Use these links to rapidly review the documentPART III

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K

|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

Commission File No. 1-7792

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

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)


Registrant's telephone number, including area code:(713) 297-5000

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

|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                   

Securities registered pursuant to Section 12(g) of the Act:
None

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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes 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.

DOCUMENT INCORPORATED BY REFERENCE

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.

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FORWARD LOOKING STATEMENTS

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.

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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 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.

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 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.

Domestic Offshore Operations

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

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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

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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. 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

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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.

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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.

International Operations

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.

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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

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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

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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

9

---

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.

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.

10

---

Miscellaneous



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.

11

---

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

12

---

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.

13

---



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.

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.



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

14

---

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

NetDomestic OffshoreLouisiana

142,126

52,498

137,604

101,324Texas

17,280

6,141

23,040

5,904Total Domestic Offshore

159,406

58,639

160,644

107,228Domestic OnshoreLouisiana

9,407

2,577

9,334

3,279Mississippi

1,280

26



New Mexico

54,357

38,505

74,879

57,510Texas

185,262

85,950

63,523

41,909Wyoming

29,205

3,700

50,614

20,287Other

6,120

2,211

80

15Total Domestic Onshore

285,631

132,969

198,430

123,000Total Domestic

445,037

191,608

359,074

230,228InternationalGulf of Thailand

415,824

192,698

318,444

147,572North Sea





81,000

32,400Hungary





764,315

764,315Total International

415,824

192,698

1,163,759

944,287Total 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

15

---

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

2003

2002

2001Average Production (Lifting) Costs per Mcfe(a)(b):Located in the United States

$
0.68

$
0.69

$
0.81Located in the Kingdom of Thailand

$
0.67

$
0.59

$
0.65Total Company

$
0.68

$
0.66

$
0.76


---



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.

Oil Wells(a)(b)

Natural Gas
Wells(a)(b)Gross

Net

Gross

NetDomestic Offshore

143

45.80

66

22.45Domestic Onshore

937

658.90

944

457.07Kingdom of Thailand

87

40.30

55

25.50Hungary





1

1.00Total

1,167

745.00

1,066

506.02


---

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

16

---

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

2001Productive

Dry

Productive

Dry

Productive

DryGross Wells:Offshore United StatesExploratory

5.0

2.0

5.0

2.0

2.0

3.0Development

3.0



13.0



22.0

Onshore North America(a)Exploratory

9.0

3.0

1.0

4.0

7.0

3.0Development

169.0

9.0

83.0

5.0

61.0

3.0Offshore Kingdom of ThailandExploratory

5.0

1.0

6.0



11.0

Development

40.0

1.0

51.0

2.0

18.0

EuropeExploratory

1.0









Development











Total

232.0

16.0

159.0

13.0

121.0

9.0Net Wells:Offshore United StatesExploratory

2.3

2.0

5.0

2.0

2.0

1.7Development

2.2



8.8



8.3

Onshore North America(a)Exploratory

5.9

2.0

0.8

3.2

5.0

1.3Development

75.9

3.5

54.7

3.4

38.0

1.6Offshore Kingdom of ThailandExploratory

2.3

0.5

2.8



5.1

Development

18.5

0.5

23.5

0.9

8.3

EuropeExploratory

1.0









Development











Total

108.1

8.5

95.6

9.5

66.7

4.6


---

17

---





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.

|                                 |                                                                                    | As of December 31,                
|-------------------------------- | ---------------------------------------------------------------------------------- | ----------------------------------
|
|Total Proved Reserves:           |                                                                                    |                                   
|                                 | Oil, condensate and natural gas liquids (MBbls)                                    |                                   
|                                 |                                                                                    | Located in North America          
|                                 |                                                                                    | Located in the Kingdom of Thailand
|                                 |                                                                                    | Located in Hungary                
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 | Natural Gas (MMcf)                                                                 |                                   
|                                 |                                                                                    | Located in North America          
|                                 |                                                                                    | Located in the Kingdom of Thailand
|                                 |                                                                                    | Located in Hungary                
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 | Present value of estimated future net revenues, before income taxes (in thousands) |                                   
|                                 |                                                                                    | Located in North America          
|                                 |                                                                                    | Located in the Kingdom of Thailand
|                                 |                                                                                    | Located in Hungary                
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|Total Proved Developed Reserves: |                                                                                    |                                   
|                                 | Oil, condensate and natural gas liquids (MBbls)                                    |                                   
|                                 |                                                                                    | Located in North America          
|                                 |                                                                                    | Located in the Kingdom of Thailand
|                                 |                                                                                    | Located in Hungary                
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 | Natural Gas (MMcf)                                                                 |                                   
|                                 |                                                                                    | Located in North America          
|                                 |                                                                                    | Located in the Kingdom of Thailand
|                                 |                                                                                    | Located in Hungary                
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 | Present value of estimated future net revenues, before income taxes (in thousands) |                                   
|                                 |                                                                                    | Located in North America          
|                                 |                                                                                    | Located in the Kingdom of Thailand
|                                 |                                                                                    | Located in Hungary                
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   
|                                 |                                                                                    |                                   

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

18

---

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

2001Initial Weighted Average Price (in Dollars):Oil, condensate and natural gas liquids (per Bbl)Located in North America(a)

$
31.34

$
28.72

$
18.75Located in the Kingdom of Thailand

$
30.27

$
32.41

$
18.94Located in Hungary

$
26.00

$


$
Natural Gas (per Mcf)Located in North America(a)

$
5.70

$
4.70

$
2.48Located in the Kingdom of Thailand

$
2.51

$
2.24

$
2.31Located 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

19

---

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.

Government Regulations



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"

20

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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

21

---

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.

Employees

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.

22

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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:



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 immaterial at this time. See "BusinessGovernment Regulation; Other Laws and Regulations."

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, 2003.

23

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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, 2003, and the year each was elected to his current position are as follows:

Executive Officer

Executive Office

Age

Year
ElectedPaul G. Van Wagenen

Chairman, President and Chief Executive Officer

57

1991Stephen R. Brunner

Executive Vice PresidentOperations

45

2002Stuart P. Burbach

Executive Vice PresidentExploration

51

1998Jerry A. Cooper

Executive Vice President and Regional ManagerWestern United States

55

2002John O. McCoy, Jr.

Executive Vice President and Chief Administrative Officer

52

2002David R. Beathard

Senior Vice PresidentEngineering

45

2002Gerald A. Morton

Senior Vice President and Regional ManagerAsia and Pacific and Corporate Secretary

45

2003James P. Ulm, II

Senior Vice President and Chief Financial Officer

40

2002Thomas E. Hart

Vice President and Chief Accounting Officer

60

1999Michael 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.

24

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PART II

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.

Low

High20021st Quarter

$
23.00

$
31.752nd Quarter

$
29.44

$
35.493rd Quarter

$
25.44

$
34.714th Quarter

$
31.90

$
39.2820031st Quarter

$
34.29

$
39.982nd Quarter

$
38.68

$
45.413rd Quarter

$
40.30

$
46.424th 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.

25

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ITEM 6.Selected Financial Data.

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."

|                                                                         |                                                                           | For the Year Ended December 31, |          
|------------------------------------------------------------------------ | ------------------------------------------------------------------------- | ------------------------------- | ---------
|
|
|Financial Data                                                           |                                                                           |                                 |          
|Revenues:                                                                |                                                                           |                                 |          
|                                                                         | Crude oil and condensate                                                  |                                 | $        
|                                                                         | Natural gas                                                               |                                 |          
|                                                                         | Natural gas liquids                                                       |                                 |          
|                                                                         |                                                                           |                                 |          
|                                                                         | Oil and gas revenues                                                      |                                 |          
|                                                                         | Other                                                                     |                                 |          
|                                                                         |                                                                           |                                 |          
|                                                                         |                                                                           | Total                           |          
|                                                                         |                                                                           |                                 |          
|Income (loss) before cumulative effect of change in accounting principle |                                                                           | $                               | 295,107  
|Cumulative effect of change in accounting principle                      |                                                                           |                                 | (4,166   
|                                                                         |                                                                           |                                 |          
|Net income (loss)                                                        |                                                                           | $                               | 290,941  
|                                                                         |                                                                           |                                 |          
|Per share data:                                                          |                                                                           |                                 |          
|                                                                         | Income (loss) before cumulative effect of change in accounting principle |                                 |          
|                                                                         |                                                                           | Basic                           |          
|                                                                         |                                                                           | Diluted                         |          
|                                                                         | Cash dividends on common stock                                            |                                 | $        
|                                                                         | Price range of common stock:                                              |                                 |          
|                                                                         |                                                                           | High                            |          
|                                                                         |                                                                           | Low                             |          
|Weighted average number of common shares outstanding                     |                                                                           |                                 | 62,538   
|Long-term debt at year end                                               |                                                                           | $                               | 487,261  
|Minority interest at year end                                            |                                                                           | $                               |         
|Shareholders' equity at year end                                         |                                                                           | $                               | 1,453,653
|Total assets at year end                                                 |                                                                           | $                               | 2,762,036
|Production (Sales) Data                                                  |                                                                           |                                 |          
|Net daily average production and weighted average price:                 |                                                                           |                                 |          
|                                                                         | Natural gas (Mcf per day)                                                 |                                 |          
|                                                                         |                                                                           | Price (per Mcf)                 |          
|                                                                         | Crude oil-condensate (Bbl per day)                                        |                                 |          
|                                                                         |                                                                           | Price (per Bbl)                 |          
|                                                                         | Natural gas liquids (Bbl per day)                                         |                                 |          
|                                                                         |                                                                           | Price (per Bbl)                 |          

26

---

|                                                      |                        | For the Year Ended December 31,
|----------------------------------------------------- | ---------------------- | -------------------------------
|
|
|Capital Expenditures
(including interest capitalized) |                        |                                
|Oil and gas:                                          |                        |                                
|                                                      | Domestic Offshore     |                                
|                                                      |                        | Exploration                    
|                                                      |                        | Development                    
|                                                      |                        | Purchase of reserves           
|                                                      | Onshore North America |                                
|                                                      |                        | Exploration                    
|                                                      |                        | Development                    
|                                                      |                        | Purchase of reserves           
|                                                      | International         |                                
|                                                      |                        | Exploration                    
|                                                      |                        | Development                    
|                                                      |                        | Purchase of reserves           
|                                                      |                        |                                
|                                                      | Total oil and gas      |                                
|Other                                                 |                        |                                
|                                                      |                        |                                
|                                                      | Total                  |                                
|                                                      |                        |                                

---

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

27

---

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.

Executive Overview

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.

28

---

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.

Results of Operations



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
2001Increase (decrease) in oil and gas revenues resulting from variances in:Natural gasPrice

$
152,879

$
(71,612
)Production


28,749


43,428181,628


(28,184
)Crude oil and condensatePrice


72,984


9,866Production


146,581


160,677219,565


170,543Natural gas liquids ("NGL")


7,950


11,965Increase 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.

29

---

2003

2002

% Change
2003
to
2002

2001

% Change
2002
to
2001Comparison of Increases (Decreases) in:Natural GasAverage pricesNorth 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
%


---

30

---



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

31

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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  | %                     | $          
|                                                         | Kingdom of Thailand          |                                | $            | 41,367,000  |             | $                     | 38,247,000  |             | 8   | %                     | $          
|                                                         |                              |                                |              |             |             |                       |             |             |     |                       |            
|                                                         |                              | Total Lease Operating Expenses |              | $           | 123,098,000 |                       | $           | 112,663,000 |     | 9                     | %          
|                                                         |                              |                                |              |             |             |                       |             |             |     |                       |            
|General and Administrative Expenses                      |                              | $                              | 61,291,000   |             | $           | 49,490,000            |             | 24          | %   | $                     | 39,162,000 
|Exploration Expenses                                     |                              | $                              | 7,547,000    |             | $           | 4,783,000             |             | 58          | %   | $                     | 23,373,000 
|Dry Hole and Impairment Expenses                         |                              | $                              | 35,102,000   |             | $           | 26,999,000            |             | 30          | %   | $                     | 26,945,000 
|Depreciation, Depletion and Amortization (DD&A) Expenses |                              | $                              | 325,820,000  |             | $           | 287,809,000           |             | 13          | %   | $                     | 206,609,000
|                                                         | DD&A rate                    |                                | $            | 1.29        |             | $                     | 1.33        |             | (3  | )%                    | $          
|                                                         | Mcfe sold                    |                                |              | 253,422,703 |             |                       | 215,728,000 |             | 17  | %                     |            
|Production and Other Taxes                               |                              | $                              | 35,485,000   |             | $           | 20,058,000            |             | 77          | %   | $                     | 22,007,000 
|Transportation and Other                                 |                              | $                              | 25,924,000   |             | $           | 12,879,000            |             | 101         | %   | $                     | 19,447,000 
|Interest                                                |                              |                                |              |             |             |                       |             |             |     |                       |            
|                                                         | Charges                      |                                | $            | (46,360,000 | )           | $                     | (57,450,000 | )           | (19 | )%                    | $          
|                                                         | Capitalized Interest Expense |                                | $            | 16,531,000  |             | $                     | 24,033,000  |             | (31 | )%                    | $          
|Loss on debt extinguishment                              |                              | $                              | (5,893,000   | )           | $           |                      |             | N/M         |     | $                     |           
|Minority InterestDividends and Costs                    |                              | $                              |             |             | $           | (4,140,000            | )           | N/M         |     | $                     | (9,999,000 
|Income Tax Expense                                       |                              | $                              | (220,122,000 | )           | $           | (97,780,000           | )           | 125         | %   | $                     | (61,613,000



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

32

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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

33

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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.

34

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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

35

---

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,

36

---

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.

Liquidity and Capital Resources

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.

37

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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 YearsLong Term Debt

$
489.0

$
0.0

$
139.0

$
0.0

$
350.0Operating Leases(a)

$
144.3

$
22.3

$
43.9

$
34.1

$
44.0Purchase Obligations(b)

$
64.9

$
19.0

$
25.9

$
8.6

$
11.4Asset Retirement Obligations (c)

$
236.4

$
1.7

$
7.5

$
14.7

$
212.5Total

$
934.6

$
43.0

$
216.3

$
57.4

$
617.9


---

38

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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

39

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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.

Application of Critical Accounting Policies and Management's Estimates

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

40

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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.

41

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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

42

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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

43

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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."

44

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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

45

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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.

ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk.

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

Commodity Price Risk

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."

Interest Rate Risk

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:

|                |                       | 2004 |   | 2005 |  | 2006 |   | 2007 |   | 2008    |   | Thereafter |   | Total |   | Fair Value
|--------------- | --------------------- | ---- | - | ---- |  | ---- | - | ---- | - | ------- | - | ---------- | - | ----- | - | ----------
|Long-Term Debt: |                       |      |   |      |  |      |   |      |   |         |   |            |   |       |   |           
|                | Variable Rate         |      | $ | 0    |  | $    | 0 |      | $ | 139,000 |   | $          | 0 |       | $ | 0         
|                | Average Interest Rate |      |   |     |  |      |  |      |   | 2.31    | % |            |  |       |   |          
|                | Fixed Rate            |      | $ | 0    |  | $    | 0 |      | $ | 0       |   | $          | 0 |       | $ | 0         
|                | Average Interest Rate |      |   |     |  |      |  |      |   |        |   |            |  |       |   |          

Foreign Currency Exchange Rate Risk

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

46

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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.

Current Hedging Activity

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.

47

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ITEM 8.Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT AUDITORS

To
the Shareholders and Board of
Directors of Pogo Producing Company:

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.

PRICEWATERHOUSECOOOPERS
LLP

Houston,
Texas
February 24, 2004

48

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REPORTS OF INDEPENDENT PUBLIC ACCOUNTANTS

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.

To
the Shareholders and Board of
Directors of Pogo Producing Company:

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.

ARTHUR
ANDERSEN LLP

Houston,
Texas
February 28, 2002

49

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POGO PRODUCING COMPANY & SUBSIDIARIES    CONSOLIDATED STATEMENTS OF INCOME

|                                                                                                                                    |                                          | Year Ended December 31,                                           |         
|----------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------- | ----------------------------------------------------------------- | --------
|
|
|Revenues:                                                                                                                           |                                          |                                                                   |         
|                                                                                                                                    | Oil and gas                              |                                                                   | $       
|                                                                                                                                    | Other                                    |                                                                   |         
|                                                                                                                                    |                                          |                                                                   |         
|                                                                                                                                    |                                          | Total                                                             |         
|                                                                                                                                    |                                          |                                                                   |         
|Operating Costs and Expenses:                                                                                                       |                                          |                                                                   |         
|                                                                                                                                    | Lease operating                          |                                                                   |         
|                                                                                                                                    | General and administrative               |                                                                   |         
|                                                                                                                                    | Exploration                              |                                                                   |         
|                                                                                                                                    | Dry hole and impairment                  |                                                                   |         
|                                                                                                                                    | Depreciation, depletion and amortization |                                                                   |         
|                                                                                                                                    | Production and other taxes               |                                                                   |         
|                                                                                                                                    | Transportation and other                 |                                                                   |         
|                                                                                                                                    |                                          |                                                                   |         
|                                                                                                                                    |                                          | Total                                                             |         
|                                                                                                                                    |                                          |                                                                   |         
|Operating Income                                                                                                                    |                                          |                                                                   | 547,729 
|Interest:                                                                                                                           |                                          |                                                                   |         
|                                                                                                                                    | Charges                                  |                                                                   |         
|                                                                                                                                    | Income                                   |                                                                   |         
|                                                                                                                                    | Capitalized                              |                                                                   |         
|Loss on debt extinguishment                                                                                                         |                                          |                                                                   | (5,893  
|Minority InterestDividends and costs associated with mandatorily redeemable convertible preferred securities of a subsidiary trust |                                          |                                                                   |        
|Foreign Currency Transaction Gain (Loss)                                                                                            |                                          |                                                                   | 1,370   
|                                                                                                                                    |                                          |                                                                   |         
|Income Before Taxes and Cumulative Effect of Change in Accounting Principle                                                         |                                          |                                                                   | 515,229 
|Income Tax Expense                                                                                                                  |                                          |                                                                   | (220,122
|                                                                                                                                    |                                          |                                                                   |         
|Income Before Cumulative Effect of Change in Accounting Principle                                                                   |                                          |                                                                   | 295,107 
|Cumulative Effect of Change in Accounting Principle                                                                                 |                                          |                                                                   | (4,166  
|                                                                                                                                    |                                          |                                                                   |         
|Net Income                                                                                                                          |                                          | $                                                                 | 290,941 
|                                                                                                                                    |                                          |                                                                   |         
|Earnings (Loss) per Common Share:                                                                                                   |                                          |                                                                   |         
|                                                                                                                                    | Basic                                    |                                                                   |         
|                                                                                                                                    |                                          | Income before cumulative effect of change in accounting principle |         
|                                                                                                                                    |                                          | Cumulative effect of change in accounting principle               |         
|                                                                                                                                    |                                          |                                                                   |         
|                                                                                                                                    |                                          | Net income                                                        |         
|                                                                                                                                    |                                          |                                                                   |         
|                                                                                                                                    | Diluted                                  |                                                                   |         
|                                                                                                                                    |                                          | Income before cumulative effect of change in accounting principle |         
|                                                                                                                                    |                                          | Cumulative effect of change in accounting principle               |         
|                                                                                                                                    |                                          |                                                                   |         
|                                                                                                                                    |                                          | Net income                                                        |         
|                                                                                                                                    |                                          |                                                                   |         
|Dividends per Common Share                                                                                                          |                                          | $                                                                 | 0.20    
|                                                                                                                                    |                                          |                                                                   |         

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

50

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POGO PRODUCING COMPANY & SUBSIDIARIES    CONSOLIDATED BALANCE SHEETS

|                        |                                                            | December 31,           |           
|----------------------- | ---------------------------------------------------------- | ---------------------- | ----------
|
|
|ASSETS                  |                                                           
|Current Assets:         |                                                            |                        |           
|                        | Cash and cash equivalents                                  |                        | $         
|                        | Accounts receivable                                        |                        |           
|                        | Other receivables                                          |                        |           
|                        | Deferred income tax                                        |                        |           
|                        | Inventoryproduct                                          |                        |           
|                        | Inventoriestubulars                                       |                        |           
|                        | Other                                                      |                        |           
|                        |                                                            |                        |           
|                        |                                                            | Total current assets   |           
|                        |                                                            |                        |           
|Property and Equipment: |                                                            |                        |           
|                        | Oil and gas, on the basis of successful efforts accounting |                        |           
|                        |                                                            | Proved properties      |           
|                        |                                                            | Unevaluated properties |           
|                        | Other, at cost                                             |                        |           
|                        |                                                            |                        |           
|                        |                                                            |                        | 4,056,892 
|                        |                                                            |                        |           
|                        | Accumulated depreciation, depletion, and amortization      |                        |           
|                        |                                                            | Oil and gas            |           
|                        |                                                            | Other                  |           
|                        |                                                            |                        |           
|                        |                                                            |                        | (1,681,051
|                        |                                                            |                        |           
|                        | Property and equipment, net                                |                        |           
|                        |                                                            |                        |           
|Other Assets:           |                                                            |                        |           
|                        | Deferred income tax                                        |                        |           
|                        | Foreign value added taxes receivable                       |                        |           
|                        | Other                                                      |                        |           
|                        |                                                            |                        |           
|                        |                                                            |                        | 31,840    
|                        |                                                            |                        |           
|                        |                                                            | $                      | 2,762,036 
|                        |                                                            |                        |           

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

51

---



POGO PRODUCING COMPANY & SUBSIDIARIES    CONSOLIDATED BALANCE SHEETS

|                                       |                                                                                                                    | December 31,               |          
|-------------------------------------- | ------------------------------------------------------------------------------------------------------------------ | -------------------------- | ---------
|
|
|LIABILITIES AND SHAREHOLDERS' EQUITY   |                                                                                                                   
|Current Liabilities:                   |                                                                                                                    |                            |          
|                                       | Accounts payableoperating activities                                                                              |                            | $        
|                                       | Accounts payableinvesting activities                                                                              |                            |          
|                                       | Income taxes payable                                                                                               |                            |          
|                                       | Accrued interest payable                                                                                           |                            |          
|                                       | Accrued payroll and related benefits                                                                               |                            |          
|                                       | Deferred income tax                                                                                                |                            |          
|                                       | Other                                                                                                              |                            |          
|                                       |                                                                                                                    |                            |          
|                                       |                                                                                                                    | Total current liabilities  |          
|Long-Term Debt                         |                                                                                                                    |                            | 487,261  
|Deferred Income Tax                    |                                                                                                                    |                            | 546,709  
|Asset Retirement Obligation            |                                                                                                                    |                            | 70,790   
|Other Liabilities and Deferred Credits |                                                                                                                    |                            | 20,039   
|                                       |                                                                                                                    |                            |          
|                                       | Total liabilities                                                                                                  |                            |          
|                                       |                                                                                                                    |                            |          
|Commitments and Contingencies (Note 5) |                                                                                                                    |                            |         
|                                       |                                                                                                                    |                            |          
|Shareholders' Equity:                  |                                                                                                                    |                            |          
|                                       | Preferred stock, $1 par; 4,000,000 shares authorized                                                               |                            |          
|                                       | Common stock, $1 par; 200,000,000 shares authorized, and and 63,813,283 and 61,061,888 shares issued, respectively |                            |          
|                                       | Additional capital                                                                                                 |                            |          
|                                       | Retained earnings                                                                                                  |                            |          
|                                       | Accumulated other comprehensive income (loss)                                                                      |                            |          
|                                       | Deferred compensation                                                                                              |                            |          
|                                       | Treasury stock (55,359 shares), at cost                                                                            |                            |          
|                                       |                                                                                                                    |                            |          
|                                       |                                                                                                                    | Total shareholders' equity |          
|                                       |                                                                                                                    |                            |          
|                                       |                                                                                                                    | $                          | 2,762,036
|                                       |                                                                                                                    |                            |          

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

52

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POGO PRODUCING COMPANY & SUBSIDIARIES    CONSOLIDATED STATEMENTS OF CASH FLOWS

|                                                                           |                                                                                  | Year Ended December 31,                             |                                                 
|-------------------------------------------------------------------------- | -------------------------------------------------------------------------------- | --------------------------------------------------- | ------------------------------------------------
|
|
|Cash flows from operating activities:                                      |                                                                                  |                                                     |                                                 
|                                                                           | Cash received from customers                                                     |                                                     | $                                               
|                                                                           | Operating, exploration and general and administrative expenses paid              |                                                     |                                                 
|                                                                           | Income taxes paid                                                                |                                                     |                                                 
|                                                                           | Income taxes received                                                            |                                                     |                                                 
|                                                                           | Interest paid                                                                    |                                                     |                                                 
|                                                                           | Cash received (paid) related to price hedge contracts                            |                                                     |                                                 
|                                                                           | Value added taxes (paid) received                                                |                                                     |                                                 
|                                                                           | Other                                                                            |                                                     |                                                 
|                                                                           |                                                                                  |                                                     |                                                 
|                                                                           |                                                                                  | Net cash provided by operating activities           |                                                 
|                                                                           |                                                                                  |                                                     |                                                 
|Cash flows from investing activities:                                      |                                                                                  |                                                     |                                                 
|                                                                           | Capital expenditures                                                             |                                                     |                                                 
|                                                                           | Purchase of properties                                                           |                                                     |                                                 
|                                                                           | Proceeds from the sale of property and tubular stock                             |                                                     |                                                 
|                                                                           | Acquisition of NORIC, net of $21,235,000 cash acquired                           |                                                     |                                                 
|                                                                           | Proceeds from the sale of Canadian subsidiary                                    |                                                     |                                                 
|                                                                           |                                                                                  |                                                     |                                                 
|                                                                           |                                                                                  | Net cash used in investing activities               |                                                 
|                                                                           |                                                                                  |                                                     |                                                 
|Cash flows from financing activities:                                      |                                                                                  |                                                     |                                                 
|                                                                           | Borrowings under senior debt agreements                                          |                                                     |                                                 
|                                                                           | Payments under senior debt agreements                                            |                                                     |                                                 
|                                                                           | Redemption of debt                                                               |                                                     |                                                 
|                                                                           | Proceeds from exercise of stock options                                          |                                                     |                                                 
|                                                                           | Payment of cash dividends on common stock                                        |                                                     |                                                 
|                                                                           | Proceeds from issuance of new debt                                               |                                                     |                                                 
|                                                                           | Payment of North Central senior debt acquired                                    |                                                     |                                                 
|                                                                           | Payment of preferred dividends of a subsidiary trust                             |                                                     |                                                 
|                                                                           | Payment of financing issue costs and other                                       |                                                     |                                                 
|                                                                           |                                                                                  |                                                     |                                                 
|                                                                           |                                                                                  | Net cash (used in) provided by financing activities |                                                 
|                                                                           |                                                                                  |                                                     |                                                 
|Effect of exchange rate changes on cash                                    |                                                                                  |                                                     | 739                                             
|                                                                           |                                                                                  |                                                     |                                                 
|Net increase in cash and cash equivalents                                  |                                                                                  |                                                     | 44,305                                          
|Cash and cash equivalents at the beginning of the year                     |                                                                                  |                                                     | 134,449                                         
|                                                                           |                                                                                  |                                                     |                                                 
|Cash and cash equivalents at the end of the year                           |                                                                                  | $                                                   | 178,754                                         
|                                                                           |                                                                                  |                                                     |                                                 
|Reconciliation of net income to net cash provided by operating activities: |                                                                                  |                                                     |                                                 
|                                                                           | Net income                                                                       |                                                     | $                                               
|                                                                           | Adjustments to reconcile net income to net cash provided by operating activities |                                                     |                                                 
|                                                                           |                                                                                  | Cumulative effect of change in accounting principle |                                                 
|                                                                           |                                                                                  | Minority interest                                   |                                                 
|                                                                           |                                                                                  | Gains on sales                                      |                                                 
|                                                                           |                                                                                  | Depreciation, depletion and amortization            |                                                 
|                                                                           |                                                                                  | Dry hole and impairment                             |                                                 
|                                                                           |                                                                                  | Interest capitalized                                |                                                 
|                                                                           |                                                                                  | Price hedge contracts                               |                                                 
|                                                                           |                                                                                  | Other                                               |                                                 
|                                                                           |                                                                                  | Increase (decrease) in deferred income taxes        |                                                 
|                                                                           |                                                                                  | Change in assets and liabilities:                   |                                                 
|                                                                           |                                                                                  |                                                     | (Increase) decrease in accounts receivable      
|                                                                           |                                                                                  |                                                     | Increase in federal income taxes receivable     
|                                                                           |                                                                                  |                                                     | (Increase) decrease in inventoryproduct        
|                                                                           |                                                                                  |                                                     | Increase in other current assets                
|                                                                           |                                                                                  |                                                     | (Increase) decrease in other assets             
|                                                                           |                                                                                  |                                                     | Increase (decrease) in accounts payable         
|                                                                           |                                                                                  |                                                     | Increase in income taxes payable                
|                                                                           |                                                                                  |                                                     | Increase (decrease) in accrued interest payable 
|                                                                           |                                                                                  |                                                     | Increase in accrued payroll and related benefits
|                                                                           |                                                                                  |                                                     | Increase (decrease) in other current liabilities
|                                                                           |                                                                                  |                                                     | Increase in deferred credits                    
|                                                                           |                                                                                  |                                                     |                                                 
|Net cash provided by operating activities                                  |                                                                                  | $                                                   | 744,559                                         
|                                                                           |                                                                                  |                                                     |                                                 

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

53

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POGO PRODUCING COMPANY & SUBSIDIARIES    CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY  (Expressed in thousands)

|                                                                  |                                                    | 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  
|Net income                                                        |                                                    |                |   |                    |        |                             |   | 87,954                                        |   |                                        |        |                |   |                     |   |                             |      
|Shares issued for stock and debt of acquired company              |                                                    | 12,615          |   |                    | 351,729 |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Exercise of stock options                                         |                                                    | 378             |   |                    | 7,718   |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Shares issued as compensation                                     |                                                    | 38              |   |                    | 895     |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Dividends ($0.12 per common share)                                |                                                    |                |   |                    |        |                             |   | (6,047                                        | ) |                                        |        |                |   |                     |   |                             |      
|Exchange gain on Canadian currency                                |                                                    |                |   |                    |        |                             |   |                                              |   |                                        | 389     |                |   |                     |   |                             |      
|                                                                  | Reclassification adjustment included in net income |                 |  |                    |         |                            |   |                                               |  |                                        |         | 673            |   |                      |  |                             |       
|Cumulative effect of change in accounting principle               |                                                    |                |   |                    |        |                             |   |                                              |   |                                        | (2,438  | )              |   |                     |   |                             |      
|Unrealized gains arising during the year on price hedge contracts |                                                    |                |   |                    |        |                             |   |                                              |   |                                        | 22,195  |                |   |                     |   |                             |      
|                                                                  | Reclassification adjustment included in net income |                 |  |                    |         |                            |   |                                               |  |                                        |         | (9,485         | ) |                      |  |                             |       
|                                                                  | Net unrealized gains on price hedge contracts      |                 |  |                    |         |                            |   |                                               |  |                                        |         |               |   |                      |  |                             |       
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       
|Comprehensive income                                              |                                                    |                |   |                    |        |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       
|Balance at December 31, 2001                                      |                                                    | 53,691          |   | $                  | 659,227 |                             | $ | 102,019                                       |   | $                                      | 10,272  |                | $ |                     |   | $                           | (324  
|Net income                                                        |                                                    |                |   |                    |        |                             |   | 107,031                                       |   |                                        |        |                |   |                     |   |                             |      
|Exercise of stock options                                         |                                                    | 1,022           |   |                    | 23,460  |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Shares issued as compensation                                     |                                                    | 39              |   |                    | 1,124   |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Conversion of Trust Preferred Securities                          |                                                    | 6,310           |   |                    | 138,715 |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Dividends ($0.12 per common share)                                |                                                    |                |   |                    |        |                             |   | (6,895                                        | ) |                                        |        |                |   |                     |   |                             |      
|Shares received in satisfaction of note receivable                |                                                    |                |   |                    |        |                             |   |                                              |   |                                        |        |                |   |                     |   |                             | (1,386
|Unrealized loss arising during the year on price hedge contracts  |                                                    |                |   |                    |        |                             |   |                                              |   |                                        | (14,155 | )              |   |                     |   |                             |      
|                                                                  | Reclassification adjustment included in net income |                 |  |                    |         |                            |   |                                               |  |                                        |         | (2,366         | ) |                      |  |                             |       
|                                                                  | Net unrealized losses on price hedge contracts     |                 |  |                    |         |                            |   |                                               |  |                                        |         |               |   |                      |  |                             |       
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       
|Comprehensive income                                              |                                                    |                |   |                    |        |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       
|Balance at December 31, 2002                                      |                                                    | 61,062          |   | $                  | 822,526 |                             | $ | 202,155                                       |   | $                                      | (6,249  | )              | $ |                     |   | $                           | (1,710
|Net income                                                        |                                                    |                 |   |                    |         |                             |   | 290,941                                       |   |                                        |         |                |   |                      |   |                             |       
|Stock option activity and other                                   |                                                    | 1,573           |   |                    | 43,915  |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Shares issued as compensation                                     |                                                    | 170             |   |                    | 6,865   |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Conversion of 2006 Notes                                          |                                                    | 1,008           |   |                    | 41,186  |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|Issuance of restricted stock, less amortization of $412           |                                                    |                |   |                    |        |                             |   |                                              |   |                                        |        |                |   | (3,518               | ) |                             |      
|Dividends ($0.20 per common share)                                |                                                    |                |   |                    |        |                             |   | (12,520                                       | ) |                                        |        |                |   |                     |   |                             |      
|Unrealized loss arising during the year on price hedge contracts  |                                                    |                |   |                    |        |                             |   |                                              |   |                                        | (8,624  | )              |   |                     |   |                             |      
|                                                                  | Reclassification adjustment included in net income |                 |  |                    |         |                            |   |                                               |  |                                        |         | 14,873         |   |                      |  |                             |       
|                                                                  | Net unrealized gains on price hedge contracts      |                 |  |                    |         |                            |   |                                               |  |                                        |         |               |   |                      |  |                             |       
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       
|Comprehensive income                                              |                                                    |                |   |                    |        |                             |   |                                              |   |                                        |        |                |   |                     |   |                             |      
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       
|Balance at December 31, 2003                                      |                                                    | 63,813          |   | $                  | 914,492 |                             | $ | 480,576                                       |   | $                                      |        |                | $ | (3,518               | ) | $                           | (1,710
|                                                                  |                                                    |                 |   |                    |         |                             |   |                                               |   |                                        |         |                |   |                      |   |                             |       

---

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

54

---



POGO PRODUCING COMPANY & SUBSIDIARIES        NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)   Summary of Significant Accounting Policies



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

55

---

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.

56

---



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.

57

---

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

2001Net income, as reported

$
290,941

$
107,031

$
87,954Add: Employee stock-based compensation expense, net of related tax effects, included in net income, as reported


1,408


756


606Deduct: 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

$
83,445Earnings per share:Basicas reported

$
4.65

$
1.85

$
1.72Basicpro forma

$
4.56

$
1.75

$
1.64Dilutedas reported

$
4.54

$
1.77

$
1.62Diluted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.

58

---



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").

59

---

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.

(2)   Earnings per Share

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, 2003Income(a)

Shares

Per ShareBasic earnings per share

$
295,107

62,538

$
4.72Effect 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




683Interest 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

1,391Diluted earnings per share

$
297,213

64,612

$
4.60Antidilutive 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


---

60

---

For the Year Ended
December 31, 2002Income

Shares

Per ShareBasic earnings per share

$
107,031

57,963

$
1.85Effect 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




980Interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $42.185 per share of the 2006 Notes


4,111

2,726Minority 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

2,652Diluted earnings per share

$
113,803

64,321

$
1.77Antidilutive 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, 2001Income

Shares

Per ShareBasic earnings per share

$
87,954

51,031

$
1.72Effect 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




749Interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $42.185 per share of the 2006 Notes


4,111

2,726Minority 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

6,316Diluted earnings per share

$
98,403

60,822

$
1.62Antidilutive 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


61

---

(3)   Income Taxes

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):

2003

2002

2001United States

$
364,097

$
101,349

$
81,619Foreign


151,132


103,462


67,948Income before income taxes and cumulative effect of change in accounting principle

$
515,229

$
204,811

$
149,567


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):

2003

2002

2001CurrentUnited States

$
116,813

$
15,497

$
Foreign


51,491


11,351


10,996DeferredUnited States


26,375


32,451


59,823Foreign


25,443


38,481


(9,206
)Income tax expense

$
220,122

$
97,780

$
61,613


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

2001Federal statutory income tax rate

35.0
%
35.0
%
35.0
%Increases (reductions) resulting from:Foreign income taxed at different rates

4.6

7.8

11.3Recognition of net operating loss carryforwards





(20.4
)U.S. taxes on repatriation of foreign earnings

1.9

2.3

5.7State income taxes, net of federal benefits

0.7

0.5

4.0Other

0.5

2.2

5.642.7
%
47.8
%
41.2
%


62

---

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

2002Deferred tax assets:Foreign deferred tax assets and net operating loss carry forwards

$
2,795

$
22,700Valuation allowance of foreign deferred tax assets and net operating loss


(379
)

(243
)Tax basis in excess of book basis for price hedge contracts





8,895Other


9,938


3,65412,354


35,006Deferred 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.

63

---

(4)   Long-Term Debt

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

December 31,2003

2002Senior debtBank 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

$
135,000Swing 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)





24,987Total senior debt


139,000


159,987Subordinated debt103/8% Senior subordinated notes, due 2009


150,000


150,00081/4% Senior subordinated notes, due 2011


200,000


200,00051/2% Convertible subordinated notes, due 2006 (redeemed July 7, 2003)





115,00083/4% Senior subordinated notes, due 2007 (redeemed August 6, 2003)





100,000Total subordinated debt


350,000


565,000Unamortized 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.

64

---

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.

65

---

(5)   Commitments and Contingencies

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.

(6)   Geographic Information

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

$
1,748,046Kingdom of Thailand


420,856


378,260


342,411Other


11,421


358


271Total

$
2,375,841

$
2,159,049

$
2,090,728Capital Expenditures:(including interest capitalized)For the year ended December 31,United States

$
376,430

$
269,250

$
1,458,549Kingdom of Thailand


132,409


112,440


73,192Other


11,485





3,071Total

$
520,324

$
381,690

$
1,534,812Revenues:For the year ended December 31,United States

$
858,505

$
542,014

$
422,120Kingdom of Thailand


303,470


212,763


183,074Other


21


77


4,923Total

$
1,161,996

$
754,854

$
610,117Depreciation, depletion, and amortization expense:For the year ended December 31,United States

$
237,853

$
221,646

$
142,643Kingdom of Thailand


87,906


66,099


61,814Other


61


64


2,152Total

$
325,820

$
287,809

$
206,609Operating income (loss):For the year ended December 31,United States

$
399,678

$
138,934

$
113,976Kingdom of Thailand


151,830


103,021


76,493Other


(3,779
)

(1,782
)

(10,588
)Total

$
547,729

$
240,173

$
179,881


66

---

(7)   Sales to Major Customers

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

2001China Intl. United Petroleum and Chemical Co. Ltd.

$
119,444

$
55,140

$
13,665Enron Corp. and affiliates


827


5,594


96,970


(8)   Credit Risk

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.

(9)   Employee Benefit Plans

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

67

---

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 |      
|--------------------------------------- | ---------------------------------------------- | ---------------------------- | ------ | ---------------------------- | -----
|
|Change in benefit obligation            |                                                |                              |        |                              |      
|                                        | Benefit obligation at beginning of year        |                              | $      | 24,297                       |      
|                                        |                                                | Service cost                 |        |                              | 2,248
|                                        |                                                | Interest cost                |        |                              | 1,546
|                                        |                                                | Plan amendments              |        |                              |     
|                                        |                                                | Benefits paid                |        |                              | (340 
|                                        |                                                | Actuarial loss               |        |                              | 1,768
|                                        |                                                |                              |        |                              |      
|                                        | Benefit obligation at end of year              |                              | $      | 29,519                       |      
|                                        |                                                |                              |        |                              |      
|Change in plan assets                   |                                                |                              |        |                              |      
|                                        | Fair value of plan assets at beginning of year |                              | $      | 26,625                       |      
|                                        |                                                | Actual return on plan assets |        |                              | 6,234
|                                        |                                                | Employer contributions       |        |                              |     
|                                        |                                                | Benefits paid                |        |                              | (340 
|                                        |                                                | Administrative expenses      |        |                              | (283 
|                                        |                                                |                              |        |                              |      
|                                        | Fair value of plan assets at end of year       |                              | $      | 32,236                       |      
|                                        |                                                |                              |        |                              |      
|Reconciliation of funded status         |                                                |                              |        |                              |      
|                                        | Funded status                                  |                              | $      | 2,717                        |      
|                                        | Unrecognized actuarial loss                    |                              |        | 9,037                        |      
|                                        | Unrecognized transition (asset) or obligation  |                              |        |                             |      
|                                        | Unrecognized prior service cost                |                              |        | 671                          |      
|                                        |                                                |                              |        |                              |      
|                                        | Prepaid (accrued) benefit cost at year-end     |                              | $      | 12,425                       |      
|                                        |                                                |                              |        |                              |      
|Components of net periodic benefit cost |                                                |                              |        |                              |      
|                                        | Service cost                                   |                              | $      | 2,248                        |      
|                                        | Interest cost                                  |                              |        | 1,546                        |      
|                                        | Expected return on plan assets                 |                              |        | (2,176                       | )    
|                                        | Amortization of prior service cost             |                              |        | 43                           |      
|                                        | Amortization of transition (asset) obligation  |                              |        |                             |      
|                                        | Amortization of net loss                       |                              |        | 1,040                        |      
|                                        |                                                |                              |        |                              |      
|                                        |                                                | $                            | 2,701  |                              | $    
|                                        |                                                |                              |        |                              |      
|Accumulated benefit obligation          |                                                | $                            | 23,591 |                              | $    
|                                        |                                                |                              |        |                              |      

68

---

Plan Assumptions

Retirement Plan

Post-Retirement
Medical Plan2003

2002

2001

2003

2002

2001Plan assumptions to determine benefit obligationsDiscount 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 costDiscount 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 CategoryTarget

2003

2002Equity 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 PointIncrease

DecreaseEffect on total of service and interest cost components for 2003

$
387

$
(310
)Effect on year-end 2003 postretirement benefit obligation

$
2,838

$
(2,305
)


69

---

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.

(10) Stock-Based Compensation Plans

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 Value2003

144,000

$
6,045,8402002

40,065

$
1,192,9352001

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.

70

---



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
PriceOutstanding, December 31, 2000

3,401,854

$
20.46Granted in 2001

1,035,400

$
25.35Exercised in 2001

(377,764
)
$
17.30Canceled in 2001

(206,910
)
$
21.75Outstanding, December 31, 2001

3,852,580

$
22.01Exercisable, December 31, 2001

2,267,561

$
21.09Weighted-average fair value of options granted during 2001



$
11.98Outstanding, December 31, 2001

3,852,580

$
22.01Granted in 2002

960,900

$
29.84Exercised in 2002

(1,022,034
)
$
19.72Canceled in 2002

(44,000
)
$
23.49Outstanding, December 31, 2002

3,747,446

$
24.62Exercisable, December 31, 2002

1,992,883

$
22.41Weighted-average fair value of options granted during 2002



$
12.43Outstanding, December 31, 2002

3,747,446

$
24.54Granted in 2003

403,000

$
42.02Exercised in 2003

(1,553,573
)
$
21.48Canceled in 2003

(14,100
)
$
17.14Outstanding, December 31, 2003

2,582,773

$
29.16Exercisable, December 31, 2003

1,258,999

$
25.75Weighted-average fair value of options granted during 2003



$
9.61


71

---

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

Options Outstanding

Options ExercisableRange 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

$
40.92Total

2,582,773

2,769

$
29.16

1,258,999

$
25.75


(11) Change in Accounting Principle

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):

Year Ended
December 31, 2003Initial ARO as of January 1, 2003

$
63,643Liabilities incurred during period


3,001Liabilities settled during period


(691
)Accretion expense


4,837Balance of ARO as of December 31, 2003

$
70,790


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

72

---

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, 2001As
Reported

Pro forma

As
Reported

Pro formaNet Income

$
107,031

$
106,662

$
87,954

$
85,873Earnings per share:Basic

$
1.85

$
1.84

$
1.72

$
1.68Diluted

$
1.77

$
1.76

$
1.62

$
1.58


(12) Acquisition

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

73

---

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.

Year Ended December 31, 2001Revenues

$
668,480Income before cumulative effect of change in accounting principle

$
104,348Net income

$
104,348Earnings per share:BasicIncome before cumulative effect of change in accounting principle

$
1.95Net income

$
1.95DilutedIncome before cumulative effect of change in accounting principle

$
1.81Net income

$
1.81


(13) Minority Interest

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.

(14) Fair Value of Financial Instruments

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.



Fair value is carrying value.



Fair value is approximately carrying value.



Fair value is carrying value.

74

---



|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

2002Carrying
Value

Fair
Value

Carrying
Value

Fair
ValueCash and cash equivalents

$
178,754

$
178,754

$
134,449

$
134,449Receivables

$
156,467

$
156,467

$
116,441

$
116,441Payables

$
(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.

(15) Hedging Activities

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.

75

---



POGO PRODUCING COMPANY & SUBSIDIARIES        UNAUDITED SUPPLEMENTARY FINANCIAL DATA



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)2003Revenues

$
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
)2002Revenues

$
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
)

14Operating results

$
163,341

$
117,708

$
45,697

$
(64
)2001Revenues

$
596,077

$
408,514

$
183,005

$
4,558Lease 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
)

2,330Operating results

$
127,336

$
97,683

$
36,285

$
(6,632
)


---

76

---

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

|                                                         |                                                        | Total
Company                    |             | United
States |           | Kingdom of
Thailand |         | Other
International(a)
|-------------------------------------------------------- | ------------------------------------------------------ | -------------------------------- | ----------- | ------------- | --------- | ------------------- | ------- | ----------------------
|Costs incurred
(capitalized unless otherwise indicated): |                                                        |                                  |             |               |           |                     |         |                       
|                                                         | 2003:                                                  |                                  |             |               |           |                     |         |                       
|                                                         |                                                        | Property acquisition             |             |               |           |                     |         |                       
|                                                         |                                                        |                                  | Proved      |               | $         | 177,680             |         | $                     
|                                                         |                                                        |                                  | Unproved    |               |           | 15,540              |         |                       
|                                                         |                                                        | Exploration                      |             |               |           |                     |         |                       
|                                                         |                                                        |                                  | Capitalized |               |           | 59,714              |         |                       
|                                                         |                                                        |                                  | Expensed    |               |           | 7,547               |         |                       
|                                                         |                                                        | Development                      |             |               | 248,348   |                     |         | 131,732               
|                                                         |                                                        | Asset retirement cost(b)         |             |               | 59,142    |                     |         | 49,706                
|                                                         |                                                        | Interest                         |             |               | 16,531    |                     |         | 10,194                
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         |                                                        | Total oil and gas costs incurred |             | $             | 584,502   |                     | $       | 430,524               
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         | Provision for depreciation, depletion and amortization |                                  | $           | 321,572       |           | $                   | 234,579 |                       
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         | 2002:                                                  |                                  |             |               |           |                     |         |                       
|                                                         |                                                        | Property acquisition             |             |               |           |                     |         |                       
|                                                         |                                                        |                                  | Proved      |               | $         |                    |         | $                     
|                                                         |                                                        |                                  | Unproved    |               |           | 8,030               |         |                       
|                                                         |                                                        | Exploration                      |             |               |           |                     |         |                       
|                                                         |                                                        |                                  | Capitalized |               |           | 43,165              |         |                       
|                                                         |                                                        |                                  | Expensed    |               |           | 4,783               |         |                       
|                                                         |                                                        | Development                      |             |               | 303,197   |                     |         | 205,035               
|                                                         |                                                        | Interest                         |             |               | 24,033    |                     |         | 12,892                
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         |                                                        | Total oil and gas costs incurred |             | $             | 383,208   |                     | $       | 270,146               
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         | Provision for depreciation, depletion and amortization |                                  | $           | 283,865       |           | $                   | 218,636 |                       
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         | 2001:                                                  |                                  |             |               |           |                     |         |                       
|                                                         |                                                        | Property acquisition             |             |               |           |                     |         |                       
|                                                         |                                                        |                                  | Proved      |               | $         | 949,704             |         | $                     
|                                                         |                                                        |                                  | Unproved    |               |           | 172,947             |         |                       
|                                                         |                                                        | Exploration                      |             |               |           |                     |         |                       
|                                                         |                                                        |                                  | Capitalized |               |           | 59,390              |         |                       
|                                                         |                                                        |                                  | Expensed    |               |           | 23,373              |         |                       
|                                                         |                                                        | Development                      |             |               | 314,736   |                     |         | 255,800               
|                                                         |                                                        | Interest                         |             |               | 33,242    |                     |         | 27,046                
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         |                                                        | Total oil and gas costs incurred |             | $             | 1,553,392 |                     | $       | 1,465,633             
|                                                         |                                                        |                                  |             |               |           |                     |         |                       
|                                                         | Provision for depreciation, depletion and amortization |                                  | $           | 203,676       |           | $                   | 140,304 |                       
|                                                         |                                                        |                                  |             |               |           |                     |         |                       

---

77

---

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.

Estimates of Proved Reserves        Oil, Condensate and Natural Gas Liquids (Bbls.)

|                                        |                                             | 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 |                     |        

78

---

Estimates of Proved Reserves        Natural Gas (MMcf)

|                                        |                                             | 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  |                     |      

79

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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.

|                                                                                     |                                                      | Year Ended December 31, 2003 |                                                                       
|------------------------------------------------------------------------------------ | ---------------------------------------------------- | ---------------------------- | ----------------------------------------------------------------------
|
|
|Beginning balance                                                                    |                                                      | $                            | 2,055,215                                                             
|Revisions to prior years' proved reserves:                                           |                                                      |                              |                                                                       
|                                                                                     | Net changes in prices and production costs           |                              |                                                                       
|                                                                                     | Net changes due to revisions in quantity estimates   |                              |                                                                       
|                                                                                     | Net changes in estimates of future development costs |                              |                                                                       
|                                                                                     | Accretion of discount                                |                              |                                                                       
|                                                                                     | Changes in production rate and other                 |                              |                                                                       
|                                                                                     |                                                      |                              |                                                                       
|                                                                                     |                                                      | Total revisions              |                                                                       
|New field discoveries and extensions, net of future production and development costs |                                                      |                              | 320,188                                                               
|Purchases of properties                                                              |                                                      |                              | 289,484                                                               
|Sales of oil and gas produced, net of production costs                               |                                                      |                              | (987,981                                                              
|Previously estimated development costs incurred                                      |                                                      |                              | 246,863                                                               
|Net change in income taxes                                                           |                                                      |                              | (196,830                                                              
|                                                                                     |                                                      |                              |                                                                       
|                                                                                     |                                                      |                              | Net change in standardized measure of discounted future net cash flows
|                                                                                     |                                                      |                              |                                                                       
|Ending balance                                                                       |                                                      | $                            | 2,450,030                                                             
|                                                                                     |                                                      |                              |                                                                       

80

---

|                                                                                     |                                                      | Year Ended December 31, 2002 |                                                                       
|------------------------------------------------------------------------------------ | ---------------------------------------------------- | ---------------------------- | ----------------------------------------------------------------------
|
|
|Beginning balance                                                                    |                                                      | $                            | 1,138,048                                                             
|Revisions to prior years' proved reserves:                                           |                                                      |                              |                                                                       
|                                                                                     | Net changes in prices and production costs           |                              |                                                                       
|                                                                                     | Net changes due to revisions in quantity estimates   |                              |                                                                       
|                                                                                     | Net changes in estimates of future development costs |                              |                                                                       
|                                                                                     | Accretion of discount                                |                              |                                                                       
|                                                                                     | Changes in production rate and other                 |                              |                                                                       
|                                                                                     |                                                      |                              |                                                                       
|                                                                                     |                                                      | Total revisions              |                                                                       
|New field discoveries and extensions, net of future production and development costs |                                                      |                              | 334,335                                                               
|Sales of properties                                                                  |                                                      |                              | (2,344                                                                
|Sales of oil and gas produced, net of production costs                               |                                                      |                              | (607,486                                                              
|Previously estimated development costs incurred                                      |                                                      |                              | 304,661                                                               
|Net change in income taxes                                                           |                                                      |                              | (640,529                                                              
|                                                                                     |                                                      |                              |                                                                       
|                                                                                     |                                                      |                              | Net change in standardized measure of discounted future net cash flows
|                                                                                     |                                                      |                              |                                                                       
|Ending balance                                                                       |                                                      | $                            | 2,055,215                                                             
|                                                                                     |                                                      |                              |                                                                       

|                                                                                     |                                                      | Year Ended December 31, 2001 |                                                                       
|------------------------------------------------------------------------------------ | ---------------------------------------------------- | ---------------------------- | ----------------------------------------------------------------------
|
|
|Beginning balance                                                                    |                                                      | $                            | 1,715,176                                                             
|Revisions to prior years' proved reserves:                                           |                                                      |                              |                                                                       
|                                                                                     | Net changes in prices and production costs           |                              |                                                                       
|                                                                                     | Net changes due to revisions in quantity estimates   |                              |                                                                       
|                                                                                     | Net changes in estimates of future development costs |                              |                                                                       
|                                                                                     | Accretion of discount                                |                              |                                                                       
|                                                                                     | Changes in production rate and other                 |                              |                                                                       
|                                                                                     |                                                      |                              |                                                                       
|                                                                                     |                                                      | Total revisions              |                                                                       
|New field discoveries and extensions, net of future production and development costs |                                                      |                              | 166,518                                                               
|Purchases of properties                                                              |                                                      |                              | 345,728                                                               
|Sales of properties                                                                  |                                                      |                              | (93,384                                                               
|Sales of oil and gas produced, net of production costs                               |                                                      |                              | (477,970                                                              
|Previously estimated development costs incurred                                      |                                                      |                              | 128,440                                                               
|Net change in income taxes                                                           |                                                      |                              | 337,128                                                               
|                                                                                     |                                                      |                              |                                                                       
|                                                                                     |                                                      |                              | Net change in standardized measure of discounted future net cash flows
|                                                                                     |                                                      |                              |                                                                       
|Ending balance                                                                       |                                                      | $                            | 1,138,048                                                             
|                                                                                     |                                                      |                              |                                                                       

81

---

|                                                                                                |                         | Total
Company |            | United
States |   | Kingdom of
Thailand |            | Hungary |          
|----------------------------------------------------------------------------------------------- | ----------------------- | ------------- | ---------- | ------------- | - | ------------------- | ---------- | ------- | ---------
|
|
|Future gross revenues                                                                           |                         | $             | 8,507,228  |               | $ | 6,912,547           |            | $       | 1,545,580
|Future production costs:                                                                        |                         |               |            |               |   |                     |            |         |          
|                                                                                                | Lease operating expense |               |            | (1,811,584    | ) |                     | (1,417,118 | )       |          
|Future development and abandonment costs                                                        |                         |               | (520,159   | )             |   | (324,813            | )          |         | (181,396 
|                                                                                                |                         |               |            |               |   |                     |            |         |          
|Future net cash flows before income taxes                                                       |                         |               | 6,175,485  |               |   | 5,170,616           |            |         | 979,126  
|Discount at 10% per annum                                                                       |                         |               | (2,485,484 | )             |   | (2,241,953          | )          |         | (234,304 
|                                                                                                |                         |               |            |               |   |                     |            |         |          
|Discounted future net cash flows before income taxes                                            |                         |               | 3,690,001  |               |   | 2,928,663           |            |         | 744,822  
|Future income taxes, net of discount at 10% per annum                                           |                         |               | (1,239,971 | )             |   | (919,540            | )          |         | (320,383 
|                                                                                                |                         |               |            |               |   |                     |            |         |          
|Standardized measure of discounted future net cash flows related to proved oil and gas reserves |                         | $             | 2,450,030  |               | $ | 2,009,123           |            | $       | 424,439  
|                                                                                                |                         |               |            |               |   |                     |            |         |          
|                                                                                                |                         |               |            |               |   |                     |            |         |          
|                                                                                                |                         | 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 | )       |          
|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   | )       |          
|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  
|                                                                                                |                         |               |            |               |   |                     |            |         |          

82

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

|     |                        | Quarter Ended
|---- | ---------------------- | -------------
|
|
|2003 |                        |              
|     | Revenues               |              
|     | Gross profit(a)        |              
|     | Net income             |              
|     | Earnings per share(b): |              
|     |                        | Basic        
|     |                        | Diluted      
|2002 |                        |              
|     | Revenues               |              
|     | Gross profit(a)        |              
|     | Net income             |              
|     | Earnings per share(b): |              
|     |                        | Basic        
|     |                        | Diluted      

---

83

---



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.

ITEM 9A.    Controls and Procedures

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.

PART III

ITEM 10.Directors and Executive Officers of the Registrant.

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.

ITEM 11.Executive Compensation.

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.

ITEM 13.Certain Relationships and Related Transactions.

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

ITEM 14.Principal Accountant Fees and Services.

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

84

---

PART IV

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

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



1.
Financial Statements and Supplementary Data:Report of Independent AuditorsConsolidated statements of incomeConsolidated balance sheetsConsolidated statements of cash flowsConsolidated statements of shareholders' equityNotes to consolidated financial statementsUnaudited supplementary financial data2.
Financial Statement Schedules:


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

|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).                                                                                                                                                                                                           
|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                                              

85

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|*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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|                                                                                                  |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         

86

---

|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)                                                          
|       |  |                                                                                                                                                                                                                            

87

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|*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.                                                                                                                                                                                                                                                                                                                           

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(b)   Reports
on Form 8-K



88

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SIGNATURES

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

|                        |  | POGO PRODUCING COMPANY
    (REGISTRANT)
|----------------------- |  | ---------------------------------------
|                        |  |                                        
|                        |  | BY:                                    
|Date: February 24, 2004 |  |                                        

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.

|Signatures                                                                                 |  | Title                                   
|------------------------------------------------------------------------------------------ |  | ----------------------------------------
|                                                                                           |  |                                         
|/S/  PAUL G. VAN WAGENENPaul G. Van WagenenChairman, President and Chief Executive Officer |  | Principal Executive Officer and Director
|/S/  JAMES P. ULM, IIJames P. Ulm, IISenior Vice President and Chief Financial Officer     |  | Principal Financial Officer             
|/S/  THOMAS E. HARTThomas E. HartVice President and Chief Accounting Officer               |  | Principal Accounting Officer            
|/S/  JERRY M. ARMSTRONGJerry M. Armstrong                                                  |  | Director                                
|/S/  ROBERT H. CAMPBELLRobert H. Campbell                                                  |  | Director                                
|/S/  WILLIAM L. FISHERWilliam L. Fisher                                                    |  | Director                                
|                                                                                           |  |                                         

89

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|/S/  GERRIT W. GONGGerrit W. Gong                 |  | Director
|------------------------------------------------- |  | --------
|/S/  CARROLL W. SUGGSCarroll W. Suggs             |  | Director
|/S/  STEPHEN A. WELLSStephen A. Wells             |  | Director
|/S/  THOMAS E. HARTThomas E. HartAttorney-in-Fact |  |         

90

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