for each of the three years in the period ended December 31, 2003, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as percent of pretax income):

			2003		2002		2001
Federal statutory income tax rate			35.0	%	35.0	%	35.0	%
	Increases (reductions) resulting from:
		Foreign income taxed at different rates	4.6		7.8		11.3
		Recognition of net operating loss carryforwards	—		—		(20.4	)
		U.S. taxes on repatriation of foreign earnings	1.9		2.3		5.7
		State income taxes, net of federal benefits	0.7		0.5		4.0
		Other	0.5		2.2		5.6

			42.7	%	47.8	%	41.2	%

The principal components of the Company's deferred income tax assets and liabilities at December 31, 2003 and 2002 (expressed in thousands) are as follows:

		December 31,
		2003			2002
Deferred tax assets:
	Foreign deferred tax assets and net operating loss carry forwards	$	2,795		$	22,700
	Valuation allowance of foreign deferred tax assets and net operating loss		(379	)		(243	)
	Tax basis in excess of book basis for price hedge contracts		—			8,895
	Other		9,938			3,654

			12,354			35,006

Deferred tax liabilities:
	Book basis in excess of tax basis for oil and gas properties and equipment		(553,967	)		(538,132	)
	Other		(8,004	)		(6,638	)

			(561,971	)		(544,770	)

Net deferred tax liability		$	(549,617	)	$	(509,764	)

Book basis in excess of tax basis for oil and gas properties and equipment primarily results from differing methodologies for recording property costs and depreciation, depletion and amortization under United States generally accepted accounting principles and income tax reporting. In addition, the Company recorded a deferred tax liability resulting from book and tax basis differences of the acquired NORIC net assets (see Note 12).

During 2003, the Company utilized its remaining Thailand net operating loss carryforwards to offset current year income taxes. As of December 31, 2003 the Company had $8,300,000 in net operating loss carryforwards available to offset future income tax in Hungary. Such net operating loss carryforwards do not expire.

Where the Company's present intention is to reinvest the unremitted earnings in its foreign operations, the Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries. Unremitted earnings of foreign subsidiaries for which U.S. income taxes have not been provided are approximately $128,825,000 at December 31, 2003. It is not practicable to determine the amount of U.S. income taxes that would be payable upon remittance of the assets that represent those earnings.

During the third quarter of 2001, the Company reevaluated its global tax and cash position, including estimates regarding the realization of its Thailand operating loss carryforwards as well as its ability to indefinitely reinvest all unremitted foreign earnings in its foreign operations. Based on the Company's expectations for its Thailand operations, the Company determined it to be more likely than not that its remaining Thailand operating loss carryforwards would be realized and, therefore, reversed the remaining valuation allowance accordingly. In addition, the Company provided for U.S. income taxes on the unremitted earnings from a portion of its Thailand operations determined to be subject to repatriation. However, where the Company's continued intention is to reinvest the unremitted earnings of a foreign subsidiary in foreign operations, the Company will continue to not provide U.S. income taxes on those earnings.

Long-term debt at December 31, 2003 and 2002, consists of the following (dollars expressed in thousands):

			December 31,
			2003			2002
Senior debt
	Bank revolving credit agreement:
		LIBOR based loans, borrowings at December 31, 2003 and 2002 at interest rates of 2.3125% and 2.5625%, respectively	$	135,000		$	135,000
		Swing line money market loans, borrowings at December 31, 2003 at an interest rate of 2.375%		4,000			—
	Banker's Acceptance loans, borrowings at December 31, 2002 at an interest rate of 2.2765% (terminated on April 11, 2003)			—			24,987

Total senior debt				139,000			159,987

Subordinated debt—
	10³/8% Senior subordinated notes, due 2009			150,000			150,000
	8¹/4% Senior subordinated notes, due 2011			200,000			200,000
	5¹/2% Convertible subordinated notes, due 2006 (redeemed July 7, 2003)			—			115,000
	8³/4% Senior subordinated notes, due 2007 (redeemed August 6, 2003)			—			100,000

Total subordinated debt				350,000			565,000

Unamortized discount on 2009 Notes				(1,739	)		(2,084	)

Long-term debt			$	487,261		$	722,903

On March 8, 2001, the Company entered into the Credit Facility, a reserve based revolving credit facility. The Credit Facility provides for a $515,000,000 revolving credit facility until March 7, 2006. The amount that may be borrowed may not exceed a borrowing base which is determined semi-annually and is calculated based upon substantially all of the Company's proved oil and gas properties. The borrowing base is currently established at $800,000,000. The Credit Facility is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, and limitations on the creation of liens, commodity hedging above specified limits, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. The Company has pledged the stock of North Central and its inter-company receivables with North Central as collateral for its obligations under the Credit Facility. The Credit Facility also permits short-term swing-line loans and the issuance of up to $50,000,000 in letters of credit as part of the facility. Borrowings under the Credit Facility bear interest, at the Company's option, at a base (prime) rate plus a variable margin (currently none) or LIBOR plus a variable margin (currently l.125%). The margin varies as a function of the percentage of the borrowing base utilized and, with respect to the LIBOR rate, the Company's credit rating. A commitment fee on the unborrowed amount that is currently available under the Credit Facility is also charged based on the percentage of the borrowing base that is being utilized.

On January 15, 1999, the Company issued $150,000,000 principal amount of 2009 Notes. The 2009 Notes bear interest at a rate of 10³/8%, payable semi-annually in arrears on February 15 and August 15 of each year. The 2009 Notes are generally unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Facility, and are equal in right of payment to the 2011 Notes. The Company, at its option, may redeem the 2009 Notes in whole or in part, at any time on or after February 15, 2004, at a redemption price of 105.188% of their principal value and decreasing percentages thereafter. The indenture governing the 2009 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indenture governing the 2011 Notes, described below.

On April 10, 2001, the Company issued $200,000,000 principal amount of 2011 Notes. The 2011 Notes bear interest at a rate of 8¹/4%, payable semi-annually in arrears on April 15 and October 15 of each year. The 2011 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Facility, and are equal in right of payment to the 2009 Notes. The Company, at its option, may redeem the 2011 Notes in whole or in part, at any time on or after April 15, 2006, at a redemption price of 104.125% of their principal value and decreasing percentages thereafter. The indentures governing the 2011 Notes also impose certain covenants on the Company including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets. As of December 31, 2003, $338,121,000 was available for dividends under this limitation, which is currently the Company's most restrictive covenant.

The Company gave notice on June 6, 2003 of its intent to redeem all $115,000,000 of its 5¹/2% Convertible Subordinated Notes due 2006 (the "2006 Notes") at 101.65% of their face amount. Prior to the redemption date of July 7, 2003, holders of $42,536,000 face value of the 2006 Notes converted their notes into 1,008,299 shares of the Company's common stock at the $42.185 per share conversion price. In connection with the redemption, the Company paid a total of $73,661,000 in cash to former holders of the 2006 Notes. The cash redemption payment was funded through a combination of available cash and borrowings under the Company's Credit Facility. The Company recorded a pre-tax loss on the redemption of the 2006 Notes of $1.8 million in "Loss on debt extinguishment" during the year ended December 31, 2003.

The Company also gave notice on July 7, 2003 of its intent to redeem all $100,000,000 of its 8³/4% Senior Subordinated Notes due 2007 (the "2007 Notes") at 102.917% of their face amount. On August 6, 2003, the Company paid $102,917,000 in cash to holders of the 2007 Notes. The cash redemption payment was funded through a combination of available cash and borrowings under the Company's existing bank credit facility. The Company recorded a pre-tax loss on the redemption of the 2007 Notes of $4.1 million in "Loss on debt extinguishment" during the year ended December 31, 2003.

The Company currently has no maturities or sinking fund requirements during the next three years in connection with the above long-term debt. In 2006, maturities of $139,000,000 will become due consisting of the senior debt currently outstanding. The Company is currently in compliance with all debt covenants.

The Company has commitments for operating leases (primarily for office space) in Houston, Midland, Fort Worth, Bangkok, Budapest, for an FPSO and FSO in the Gulf of Thailand, and for other equipment (including gas compressors). Rental expense for office space was $2,942,000 in 2003, $2,821,000 in 2002, and $2,623,000 in 2001. Expenses for the FPSO lease were approximately $10,600,000 in each of the years 2003, 2002 and 2001. Expenses for the FSO were approximately $4,000,000 in each of the years 2003, 2002 and 2001. Rental expense for other equipment was $4,241,000 in 2003, $2,022,000 in 2002 and $654,000 in 2001.

Future minimum lease payments related to the Company's operating leases at December 31, 2003 are approximately $22,300,000 in 2004; $22,000,000 in 2005; $21,900,000 in 2006; $18,800,000 in 2007; $15,300,000 in 2008 and $44,000,000 thereafter. Where rented equipment such as compressors is considered essential to the operation of the lease, the Company has assumed that such equipment will be leased for the estimated productive life of the reserves, even if the contract terminates prior to such date.

The Company's reportable geographic information is identified below. The accounting policies of the geographic regions are the same as those described in the summary of significant accounting policies (Note 1). The Company evaluates performance based on operating income (loss). Financial information by geographic region is presented below:

			2003			2002			2001
			(Expressed in thousands)
Long-Lived Assets:
	As of December 31,
		United States	$	1,943,564		$	1,780,431		$	1,748,046
		Kingdom of Thailand		420,856			378,260			342,411
		Other		11,421			358			271

		Total	$	2,375,841		$	2,159,049		$	2,090,728

Capital Expenditures: (including interest capitalized)
	For the year ended December 31,
		United States	$	376,430		$	269,250		$	1,458,549
		Kingdom of Thailand		132,409			112,440			73,192
		Other		11,485			—			3,071

		Total	$	520,324		$	381,690		$	1,534,812

Revenues:
	For the year ended December 31,
		United States	$	858,505		$	542,014		$	422,120
		Kingdom of Thailand		303,470			212,763			183,074
		Other		21			77			4,923

		Total	$	1,161,996		$	754,854		$	610,117

Depreciation, depletion, and amortization expense:
	For the year ended December 31,
		United States	$	237,853		$	221,646		$	142,643
		Kingdom of Thailand		87,906			66,099			61,814
		Other		61			64			2,152

		Total	$	325,820		$	287,809		$	206,609

Operating income (loss):
	For the year ended December 31,
		United States	$	399,678		$	138,934		$	113,976
		Kingdom of Thailand		151,830			103,021			76,493
		Other		(3,779	)		(1,782	)		(10,588	)

		Total	$	547,729		$	240,173		$	179,881

The Company is an oil and gas exploration and production company that generally sells its oil and gas to numerous customers on a month-to-month basis. For purposes of comparison, sales have been presented for all three years for those customers who have exceeded 10% of revenues in any given year (expressed in thousands):

		2003		2002		2001
China Intl. United Petroleum and Chemical Co. Ltd.		$	119,444		$	55,140		$	13,665
Enron Corp. and affiliates			827			5,594			96,970

Substantially all of the Company's accounts receivable at December 31, 2003 and 2002, result from oil and gas sales and joint interest billings to other companies in the energy industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. As of December 31, 2003 and 2002, the Company had provided reserves for receivables from customers and joint interest owners that are considered doubtful of collection of $3,810,000 and $5,542,000, respectively.

A substantial portion of the Company's oil and gas operations are conducted in Southeast Asia, and a substantial portion of its natural gas and liquids hydrocarbon production are sold there. Southeast Asia in general, and the Kingdom of Thailand in particular, experienced severe economic difficulties in 1997 and 1998 which were characterized by sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. Since that time, the economic situation in the Kingdom of Thailand has generally stabilized and begun to improve. However, as with most emerging market economies, the Thai economy remains particularly sensitive to worldwide economic trends. The economic health of the Thai economy and its effect on the volatility of the Thai Baht against the U.S. dollar will continue to have a material impact on the Company's operations in the Kingdom of Thailand, as well as the prices that the company receives for its natural gas production there.

As a result of the substantial oil and gas operations and earnings from its Thailand operations, the Company generates a significant amount of cash which is maintained in various bank accounts with multi-national banks for future foreign investment. These balances are diversified between cash and short-term investments.

The Company has a tax-advantaged savings plan in which all U.S. salaried employees may participate. Under such plan, a participating employee may allocate up to 30% of their salary, up to a maximum allowed by law, and the Company will then match the employee's contribution on a dollar for dollar basis up to the lesser of 6% of the employee's salary or $12,000 in 2003. Funds contributed by the employee and the matching funds contributed by the Company are held in trust by a bank trustee in six separate funds. Amounts contributed and earnings and accretions thereon may be used to purchase shares of the Company's common stock, invest in a money market fund or invest in four stock, bond, or blended stock and bond mutual funds according to instructions from the employee. The Company contributed $1,233,000 to the savings plan in 2003, $1,068,000 in 2002, and $928,000 in 2001.

The Company has adopted a trusteed retirement plan for its U.S. salaried employees. The benefits are based on years of service and the employee's average compensation for five consecutive years within the

final ten years of service which produce the highest average compensation. The Company makes annual contributions to the plan in the amount of retirement plan cost accrued or the maximum amount that can be deducted for federal income tax purposes. The Company does not expect to make a contribution to the plan in 2004. The plan's investment strategy and goals are to ensure, over the long-term life of the retirement plan, an adequate pool of sufficiently liquid assets to support the benefit obligations to participants, retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles of three to five years.

Although the Company has no obligation to do so, the Company currently provides full medical benefits to its retired U.S. employees and dependents. For current employees, the Company assumes all or a portion of post-retirement medical and term life insurance costs based on the employee's age and length of service with the Company. The post-retirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis. The expected Company contributions to the post-retirement medical plan during 2004 are approximately $556,000.

The following table sets forth the plans' status (in thousands of dollars) as of December 31, 2003 and 2002. The Company uses a December 31 measurement date for its plans.

		Retirement Plan						Post-Retirement Medical Plan
		2003		2002		2001		2003		2002		2001
Plan assumptions to determine benefit obligations
	Discount rate	6.00	%	6.50	%	7.25	%	6.00	%	6.50	%	7.25	%
	Rate of compensation increase	4.75	%	4.75	%	4.75	%	—		—		—
Plan assumptions to determine net cost
	Discount rate	6.50	%	7.25	%	7.50	%	6.50	%	7.25	%	7.50	%
	Expected long-term rate of return on plan assets	8.50	%	9.50	%	9.50	%	—		—		—
	Rate of compensation increase	4.75	%	4.75	%	4.75	%	—		—		—

To develop the expected long-term rate of return on plan assets assumption, the Company considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of the risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on plan assets assumption for the portfolio. This resulted in the selection of the 8.50% assumption for 2003.

The following table provides the target and actual asset allocations in the retirement plan:

				Actual as of December 31,
Asset Category
	Target		2003		2002
Equity securities		100	%	100	%	99	%
Debt securities		0	%	0	%	0	%
Real estate		0	%	0	%	0	%
Other		0	%	0	%	1	%

	Total		100	%	100	%	100	%

For measurement purposes related to the Company's post-retirement medical plan, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004. The rate is assumed to decrease gradually to 5% for 2012 and remain at that level thereafter. This compares to the amounts used for 2003 measurement purposes, where a 13% annual rate of increase in the per capita cost of covered health care benefits was assumed, decreasing gradually to 5% for 2012 and remaining level thereafter.

Assumed health care cost trends have a significant effect on the amount reported for the health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):

	One Percentage Point
	Increase		Decrease
Effect on total of service and interest cost components for 2003	$	387		$	(310	)
Effect on year-end 2003 postretirement benefit obligation	$	2,838		$	(2,305	)

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) became law. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. Pursuant to guidance recently published by the FASB, the Company has elected to defer recognizing the effects of the Act in the accounting for and disclosure of our postretirement medical plan until authoritative guidance on the accounting for the federal subsidy is issued. Accordingly, the disclosures of the accumulated postretirement benefit obligation and the net periodic postretirement benefit cost included herein do not reflect the effects of the Act on the postretirement medical plan. Authoritative guidance on accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information. The Company does not believe however that the effects of the Act will have a material effect on its financial condition or results of operations.

The Company's incentive plans authorize awards granted wholly or partly in common stock (including rights or options which may be exercised for or settled in common stock) to key employees and non-employee directors. Awards to employees of the Company may be made as grants of stock options, stock appreciation rights, stock awards, cash awards, performance awards or any combination thereof (collectively, "Awards"). Employee Awards generally become exercisable in three installments. The number of shares available for future issuance was 2,297,657, 2,911,565 and 898,520 as of December 31, 2003, 2002 and 2001, respectively. Stock options granted in 2003 expire 5 years from the date of grant, if not exercised. Stock options granted prior to 2003, if not exercised, expire 10 years from the date of grant.

The Company granted the following shares of restricted stock during the indicated periods:

Year Ended December 31,	Number of Awards	Weighted Average Grant Date Fair Value
2003	144,000	$	6,045,840
2002	40,065	$	1,192,935
2001	41,102	$	1,018,097

The number of unvested shares of restricted stock was 157,019, 38,621 and 39,394 as of December 31, 2003, 2002 and 2001, respectively.

A summary of the status of the Company's stock option activity as of December 31, 2003, 2002 and 2001, and changes during the years ended on those dates is presented below:

		Number of Awards		Weighted Average Exercise Price
Outstanding, December 31, 2000		3,401,854		$	20.46
	Granted in 2001	1,035,400		$	25.35
	Exercised in 2001	(377,764	)	$	17.30
	Canceled in 2001	(206,910	)	$	21.75

Outstanding, December 31, 2001		3,852,580		$	22.01

Exercisable, December 31, 2001		2,267,561		$	21.09

Weighted-average fair value of options granted during 2001				$	11.98
Outstanding, December 31, 2001		3,852,580		$	22.01
	Granted in 2002	960,900		$	29.84
	Exercised in 2002	(1,022,034	)	$	19.72
	Canceled in 2002	(44,000	)	$	23.49

Outstanding, December 31, 2002		3,747,446		$	24.62

Exercisable, December 31, 2002		1,992,883		$	22.41

Weighted-average fair value of options granted during 2002				$	12.43
Outstanding, December 31, 2002		3,747,446		$	24.54
	Granted in 2003	403,000		$	42.02
	Exercised in 2003	(1,553,573	)	$	21.48
	Canceled in 2003	(14,100	)	$	17.14

Outstanding, December 31, 2003		2,582,773		$	29.16

Exercisable, December 31, 2003		1,258,999		$	25.75

Weighted-average fair value of options granted during 2003				$	9.61

The following table summarizes information about stock options outstanding at December 31, 2003:

	Options Outstanding				Options Exercisable
Range of Option Prices	Number Outstanding	Weighted Average Remaining Contractual Life (days)	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$17.91 to $19.56	71,700	1,912	$	18.60	71,700	$	18.60
$20.31 to $24.77	1,024,569	2,457	$	23.27	739,233	$	22.71
$25.38 to $29.78	923,504	3,069	$	29.62	291,399	$	29.35
$31.18 to $33.94	56,000	2,473	$	32.09	52,667	$	32.06
$36.00	40,000	885	$	36.00	40,000	$	36.00
$40.63 to $43.46	467,000	3,193	$	41.87	64,000	$	40.92

Total	2,582,773	2,769	$	29.16	1,258,999	$	25.75

The Company adopted Statement of Financial Accounting Standard ("SFAS") No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), as of January 1, 2003. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation ("ARO") in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost ("ARC") was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, a cumulative effect of a change in accounting principle was also required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. This periodic accretion expense is recorded as "Transportation and other" in the consolidated statement of income. Upon settlement of the liability, the Company will settle the obligation against its recorded amount and will record any resulting gain or loss.

Activity related to the Company's ARO during the year ended December 31, 2003 is as follows (in thousands):

For the year ended December 31, 2003, the Company recognized depreciation expense related to its ARC of $3,850,000. As a result of the adoption of SFAS 143 on January 1, 2003, the Company recorded a $56,769,000 increase in the net capitalized cost of its oil and gas properties and recognized an after-tax

charge of $4,166,000 for the cumulative effect of the change in accounting principle (net of related income tax benefit of $2,707,000).

Had the Company adopted SFAS 143 on January 1, 2002, the pro forma ARO would have been $58,187,000. Had SFAS 143 been applied retroactively during the years ended December 31, 2002 and 2001, the Company's net income and earnings per share would have been as follows (expressed in thousands, except per share amounts):

		Year Ended December 31, 2002		Year Ended December 31, 2001
		As Reported		Pro forma		As Reported		Pro forma
Net Income		$	107,031		$	106,662		$	87,954		$	85,873
Earnings per share:
	Basic		$	1.85		$	1.84		$	1.72		$	1.68
	Diluted		$	1.77		$	1.76		$	1.62		$	1.58

On March 14, 2001, the merger of the Company and NORIC was consummated. As a result of the merger, the Company acquired all of the outstanding capital stock of North Central which was the principal asset of NORIC. North Central was an independent domestic oil and gas exploration and production company. The merger was accounted for using the purchase method of accounting. Accordingly, the purchase price was allocated to the net assets acquired based on their estimated fair values at the date of acquisition. Commencing March 14, 2001, North Central's operations were consolidated with the operations of the Company. Pursuant to the merger agreement among the Company and NORIC and certain former NORIC shareholders, the former shareholders received 12,615,816 shares of the Company's common stock and approximately $344,711,000 in cash. In addition, at the closing all the $78,600,000 principal amount of North Central's existing bank debt was repaid.

The following summary presents unaudited pro forma consolidated results of operations as if the acquisition had occurred at the beginning of the period presented. The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results of North Central, such as increased depreciation, depletion and amortization expense resulting from the allocation of fair value to oil and gas properties acquired and increased interest expense on acquisition debt. The unaudited pro forma information (presented in thousands of dollars, except per share amounts) is not

necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor are they necessarily indicative of future operating results.

Pogo Trust I, a subsidiary of the Company, called for redemption its 6¹/2% Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the "Trust Preferred Securities") on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities converted their Trust Preferred Securities, representing $149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares of the Company's common stock. In connection with the redemption, Pogo Trust I paid a total of $147,000 to former holders of the Trust Preferred Securities. Subsequent to June 3, 2002, there were no Trust Preferred Securities outstanding.

The amounts recorded under "Minority Interests—Dividends and costs associated with mandatorily redeemable preferred securities of a subsidiary trust" principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value.

Instrument		Basis of Fair Value Estimate
Bank revolving credit agreement		Fair value is carrying value as of December 31, 2003 and 2002 based on the market value interest rates.
Banker's acceptance loans		Fair value is carrying value as of December 31, 2002 based on the market value interest rates.
2007 Notes		Fair value is 104.3% of carrying value as of December 31, 2002, based on quoted market values. This instrument was redeemed by the Company on August 6, 2003.
2009 Notes		Fair value is 106% and 108% of carrying value as of December 31, 2003 and 2002, respectively, based on quoted market values.
2011 Notes		Fair value is 110.6% and 105% of carrying value as of December 31, 2003 and 2002, based on quoted market value.
2006 Notes		Fair value is 106.7% of carrying value as of December 31, 2002, based on quoted market values. This instrument was redeemed by the Company on July 7, 2003.

The carrying value and estimated fair value of the Company's financial instruments at December 31, 2003 and 2002 (in thousands of dollars) are as follows:

		2003						2002
		Carrying Value			Fair Value			Carrying Value			Fair Value
Cash and cash equivalents		$	178,754		$	178,754		$	134,449		$	134,449
Receivables		$	156,467		$	156,467		$	116,441		$	116,441
Payables		$	(148,942	)	$	(148,942	)	$	(125,592	)	$	(125,592	)
Debt:
	Bank revolving credit agreement loans	$	(139,000	)	$	(139,000	)	$	(135,000	)	$	(135,000	)
	Banker's acceptance loans	$	—		$	—		$	(24,987	)	$	(24,987	)
	2007 Notes	$	—		$	—		$	(100,000	)	$	(104,250	)
	2009 Notes	$	(148,261	)	$	(159,000	)	$	(147,916	)	$	(162,000	)
	2011 Notes	$	(200,000	)	$	(221,250	)	$	(200,000	)	$	(210,000	)
	2006 Notes	$	—		$	—		$	(115,000	)	$	(122,711	)

The Company occasionally enters into hedging contracts to minimize the impact of oil and gas price fluctuations. See Note 15 for a further discussion of these contracts.

During 2003, the Company recognized a pre-tax loss of $22,822,000 ($14,873,000 after tax) from its price hedge contracts which are included in oil and gas revenues. During 2002 and 2001, the Company recognized pre-tax gains of $3,640,000 ($2,367,000 after tax) and $14,592,000 ($9,485,000 after tax), respectively, from its price hedge contracts which are included in oil and gas revenues. As of December 31, 2003, the Company held no derivative instruments.

The results of operations from oil and gas producing activities exclude non-oil and gas revenues, general and administrative expenses, other non oil and gas producing expenses, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pretax operating results with adjustments for permanent differences.

	Total Company			United States			Kingdom of Thailand			Other International
	(Expressed in thousands)
	2003
Revenues	$	1,159,544		$	856,074		$	303,470		$	—
Lease operating expense		(123,098	)		(81,731	)		(41,367	)		—
Exploration expense		(7,547	)		(6,899	)		(644	)		(4	)(a)
Dry hole and impairment expense		(35,102	)		(31,600	)		(3,231	)		(271	)(a)
Depreciation, depletion and amortization expense		(321,572	)		(234,579	)		(86,993	)		—
Production and other taxes		(35,485	)		(23,735	)		(11,750	)		—
Transportation and accretion		(17,952	)		(16,949	)		(1,003	)		—

Pretax operating results		618,788			460,581			158,482			(275	)
Income tax (expense) benefit		(256,198	)		(176,957	)		(79,241	)		—

Operating results	$	362,590		$	283,624		$	79,241		$	(275	)


	2002
Revenues	$	750,401		$	537,717		$	212,684		$	—
Lease operating expense		(112,663	)		(74,416	)		(38,247	)		—
Exploration expense		(4,783	)		(4,161	)		(544	)		(78	)(a)
Dry hole and impairment expense		(26,999	)		(26,999	)		—			—
Depreciation, depletion and amortization expense		(283,865	)		(218,636	)		(65,229	)		—
Production and other taxes		(20,058	)		(20,058	)		—			—
Transportation		(10,194	)		(10,194	)		—			—

Pretax operating results		291,839			183,253			108,664			(78	)
Income tax (expense) benefit		(128,498	)		(65,545	)		(62,967	)		14

Operating results	$	163,341		$	117,708		$	45,697		$	(64	)


	2001
Revenues	$	596,077		$	408,514		$	183,005		$	4,558
Lease operating expense		(92,693	)		(54,452	)		(36,993	)		(1,248	)
Exploration expense		(23,373	)		(11,877	)		(2,162	)		(9,334	)(b)
Dry hole and impairment expense		(26,945	)		(26,136	)		—			(809	)
Depreciation, depletion and amortization expense		(203,676	)		(140,304	)		(61,243	)		(2,129	)
Production and other taxes		(22,007	)		(22,007	)		—			—
Transportation		(3,457	)		(3,457	)		—			—

Pretax operating results		223,926			150,281			82,607			(8,962	)
Income tax (expense) benefit		(96,590	)		(52,598	)		(46,322	)		2,330

Operating results	$	127,336		$	97,683		$	36,285		$	(6,632	)

The following table sets forth the Company's costs incurred (expressed in thousands) for oil and gas producing activities during the years indicated.

The following information regarding estimates of the Company's proved oil and gas reserves, which are located offshore in United States waters of the Gulf of Mexico, onshore in the United States, offshore in the Kingdom of Thailand and in Hungary is based on reports prepared by Ryder Scott Company, L.P. and Miller & Lents, Ltd. The definitions and assumptions that serve as the basis for the discussions under the caption "Item 1, Business—Exploration and Production Data—Reserves" should be referred to in connection with the following information.

POGO PRODUCING COMPANY & SUBSIDIARIES

STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES—Unaudited

The standardized measure of discounted future net cash flows from the production of proved reserves is developed as follows:

The standardized measure of discounted future net cash flows does not purport to present the fair value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The following are the principal sources of change in the standardized measure of discounted future net cash flows. All amounts are related to changes in reserves located in the United States, the Kingdom of Thailand, Hungary, and Canada, as noted.

Summaries of the Company's results of operations by quarter for the years 2003 and 2002 are as follows:

ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

Information regarding a change in accountants was previously reported on a Form 8-K dated April 17, 2002.

The Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer, of the effectiveness of the Company's disclosure controls and procedures pursuant to Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this quarterly report. Based upon that evaluation, the Company's Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic Securities and Exchange Commission filings.

There were no changes in the Company's internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

The information responsive to Items 401, 405 and 406 of Regulation S-K in the Company's definitive Proxy Statement for its annual meeting to be held on April 27, 2004, to be filed within 120 days of December 31, 2003 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the Company's "2004 Proxy Statement"), is incorporated herein by reference. See also Item S-K 401(b) appearing in Part I of this Form 10-K.

The information responsive to Item 402 of Regulation S-K in the Company's 2004 Proxy Statement is incorporated herein by reference. The portion of the incorporated material consisting of the Compensation Committee Report on Executive Compensation and the Performance Graph is not be considered "filed" with the Commission.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information responsive to Items 201(d) and 403 of Regulation S-K in the Company's 2004 Proxy Statement is incorporated herein by reference.

The information responsive to Item 404 of Regulation S-K in the Company's 2003 Proxy Statement is incorporated herein by reference.

The information responsive to Item 9(e) of Schedule 14A in the Company's 2004 Proxy Statement is incorporated herein by reference.

ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

(a) Financial Statements and Supplementary Data, Financial Statement Schedules and Exhibits

All Financial Statement Schedules have been omitted because they are not required, are not applicable or the information required has been included elsewhere herein.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on February 24, 2004.

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
o	TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from to

Delaware (State or other jurisdiction of incorporation or organization)		74-1659398 (I.R.S. Employer Identification No.)
5 Greenway Plaza, P.O. Box 2504 Houston, Texas (Address of principal executive offices)		77252-2504 (Zip Code)

			2003		2002		2001
Average Production (Lifting) Costs per Mcfe(a)(b):
	Located in the United States		$	0.68	$	0.69	$	0.81

	Located in the Kingdom of Thailand		$	0.67	$	0.59	$	0.65

		Total Company	$	0.68	$	0.66	$	0.76

				As of December 31,
				2003		2002		2001
Total Proved Reserves:
	Oil, condensate and natural gas liquids (MBbls)
		Located in North America			77,553		80,092		79,979
		Located in the Kingdom of Thailand			37,307		38,087		39,301
		Located in Hungary			10		—		—

			Total Company		114,870		118,179		119,280

	Natural Gas (MMcf)
		Located in North America			837,004		713,906		670,567
		Located in the Kingdom of Thailand			165,188		159,604		148,225
		Located in Hungary			10,131		—		—

			Total Company		1,012,323		873,510		818,792

	Present value of estimated future net revenues, before income taxes (in thousands)
		Located in North America		$	2,928,663	$	2,495,558	$	1,130,353
		Located in the Kingdom of Thailand			744,822		602,798		410,307
		Located in Hungary			16,516		—		—

			Total Company	$	3,690,001	$	3,098,356	$	1,540,660

Total Proved Developed Reserves:
	Oil, condensate and natural gas liquids (MBbls)
		Located in North America			67,391		74,041		59,383
		Located in the Kingdom of Thailand			19,878		23,832		20,394
		Located in Hungary			—		—		—

			Total Company		87,269		97,873		79,777

	Natural Gas (MMcf)
		Located in North America			702,836		600,255		532,348
		Located in the Kingdom of Thailand			77,938		87,301		69,997
		Located in Hungary			—		—		—

			Total Company		780,774		687,556		602,345

	Present value of estimated future net revenues, before income taxes (in thousands)
		Located in North America		$	2,455,495	$	2,239,781	$	951,040
		Located in the Kingdom of Thailand			458,511		422,219		241,860
		Located in Hungary			—		—		—

			Total Company	$	2,914,006	$	2,662,000	$	1,192,900

			For the Year Ended December 31,
			2003			2002		2001(a)		2000(a)			1999(a)
			(Expressed in thousands, except per share and production data)
Financial Data
Revenues:
	Crude oil and condensate		$	651,334		$	431,769	$	261,226	$	272,932		$	109,803
	Natural gas			475,834			294,206		322,390		190,401			111,152
	Natural gas liquids			32,376			24,426		12,461		15,869			9,544

	Oil and gas revenues			1,159,544			750,401		596,077		479,202			230,499
	Other			2,452			4,453		14,040		18,789			44,617	(d)

		Total	$	1,161,996		$	754,854	$	610,117	$	497,991		$	275,116

Income (loss) before cumulative effect of change in accounting principle			$	295,107		$	107,031	$	87,954	$	89,023		$	22,134
Cumulative effect of change in accounting principle				(4,166	)(b)		—		—		(1,768	)(c)		—

Net income (loss)			$	290,941		$	107,031	$	87,954	$	87,255		$	22,134

Per share data:
	Income (loss) before cumulative effect of change in accounting principle—
		Basic	$	4.72		$	1.85	$	1.72	$	2.20		$	0.55
		Diluted	$	4.60		$	1.77	$	1.62	$	1.99		$	0.55
	Cash dividends on common stock		$	0.20		$	0.12	$	0.12	$	0.12		$	0.12
	Price range of common stock:
		High	$	49.50		$	39.28	$	34.50	$	33.19		$	23.44
		Low	$	34.29		$	23.00	$	20.45	$	18.00		$	8.94
Weighted average number of common shares outstanding				62,538			57,963		51,031		40,445			40,178
Long-term debt at year end			$	487,261		$	722,903	$	792,561	$	365,000		$	375,000
Minority interest at year end			$	—		$	—	$	145,086	$	144,913		$	144,751
Shareholders' equity at year end			$	1,453,653		$	1,077,784	$	824,885	$	358,271		$	268,512
Total assets at year end			$	2,762,036		$	2,491,593	$	2,423,979	$	1,114,649		$	948,193
Production (Sales) Data
Net daily average production and weighted average price:
	Natural gas (Mcf per day)			297,000			279,000		237,800		164,600			141,600
		Price (per Mcf)	$	4.39		$	2.89	$	3.71	$	3.16		$	2.15
	Crude oil-condensate (Bbl per day)			62,121			47,360		29,590		25,788			16,036
		Price (per Bbl)	$	29.10		$	24.89	$	23.99	$	28.92		$	18.76
	Natural gas liquids (Bbl per day)			4,109			4,480		2,118		2,141			2,077
		Price (per Bbl)	$	21.59		$	14.94	$	16.12	$	20.25		$	12.59

		2004		2005		2006			2007		2008		Thereafter			Total			Fair Value
Long-Term Debt:
	Variable Rate	$	0	$	0	$	139,000		$	0	$	0	$	0		$	139,000		$	139,000
	Average Interest Rate		—		—		2.31	%		—		—		—			2.31	%		—
	Fixed Rate	$	0	$	0	$	0		$	0	$	0	$	350,000		$	350,000		$	380,250
	Average Interest Rate		—		—		—			—		—		9.16	%		9.16	%		—

		Common Stock(a)	Additional Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Deferred Compensation Restricted Stock			Treasury Stock			Shareholders' Equity			Comprehensive Income (Loss)
Balance at December 31, 2000		40,660	$	298,885	$	20,112		$	(1,062	)	$	—		$	(324	)	$	358,271
Net income		—		—		87,954			—			—			—			87,954		$	87,954
Shares issued for stock and debt of acquired company		12,615		351,729		—			—			—			—			364,344
Exercise of stock options		378		7,718		—			—			—			—			8,096
Shares issued as compensation		38		895		—			—			—			—			933
Dividends ($0.12 per common share)		—		—		(6,047	)		—			—			—			(6,047	)
Exchange gain on Canadian currency		—		—		—			389			—			—			389			389
	Reclassification adjustment included in net income	—		—		—			673			—			—			673			(389	)
Cumulative effect of change in accounting principle		—		—		—			(2,438	)		—			—			(2,438	)		(2,438	)
Unrealized gains arising during the year on price hedge contracts		—		—		—			22,195			—			—			22,195
	Reclassification adjustment included in net income	—		—		—			(9,485	)		—			—			(9,485	)
	Net unrealized gains on price hedge contracts	—		—		—			—			—			—			—			12,710

Comprehensive income		—		—		—			—			—			—			—		$	98,226

Balance at December 31, 2001		53,691	$	659,227	$	102,019		$	10,272		$	—		$	(324	)	$	824,885
Net income		—		—		107,031			—			—			—			107,031		$	107,031
Exercise of stock options		1,022		23,460		—			—			—			—			24,482
Shares issued as compensation		39		1,124		—			—			—			—			1,163
Conversion of Trust Preferred Securities		6,310		138,715		—			—			—			—			145,025
Dividends ($0.12 per common share)		—		—		(6,895	)		—			—			—			(6,895	)
Shares received in satisfaction of note receivable		—		—		—			—			—			(1,386	)		(1,386	)
Unrealized loss arising during the year on price hedge contracts		—		—		—			(14,155	)		—			—			(14,155	)
	Reclassification adjustment included in net income	—		—		—			(2,366	)		—			—			(2,366	)
	Net unrealized losses on price hedge contracts	—		—		—			—			—			—			—			(16,521	)

Comprehensive income		—		—		—			—			—			—			—		$	90,510

Balance at December 31, 2002		61,062	$	822,526	$	202,155		$	(6,249	)	$	—		$	(1,710	)	$	1,077,784
Net income						290,941												290,941		$	290,941
Stock option activity and other		1,573		43,915		—			—			—			—			45,488
Shares issued as compensation		170		6,865		—			—			—			—			7,035
Conversion of 2006 Notes		1,008		41,186		—			—			—			—			42,194
Issuance of restricted stock, less amortization of $412		—		—		—			—			(3,518	)		—			(3,518	)		(3,518	)
Dividends ($0.20 per common share)		—		—		(12,520	)		—			—			—			(12,520	)
Unrealized loss arising during the year on price hedge contracts		—		—		—			(8,624	)		—			—			(8,624	)
	Reclassification adjustment included in net income	—		—		—			14,873			—			—			14,873
	Net unrealized gains on price hedge contracts	—		—		—			—			—			—			—			6,249

Comprehensive income		—		—		—			—			—			—			—		$	293,672

Balance at December 31, 2003		63,813	$	914,492	$	480,576		$	—		$	(3,518	)	$	(1,710	)	$	1,453,653

		2003		2002		2001
United States		$	364,097	$	101,349	$	81,619
Foreign			151,132		103,462		67,948

	Income before income taxes and cumulative effect of change in accounting principle	$	515,229	$	204,811	$	149,567

			2003		2002		2001
Current
	United States		$	116,813	$	15,497	$	—
	Foreign			51,491		11,351		10,996
Deferred
	United States			26,375		32,451		59,823
	Foreign			25,443		38,481		(9,206	)

		Income tax expense	$	220,122	$	97,780	$	61,613

	Year Ended December 31, 2003
Initial ARO as of January 1, 2003	$	63,643
Liabilities incurred during period		3,001
Liabilities settled during period		(691	)
Accretion expense		4,837

Balance of ARO as of December 31, 2003	$	70,790

			Year Ended December 31, 2001
Revenues			$	668,480
Income before cumulative effect of change in accounting principle			$	104,348
Net income			$	104,348
Earnings per share:
	Basic—
		Income before cumulative effect of change in accounting principle	$	1.95
		Net income	$	1.95
	Diluted—
		Income before cumulative effect of change in accounting principle	$	1.81
		Net income	$	1.81

				Total Company		United States		Kingdom of Thailand		Other International(a)
Costs incurred (capitalized unless otherwise indicated):
	2003:
		Property acquisition
			Proved	$	177,680	$	177,680	$	—	$	—
			Unproved		15,540		12,065		3,475		—
		Exploration
			Capitalized		59,714		42,248		6,155		11,311
			Expensed		7,547		6,899		644		4
		Development			248,348		131,732		116,616		—
		Asset retirement cost(b)			59,142		49,706		9,436		—
		Interest			16,531		10,194		6,163		174

		Total oil and gas costs incurred		$	584,502	$	430,524	$	142,489	$	11,489

	Provision for depreciation, depletion and amortization			$	321,572	$	234,579	$	86,993	$	—

	2002:
		Property acquisition
			Proved	$	—	$	—	$	—	$	—
			Unproved		8,030		8,030		—		—
		Exploration
			Capitalized		43,165		40,028		3,137		—
			Expensed		4,783		4,161		544		78
		Development			303,197		205,035		98,162		—
		Interest			24,033		12,892		11,141		—

		Total oil and gas costs incurred		$	383,208	$	270,146	$	112,984	$	78

	Provision for depreciation, depletion and amortization			$	283,865	$	218,636	$	65,229	$	—

	2001:
		Property acquisition
			Proved	$	949,704	$	949,673	$	—	$	31
			Unproved		172,947		172,947		—		—
		Exploration
			Capitalized		59,390		48,290		9,180		1,920
			Expensed		23,373		11,877		2,162		9,334
		Development			314,736		255,800		57,816		1,120
		Interest			33,242		27,046		6,196		—

		Total oil and gas costs incurred		$	1,553,392	$	1,465,633	$	75,354	$	12,405

	Provision for depreciation, depletion and amortization			$	203,676	$	140,304	$	61,243	$	2,129

		Total Company		United States		Kingdom of Thailand		Other International
Proved Reserves as of December 31, 2000		95,321,497		57,478,436		37,065,285		777,776
	Revisions of previous estimates	8,694,016		3,521,490		5,172,457		69
	Extensions, discoveries and other additions	18,278,228		15,818,428		2,459,800		—
	Purchase of properties	10,115,300		10,115,300		—		—
	Sale of properties	(1,556,413	)	(837,413	)	—		(719,000	)
	Estimated 2001 production	(11,573,233	)	(6,117,546	)	(5,396,842	)	(58,845	)

Proved Reserves as of December 31, 2001		119,279,395		79,978,695		39,300,700		—
	Revisions of previous estimates	9,563,087		9,290,517		272,570		—
	Extensions, discoveries and other additions	8,460,885		3,965,585		4,495,300		—
	Sale of properties	(202,785	)	(202,785	)	—		—
	Estimated 2002 production	(18,921,750	)	(12,939,750	)	(5,982,000	)	—

Proved Reserves as of December 31, 2002		118,178,832		80,092,262		38,086,570		—
	Revisions of previous estimates	9,964,506		6,338,668		3,625,838		—
	Extensions, discoveries and other additions	6,305,471		2,982,400		3,312,627		10,444
	Purchase of properties	4,301,200		4,301,200		—		—
	Estimated 2003 production	(23,880,000	)	(16,162,000	)	(7,718,000	)	—

Proved Reserves as of December 31, 2003		114,870,009		77,552,530		37,307,035		10,444

Proved Developed Reserves as of:
	December 31, 2000	60,656,634		35,132,295		24,746,563		777,776
	December 31, 2001	79,777,300		59,383,200		20,394,100		—
	December 31, 2002	97,873,000		74,041,149		23,831,851		—
	December 31, 2003	87,269,277		67,391,031		19,878,246		—

		Total Company		United States		Kingdom of Thailand		Other International
Proved Reserves as of December 31, 2000		369,983		214,621		153,304		2,058
	Revisions of previous estimates	11,749		(743	)	12,492		—
	Extensions, discoveries and other additions	63,519		57,344		6,175		—
	Purchase of properties	468,776		468,776		—		—
	Sale of properties	(8,477	)	(6,949	)	—		(1,528	)
	Estimated 2001 production	(86,758	)	(62,482	)	(23,746	)	(530	)

Proved Reserves as of December 31, 2001		818,792		670,567		148,225		—
	Revisions of previous estimates	66,796		38,237		28,559		—
	Extensions, discoveries and other additions	89,774		78,575		11,199		—
	Estimated 2002 production	(101,852	)	(73,473	)	(28,379	)	—

Proved Reserves as of December 31, 2002		873,510		713,906		159,604		—
	Revisions of previous estimates	22,408		5,686		16,722		—
	Extensions, discoveries and other additions	95,664		65,095		20,438		10,131
	Purchase of properties	129,119		129,119		—		—
	Estimated 2003 production	(108,378	)	(76,802	)	(31,576	)	—

Proved Reserves as of December 31, 2003		1,012,323		837,004		165,188		10,131

Proved Developed Reserves as of:
	December 31, 2000	239,978		150,684		87,236		2,058
	December 31, 2001	602,345		532,348		69,997		—
	December 31, 2002	687,556		600,255		87,301		—
	December 31, 2003	780,774		702,836		77,938		—

		Total Company			United States			Kingdom of Thailand			Hungary
		(Expressed in thousands)
		2003
Future gross revenues		$	8,507,228		$	6,912,547		$	1,545,580		$	49,101
Future production costs:
	Lease operating expense		(1,811,584	)		(1,417,118	)		(385,058	)		(9,408	)
Future development and abandonment costs			(520,159	)		(324,813	)		(181,396	)		(13,950	)

Future net cash flows before income taxes			6,175,485			5,170,616			979,126			25,743
Discount at 10% per annum			(2,485,484	)		(2,241,953	)		(234,304	)		(9,227	)

Discounted future net cash flows before income taxes			3,690,001			2,928,663			744,822			16,516
Future income taxes, net of discount at 10% per annum			(1,239,971	)		(919,540	)		(320,383	)		(48	)

Standardized measure of discounted future net cash flows related to proved oil and gas reserves		$	2,450,030		$	2,009,123		$	424,439		$	16,468


		2002
Future gross revenues		$	7,078,353		$	5,486,454		$	1,591,899		$	—
Future production costs:
	Lease operating expense		(1,819,485	)		(1,150,305	)		(669,180	)		—
Future development and abandonment costs			(406,101	)		(267,578	)		(138,523	)		—

Future net cash flows before income taxes			4,852,767			4,068,571			784,196			—
Discount at 10% per annum			(1,754,411	)		(1,573,013	)		(181,398	)

Discounted future net cash flows before income taxes			3,098,356			2,495,558			602,798			—
Future income taxes, net of discount at 10% per annum			(1,043,141	)		(780,770	)		(262,371	)		—

Standardized measure of discounted future net cash flows related to proved oil and gas reserves		$	2,055,215		$	1,714,788		$	340,427		$	—


		2001
Future gross revenues		$	4,202,888		$	3,115,416		$	1,087,472		$	—
Future production costs:
	Lease operating expense		(1,354,815	)		(899,262	)		(455,553	)		—
Future development and abandonment costs			(445,239	)		(325,600	)		(119,639	)		—

Future net cash flows before income taxes			2,402,834			1,890,554			512,280			—
Discount at 10% per annum			(862,174	)		(760,201	)		(101,973	)

Discounted future net cash flows before income taxes			1,540,660			1,130,353			410,307			—
Future income taxes, net of discount at 10% per annum			(402,612	)		(303,783	)		(98,829	)		—

Standardized measure of discounted future net cash flows related to proved oil and gas reserves		$	1,138,048		$	826,570		$	311,478		$	—

			For the Year Ended December 31,
			2003		2002		2001		2000		1999
			(Expressed in thousands)
Capital Expenditures (including interest capitalized)
Oil and gas:
	Domestic Offshore—
		Exploration	$	28,100	$	33,600	$	18,000	$	18,700	$	12,600
		Development		23,900		100,700		169,000		43,700		43,200
		Purchase of reserves		—		—		87,700		—		—
	Onshore North America—
		Exploration		26,200		14,500		38,300		19,700		9,800
		Development		118,000		117,200		113,600		34,700		19,800
		Purchase of reserves		177,700		—		1,027,200		8,400		19,500
	International—
		Exploration		20,900		3,100		11,500		9,400		3,500
		Development		123,000		109,300		64,700		51,500		106,300
		Purchase of reserves		—		—		—		—		—

	Total oil and gas			517,800		378,400		1,530,000		186,100		214,700
Other				2,500		3,300		4,800		700		2,200

	Total		$	520,300	$	381,700	$	1,534,800	$	186,800	$	216,900

			Quarter Ended
			Mar. 31		June 30		Sept. 30		Dec. 31
			(Expressed in thousands, except per share amounts)
2003
	Revenues		$	312,673	$	297,146	$	279,332	$	272,845
	Gross profit(a)		$	181,206	$	158,970	$	148,682	$	120,162
	Net income		$	88,477	$	79,719	$	67,660	$	55,085
	Earnings per share(b):
		Basic	$	1.45	$	1.29	$	1.07	$	0.87
		Diluted	$	1.37	$	1.24	$	1.06	$	0.86
2002
	Revenues		$	143,016	$	184,546	$	209,165	$	218,127
	Gross profit(a)		$	40,821	$	71,006	$	86,040	$	91,795
	Net income		$	9,025	$	28,618	$	31,637	$	37,751
	Earnings per share(b):
		Basic	$	0.17	$	0.51	$	0.52	$	0.62
		Diluted	$	0.17	$	0.48	$	0.51	$	0.60


1.	Financial Statements and Supplementary Data:
	Report of Independent Auditors
	Consolidated statements of income
	Consolidated balance sheets
	Consolidated statements of cash flows
	Consolidated statements of shareholders' equity
	Notes to consolidated financial statements
	Unaudited supplementary financial data
2.	Financial Statement Schedules:

3.		Exhibits:
*3.1		Restated Certificate of Incorporation of Pogo Producing Company (Exhibit 3(a), Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-7792).
*3.2		Amendment to Amended and Restated Certificate of Incorporation of Pogo Producing Company (Exhibit 4.3, Registration Statement on Form S-3, filed May 11, 2001, File No. 333-60800).
*3.3		Certificate of Designations of Series A Junior Participating Preferred Stock of Pogo Producing Company, dated April 26, 1994 (Exhibit 4(d), Registration Statement on Form S-8, filed August 9, 1994, File No. 33-54969).
*3.4		Bylaws of Pogo Producing Company, as amended and restated through July 16, 2002 (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-7792).
*4.1		Credit Agreement dated as of March 8, 2001 among Pogo Producing Company, as the Borrower, certain commercial lending institutions, as the Lenders, Bank of Montreal as Administrative Agent, Toronto Dominion (Texas), Inc., as Syndication Agent, BNP Paribas, as Documentation Agent and Bank of America, N.A. and Fleet National Bank, as Managing Agents (Exhibit 4.4, Current Report on Form 8-K filed March 26, 2001, File No. 1-7792).
*4.2		Indenture dated as of January 15,1999, between Pogo Producing Company and State Street Bank & Trust Company as Trustee (Exhibit 4.2, Registration Statement on Form S-4, filed February 10, 1999, File No. 333-72129).
*4.3		Indenture dated as of April 10, 2001, between Pogo Producing Company and Wells Fargo Bank Minnesota, National Association, as Trustee (Exhibit 4.2, Registration Statement on Form S-4, filed April 24, 2001, File No. 333-59426).

*4.4		Rights Agreement dated as of April 26, 1994, between Pogo Producing Company and Harris Trust Company of New York, as Rights Agent (Exhibit 4, Current Report on Form 8-K filed, April 26, 1994, File No. 1-7792). Other instruments defining the rights of holders of long-term debt of Pogo Producing Company and its subsidiaries are not being filed because the total amount of securities authorized by such instruments does not exceed 10% of the total assets of Pogo Producing Company and its subsidiaries on a consolidated basis as of December 31, 2003. Pogo Producing Company hereby agrees to furnish to the Commission a copy of any such debt instrument upon request.
Executive Compensation Plans and Arrangements (comprising Exhibits 10.1 through 10.33, inclusive)
*10.1		1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Company, as amended and restated effective January 25, 1994 (Exhibit 99, Definitive Proxy Statement on Schedule 14A, filed March 22, 1994, File No. 1-7792).
*10.2		Form of Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan, as amended and restated effective January 22, 1991 (Exhibit 10(d)(1), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468).
*10.3		Form of Director Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan as amended and restated effective January 22, 1991 (Exhibit 10(d)(2), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468).
*10.4		1995 Long-Term Incentive Plan (Exhibit 4(c), Registration Statement on Form S-8 filed May 22, 1996, File No. 333-04233).
*10.5		1998 Incentive Plan (Exhibit 4.7, Registration Statement on Form S-8 filed August 15, 2002, File No. 333-98205).
*10.6		2000 Incentive Plan (Exhibit B to the Company's Definitive Proxy Statement filed on Schedule 14A, March 27, 2000, File No. 001-7792).
*10.7		2002 Incentive Plan (Exhibit B to the Company's Definitive Proxy Statement filed on Schedule 14A, March 25, 2002, File No. 001-7792).
*10.8		Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated February 1, 2003 (Exhibit 10.12, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.9		Extension Agreement to Executive Employment Agreement between Paul G. Van Wagenen and Pogo Producing Company, dated effective February 1, 2003
*10.10		Executive Employment Agreement by and between Pogo Producing Company and Stephen R. Brunner, dated as of February 1, 2003 (Exhibit 10.15, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.11		Extension Agreement to Executive Employment Agreement between Stephen R. Brunner and Pogo Producing Company, dated effective February 1, 2003.
*10.12		Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated February 1, 2003 (Exhibit 10.8, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.13		Extension Agreement to Executive Employment Agreement between Stuart P. Burbach and Pogo Producing Company, dated effective February 1, 2003.
*10.14		Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated February 1, 2003 (Exhibit 10.9, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).

10.15		Extension Agreement to Executive Employment Agreement between Jerry A. Cooper and Pogo Producing Company, dated effective February 1, 2003
*10.16		Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated February 1, 2003 (Exhibit 10.11, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.17		Extension Agreement to Executive Employment Agreement between John O. McCoy, Jr. and Pogo Producing Company, dated effective February 1, 2003
*10.18		Executive Employment Agreement by and between Pogo Producing Company and David R. Beathard, dated as of February 1, 2003 (Exhibit 10.14, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.19		Extension Agreement to Executive Employment Agreement between David R. Beathard and Pogo Producing Company, dated effective February 1, 2003
*10.20		Executive Employment Agreement by and between Pogo Producing Company and Radford P. Laney, dated February 1, 2003 (Exhibit 10.10, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.21		Extension Agreement to Executive Employment Agreement between Radford P. Laney and Pogo Producing Company, dated effective February 1, 2003.
*10.22		Executive Employment Agreement by and between Pogo Producing Company and J. Don McGregor, dated as of February 1, 2003 (Exhibit 10.16, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.23		Extension Agreement to Executive Employment Agreement between J. Don McGregor and Pogo Producing Company, dated effective February 1, 2003.
*10.24		Executive Employment Agreement by and between Pogo Producing Company and Gerald A. Morton, dated as of February 1, 2003 (Exhibit 10.17, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.25		Extension Agreement to Executive Employment Agreement between Gerald A. Morton and Pogo Producing Company, dated effective February 1, 2003.
*10.26		Executive Employment Agreement by and between Pogo Producing Company and James P. Ulm, II, dated as of February 1, 2003 (Exhibit 10.18, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.27		Extension Agreement to Executive Employment Agreement between James P. Ulm, II and Pogo Producing Company, dated effective February 1, 2003.
10.28		Executive Employment Agreement by and between Pogo Producing Company and Barry W. Acomb, dated February 1, 2004.
*10.29		Executive Employment Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated as of February 1, 2003 (Exhibit 10.13, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
10.30		Extension Agreement to Executive Employment Agreement between Bruce E. Archinal and Pogo Producing Company, dated effective February 1, 2003.
10.31		Executive Employment Agreement by and between Pogo Producing Company and Michael J. Killelea, dated February 1, 2004.
*10.32		Form of Restricted Stock Award Agreement Under Incentive Plans (Exhibit 10.1, Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-7792)

*10.33		Form of Directors Phantom Stock Agreement (Exhibit 10.2, Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 1-7792)
*10.34		Amended and Restated Bareboat Charter Agreement by and between Tantawan Services, L.L.C. and Tantawan Production B.V., dated as of February 9,1996 (Exhibit 10.26, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792).
*10.35		Bareboat Charter Agreement by and between Thaipo Limited, Thai Romo Limited, Palang Sophon Limited, B8/32 Partners Limited and Watertight Shipping B.V. dated as of August 24, 1998 (Exhibit 10.27, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792).
*10.36		Gas Sales Agreement dated November 7, 1995, among The Petroleum Authority of Thailand, Thaipo, Limited, Thai Romo Ltd. and The Sophonpanich Co., Ltd. (Exhibit 10(k), Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792).
*10.37		The First Amendment to the Gas Sales Agreement dated November 12, 1997, among The Petroleum Authority of Thailand, B8/32 Partners Limited, Thaipo, Limited, Thai Romo Limited and Palang Sophon Limited (Exhibit 10(g)(ii), Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-7792).
*10.38		The Second Amendment to the Gas Sales Agreement dated effective as of October 1, 2001, among The Petroleum Authority of Thailand, Chevron Offshore (Thailand) Limited, Thaipo Limited, Palang Sophon Limited and B8/32 Partners Limited (Exhibit 10.23, Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-7792).
*10.39		The Third Amendment to the Gas Sales Agreement dated November 7, 1995 between PTT Public Company Limited and Chevron Offshore (Thailand) Limited, Thaipo Limited, Palang Sophon Limited and B8/32 Partners Limited, dated effective as of October 1, ]2001 (Exhibit 10.1, Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-7792).
21		List of Subsidiaries of Pogo Producing Company
23.1		Consent of Arthur Anderson LLP (omitted pursuant to Rule 437a of the Securities Act)
23.2		Consent of PricewaterhouseCoopers LLP
23.3		Consent of Ryder Scott Company, L.P.
23.4		Consent of Miller and Lents, Ltd.
24		Powers of Attorney from each director of Pogo Producing Company whose signature is affixed to this Form 10-K for year ended December 31, 2003.
31.1		Certification of Chief Executive Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act.
31.2		Certification of Chief Financial Officer, pursuant to Rule 13a-14(a) under the Securities Exchange Act.
32.1		Certification of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350.
32.2		Certification of Chief Financial Officer, pursuant to 18 U.S.C. Section 1350
99.1		Summary Report of Ryder Scott Company, L.P.
99.2		Summary Report of Miller and Lents, Ltd.

	POGO PRODUCING COMPANY (REGISTRANT)

	BY:	/S/ PAUL G. VAN WAGENEN Paul G. Van Wagenen Chairman, President and Chief Executive Officer
Date: February 24, 2004

Signatures		Title

/S/ PAUL G. VAN WAGENEN Paul G. Van Wagenen Chairman, President and Chief Executive Officer		Principal Executive Officer and Director
/S/ JAMES P. ULM, II James P. Ulm, II Senior Vice President and Chief Financial Officer		Principal Financial Officer
/S/ THOMAS E. HART Thomas E. Hart Vice President and Chief Accounting Officer		Principal Accounting Officer
/S/ JERRY M. ARMSTRONG Jerry M. Armstrong		Director
/S/ ROBERT H. CAMPBELL Robert H. Campbell		Director
/S/ WILLIAM L. FISHER William L. Fisher		Director

/S/ GERRIT W. GONG Gerrit W. Gong		Director
/S/ CARROLL W. SUGGS Carroll W. Suggs		Director
/S/ STEPHEN A. WELLS Stephen A. Wells		Director
/S/ THOMAS E. HART Thomas E. Hart Attorney-in-Fact