UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

o        TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from                to                

Commission File No. 1-7792

Pogo Producing Company

(Exact name of registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x     No 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. x

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes x     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 $3,200,000,000 as of June 30, 2004 (based on $49.40 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange Composite Tape on such date).

63,601,714 shares of the registrant’s Common Stock were outstanding as of March 1, 2005.

DOCUMENT INCORPORATED BY REFERENCE

Portions of the Company’s definitive Proxy Statement respecting the annual meeting of shareholders to be held on April 26, 2005 (to be filed not later than 120 days after December 31, 2004) are incorporated by reference in Part III of this Form 10-K.

FORWARD LOOKING STATEMENTS

The statements included or incorporated by reference in this Annual Report on Form 10-K for the year ended December 31, 2004 (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:

·       the cyclical nature of the oil and natural gas industries

·       the Company’s ability to successfully and profitably find, produce and market oil and gas

·       uncertainties associated with the United States and worldwide economies

·       current and potential governmental regulatory actions in countries where the Company operates

·       substantial competition from larger companies

·       the Company’s ability to implement cost reductions

·       the Company’s ability to acquire additional oil and gas reserves

·       operating interruptions (including leaks, explosions, fires, mechanical failure, unscheduled downtime, transportation interruptions, and spills and releases and other environmental risks)

·       fluctuations in foreign currency exchange rates in areas of the world where the Company conducts operations, particularly Southeast Asia

·       covenant restrictions in the Company’s debt agreements

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.

2

CERTAIN DEFINITIONS

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 and information related to production contained in this Annual Report, unless otherwise noted, are reported on a “net” basis. Information regarding acreage and numbers of wells are set forth on a gross basis, unless otherwise noted.

PART I

ITEM 1.   Business.

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, New Zealand and in Hungary. As of December 31, 2004, the Company had interests in 91 lease blocks offshore Louisiana and Texas, approximately 705,000 gross acres onshore in the United States, approximately 588,000 gross acres offshore in the Kingdom of Thailand, approximately 778,000 gross acres in Hungary, and approximately 1,044,000 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, the Panhandle of Texas, 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 currently oversees activity principally in Hungary. The Company’s New Ventures Group is primarily responsible for identifying new projects and opportunities for the Company outside the United States.

Domestic Offshore Operations

Gulf of Mexico Region.   Approximately 18% of the Company’s proved reserves as of December 31, 2004 were located in the Gulf of Mexico. During 2004, approximately 18% of the Company’s natural gas production and 44% of its oil and condensate production came from the Company’s domestic offshore properties, contributing approximately 33% of the Company’s consolidated oil and gas revenues. The Company’s exploration and development efforts in this region are primarily focused in the shallower waters of the continental shelf.

Exploration and Development

The scope of exploration and development programs relating to the Company’s domestic 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 2004 were approximately $150,300,000, or 148% higher than the Company’s domestic offshore capital and exploration expenditures of approximately $60,500,000 for 2003, and 15% higher than the Company’s domestic offshore capital and exploration expenditures of approximately $130,265,000 for

3

2002. The increase in the Company’s domestic offshore capital and exploration expenditures for 2004, compared with 2003, resulted primarily from increased expenditures for exploration and development wells and facilities construction. During 2004, the Company invested approximately $87,695,000 on exploration and development wells and $22,952,000 on facilities construction for its Gulf of Mexico operations. The Company has currently budgeted approximately $109,000,000 for capital and exploration expenditures during 2005 in the Gulf of Mexico, of which $59,803,000 is budgeted for exploration and development wells and $15,976,000 for facilities construction.

The Company maintains a significant presence in the Gulf of Mexico where it participated in drilling 12 wells during 2004, 83% of which were considered successful. At December 31, 2004, the Company held varying interests in 175 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 59 of the 91 offshore leases in which it had an interest as of December 31, 2004.

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.

Lease Acquisitions

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, 2004, the Company owned interests in 78 federal leases and 13 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 14 offshore leases at the lease sale conducted by the Minerals Management Service of the Department of the Interior (the “MMS”) on March 17, 2004. 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. 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

4

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

Domestic Onshore Operations

The Company’s Gulf Coast region is headquartered in Houston, Texas, with field offices in Laredo and Manvel, Texas and Thibodaux, Louisiana. The Company’s Western U.S. region has an office in Midland, Texas, two field offices in Southeastern New Mexico, one field office in West Texas and two field offices in the Panhandle of Texas. The Company conducts its onshore operations in the United States directly and through its wholly owned subsidiaries. Domestic onshore reserves as of December 31, 2004, accounted for approximately 63% of the Company’s total proved reserves, with the Gulf Coast region and the Western U.S. region contributing approximately 19% and 44%, respectively, of the Company’s total proved reserves. During 2004, approximately 58% of the Company’s natural gas production and 21% of its oil and condensate production was from its domestic onshore properties, contributing approximately 41% of the Company’s consolidated oil and gas revenues.

Exploration and Development

The Company’s onshore capital and exploration expenditures for 2004 were approximately $196,500,000 (excluding approximately $489,600,000 of net property acquisitions), or 38% higher than comparable expenditures for 2003, and approximately 48% higher than comparable expenditures for 2002. The increase in the Company’s onshore capital and exploration expenditures for 2004, compared to 2003, resulted primarily from expenditures related to increased exploratory and development drilling. The Company has currently budgeted approximately $170,300,000 for capital and exploration expenditures during 2005 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.

Western U.S. Region.   The Company’s Western U.S. region has actively explored in West Texas and New Mexico for more than 25 years and, during this period, has participated in the discovery or development of over 31 oil and gas fields. In 2004, the Company participated in the drilling of 159 wells in these areas (97% of which were successfully completed). The Company believes that, during the past decade, it has been one of the more active companies drilling for oil and natural gas in the Permian Basin of West Texas and southeastern New Mexico.

During 2005, the Company plans to drill approximately 84 wells in various known fields and exploratory prospects located in the Permian Basin and Texas Panhandle. Drilling objectives for these wells range in vertical depth from 3,200 feet to 18,500 feet below the surface and target numerous formations, including, among others, the Brown Dolomite, Canyon, Delaware (Brushy Canyon), Bone Spring, Spraberry, Wolfcamp, Granite & Atoka Wash, and Pennsylvanian 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 14.5% across the unit area. Recent drilling activity in the Madden Deep Unit has focused on the Lower Fort Union formation (where productive zones are historically found from approximately 5,500 feet to 9,500 feet below the surface). Additionally, a 16,950-foot Cody test well has been drilled in this Unit and is currently awaiting completion.

An active Rocky Mountain drilling program of approximately 57 wells is anticipated for 2005. In addition to the Company’s continued participation in the development of the Madden Deep Unit, the

5

Company also plans to initiate several exploratory tests elsewhere in Wyoming that will target the Lower Fort Union and Lance formations at total depths ranging from 10,000 feet to 11,000 feet.

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 2004, the Gulf Coast region participated in drilling 54 wells, 91% of which were successfully completed.

The Company’s most active drilling in its Gulf Coast region during 2004 drilling took place on its 65,000 gross acres of leasehold in South Texas’ Webb and Zapata Counties. The Company has been developing gas reserves primarily in its Los Mogotes, Hundido and South Hundido 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. At its Los Mogotes Field, where its working interest averages 71%, the Company drilled 37 wells in 2004. There were 62 locations identified to drill at Los Mogotes at the beginning of 2005, and the Company has already successfully drilled six of those. A total of six wells were drilled in the Company’s 100%-owned South Hundido Field in 2004 and one has already been drilled in 2005. A new exploratory well was recently completed successfully by the Company on the South Rosita Prospect in Duvall County, Texas. Additional exploratory and development drilling is planned for this prospect. The Company intends to actively explore in various portions of the Wilcox trend of Texas during 2005.

During 2004, the Company participated in drilling several Miocene wells and several Oligocene wells in South Louisiana. In the Upper Texas Gulf Coast, the Company is actively exploring the Woodbine Formation for new gas reserves in Polk and Tyler Counties, Texas.

Property Acquisitions

In four transactions in 2004, the Company acquired interests in producing properties located primarily in Hidalgo and Lavaca Counties in the Texas Gulf Coast area, the San Juan Basin in New Mexico and in several counties in West Texas. In two additional transactions during 2004, the Company increased its working interest in the Myette Point Field from approximately 25% to 50%, and in the Thibodaux Field from approximately 48% to 60%.

International Operations

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

Thailand and Hungary Disposition

The Company announced during the first quarter of 2005 that it would consider the sale or swap of the Company’s operations in Thailand and Hungary, and that it has retained Goldman, Sachs & Co. to advise it on the potential transactions. International asset sale proceeds could be favorably treated by the one-time tax provisions of the “American Jobs Creation Act of 2004,” if the sale is completed and the proceeds are repatriated by year-end 2005. Exploration activities in Thailand and development activities in both Thailand and Hungary will continue during the Company’s consideration of the sale of its operations.

6

Exploration and Development

The Company’s international capital and exploration expenditures were approximately $148,900,000 for 2004, or 8% higher than comparative expenditures for 2003, and 44% higher than comparable expenditures for 2002. The increase in the Company’s capital and exploration expenditures for 2004 resulted primarily from expenditures for facilities costs and increased drilling activity.

The Company has currently budgeted approximately $66,000,000 for capital and exploration expenditures during 2005 in areas outside the United States, including approximately $51,200,000 in Thailand and $4,800,000 in Europe. These budgeted numbers presume the sale of the Company’s Thailand and Hungarian operations is consummated on or around the middle of the year. If the sale of the Company’s Thailand Concession does not take place in mid-2005, these budgeted amounts will need to be increased, since additional capital expenditures in Thailand related to facilities construction and long-term rig contracts have already been contracted for through the end of the year and are, therefore, essentially non-discretionary in nature. In addition, the Company has budgeted approximately $10,000,000 for 2005 for its international new venture operations in New Zealand and elsewhere.

Asia and Pacific Region

The Company’s Thailand Concession consists of approximately 588,000 acres in the central portions of the Gulf of Thailand, about 250 miles south southeast of Bangkok in approximately 230 feet of water. 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”), and Palang Sophon Limited (“Palang”). Chevron owns, directly and indirectly, a 51.66% working interest in the Thailand Concession and is currently the operator of the Thailand Concession. The remaining 2% working interest in the Thailand Concession is owned by Palang Sophon Two Limited, a private entity controlled by members of the Sophonpanich family. Through voting procedures in the joint operating agreement governing the Thailand Concession, and the close working relationship between Chevron’s and Thaipo’s exploration staff, Thaipo exerts substantial influence over the development of the Thailand Concession. As of December 31, 2004, the Company’s proved reserves located in the Kingdom of Thailand accounted for approximately 19% of the Company’s total proved reserves. During 2004, approximately 25% of the Company’s natural gas production and 35% 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 132,000 acres is designated as the Benchamas and Pakakrong production area and another portion is known as the Benchamas North production area. Collectively, these two production areas are called the “Benchamas Field.” There are 14 production platforms installed in the Benchamas Field. An additional four platforms for the Benchamas Field are currently under construction and expected to be set commencing in late 2005. 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. 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.” During 2004, 49 productive development wells, including one horizontal well, were drilled in the Benchamas Field. In addition, in early January 2005, an exploration well, the Benchamas 28, encountered 365 feet of pay confirming the need for

7

at least one additional platform there. For 2005, an active development 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—Crude Oil and Condensate—Production.” During 2004, 15 productive development wells were drilled in the field. Currently, there is production from six platforms. 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 Block 9A was designated a production area in 2004. It is planned to be developed from and through existing Tantawan Field facilities. Current plans call for 2005 to be the most active development drilling program in the history of the field, with over 30 wells currently planned from five platforms.

Maliwan Field.   Approximately 91,000 acres of the Thailand Concession are designated as the Maliwan production area or the “Maliwan Field.” Eleven exploration wells have been drilled to delineate this field. An additional exploration well is currently planned for the latter half of 2005. In addition, seven production wells have been drilled from the first platform set in the field, the Maliwan “A” platform. Production from this platform is delivered to the central Benchamas Field production handling facilities for processing and sale. Current plans call for an additional eight development wells to be drilled from this platform in 2005. In addition, a second platform should be set in this field late in 2005. Final development plans for the remainder of the field are currently being finalized with our partners with the intent of sanctioning this project within the next several months.

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, was set in the second quarter of 2004 and 12 development wells were successfully drilled there. Additional exploration and development drilling is currently expected to occur in 2005. Production from this platform is 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 in conjunction with the development plans for the Maliwan Field.

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 2004, Thaipo and its joint venture partners drilled two exploratory wells and have currently budgeted to drill an additional four exploratory wells during 2005. Two of these wells, the Benchamas 28 discussed earlier, and the Chaba 4 have already been drilled. Each of these two wells encountered potentially commercial quantities of hydrocarbons. Two more wells are planned for later this year. Interpretation of the data provided by these wells and existing 3-D seismic and other 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

8

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 first fourteen production platforms and related facilities installed in the Tantawan, Benchamas and Maliwan Fields averaged approximately $17,400,000 per platform. The gross cost of each of the five “third generation” platforms currently under construction is currently expected to average approximately $10,000,000 per platform. Efforts are currently underway to design and construct even less expensive platforms. 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.

Contractual Terms Governing the Thailand Concession and Related Production

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, 2005. No more extensions can be obtained. On July 31, 2005, all acreage for which production area status has not been granted or applied for will revert to the government of Thailand. Prior to that date, the Company and its joint venture partners currently intend to apply for a production area designation for all remaining acreage in the Thailand Concession that has not already been designated a production area. 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. To date, the Benchamas Field (including the North Benchamas area), Tantawan Field (including Block 9A), Maliwan Field and Jarmjuree Field have been designated as production areas. The earliest date at which any of these production areas could revert to the government is June 15, 2017 (with respect to portions of the Tantawan Field).

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 made significant SRB payments during 2004 and expects to be obligated to pay additional SRB during 2005. 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 2004, gas production averaged approximately 197 MMcf per day (80 MMcf per day net to the Company).

9

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% through January 1, 2006) of the then-current sales price of the gas not delivered. Thaipo currently meets the minimum DCQ, but due to facilities constraints and process-related issues, has recently been unable to meet all of its Supplemental DCQ requirements. The price that the Company receives for its natural gas under the Gas Sales Agreement reflects the Company’s underdelivery of Supplemental DCQ. However, the reduction in revenue related penalty is not considered significant by the Company, amounting to a discount on delivered gas (net to the Company) of less than approximately $499,000 for all of 2004. There can be no assurance that Thaipo will be able to meet its DCQ and Supplemental DCQ obligations 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, 2004, the Company was receiving a blended average price of approximately $2.46 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.”

Other Areas of the World

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 778,000 acres. The exploration term of the license is currently set to expire on April 20, 2007. 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 of the Company’s 3-D surveys 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. During its drilling program that commenced in 2003, Pogo Hungary has drilled nine wells, seven of which were either temporarily or permanently abandoned.

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. One well was drilled during 2004 pursuant to this license, which has been abandoned. This license interest was held by the Company’s Danish subsidiary, Pogo Denmark ApS, and expired on September 14, 2004.

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. The joint venture relinquished its interest in the license area back to the Department of Trade and Industry on December 23, 2003.

New Zealand.   During 2004, the Company was granted three petroleum exploration licenses over approximately 1,044,000 acres in the offshore Northern Taranaki Basin. The primary exploration term of these licenses is for five years, subject to extension for up to an additional ten years, provided that at least

10

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 and to reprocess 433 miles of existing 2-D seismic data. During 2004 and early 2005, the Company exceeded its work obligations with respect to both 3-D data acquisition and 2-D seismic data reprocessing. The 3-D seismic data acquired by the Company is currently being processed and will then be analyzed later this year with a goal of committing to drill multiple exploration wells as early as the first half of 2006. 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.

Geographic Information

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.

Miscellaneous

Other Assets

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.

Sales

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 market successfully 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 platforms located in the northern portion of the Maliwan Field and the Jarmjuree Field, respectively, are initially stored aboard the FSO. A portion of this production is sold under a term sales agreement with Pacific Petroleum and Trading Co., Ltd. that expires in August 2005. 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.

11

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 2004, the price that the Company received for its crude oil production from the Thailand Concession ranged between a $1.50 per Bbl premium and a $1.65 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 2004, crude oil sales to two customers (Pacific Petroleum and Trading Co., Ltd. and Shell Trading Company) constituted more than 10% of the Company’s consolidated revenues.

Risks Associated with Acquisitions

From time to time the Company acquires additional interests in oil and gas properties, either through acquisition of the properties themselves or, 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

12

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.

Competition and Market Conditions

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, 2004, the Company was a party to certain natural gas or crude oil option contracts (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Current Hedging Activity”). 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.

Operating and Uninsured Risks

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 lack of suitable rigs in the region. This may lead to difficulty and delays in

13

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.

Risks of Foreign Operations

Ownership of property interests and production operations in Thailand, Hungary, 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.

Exploration and Production Data

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.

14

Acreage

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, 2004:

(a)           “Developed acreage” consists of lease acres spaced or assignable to production (including acreage held by production) on which wells have been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas. “Developed acreage” in Thailand includes all acreage designated as a production area by the Thai government, which currently includes Benchamas, North Benchamas, Tantawan, Block 9A, Maliwan and Jarmjuree production licenses.

(b)          Approximately 8.3% of the Company’s total domestic offshore net undeveloped acreage is under leases that have minimum terms expiring in 2005 and no leases set to expire in 2006. Approximately 7.2% of the Company’s total domestic onshore net undeveloped acreage is under leases with minimum terms expiring in 2005 and another 27.2% expires in 2006. All of the Company’s undeveloped acreage in the Kingdom of Thailand has an exploratory term expiring July 31, 2005. See “International Operations; Contractual Terms Governing the Thailand Concession and Related Production.”

In addition, the Company holds 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.

Average Production (Lifting) Costs per Unit of Production

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

15

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.” Production (lifting) costs are defined as the sum of lease operating expenses (which include insurance and producing well overhead), production and other taxes and transportation costs.

(a)           Production costs were converted to common units of measure on the basis of relative energy content. Such production costs exclude all depletion, depreciation and amortization associated with property and equipment.

Productive Wells and Drilling Activity

The following table shows the Company’s interest in productive oil and natural gas wells as of December 31, 2004. 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.

(a)           One or more completions in the same bore hole are counted as one well. The data in the above table includes 24 gross (10.5 net) oil wells and 6 gross (1.9 net) natural gas wells with multiple completions.

(b)          The Company was in the process of drilling a total of 15 gross (6.9 net) oil wells and 32 gross (16.3 net) natural gas wells as of December 31, 2004.

16

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. For accounting purposes, a well is considered a dry hole when the above criteria indicates that proved reserves have not been found. For purposes of this table, a well is classified as a dry hole in the period in which the Company reports permanent abandonment to the appropriate agency.

Reserves

The following table sets forth information as to the Company’s net proved and proved developed reserves as of December 31, 2004, 2003 and 2002, 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 reports prepared by the Company and reviewed by Miller and Lents, Ltd. (“Miller and Lents”), in accordance with criteria prescribed by the Commission. The summary reports of Ryder Scott and Miller and Lents, independent petroleum engineering firms, on the Company’s reserves are set forth as exhibits to this

17

Annual Report on Form 10-K and are incorporated herein by reference. The Ryder Scott report covers all of the Company’s reserves, except for certain domestic onshore areas on the Texas/Louisiana Gulfcoast and in Wyoming, which are covered by the Miller and Lents report.

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.

18

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. The present value amounts set forth in the above table are, as indicated, before income taxes. For the Company’s standardized measure of discounted future net cash flows from production of proved reserves, calculated after the estimated effect of future income taxes, see “Unaudited Supplementary Financial Data—Oil and Gas Producing Activities.”

Natural gas liquids comprised approximately 13% of the Company’s total proved liquids reserves and approximately 13% of the Company’s proved developed liquids reserves as of December 31, 2004. 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:

In computing future revenues from gas reserves attributable to the Company’s domestic interests, prices in effect at December 31, 2004, 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, 2004, 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

19

giving effect to any of the future adjustments provided for in the Gas Sales Agreement, due to their indeterminate nature as of December 31, 2004, 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, 2004, 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 2004. 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 used as a basis for the estimates set forth above 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, 2004, 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.

20

Government Regulations

Federal Income Tax

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.

American Jobs Creation Act of 2004

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”). The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, as of February 22, 2005, uncertainty remains as to how to interpret numerous provisions of the Act. As a result, the Company is not yet in a position to decide whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S., therefore, if technical corrections to the Act are passed, the Company may repatriate in 2005 an amount up to approximately $195.7 million of the cash and current investments held by international subsidiaries discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Assuming 15% of such cash is subject to tax at the U.S. statutory rate, the repatriation would be subject to a tax liability of approximately $10.2 million. This amount excludes any proceeds that may be realized from the potential sale of the Company’s Thailand and Hungarian operations.

Environmental Matters

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

21

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 2004, the Company incurred capital expenditures of approximately $6,343,000 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 $1,475,000 for expenditures involving environmental control facilities during 2005, including, among other things, anticipated site restoration costs and the installation of environmental control equipment.

Other Laws and Regulations

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

22

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.

Employees

As of December 31, 2004, the Company and its subsidiaries had 260 full-time employees, including six in its Bangkok, Thailand office and five in its Budapest, Hungary office. None of the Company’s employees are presently represented by a union for collective bargaining purposes.

Available Information

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:

·       The Company’s Code of Business Conduct and Ethics

·       The Company’s Corporate Governance Guidelines

·       The Charters of the Company’s Audit, Compensation and Nominating and Corporate Governance Committees

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.

ITEM 2.   Properties.

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

ITEM 3.   Legal Proceedings.

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 not material. See “Business—Government Regulation; Other Laws and Regulations.”

23

ITEM 4.   Submission of Matters to a Vote of Security-Holders.

No matters were submitted to a vote of the Company’s security holders during the fourth quarter of the year ended December 31, 2004.

ITEM S-K 401(b).   Executive Officers of Registrant.

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, 2004, and the year each was elected to his current position are as follows:

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. 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.

24

PART II

ITEM 5.   Market for the Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities.

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.

As of February 1, 2005, there were 2,118 holders of record of the Company’s Common Stock.

In 2003, the Company paid four quarterly dividends of $0.05 per share on its Common Stock. In 2004, the Company paid three quarterly dividends of $0.05 per share on its Common Stock. On October 19, 2004, the Company’s dividend was increased by 25% to $0.0625 per share on its Common Stock and it paid one quarterly dividend at that amount during 2004. 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 entered into a new revolving credit facility on December 16, 2004 (the “Facility”), under which the Company has borrowed funds. The Facility and the Indenture relating to the Company’s 8¼% 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 believe that either 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, 2004.

During the fourth quarter of the year ended December 31, 2004, no equity securities of the Company of any class registered by the Company 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.

25

ITEM 6.   Selected Financial Data.

In the following table, the Company’s financial, production and other data for 2001 through 2004 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.”

26

(a)           The Company’s financial statements for 2000—2001 were audited by Arthur Andersen LLP, who have ceased operations.

(b)          Effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accounting for Asset Retirement Obligations.” This new accounting standard required a change in the accounting for asset retirement obligations. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Application of Critical Accounting Policies and Management’s Estimates, Future Development and Abandonment Costs” for further discussion of the provisions of SFAS 143.

(c)           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. Effective January 1, 2000, the Company adopted the provisions of the Securities and Exchange Commission’s (the “SEC”) Staff Accounting Bulletin No. 101, Revenue Recognition, and revised its long-standing historical practice of recording such product inventories at their net realizable value. The cumulative effect of this change in accounting principle through December 31, 1999 ($1,768,000, net of tax benefits of $1,768,000) was charged to earnings effective January 1, 2000.

27

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