**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, 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, 2002**                                                                                                                                                                                       |
|                                                                                                                                                                                                                                  |
| 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**                                                                |   | **74-1659398**                        |
|-----------------------------------------------------------------------------|--------|---------------------------------------|
| (State or other jurisdiction of  incorporation or organization)             |   | (I.R.S. Employer  Identification No.) |
|                                                                        |   |                                  |
| **5 Greenway Plaza, P.O. Box 2504  Houston, Texas**                         |   | **77252-2504**                        |
| (Address of principal executive offices)                                    |   | (Zip Code)                            |
|                                                                        |   |                                  |
| Registrant’s telephone number, including area code: **(713) 297-5000** |

 

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**Securities registered pursuant to Section 12(b) of theAct:**

 

| **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:** |
|                                                             |
| **51⁄2% Convertible Subordinated Notes due June 15, 2006**    |

 

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Indicateby check mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934 during thepreceding 12 months (or for such shorter period that the registrant wasrequired to file such reports), and (2) has been subject to such filingrequirements for the past 90 days. Yes ý     No o

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K.  ý

 

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

 

The aggregate marketvalue of the Common Stock held by non-affiliates of the registrant (treatingall executive officers and directors of the registrant, for this purpose, as if they maybe affiliates of the registrant) was approximately $1,981,295,154 as of June30, 2002 (based on $32.62 per share, the last sale price of the Common Stock asreported on the New York Stock Exchange Composite Tape on such date).

 

61,201,834shares of the registrant’s Common Stock were outstanding as of February 26,2003.

 

###### **DOCUMENT INCORPORATED BY REFERENCE**

 

Portionsof the Company’s definitive Proxy Statement respecting the annual meeting ofshareholders to be held on April 22, 2003 (to be filed not later than 120 daysafter December 31, 2002) are incorporated by reference in Part III of this Form10-K.

 

 

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### **FORWARD LOOKING STATEMENTS**

 

The statements included or incorporated by referencein this Annual Report on Form 10-K for the year ended December 31, 2002 (this“Annual Report”) include “forward-looking statements” within the meaning ofSection 27A of the Securities Act of 1933, as amended, and Section 21E of theSecurities Exchange Act of 1934, as amended. All statements included orincorporated by reference herein, other than statements of historical fact, areforward-looking statements. In some cases, you can identify our forward-lookingstatements by the words “anticipate,” “estimate,” “expect,” “objective,”“projection,” “forecast,” “goal,” and similar expressions. Such forward-lookingstatements include, without limitation, the statements herein and thereinregarding the timing of future events regarding the operations of PogoProducing Company (the “Company”) and its subsidiaries, and the statementsunder the caption “Management’s Discussion and Analysis of Financial Conditionand Results of Operations—Liquidity and Capital Resources” regarding theCompany’s anticipated future financial position and cash requirements. Althoughthe Company believes that the expectations reflected in these forward-lookingstatements are reasonable, it can give no assurance that such expectations willprove to have been correct. Important factors that could cause actual resultsto differ materially from the Company’s expectations (“Cautionary Statements”)are disclosed in this Annual Report and in other filings by the Company withthe Securities and Exchange Commission (the “Commission”). All subsequentwritten and oral forward-looking statements attributable to the Company orpersons acting on its behalf are expressly qualified in their entirety by theCautionary Statements. The Company’s actual results could differ materiallyfrom those anticipated in these forward-looking statements as a result of therisk factors set forth below and other factors set forth in or incorporated byreference in this Annual Report. These factors include:

 

•                  the cyclicalnature of the oil and natural gas industries

 

•                  our ability to successfully and profitablyfind, produce and market oil and gas

 

•                  uncertaintiesassociated with the United States and worldwide economies

 

•                  current andpotential governmental regulatory actions in countries where the Companyoperates

 

•                  substantialcompetition from larger companies

 

•                  the Company’sability to implement cost reductions

 

•                  operatinginterruptions (including leaks, explosions, fires, mechanical failure,unscheduled downtime, transportation interruptions, and spills and releases andother environmental risks)

 

•                  fluctuations inforeign currency exchange rates in areas of the world where the Companyconducts operations, particularly Southeast Asia

 

•                  covenantrestrictions in the Company’s debt agreements

 

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

 

All subsequent written and oral forward-looking statements attributableto the Company and persons acting on the Company’s behalf are qualified intheir entirety by the Cautionary Statements contained in this section andelsewhere in this Annual Report.

 

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###### **CERTAIN DEFINITIONS**

 

As used in this Annual Report, “Mcf” means thousandcubic feet, “MMcf” means million cubic feet, “Bcf” means billion cubic feet, “Bbl”means barrel, “MBbls” means thousand barrels and “MMBbls” means millionbarrels. “BOE” means barrel of oil equivalent, “Mcfe” means thousand cubic feetof natural gas equivalent, “MMcfe” means million cubic feet of natural gasequivalent and “Bcfe” means billion cubic feet of natural gas equivalent.Natural gas equivalents and crude oil equivalents are determined using theratio of six Mcf of natural gas to one Bbl of crude oil, condensate or naturalgas liquids (“NGL”). References to “$” and “dollars” refer to United Statesdollars. All estimates of reserves contained in this Annual Report, unlessotherwise noted, are reported on a “net” basis. Information regardingproduction, acreage and numbers of wells are set forth on a gross basis, unlessotherwise noted.

 

###### **PART I**

 

**ITEM 1.*    Business.***

 

The Company was incorporated in 1970 and is engaged inoil and gas exploration, development, acquisition and production activities onits properties located offshore in the Gulf of Mexico, onshore in selectedareas including Texas, New Mexico, Wyoming and Louisiana, and internationally,primarily in the Gulf of Thailand and in Hungary. As of December 31, 2002, theCompany had interests in 69 lease blocks offshore Louisiana and Texas,approximately 415,000 gross acres onshore in the United States, approximately714,000 gross acres offshore in the Kingdom of Thailand, approximately 194,000gross acres in the Danish and British sectors of the North Sea andapproximately 782,000 gross acres in Hungary.

 

On March 14, 2001, the Company acquired North Central Oil Corporation(“North Central”) through a direct merger with its parent company, NORICCorporation (“NORIC”). The Company accounted for the merger using the purchasemethod of accounting. Therefore, the information contained in this AnnualReport does not reflect the operations of North Central prior to that date. Inconnection with the merger, the Company paid $344,711,000 in cash to the formershareholders of NORIC, issued them 12,615,816 shares of Common Stock, and assumedapproximately $78,600,000 of North Central’s debt.

 

The Company organizes its exploration and production activitiesprincipally into five operating regions and a New Ventures Group. The operatingregions are its Gulf of Mexico region, which is responsible for the Company’soperations 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 Texasand in the Madden Field in Wyoming; its Gulf Coast region, which includes theCompany’s onshore operations principally in South Texas and Louisiana; the Asiaand Pacific region, which has responsibility for the Company’s operations onits Block B8/32 Concession in the Kingdom of Thailand (the “ThailandConcession”), and its Europe region, which is currently active principally inHungary and the North Sea. The Company’s New Ventures Group is primarilyresponsible for identifying new projects and opportunities for the Companyoutside the United States.

 

**Domestic Offshore Operations**

 

*Gulf ofMexico Region.*Historically, the Company’s interests havebeen concentrated in the Gulf of Mexico, where approximately 26% of theCompany’s proved reserves were located as of December 31, 2002. During 2002,approximately 27% of the Company’s natural gas production and 50% of its oiland condensate production came from the Company’s domestic offshore properties,contributing approximately 43% of the Company’s consolidated oil and gasrevenues. The Company’s exploration and development efforts are primarilyfocused in the shallower waters of the continental shelf.

 

*Exploration andDevelopment*

 

The scope of exploration and development programs relating to theCompany’s offshore interests is affected by prices for oil and gas, and byfederal, state and local legislation, regulations and ordinances applicable tothe petroleum industry. The Company’s domestic offshore capital and explorationexpenditures for 2002 were approximately $130,265,000, or 24% lower than theCompany’s domestic offshore capital and exploration expenditures ofapproximately $170,800,000 (excluding approximately $87,700,000 of net propertyacquisitions principally related to the North Central acquisition) for 2001,and 105% higher than the Company’s domestic offshore capital and explorationexpenditures of approximately $63,600,000 for 2000. The decrease in theCompany’s domestic offshore capital and exploration expenditures for 2002,compared with 2001, resulted primarily from decreased expenditures forfacilities construction. During 2002, the Company invested approximately$51,800,000 on facilities construction for its Gulf of Mexico operations,principally the fabrication and installation of platforms in the Company’s MainPass Blocks 61/62 Field. The Company has currently budgeted approximately$60,000,000 for capital and exploration expenditures during 2003 in the Gulf ofMexico, of which $11,600,000 is budgeted for facilities construction.

 

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The Company maintains a significant presence in the Gulf of Mexico whereit participated in drilling 20 wells during 2002, 90% of which were consideredsuccessful. At December 31, 2002, the Company held varying interests in 248producing oil and gas wells in the Gulf of Mexico.

 

Leases acquired by the Company and other participants in its biddinggroups are customarily committed, on a block-by-block basis, to separateoperating agreements under which the appointed operator supervises explorationand development operations for the account and at the expense of the group.These agreements usually contain terms and conditions that have becomerelatively standardized in the industry. Major decisions regarding developmentand operations typically require the consent of at least a majority (in workinginterest) of the participants. Because the Company generally has a meaningfulworking interest position, the Company believes it can significantly influence(but not always control) decisions regarding development and operations on mostof the leases in which it has a working interest even though it may not be theoperator of a particular lease. The Company is the operator on all or a portionof 33 of the 69 offshore leases in which it had an interest on December 31,2002.

 

Platforms and related facilities are installed on an offshore leaseblock when, in the judgment of the lease interest owners, the necessary capitalexpenditures are justified. A decision to install a platform generally is madeafter the drilling of one or more exploratory wells with contracted drillingequipment. Platform costs vary depending on, among other factors, the number ofwell slots, water depth, currents, and sea floor conditions. During 2002, theCompany completed the installation of an additional production platform and a pressuremaintenance platform, together with related facilities, in its new, whollyowned Main Pass Blocks 61/62 Field. The average cost of constructing andinstalling these two platforms was approximately $27,000,000 per platform.

 

*LeaseAcquisitions*

 

The Company has participated, either on its own or with other companies,in bidding on and acquiring interests in federal and state leases offshore inthe Gulf of Mexico since 1970. As a result of such purchases and subsequentactivities, as of December 31, 2002, the Company owned interests in 56 federalleases and 13 state leases offshore Louisiana and Texas. Federal leasesgenerally have primary terms of five, eight or ten years, depending on waterdepth, and state leases generally have terms of three or five years, dependingon location, in each case subject to extension by development and productionoperations.

 

As part of its strategy, the Company intends to continue an active leaseevaluation program in the Gulf of Mexico in order to identify exploration andexploitation opportunities. The Company acquires leases through participationin federal and state lease sales, farmouts and by acquisition. For example, theCompany acquired six offshore leases at the lease sale conducted by theMinerals Management Service of the Department of the Interior (the “MMS”) onMarch 20, 2002.  The Company alsoacquired three state leases through sales conducted by the State of Louisianain 2002. The Company also maintains an active asset rationalization processthrough which it seeks to sell or farmout blocks that the Company believes havelittle or no remaining upside potential, or face significant futureexpenditures that would likely result in a rate of return which does not meetthe Company’s internal criteria. As part of this process, the Company sold onelease in 2002. The extent to which the Company participates in future biddingon federal or state offshore lease sales or otherwise acquires additional leaseblocks will depend on the availability of funds and its estimates ofhydrocarbon deposits, operating expenses and future revenues that mayreasonably be expected from available lease blocks. Such estimates typicallytake 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 certain producing leaseholdproperties in areas where additional low-risk exploration and developmentdrilling or improved production methods can provide attractive rates of return.

** **

**Domestic Onshore Operations**

 

The Company’s Gulf Coast region is headquartered inHouston, Texas, with field offices in Laredo and Manvel, Texas. The Company’sWestern U.S. region has an office in Midland, Texas and two field offices inSoutheastern New Mexico. The Company conducts its onshore operations in theUnited States directly and through its wholly owned subsidiaries, North Centraland Arch Petroleum Inc. (“Arch”). Domestic onshore reserves as of December 31,2002, accounted for approximately 50% of the Company’s total proved reserves,with the Gulf Coast region and the Western U.S. region contributingapproximately 20% and 30%, respectively, of the Company’s total proved

 

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reserves. During 2002, approximately 45% of the Company’s natural gasproduction and 18% of its oil and condensate production was from its domesticonshore properties, contributing approximately 25% of the Company’sconsolidated oil and gas revenues.

 

*Exploration and Development*

 

*Western U.S. Region.*    TheCompany’s Western U.S. region has actively explored in the west Texas andsoutheast New Mexico areas for over 23 years. Since the Company began exploringin the Brushy Canyon (Delaware) formation in 1989, it has participated indrilling 523 wells in west Texas and southeast New Mexico through December 31,2002, including 45 wells in 2002 (92% of which were successfully completed),and participated in the discovery or development of over 27 oil and gas fieldsduring that time. The Company believes that during the past ten years it hasbeen one of the most active companies drilling for oil and natural gas insoutheastern New Mexico (Lea and Eddy Counties), where the Company hasinterests in approximately 128,000 gross acres. The Company currently plans todrill approximately 82 wells in the Permian Basin during 2003 in 22 knownfields and exploratory prospects. Drilling objectives of these wells range indepth from 3,700 feet to 15,800 feet below the surface, and target numerousformations including, among others, the shallow Queen, Delaware (BrushyCanyon), Bone Springs, Spraberry and Strawn formations, to the deeper Morrow,Devonian and Ellenburger pay zones.

 

The Company’s Western U.S. region also actively participates in theexploration and development of the Madden Deep Unit in central Wyoming, wherethe Company owns varying working interests that average approximately 12.5%across the unit area. The Madden Deep Unit consists of two principal producingformations, the comparatively shallow Lower Fort Union formation (whereproductive zones are historically found from approximately 5,500 feet to 9,500feet below the surface) and the Madison formation (which currently producesfrom 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 sweetgas. Gas produced from the Madison formation, however, contains significantquantities (approximately one-third by volume) of carbon dioxide and hydrogensulfide gases. Gas from the Madison zones must be processed through the LostCabin Gas Plant to remove the carbon dioxide and hydrogen sulfide gases priorto sale. An expansion of the Lost Cabin Gas Plant was completed in 2002, whichincreased the plant’s processing capacity from 132 MMcf per day toapproximately 313 MMcf per day. The Company owns a 12.4% working interest inthis plant. The wells to the Madison formation are deep and technologicallychallenging to drill, taking up to 13 months from commencement to completion.Two Madison tests (the Bighorn 7-34 and Bighorn 8-35) were successfullycompleted as producing gas wells during 2002. Additionally, the Big Horn 9-4 isbeing drilled and is currently projected to reach total depth and completedduring 2003. An active Lower Fort Union drilling program is also anticipatedfor 2003.

 

*Gulf Coast Region.*    TheCompany’s Gulf Coast region is actively exploring in Louisiana, east Texas andsouth Texas. During 2002, the Gulf Coast region participated in drilling 44wells, 89% of which were successfully completed. In southeast Louisiana, theCompany drilled and completed two wells during 2002 on prospects that wereidentified through the Company’s Thibodaux 3-D seismic survey, which coversapproximately 39,000 acres. The Company currently plans to drill two wells inthis area during 2003.

 

In south Texas, the Company’s Gulf Coast region is active in its LosMogotes, Hundido and Hereford Ranch Fields, that produce from the Asche, Charcoand Lobo formations, and which are found at depths ranging from 7,000 to 14,000feet below the surface. In its Los Mogotes Field, where its working interestaverages approximately 72%, the Company drilled 26 wells in 2002 utilizing upto three drilling rigs at various times during that period. The Companycurrently has two rigs working in the field and has budgeted to drill 21 wellsthere during 2003. In addition, the Company enjoys significant production fromits Hundido Field, where it has an average approximate 98% working interest andfrom the Company’s Hereford Ranch Field, where it has a 100% working interest.

 

The Company generally conducts its onshore activities through jointventures and other interest-sharing arrangements with major and independent oilcompanies. The Company and its subsidiaries operate many of their onshoreproperties using both independent contractors and field personnel that areemployed by the Company or its subsidiaries.

 

The Company’s onshore capital and exploration expenditures for 2002 wereapproximately $75,000,000, or 47% lower than the Company’s onshore capital andexploration expenditures of approximately $141,000,000 (excluding approximately$1,027,200,000 of net property acquisitions primarily related to the acquisitionof North Central) for 2001, and 36% higher than the Company’s onshore capitaland exploration expenditures of approximately $55,100,000 (excludingapproximately $8,400,000 of net property acquisitions) for 2000. The decreasein the Company’s onshore capital and exploration expenditures for 2002,compared to 2001, resulted primarily from expenditures related to increasedexploratory and development drilling in its other core areas. The

 

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Company has currently budgeted approximately $117,000,000 for capitaland exploration expenditures during 2003 in its domestic onshore areas.

 

*Lease Acquisitions*

 

As it has in recent years, in 2002 the Company also successfullyparticipated in various onshore federal and state lease sales and acquiredinterests in other prospective acreage. As of December 31, 2002, the Companyheld interests in approximately 415,000 (228,000 net) acres onshore in theUnited States.

 

**International Operations**

 

The Company has conducted international explorationactivities since the late 1970’s in numerous oil and gas areas throughout theworld. The Company currently holds licenses in the Kingdom of Thailand, Hungaryand the Danish and British sectors of the North Sea. In addition, the Company’sinternational explorationists continue to evaluate other internationalopportunities that are consistent with its international exploration strategyand expertise.

 

Substantial portions of the Company’s internationaloperations are grouped under its wholly owned Dutch subsidiary, Pogo OverseasProduction B.V. Two subsidiaries of Pogo Overseas Production B.V., ThaipoLimited (“Thaipo”) and Pogo Hungary Ltd., maintain offices in Bangkok, Thailandand in Budapest, Hungary, respectively.

 

*Exploration and Development*

 

The Company’s international capital and exploration expenditures wereapproximately $103,200,000 for 2002, or 47% higher than the Company’sinternational capital and exploration expenditures of $70,100,000 for 2001, and93% higher than the Company’s international capital and explorationexpenditures of approximately $53,400,000 for 2000. The increase in theCompany’s capital and exploration expenditures for 2002, compared to 2001 and2000, resulted primarily from expenditures for facilities costs, includingconstruction and installation of five platforms for installation in theBenchamas Field and increased drilling expenses resulting from having two rigsdrilling in Thailand for a substantial portion of the year. Substantially allof the Company’s international capital and exploration expenditures for 2002were related to the Company’s license in the Kingdom of Thailand. During 2001and 2000, a significant portion of the Company’s exploration expendituresoccurred outside of Thailand; including approximately $9,020,000 in explorationexpenditures in 2001 and $3,396,000 in 2000, all of which related to 3-Dseismic data acquisition in Hungary.

 

The Company has currently budgeted approximately $143,000,000 forcapital and exploration expenditures during 2003 in areas outside the UnitedStates, including $120,000,000 in Thailand and $23,000,000 in Europe, of whichapproximately $3.4 million is designated for the Danish sector of the North Seaand the remainder is designated for the Company’s operations in Hungary.Approximately $67,700,000 of these funds are budgeted for facilities upgradesand additions in the Kingdom of Thailand, including the construction of eightplatforms for the Thailand Concession, three of which are planned to beinstalled in late 2003 and five of which are projected to be installed in 2004.

 

*Asiaand Pacific Region.*

 

*The Company currently owns, directly or indirectly, a 46.34% workinginterest in the entire Thailand Concession. The remainder of the workinginterest is owned, directly or indirectly, by Chevron Offshore (Thailand)Limited (“Chevron”) (46.34%), a subsidiary of Chevron Corporation, and PalangSophon Limited (“Palang”) (7.32%). Through its majority ownership of Palang,Chevron owns or controls, directly or indirectly, 51.66% of the workinginterests in the Thailand Concession and is currently the operator of theThailand Concession. Through voting procedures in the joint operating agreementgoverning the Thailand Concession, and the close working relationship between Chevron’sand Thaipo’s exploration staffs, Thaipo exerts substantial influence over thedevelopment of the Thailand Concession. As of December 31, 2002, the Company’sproved reserves located in the Kingdom of Thailand accounted for approximately24% of the Company’s total proved reserves. During 2002, approximately 28% ofthe Company’s natural gas production and 32% of its oil and condensateproduction came from its operations on the Thailand Concession, contributingapproximately 32% of the Company’s consolidated oil and gas revenues.*

 

*BenchamasField.*    In July1997, the government of Thailand designated a portion of the ThailandConcession comprising approximately 102,000 acres as the Benchamas andPakakrong production area or the “Benchamas Field.” Production from theBenchamas Field commenced in July 1999 from three production platforms. In2002, an additional five platforms were installed. Natural gas and oil fromthese platforms are delivered by undersea pipeline to a central processing andcompression platform where the oil, condensate and natural gas is processed andseparated. The natural gas is sold to PTT Public Company Limited (“PTT”) anddelivered into export pipelines for transportation to shore, while the crudeoil and condensate produced from the field is stored on board a FloatingStorage and Offloading system (“FSO”) known as the “Benchamas Explorer” forsale and ultimate transfer to shore by oil tanker. The FSO is moored in theBenchamas Field. Its capacity is approximately 1,400,000 Bbls of crude oil andcondensate. See “Management’s Discussion and Analysis of Financial Conditionand Results of Operations — Liquidity and Capital Resources.” Contracts havebeen signed and steel has been ordered for the construction of at least fouradditional platforms for this area.  Twoplatforms will be installed during 2003 in the Benchamas Field and additionalplatforms are scheduled for installation in 2004. Additional exploratory anddevelopment drilling is also currently planned for the Benchamas Field during2003. The temporary shutdown of the Benchamas Field to upgrade the Benchamascentral processing platform, which had been scheduled for the first quarter of2003, has now been postponed until late 2003 or early 2004.  The upgrade was delayed to allow delivery ofall of the equipment needed for the upgrade and to ensure sufficient planningto minimize the shutdown period. During 2002, 50 wells were drilled in theBenchamas Field, which currently has 98 producing wells (including 19horizontal wells) and 13 water injection wells.

 

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*Tantawan Field.*    InAugust 1995, at the request of Thaipo and its joint venture partners, thegovernment of Thailand designated a portion of the Thailand Concession comprisingapproximately 68,000 acres as the Tantawan production area or the “TantawanField.” Initial production from the Tantawan Field commenced on February 1,1997. Oil and gas production from the Tantawan Field is gathered throughpipelines from the platforms into a Floating Production Storage and Offloadingsystem (an “FPSO”) named the “Tantawan Explorer.” The FPSO is a converted oiltanker with a capacity of slightly less than 1,000,000 Bbls, that is moored inthe 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 isdelivered to PTT through an export pipeline. Oil and condensate produced fromthe field is stored on board the FPSO until sold and transferred to shore byoil tanker. See “Management’s Discussion and Analysis of Financial Conditionand Results of Operations—Liquidity and Capital Resources.” During 2002, fourdevelopment and two exploratory wells were drilled in the field. Currently,there are approximately 63 wells producing from five platforms. Current planscall for the installation of another platform in the Tantawan Field during 2003and for additional development drilling. If and when the adjacent Block 9A isassigned to Thaipo and its joint venture partners (an assignment that has beenapproved by the Minister of Energy and is awaiting final Parliamentaryapproval), an additional two exploration wells will be drilled to establish theeastern extent of the Tantawan Field, leading to the possibility of up to anadditional two platforms being installed in Block 9A in 2004 if a productionlicense is successfully obtained in a timely manner.

 

*Maliwan Field.*    InSeptember 1997, the government of Thailand designated an additionalapproximately 91,000 acres of the Thailand Concession as the Maliwan productionarea or the “Maliwan Field.” The Maliwan “A” platform was installed andcommenced production on October 29, 2001. Initial production from this firstplatform is delivered to the Benchamas Field production handling facilities forprocessing and sale. Current plans call for additional development andexploration drilling in the Maliwan Field during 2003. In addition, work will continueon finalizing a development plan for the entire field.

 

*Other Portions of the Thailand Concession.*   Thaipo and its joint venture partners have identified other potentiallypromising areas on the Thailand Concession and surrounding acreage. In November2000, approximately 124,000 additional acres of the Thailand Concession, knownas the Jarmjuree area, were designated as a production area. Development plansfor this area are still being formulated. Two exploration wells were drilled inthis production license area during 2002. Up to five more wells could bedrilled in the Jarmjuree and surrounding areas during 2003.

 

During 2002, Thaipo and its joint venture partners drilled a successfulexploration well in a portion of the Thailand Concession that is north of theBenchamas Field. On the basis of this successful well and other wellspreviously drilled in this area that tend to establish a northward extension ofthe Benchamas Field, another production license, the North Benchamas productionlicense was applied for during the fourth quarter of 2002.  Thaipo and its joint venture partnerscurrently anticipate that this production license area, covering up to anadditional 31,000 acres, could be granted to the joint venture by the end of2003. If this is the case, then Thaipo and its joint venture partners currentlyplan to install a platform in this area and tie it back to the Benchamas Fieldin late 2004. During 2002, Thaipo and its joint venture partners drilled sixexploratory wells and have currently budgeted to drill additional exploratorywells during 2003. Interpretation of the data provided by these wells and 3-Dseismic data covering the Thailand Concession is ongoing.

 

Platforms are installed on the Thailand Concession in fields where, inthe judgment of Thaipo and its joint venture partners, the necessary capitalexpenditures are justified. A decision to install a platform generally is madeafter the drilling of one or more exploratory wells with contracted drillingequipment and the area where the platform would be located has been designateda production area by the government of the Kingdom of Thailand. See“Contractual Terms Governing the Thailand Concession and Related Production.”Platforms are used to

 

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accommodate both development drilling and additional exploratorydrilling. A key focus of Thaipo and its joint venture partners has been toreduce the average cost of the platforms installed to improve the overalleconomics of the project. The gross cost of the fourteen production platformsand related facilities installed in the Tantawan, Benchamas and Maliwan Fieldsto date have averaged approximately $17,400,000 per platform. Platform costsvary, and more (or less) expensive platforms could be required in the futuredepending on, among other factors, the number of slots, water depth, currentsand sea floor conditions and the amount of facilities required to be placed onthe platform.

 

*Contractual Terms Governing the ThailandConcession and Related Production*

 

The Thailand Concession was granted in August 1991. The initialexploratory term for the Thailand Concession expired on July 31, 2000. However,through a series of one-year extensions, Thaipo and its joint venture partnershave been granted an extension of the exploratory term through July 31, 2003.Similar one-year extensions can also be applied for through July 31, 2005.Thaipo and its joint venture partners intend to continue to apply forextensions for areas of the Thailand Concession they believe to be prospectiveuntil all of the acreage has been adequately evaluated. For those portions ofthe Thailand Concession that have been designated as production areas, theinitial production period term is 20 years, which is also subject to extension,generally for a term of ten years. In November 2002, Thaipo and its jointventure partners requested that the government designate the North Benchamasarea as a production area. To date, the Benchamas Field, Tantawan Field,Maliwan Field and North Jarmjuree areas have been designated as productionareas. Subject to governmental approval, other portions of the ThailandConcession may be designated production areas in the future.

 

Production resulting from the Thailand Concession issubject to a royalty ranging from 5% to 15% of oil and gas sales. In addition,the joint venture partners expect to pay a final production bonus of $7,500,000($3,476,000 net to the Company) in the first half of 2003 as a result ofaveraging at least 100,000 BOE for one calendar month. Profits from productionin Thailand are also subject to a Special Remuneration Benefit (“SRB”). The SRBrate is calculated based on a complex formula using discounted revenue, metersdrilled and other factors specified in the Thailand Concession licenseagreement. This rate is then applied toward the net proceeds derived by eachjoint venture partner’s Thailand subsidiaries. The SRB rates can range from 20%to 75%. SRB payments are then treated as a deductible expense for Thailandincome tax calculations by such subsidiaries. The Company currently expects toaccrue SRB liabilities in 2003 on a portion of the net proceeds it derives fromthe Thailand Concession.

 

Thaipo and its joint venture partners have entered into a thirty-yearGas Sales Agreement with PTT (the “Gas Sales Agreement”), governing gasproduction from the Tantawan Field and the Benchamas Field. The terms of theGas Sales Agreement currently include a minimum daily contract quantity (“DCQ”)of 125 MMcf per day, subject to certain exceptions and will in the future bebased on a percentage of the remaining proved reserves, but in any event, willnot be less than 125 MMcf per day. In addition, the Gas Sales Agreement givesPTT the right to nominate in any given week, 115% of DCQ or approximately 145MMcf per day. Effective October 1, 2001, Thaipo and its joint venture partnersamended the Gas Sales Agreement to provide, among other things, that PTT maytake up to an additional approximate 58 billion cubic feet of gas through March1, 2004 at production rates which vary, depending upon the time period, from 26MMcf up to 85 MMcf per day (“Supplemental DCQ”) or approximately 12MMcf to40MMcf net to the Company. During 2002, gas production averaged approximately192 MMcf per day (89 MMcf per day net to the Company), with production in thefourth quarter averaging 195 MMcf per day (91 MMcf per day net to the Company).

 

Thaipo and its joint venture partners are subject to certain penaltiesif they are unable to meet the DCQ or the Supplemental DCQ under the Gas SalesAgreement. Failure to meet DCQ results in a decrease in the sales price for gassold under the Gas Sales Agreement of up to 25% of the then current sales priceand failure to meet the Supplemental DCQ will result in a credit against thenext month’s supplemental production of 12% of the then current sales price ofthe gas not delivered. Thaipo currently meets the minimum DCQ and generallymeets the Supplemental DCQ requirements, however, there can be no assurancethat Thaipo will be able to continue to meet them in the future, in which casethese penalty provisions would reduce the price received by Thaipo for its gassold to PTT under the Gas Sales Agreement.

 

The sales price for the base DCQ production under theGas Sales Agreement is subject to automatic semi-annual adjustments based upona formula that takes into account changes in: Singapore fuel oil prices; theU.S. Bureau of Labor Statistics Oilfield Machinery and Tool Index; the Thaiwholesale producer price index; and the U.S./Thai currency exchange rate.However, the Gas Sales Agreement provides for adjustment on a more frequentbasis in the event that certain indices and factors on which the price is basedfluctuate outside a given range. The sales price for Supplemental DCQproduction is 88% of the then current sales price for DCQ production. As ofDecember 31, 2002, the Company was receiving a blended average price ofapproximately $2.22 per Mcf under the Gas Sales Agreement for DCQ andSupplemental DCQ production. See “Management’s Discussion and Analysis of

 

8

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Financial Condition and Results of Operations — Results of Operations;Foreign Currency Transaction Gain (Loss)” and “Liquidity and Capital Resources;Other Matters; Southeast Asia Economic Issues.”

 

*Europe Region.*    OnApril 20, 1999, the Company’s subsidiary Pogo Hungary Ltd. (“Pogo Hungary”) wasawarded a license to explore for oil and gas in the Szolnok and Tompa areas ofcentral and south central Hungary. This license area currently consists ofapproximately 782,000 acres. The exploration term of the license is currentlyset to expire on April 19, 2005, unless otherwise extended by the government.Areas where commercial accumulation of hydrocarbons are identified may then bedesignated as “mining plots” and held through the economic productive life ofsuch reserves. During 2002, Pogo Hungary interpreted the 2-D and 3-D seismicsurveys it acquired during 2000 and 2001. One 3-D survey covers approximately97,000 acres, a substantial portion of the Tompa area, and the other coversapproximately 42,000 acres of the Szolnok area and is referred to as theKenderes 3-D survey. Based upon their detailed evaluation of this 3-D seismicdata and extensive other data acquired from government sources, a number ofprospects have been preliminarily identified. Assuming that the necessarypermits and other government and regulatory approvals and assurances areobtained in a timely manner, Pogo Hungary has budgeted to drill approximatelysix wells during the second half of 2003 to evaluate six prospective play typeson its Tompa and Szolnok areas. Three of the potential drilling locations arecurrently located in the Tompa area and the other three are located in theSzolnok area.

 

Hungary imported approximately 70% of the crude oil and approximately74% of the natural gas that it consumed in 2001. Most of the crude oil and thenatural gas that is imported into Hungary comes from Russia. The remainingimported natural gas is delivered from Austria through the Baumgarten hub.Historically, the domestic Hungarian oil and gas industry was entirelystate-owned. Following privatization of the industry during the 1990s, thewholesale and retail prices for natural gas remained heavily regulated andpartially subsidized. The Hungarian retail petroleum market was liberalized in1991. Currently, the Company believes that crude oil produced in Hungary may besold in Hungary or exported at a price based upon world market prices. The saleof natural gas in Hungary is still subject to pricing regulation under theexisting Hungarian Natural Gas Act which currently restricts the wholesaleprice of natural gas sold in Hungary to a range of approximately $3.19 to $5.21per Mcf, depending on the end user. However, in connection with its ascensionto the European Union, Hungary is obligated to liberalize its gas market and toremove price controls on at least a portion of its domestic natural gas market.The Hungarian government is currently formulating modifications to the NaturalGas Act that will comply with applicable European Union directives on marketliberalization. Alternatively, the Company currently believes that it will beable to swap gas it produces in Hungary for gas at the Baumgarten hub, which canthen be sold at unregulated European spot prices.

 

On August 5, 1999, the Danish government approved the assignment to theCompany of a 40% working interest in License 13/98 covering approximately81,000 acres in the Danish sector of the North Sea. This license interest iscurrently held by the Company’s Danish subsidiary, Pogo Denmark ApS. The workcommitment for this license requires the drilling of an exploratory well priorto the expiration of the license. The initial term of the license goes throughJune 14, 2004, unless otherwise extended or a production license is granted.Pogo Denmark ApS and its joint venture partners are reprocessing andreinterpreting an existing 3-D seismic survey and currently intend to drill awell during 2003 on one of the prospects that has been identified on the block.

 

Pogo North Sea Limited, a British subsidiary of the Company, togetherwith two joint venture partners, also holds a license governing approximately113,000 acres in the British sector of the North Sea. A possible prospect hasbeen identified on the block, based upon recently acquired 3-D seismic data,that may require the joint venture to drill a well on the license prior to itsexpiration. Discussions are currently ongoing between the joint venture and thegovernment regarding evaluation of this prospect. The current exploratory termof this license expires on December 1, 2004, unless otherwise extended or aproduction license is granted.

 

**Miscellaneous**

 

*Other Assets*

 

The Company and a subsidiary, Pogo Offshore Pipeline Co., own interestsin eight pipelines (excluding field gathering pipelines) through which offshorehydrocarbon production is transported. As previously discussed, the Companyalso owns an approximate 12.4% interest in the Lost Cabin Gas Plant located inthe Madden Field, which currently has the capacity to process 312 MMcf ofnatural gas per day. During 2002, the Company successfully divested anapproximate 19% interest of a cryogenic gas processing plant near Erath,Louisiana for approximately $3,900,000. As part of the Company’s ongoingefforts to focus on its core business of finding and producing oil and naturalgas, the Company is exploring sales opportunities for its interest in othernon-core assets if a favorable price can be obtained. The Company does notcurrently expect that the sale of any or all of these non-core assets wouldhave a substantial material impact on the Company’s business or operations,taken as a whole.

 

9

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*Sales*

 

The marketing of all of the Company’s onshore andoffshore oil and gas production is subject to the availability of pipelines andother transportation, processing and refining facilities, as well as theexistence of adequate markets. As a result, even if hydrocarbons are discoveredin commercial quantities, a substantial period of time could elapse beforecommercial production commences. If pipeline facilities in an area areinsufficient, the Company may have to await the construction or expansion ofpipeline capacity before production from that area can be marketed. TheCompany’s domestic onshore and offshore properties are generally located inareas where a pipeline infrastructure or other transportation alternatives arewell developed and there is adequate availability in such pipelines or othertransportation alternatives to transport the Company’s current and projectedfuture production.

 

The Company may not be able to successfully market all of the oil andnatural gas found and produced on the Thailand Concession. Currently, the onlypurchaser of natural gas is PTT, which maintains a monopoly over gastransmission and distribution in Thailand, including ownership of the two major(34 inches and 36 inches in diameter, respectively) natural gas pipelines thattraverse the Thailand Concession. All oil and condensate production from theTantawan Field is initially stored aboard the FPSO and then sold to variousthird parties, including PTT, on a tanker load by tanker load basis at pricesbased on then current world oil prices, typically with reference to theMalaysian Tapis Blend crude oil benchmark price. Crude oil and condensateproduction from the Benchamas Field and the first platform located in thenorthern portion of the Maliwan Field is initially stored aboard the FSO. Aportion of this production is sold under a term sale agreement with UnitedPetroleum & Chemicals Company Limited that expires in May 2003. This termsale agreement is for a total of 6,000,000 Bbls (2,780,000 Bbls net to Thaipo)at a price equal to Malaysian TAPIS less $0.55 per Bbl. The remainingproduction from the Benchamas Field is sold on a tanker load by tanker loadbasis, similar to the way Tantawan Field crude oil is currently marketed.

 

The prices that the Company receives for crude oil sales from ourThailand Concession are influenced by a number of factors including, amongothers, tanker availability, world-wide crude oil demand, size of the liftingand the perceived quality of crude oil produced. For example, crude oilproduced from the Gulf of Thailand is generally perceived as having highmercury levels. The crude oil from the Benchamas Field has high wax content.Therefore, it is sought after by some refineries and is less desirable toothers. These factors and others have led to significant fluctuations in theprice that the Company receives for its Thai crude oil production in comparisonto the Malaysian Tapis Blend benchmark price. During 2002, the price that theCompany received for its crude oil production from the Thailand Concessionranged between a $1.10 per Bbl premium and a $1.05 per Bbl discount to theMalaysian Tapis Blend benchmark price. The Company and its joint venturepartners continue to examine ways to improve the price received for crude oil,including the possibility of entering into long-term contracts for a portion ofits production, although none of its production is currently committed to suchan arrangement. In addition, because much of the oil produced from the ThailandConcession is associated with natural gas, limitations on Thaipo’s ability toproduce natural gas could limit crude oil production as well. The crude oilpurchaser is generally responsible for sending a tanker to offload the oil andcondensate it has purchased. See “International Operations; Contractual TermsGoverning the Thailand Concession and Related Production.”

 

Most of the Company’s North American natural gas sales (exclusive offorward gas sales contracts) are currently made in the “spot market” for nomore than one month at a time at then currently available prices or underlonger-term contracts with prices that are based on, and fluctuate with, spotmarket prices. Prices on the spot market fluctuate with supply and demand.Crude oil and condensate production is also generally sold one month at a timeat the price that is then currently available or under longer-term contractswith prices that also fluctuate in relationship to published market price.Other than any oil and natural gas forward sales contracts that may exist fromtime to time, and are referred to in “Miscellaneous; Competition and MarketConditions,” and the Gas Sales Agreement with PTT for production from theThailand Concession (see “International Operations; Contractual Terms Governingthe Thailand Concession and Related Production”), the Company has no existingcontracts that require the delivery of fixed quantities of oil or natural gas,other than on a best efforts basis. No customer in 2002 constituted more than10% of the Company’s consolidated revenues.

 

*Risks Associatedwith Acquisitions*

 

From time to time the Company acquires, and mayacquire in the future, additional interests in oil and gas properties, eitherthrough acquisition of the properties themselves or, as in the case of the Archand North Central acquisitions, indirectly through the purchase of an equityinterest in the entity owning such properties. The successful acquisition ofsuch properties requires an assessment of several factors, includingrecoverable reserves, projected future cash flows that are, in part, based uponfuture oil and gas prices, current and projected operating, general andadministrative and other costs, and contingent liabilities associated with theproperties or entities acquired, including potential environmental and otherliabilities.

 

10

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The accuracy of the Company’s assessment of these factors is inherentlyuncertain. To the extent reasonably practicable under the specificcircumstances of each acquisition, the Company performs a review of theproperties or entities prior to an acquisition. The Company believes that itsreview procedures are generally consistent with current industry practices. TheCompany’s review and assessment process will not reveal all existing orpotential problems nor will it permit the Company to become sufficientlyfamiliar with the properties or entities to fully assess their deficiencies andcapabilities. Even when problems are identified, the other party may beunwilling or unable to provide effective contractual protection against all orpart of the problems. The Company is generally not entitled to contractualindemnification for many liabilities, acquiring the properties on an “as is,where is” basis. In addition, successful acquisitions frequently require thesuccessful integration of operations, equipment and, in the case of indirectacquisitions, personnel. There can be no assurance that the Company will beable to successfully integrate operations and properties that it acquires andstill achieve the anticipated synergies, cost savings and efficiencies.

 

*Competition and Market Conditions*

 

The Company experiences competition from other oil and gas companies inall phases of its operations, as well as competition from other energy relatedindustries. The Company’s profitability and cash flow are highly dependent uponthe prices of oil and natural gas, which historically have been seasonal,cyclical and volatile. In general, prices of oil and gas are dependent uponnumerous factors beyond the control of the Company, including various weather,economic, political and regulatory conditions. In addition, the decisions ofthe Organization of Petroleum Exporting Countries relating to export quotasalso affect the price of crude oil. A future drop in oil or gas prices couldhave a material adverse effect on the Company’s cash flow and profitability.Sustained periods of low prices could cause the Company to shut in existingproduction and also have a material adverse effect on its operations andfinancial condition. It could also result in a reduction of funds availableunder the Company’s bank credit facilities. See “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Liquidity and CapitalResources; Credit Facility.”

 

Because it is impossible to predict future oil and gasprice movements with any certainty, the Company from time to time enters intocontracts to hedge against future market price changes on a portion of itsproduction. Such hedging transactions, historically, have never exceeded 50% ofthe Company’s total oil and gas production on an energy equivalent basis forany given period. While intended to limit the negative effect of pricedeclines, some forms of hedging transactions could effectively limit theCompany’s participation in price increases, which could be significant, for thecovered period. As of December 31, 2002, the Company was a party to the naturalgas and crude oil option contracts described in “Quantitative and QualitativeDisclosure About Market Risk.” When the Company does engage in certain types ofhedging activities, it may satisfy its obligations with its own production orby the purchase (or sale) of third-party production. The Company may alsooffset delivery obligations under these hedging transactions requiring physicaldelivery with equivalent agreements, thereby effecting a purely cashtransaction.

 

*Operating and Uninsured Risks*

 

The Company’s operations are subject to risks inherent in theexploration 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 operationsare subject to the additional hazards of marine and helicopter operations, suchas capsizing, collision and adverse weather and sea conditions. These hazardscould result in substantial losses to the Company due to injury or loss oflife, severe damage to and destruction of property and equipment, pollution andother environmental damage and suspension of operations. The Company carriesinsurance 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 riskthat no commercially productive hydrocarbon reserves will be encountered. Thecost of drilling, completing and operating wells and of installing productionfacilities and pipelines is often uncertain. The Company’s drilling operationsmay be curtailed, delayed or canceled as a result of numerous factors,including title problems, weather conditions, compliance with governmentalrequirements and shortages or delays in the delivery or availability ofmaterial, equipment and fabrication yards. In periods of increased drillingactivity resulting from high commodity prices, demand exceeds availability fordrilling rigs, drilling vessels, supply boats and personnel experienced in theoil and gas industry in general, and the offshore oil and gas industry inparticular. This may lead to difficulty and delays in consistently obtainingcertain services and equipment from vendors, obtaining drilling rigs and otherequipment at favorable rates and scheduling equipment fabrication at factoriesand fabrication yards. This in turn may lead to projects being delayed orexperiencing increased costs.

 

11

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In periods during which the industry experiences a substantial declinein oil and gas prices, many of the Company’s partners, particularly the smallerones, can experience liquidity and cash flow problems. These problems may leadto the smaller companies’ attempts to delay or slow down the pace of drillingor project development in order to conserve cash, to a point that the Companybelieves is detrimental to the project. In most cases, the Company has theability to influence the pace of development through joint operatingagreements. Some partners may be unwilling or unable to pay their share of thecosts of projects as they become due. At worst, a partner may declarebankruptcy 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 projectcosts. In most instances, the Company believes that it is contractuallyprotected from such an event through its ability to take over the non-payingpartner’s share of the project and by applicable oil and gas lien laws andbankruptcy laws. The Company believes that it would ultimately recover any sumsthat it is owed by non-paying partners that do not meet their share of thecosts of a project in a timely fashion.

 

*Risks of Foreign Operations*

 

Ownership of property interests and production operations in Thailand,Hungary, the North Sea and in any other areas outside the United States inwhich the Company may choose to do business are subject to the various risksinherent in foreign operations. These risks may include, among other things,currency restrictions and exchange rate fluctuations, loss of revenue, propertyand equipment as a result of hazards such as expropriation, nationalization,war, insurrection and other political risks, risks of increases in taxes andgovernmental royalties, renegotiation of contracts with governmental entities,changes in laws and policies governing operations of foreign-based companiesand other uncertainties arising out of foreign government sovereignty over theCompany’s international operations. See “Management’s Discussion and Analysisof Financial Condition and Results of Operations—Results of Operations; ForeignCurrency Transaction Gain (Loss),” and “Liquidity and Capital Resources; OtherMatters; Southeast Asia Economic Issues.” The Company’s internationaloperations may also be adversely affected by laws and policies of the UnitedStates affecting foreign trade, taxation and investment. In addition, in theevent of a dispute arising from foreign operations, the Company may be subjectto the exclusive jurisdiction of foreign courts or may not be successful insubjecting foreign persons to the jurisdiction of the courts of the UnitedStates. The Company seeks to manage these risks by concentrating itsinternational exploration efforts in areas where the Company believes that theexisting government is stable and favorably disposed towards United Statesexploration and production companies.

 

**Exploration and Production Data**

 

In the following data, “gross” refers to the totalacres or wells in which the Company has an interest and “net” refers to grossacres or wells multiplied by the percentage working interest owned by theCompany.

* *

*Acreage*

 

The Company owns interests in developed and undeveloped oil and gasacreage in various parts of the world. These ownership interests generally takethe form of “working interests” in oil and gas leases that have varying terms.The following table shows the Company’s interest in developed and undevelopedoil and gas acreage under lease as of December 31, 2002:

 

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|                    |   | **Developed Acreage(a)** |   | **Undeveloped Acreage(b)** |   |
|-------------------------|--------|--------------------------|--------|----------------------------|--------|
|                    |   | **Gross**                |   | **Net**                    |   | **Gross** |   | **Net** |   |
|                    |   |                     |   |                       |   |   |   |   |   |
| Domestic Offshore       |   |                     |   |                       |   |   |   |   |   |
| Louisiana               |   | 144,234                  |   | 47,896                     |   | 85,130 |   | 57,764 |   |
| Texas                   |   | 17,280                   |   | 6,141                      |   | 23,040 |   | 5,904 |   |
| Total Domestic Offshore |   | 161,514                  |   | 54,037                     |   | 108,170 |   | 63,668 |   |
|                    |   |                     |   |                       |   |   |   |   |   |
| Domestic Onshore        |   |                     |   |                       |   |   |   |   |   |
| Louisiana               |   | 10,475                   |   | 2,819                      |   | 10,188 |   | 4,790 |   |
| New Mexico              |   | 53,655                   |   | 39,861                     |   | 73,821 |   | 57,579 |   |
| Texas                   |   | 105,261                  |   | 47,231                     |   | 89,778 |   | 63,564 |   |
| Wyoming                 |   | 29,205                   |   | 3,700                      |   | 36,548 |   | 6,221 |   |
| Other                   |   | 6,120                    |   | 2,211                      |   | 80 |   | 15 |   |
| Total Domestic Onshore  |   | 204,715                  |   | 95,822                     |   | 210,415 |   | 132,169 |   |
| Total Domestic          |   | 366,229                  |   | 149,859                    |   | 318,584 |   | 195,837 |   |
|                    |   |                     |   |                       |   |   |   |   |   |
| International           |   |                     |   |                       |   |   |   |   |   |
| Gulf of Thailand        |   | 385,035                  |   | 178,431                    |   | 329,018 |   | 152,471 |   |
| North Sea               |   | 0                        |   | 0                          |   | 193,631 |   | 77,453 |   |
| Hungary                 |   | 0                        |   | 0                          |   | 781,771 |   | 781,771 |   |
| Total International     |   | 385,035                  |   | 178,431                    |   | 1,304,420 |   | 1,011,695 |   |
| Total Company           |   | 751,264                  |   | 328,290                    |   | 1,623,004 |   | 1,207,532 |   |

 

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(a)          “Developed acreage”consists of lease acres spaced or assignable to production (including acreageheld by production) on which wells have been drilled or completed to a pointthat would permit the production of commercial quantities of oil or naturalgas. “Developed acreage” in Thailand includes all acreage designated as aproduction area by the Thai government, which currently includes Benchamas,Tantawan, Maliwan and Jarmjuree production licenses.

 

(b)         Approximately 2% of theCompany’s total domestic offshore net undeveloped acreage is under leases thathave minimum terms expiring in 2003 and another 5% expires in 2004.Approximately 18% of the Company’s total domestic onshore net undevelopedacreage is under leases with minimum terms expiring in 2003 and another 18%expires in 2004. All of the Company’s undeveloped acreage in the Kingdom ofThailand is subject to one-year lease extensions that may be applied for eachyear through July 2005. See “International Operations; Contractual TermsGoverning the Thailand Concession and Related Production.”

 

In addition, the Company holds certain other types of mineral interests,including fee interests (which never expire) and royalty interests (whichgenerally terminate when the underlying mineral lease expires). The Companyowns 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 aresult of the North Central acquisition.

 

*Average Production (Lifting) Costs per Unit ofProduction*

 

The following table shows the average production (lifting) costs perunit of production during the periods indicated. For a discussion of theCompany’s average daily production and the average sales prices received by theCompany for such production see “Selected Financial Data Production (Sales)Data” and “Management’s Discussion and Analysis of Financial Condition andResults of Operations—Results of Operations; Oil and Gas Revenues.”

 
|                                              |   | **2002** |   | **2001** |   | **2000** |   |
|---------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Average Production  (Lifting) Costs per Mcfe (a): |   |     |   |     |   |     |   |
| Located in the United States                      |   | $        | 0.67   |     | $      | 0.81     |   | $ | 0.82 |   |
| Located in the Kingdom of Thailand                |   | $        | 0.59   |     | $      | 0.65     |   | $ | 0.69 |   |
| Total Company                                     |   | $        | 0.65   |     | $      | 0.75     |   | $ | 0.77 |   |

 

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(a)          Production costs wereconverted to common units of measure on the basis of relative energy content.Such production costs exclude all depletion, depreciation and amortizationassociated with property and equipment. The Company’s operations in Canada weresold effective August 31, 2001 as part of an asset rationalization process.Average production (lifting) costs in Canada, prior to its sale, were $1.37 in2001 and $0.88 in 2000.

 

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*Productive Wells and Drilling Activity*

 

The following table shows the Company’s interest in productive oil andnatural gas wells as of December 31, 2002. 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 pipelineconnections or necessary governmental certification to commence deliveries andoil wells waiting to be connected to currently installed productionfacilities). “Net wells” for purposes of this table are defined to mean theCompany’s working interest net of royalties and other burdens. This table doesnot include exploratory or developmental wells which have located commercialquantities of oil or natural gas but which are not capable of commercialproduction without the installation of material production facilities or which,for a variety of reasons, the Company does not currently believe will be placedon production.

 
|                |   | **Oil Wells (a)(b)** |   | **Natural  Gas Wells (a)(b)** |   |
|---------------------|--------|----------------------|--------|-------------------------------|--------|
|                |   | **Gross**            |   | **Net**                       |   | **Gross** |   | **Net** |   |
|                |   |                 |   |                          |   |   |   |   |   |
| Domestic Offshore   |   | 168                  |   | 49.2                          |   | 80 |   | 21.3 |   |
| Domestic Onshore    |   | 747                  |   | 559.8                         |   | 590 |   | 282.5 |   |
| Kingdom of Thailand |   | 74                   |   | 34.3                          |   | 61 |   | 28.3 |   |
| Total               |   | 989                  |   | 643.3                         |   | 731 |   | 332.1 |   |

 

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(a)          One or more completions in the same bore holeare counted as one well. The data in the above table includes 17 gross (5.8net) oil wells and 5 gross (1.9 net) natural gas wells with multiplecompletions.

 

(b)   TheCompany was in the process of drilling a total of 4 gross (.34 net) oil wellsand 14 gross (7.61 net) natural gas wells as of December 31, 2002.

 

The following table shows the number of successfulgross and net exploratory and development wells in which the Company hasparticipated and the number of gross and net wells abandoned as dry holesduring the periods indicated. An onshore well is considered successful upon theinstallation of permanent equipment for the production of hydrocarbons or whenelectric logs run to evaluate such wells indicate the presence of commerciallyproducible hydrocarbons and the Company currently intends to complete suchwells. Successful offshore wells consist of exploratory or development wellsthat have been completed or are “suspended” pending completion (which has beendetermined to be feasible and economic) and exploratory test wells that werenot intended to be completed and that encountered commercially produciblehydrocarbons. A well is considered a dry hole upon reporting of permanentabandonment to the appropriate agency.

 
|                                 |   | **2002**       |   | **2001** |   | **2000**       |   |
|--------------------------------------|--------|----------------|--------|----------|--------|----------------|--------|
|                                 |   | **Productive** |   | **Dry**  |   | **Productive** |   | **Dry** |   | **Productive** |   | **Dry** |   |
| **Gross Wells:**                     |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Offshore United States               |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Exploratory                          |   | 5.0            |   | 2.0      |   | 2.0            |   | 3.0 |   | 4.0 |   | 5.0 |   |
| Development                          |   | 13.0           |   | —   |   | 22.0           |   | — |   | 23.0 |   | 3.0 |   |
| Onshore United States and Canada (a) |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Exploratory                          |   | 1.0            |   | 4.0      |   | 7.0            |   | 3.0 |   | 14.0 |   | 5.0 |   |
| Development                          |   | 83.0           |   | 5.0      |   | 61.0           |   | 3.0 |   | 39.0 |   | — |   |
| Offshore Kingdom of Thailand         |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Exploratory                          |   | 6.0            |   | —   |   | 11.0           |   | — |   | 7.0 |   | 3.0 |   |
| Development                          |   | 51.0           |   | 2.0      |   | 18.0           |   | — |   | 24.0 |   | — |   |
|                                 |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Total                                |   | 159.0          |   | 13.0     |   | 121.0          |   | 9.0 |   | 111.0 |   | 16.0 |   |
|                                 |   |           |   |     |   |           |   |   |   |   |   |   |   |
| **Net Wells:**                       |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Offshore United States               |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Exploratory                          |   | 5.0            |   | 2.0      |   | 2.0            |   | 1.7 |   | 2.2 |   | 2.4 |   |
| Development                          |   | 8.8            |   | —   |   | 8.3            |   | — |   | 6.2 |   | 1.0 |   |
| Onshore United States and Canada (a) |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Exploratory                          |   | 0.8            |   | 3.2      |   | 5.0            |   | 1.3 |   | 3.8 |   | 2.5 |   |
| Development                          |   | 54.7           |   | 3.4      |   | 38.0           |   | 1.6 |   | 28.1 |   | — |   |
| Offshore Kingdom of Thailand         |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Exploratory                          |   | 2.8            |   | —   |   | 5.1            |   | — |   | 3.2 |   | 1.4 |   |
| Development                          |   | 23.5           |   | 0.9      |   | 8.3            |   | — |   | 11.1 |   | — |   |
|                                 |   |           |   |     |   |           |   |   |   |   |   |   |   |
| Total                                |   | 95.6           |   | 9.5      |   | 66.7           |   | 4.6 |   | 54.6 |   | 7.3 |   |

 

14

----

 

----

(a)   TheCompany’s operations in Canada were sold effective August 31, 2001 as part ofan asset rationalization program. Wells drilled in 2000 and 2001 reflect wellsdrilled in Canada by the Company prior to the sale of these operations.

 

*Reserves*

 

The following table sets forth information as to theCompany’s net proved and proved developed reserves as of December 31, 2002,2001 and 2000, and the present value as of such dates (based on an annualdiscount rate of 10%) of the estimated future net revenues from the productionand sale of those reserves, as set forth in reports prepared by Ryder ScottCompany L.P. (“Ryder Scott”) and Miller & Lents, Ltd. (“Miller &Lents”), the Company’s independent petroleum engineers, in accordance with criteriaprescribed by the Commission.

 

The Company doesnot currently believe that the calculation of estimated future net revenuesusing the assumptions prescribed by Commission guidelines and generallydescribed below is representative of the true value of future net revenues fromthe Company’s proved reserves. The future prices received by the Company forthe sales of its production may be higher or lower than the prices used incalculating the estimates of future net revenues, and the operating costs andother costs relating to such production may also increase or decrease fromexisting levels.

 
|                                                                                |   | **As of December 31,** |      |
|-------------------------------------------------------------------------------------|--------|------------------------|-----------|
|                                                                                |   | **2002**               |      | **2001** |   | **2000** |   |
| **Total Proved Reserves:**                                                          |   |                   |      |   |   |   |   |
| Oil, condensate and natural gas liquids  (MBbls)                                    |   |                   |      |   |   |   |   |
| Located in the United States and Canada (a)                                         |   | 80,092                 |      | 79,979 |   | 58,257 |   |
| Located in the Kingdom of Thailand                                                  |   | 38,087                 |      | 39,301 |   | 37,065 |   |
| Total Company                                                                       |   | 118,179                |      | 119,280 |   | 95,322 |   |
|                                                                                |   |                   |      |   |   |   |   |
| Natural Gas (MMcf)                                                                  |   |                   |      |   |   |   |   |
| Located in the United States and Canada (a)                                         |   | 713,906                |      | 670,567 |   | 216,679 |   |
| Located in the Kingdom of Thailand                                                  |   | 159,604                |      | 148,225 |   | 153,304 |   |
| Total Company                                                                       |   | 873,510                |      | 818,792 |   | 369,983 |   |
|                                                                                |   |                   |      |   |   |   |   |
| Present value of estimated future net  revenues, before income taxes (in thousands) |   |                   |      |   |   |   |   |
| Located in the United States and Canada (a)                                         |   | $                      | 2,495,558 |   | $ | 1,130,353 |   | $ | 1,948,895 |   |
| Located in the Kingdom of Thailand                                                  |   | 602,798                |      | 410,307 |   | 506,021 |   |
| Total Company                                                                       |   | $                      | 3,098,356 |   | $ | 1,540,660 |   | $ | 2,454,916 |   |
|                                                                                |   |                   |      |   |   |   |   |
| **Total Proved Developed  Reserves:**                                               |   |                   |      |   |   |   |   |
| Oil, condensate and natural gas liquids  (MBbls)                                    |   |                   |      |   |   |   |   |
| Located in the United States and Canada (a)                                         |   | 74,041                 |      | 59,383 |   | 35,910 |   |
| Located in the Kingdom of Thailand                                                  |   | 23,832                 |      | 20,394 |   | 24,747 |   |
| Total Company                                                                       |   | 97,873                 |      | 79,777 |   | 60,657 |   |
|                                                                                |   |                   |      |   |   |   |   |
| Natural Gas (MMcf)                                                                  |   |                   |      |   |   |   |   |
| Located in the United States and Canada (a)                                         |   | 600,255                |      | 532,348 |   | 152,742 |   |
| Located in the Kingdom of Thailand                                                  |   | 87,301                 |      | 69,997 |   | 87,236 |   |
| Total Company                                                                       |   | 687,556                |      | 602,345 |   | 239,978 |   |
|                                                                                |   |                   |      |   |   |   |   |
| Present value of estimated future net revenues, before income taxes  (in thousands) |   |                   |      |   |   |   |   |
| Located in the United States and Canada (a)                                         |   | $                      | 2,239,781 |   | $ | 951,040 |   | $ | 1,246,068 |   |
| Located in the Kingdom of Thailand                                                  |   | 422,219                |      | 241,860 |   | 445,033 |   |
| Total Company                                                                       |   | $                      | 2,662,000 |   | $ | 1,192,900 |   | $ | 1,691,101 |   |

 

----

(a)   The Company sold itsoperations and reserves in Canada effective August 31, 2001 as part of an assetrationalization process. Consequently, year-end 2002 and 2001 reserves, and thepresent value of future net revenues for those reserves, do not include anyreserves located in Canada.

 

The Company believes, for the reasons set forth insucceeding paragraphs, that the present value of estimated future net revenuesset forth in the Annual Report and calculated in accordance with Commission guidelinesis 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 domesticnatural gas production is currently sold on the spot market, while all of theCompany’s Thailand natural gas production is sold pursuant to a long-term gassales contract, the estimates of future net revenues from the Company’sdomestic and Thailand reserves are of limited value for comparative purposes.

 

15

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Natural gas liquids comprised approximately 6% of the Company’s totalproved liquids reserves and approximately 6% of the Company’s proved developedliquids reserves as of December 31, 2002. All hydrocarbon liquid reserves areexpressed in standard 42 gallon Bbls. All gas volumes and gas sales areexpressed in MMcf at the pressure and temperature bases of the area where thegas reserves are located.

 

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

 
|                                               |   | **As of December 31,** |   |
|----------------------------------------------------|--------|------------------------|--------|
|                                               |   | **2002**               |   | **2001** |   | **2000** |   |
| Initial Weighted Average Price (in Dollars):       |   |                   |   |   |   |   |   |
| Oil, condensate and natural gas liquids (per  Bbl) |   |                   |   |   |   |   |   |
| Located in the United States and Canada (a)        |   | $                      | 28.72  |   | $ | 18.75 |   | $ | 26.10 |   |
| Located in the Kingdom of Thailand                 |   | $                      | 32.41  |   | $ | 18.94 |   | $ | 24.23 |   |
| Natural Gas (per Mcf)                              |   |                   |   |   |   |   |   |
| Located in the United States and Canada (a)        |   | $                      | 4.70   |   | $ | 2.48 |   | $ | 10.14 |   |
| Located in the Kingdom of Thailand                 |   | $                      | 2.24   |   | $ | 2.31 |   | $ | 2.27 |   |

 

----

(a)   The Company sold itsoperations and reserves in Canada effective August 31, 2001 as part of an assetrationalization process. Consequently, average price figures do not includeCanada sales for the last five months of 2001 and all of 2002.

 

In computing future revenues from gas reservesattributable to the Company’s domestic interests, prices in effect at December31, 2002 were used, including current market prices, contract prices and fixedand determinable price escalations where applicable. In accordance with Commissionguidelines, the gas prices that were used make no allowances for seasonalvariations in gas prices that are likely to cause future yearly average gasprices to be different than December gas prices. For domestic gas sold undercontract, the contract gas price including fixed and determinable escalations,exclusive of inflation adjustments, was used until the contract expires andthen was adjusted to the current market price for the area and held at thisadjusted price to depletion of the reserves. In computing future revenues fromliquids attributable to the Company’s domestic interests, prices in effect atDecember 31, 2002 were used and these prices were held constant to depletion ofthe properties. The future net revenues are adjusted to reflect the Company’snet revenue interest in these reserves as well as any ad valorem and otherseverance taxes but do not include any provisions for corporate income taxes.

 

In computing future revenues from the Company’s gas reservesattributable to the Company’s interests in the Kingdom of Thailand, a blendedprice that took into account the current contract price under the Gas SalesAgreement for the base production (currently 145 MMcf per day) and the pricefor excess sales volumes (which varies depending on the period and thenomination) was used, without giving effect to any of the future adjustmentsprovided for in the Gas Sales Agreement, due to their indeterminate nature asof December 31, 2002, in accordance with Commission guidelines. In computingfuture revenues from liquids attributable to the Company’s interests in theKingdom of Thailand, a price was used that the Company believes approximatesthe price that the Company would have received for its production from theThailand Concession based upon the world market price for Malaysian Tapis Blendbenchmark crude on December 31, 2002, and this price was held constant untildepletion of the Company’s reserves in the Kingdom of Thailand. The future netrevenues are adjusted to reflect the Company’s net revenue interest in thesereserves and the Company’s obligations under the Thailand Concession, includingthe payment of SRB and applicable production bonuses, but do not include anyprovisions for U.S. or Thai corporate income or other taxes.

 

In accordance with Commission guidelines forcalculating future net revenues, the operating costs for the leases and wellsinclude only those costs directly applicable to the leases or wells. Whenapplicable, the operating costs include a portion of general and administrativecosts allocated directly to the leases and wells under terms of operatingagreements. Development costs are based on authorization for expenditure forthe proposed work or actual costs for similar projects. The current operatingand development costs were held constant throughout the life of the properties.The estimated net cost of abandonment after salvage was considered for theproperties. No deduction was made for indirect costs such as general andadministrative and overhead expenses, loan repayments, interest expenses andexploration 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 includesestimated production for the last few months of 2002. The future productionrates from reservoirs now on production may be more or less than estimatedbecause of, among other reasons, mechanical breakdowns and changes in marketdemand or allowables set by

 

16

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regulatory bodies. Properties that are not currently producing maystart producing earlier or later than anticipated in the estimates of futureproduction rates.

 

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

 

The Company is periodically required to file estimates of its oil andgas reserve data with various U.S. governmental regulatory authorities andagencies, including the Department of Energy, the Federal Energy RegulatoryCommission (“FERC”) and the Federal Trade Commission and, with respect toreserves located in Thailand, the Kingdom of Thailand’s Department of MineralResources and PTT, which the Company considers a quasi-governmental authority.In addition, estimates are from time to time furnished to governmental agenciesin connection with specific matters pending before such agencies. The basis forreporting reserves to these agencies, in some cases, is not comparable to thatfurnished by Ryder Scott and by Miller & Lents in accordance withCommission guidelines because of the nature of the various reports required.The major differences generally include differences in the time as of whichsuch estimates are made, differences in the definition of reserves,requirements to report in some instances on a gross, net or total operatorbasis and requirements to report in terms of smaller geographical units. During2002, no estimates by the Company of its total proved net oil and gas reserveswere filed with or included in reports to any governmental authority or agencyother than the Commission.

 

**Government Regulations**

 

*Federal Income Tax*

 

Federal income tax lawssignificantly affect the Company’s operations. The principal provisionsaffecting the Company are those that permit the Company, subject to certainlimitations, to deduct as incurred, rather than to capitalize and amortize, itsdomestic “intangible drilling and development costs” and to claim depletion ona portion of its domestic oil and gas properties based on 15% of its oil andgas gross income from such properties (up to an aggregate of 1,000 Bbls per dayof domestic crude oil and/or equivalent units of domestic natural gas), eventhough the Company has little or no basis in such properties. Under certaincircumstances, however, a portion of such intangible drilling and developmentcosts and the percentage depletion allowed in excess of basis will be taxpreference items that will be taken into account in computing the Company’s alternative minimum tax. Inaddition, the Company currently has substantial net operating losscarryforwards, principally related to its operations in Thailand, that areavailable to offset the Company’s future taxable income. The Company currentlyexpects to utilize the majority of these net operating loss carryforwards inthe next two years.

 

*Environmental Matters*

 

Domestic oil and gas operations are subject to extensive federalregulation and, with respect to federal leases, to interruption or terminationby governmental authorities on account of environmental and otherconsiderations such as the Comprehensive Environmental Response, Compensationand Liability Act (“CERCLA”) also known as the “Superfund Law.” The trendtowards stricter standards in environmental legislation and regulation couldincrease costs to the Company and others in the industry. Oil and gas lesseesare subject to liability for the costs of clean-up of pollution resulting froma lessee’s operations, and may also be subject to liability for pollutiondamages. The Company maintains insurance against costs of clean-up operations,but is not fully insured against all such risks. A serious incident ofpollution may, as it has in the past, also result in the Department of theInterior requiring lessees under federal leases to suspend or cease operationin the affected area.

 

The operators of the Company’s properties have numerous applicationspending before the Environmental Protection Agency (the “EPA”) for NationalPollution Discharge Elimination System (“NPDES”) water discharge permits withrespect to offshore drilling and production operations. NPDES permits arerequired to ensure that effluent discharges from each facility or installationcomply with the applicable federal regulations.

 

The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunderimpose a variety of regulations on “responsible parties” related to theprevention of oil spills and liability for damages resulting from such spillsin United States waters. The OPA assigns liability to each responsible partyfor oil removal costs and a variety of public and private damages. Whileliability limits apply in some circumstances, a party cannot take advantage of

 

17

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liability limits if the spill was caused by gross negligence or willfulmisconduct or resulted from violation of federal safety, construction oroperating regulations. Few defenses exist to the liability imposed by the OPA.In addition, to the extent the Company’s offshore lease operations affect statewaters, the Company may be subject to additional state and local clean-uprequirements 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 apotential spill. The amount of financial responsibility that the Company mustcurrently demonstrate for its offshore platforms is $70,000,000. The Companybelieves that it currently has established adequate proof of financialresponsibility for its offshore facilities at no significant increase inexpense over recent prior years. However, the Company cannot predict whetherthese financial responsibility requirements under the OPA amendments willresult in the imposition of substantial additional annual costs to the Companyin 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 othersimilarly situated or less capitalized owners or operators in the Gulf ofMexico.

 

The Company’s onshore operations are subject tonumerous federal, state and local laws and regulations controlling thedischarge of materials into the environment or otherwise relating to theprotection of the environment including CERCLA. Such laws and regulations, among other things, imposeabsolute liability on the lessee for the cost of clean-up of pollutionresulting from a lessee’s operations, subject the lessee to liability forpollution damages, may require suspension or cessation of operations inaffected areas, and impose restrictions on the injection of liquids intosubsurface aquifers that may contaminate groundwater. Such laws could have asignificant impact on the operating costs of the Company, as well as the oiland gas industry in general. Federal, state and local initiatives to furtherregulate the disposal of oil and gas wastes are also pending in certainjurisdictions, and these initiatives could have a similar impact on theCompany. The Company’s operations are also subject to additional federal, stateand local laws and regulations relating to protection of human health, naturalresources, and the environment pursuant to which the Company may incurcompliance costs or other liabilities.

 

The Company is asked to comment on the costs itincurred during the prior year on capital expenditures for environmentalcontrol facilities and the amount it anticipates incurring during the comingyear. The Company believes that, in the course of conducting its oil and gasoperations, many of the costs attributable to environmental control facilitieswould have been incurred absent environmental regulations as prudent, safeoilfield practice. During 2002, the Company incurred capital expenditures ofapproximately $2,211,000 for environmental control facilities, primarilyrelating to the cost of installing environmental equipment on the Company’sMain Pass Blocks 61/62 Field “B” platform and five new Benchamas platforms, theconversion of two wells to salt water disposal wells, the installation of pitand firewall spill liners, and routine site restoration costs. The Company hasbudgeted approximately $1,592,000 for expenditures involving environmentalcontrol facilities during 2003, including, among other things, anticipated siterestoration costs and the installation of environmental control equipment.

 

*Other Laws and Regulations*

 

Various laws and regulations often require permits for drilling wellsand also cover spacing of wells, the prevention of waste of oil and gasincluding maintenance of certain gas/oil ratios, rates of production and othermatters. The effect of these laws and regulations, as well as other regulationsthat could be promulgated by the jurisdictions in which the Company hasproduction, could be to limit the number of wells that could be drilled on theCompany’s properties and to limit the allowable production from the successfulwells completed on the Company’s properties, thereby limiting the Company’srevenues.

 

The MMS administers the oil and gas leases held by the Company onfederal onshore lands and offshore tracts in the Outer Continental Shelf. TheMMS holds a royalty interest in these federal leases on behalf of the federalgovernment. While the royalty interest percentage is fixed at the time that thelease is entered into, from time to time the MMS changes or reinterprets theapplicable regulations governing its royalty interests, and such action canindirectly affect the actual royalty obligation that the Company is required topay. However, the Company believes that the impact of the regulations generallydo not impact the Company to any greater extent than other similarly situatedproducers.

 

The FERC has embarked on wide-ranging regulatoryinitiatives relating to gas transportation rates and services, including theavailability of market-based and other alternative rate mechanisms to pipelinesfor transmission and storage services. In addition, the FERC has announced andimplemented a policy allowing pipelines and transportation customers tonegotiate rates above the otherwise applicable maximum lawful cost-based rateson the condition that the pipelines alternatively offer so-called recourserates equal to the maximum lawful cost-based rates. With respect to gatheringservices, the FERC has issued orders declaring that certain facilities owned byinterstate pipelines primarily perform a gathering function, and may betransferred to affiliated and non-affiliated

 

18

----

 

entities that are not subject to the FERC’s rate jurisdiction. TheCompany cannot predict the ultimate outcome of these developments, or theeffect of these developments on transportation rates. Inasmuch as the rates forthese pipeline services can affect the gas prices received by the Company forthe sale of its production, the FERC’s actions may have an impact on theCompany. However, the impact should not be substantially different on theCompany than it will on other similarly situated gas producers and sellers.

 

**Employees**

 

As of December 31, 2002, the Company and itssubsidiaries had 219 full-time employees, including seven in its Bangkok,Thailand office and four in its Budapest, Hungary office. None of the Company’semployees are presently represented by a union for collective bargainingpurposes. The Company considers its relations with its employees to begenerally excellent.

 

**Available Information**

 

The Company files annual, quarterly and currentreports, proxy statements and other information with the Commission. Thesefilings are available free of charge through our internet website atwww.pogoproducing.com as soon as reasonably practicable after we electronicallyfile such material with, or furnish it to, the Commission.

 

**ITEM 2.  *Properties.***

 

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

 

**ITEM 3.  *Legal Proceedings.***

 

The Company is a party to various legal proceedingsconsisting of routine litigation incidental to its businesses, but believesthat any potential liabilities resulting from these proceedings are adequatelycovered by insurance or are otherwise immaterial at this time. See“Business—Government Regulation; Other Laws and Regulations.”

 

**ITEM 4.*  Submissionof Matters to a Vote of Security-Holders.***

 

Not Applicable.

 

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

 

Officers of the Company are appointed annually by theCompany’s Board of Directors to serve for the ensuing year or until theirsuccessors have been elected or appointed. The officers of the Company thathave been designated as “executive officers” for purposes of Item 401(b) ofRegulation S-K and “officers” for purposes of Section 16 of the Exchange Act,their age as of December 31, 2002, and the year each was elected to his currentposition are as follows:

 
| **Executive Officer** |   | **Executive Office**                                                        |   | **Age** |   | **Year Elected** |   |
|-----------------------|--------|-----------------------------------------------------------------------------|--------|---------|--------|------------------|--------|
| Paul G. Van  Wagenen  |   | Chairman, President and Chief Executive Officer                             |   | 56      |   | 1991             |   |
| Stephen R. Brunner    |   | Executive  Vice President – Operations                                 |   | 44      |   | 2002             |   |
| Stuart P. Burbach     |   | Executive  Vice President – Exploration                                |   | 50      |   | 1998             |   |
| Jerry A. Cooper       |   | Executive Vice President and Regional  Manager – Western United States |   | 54      |   | 2002             |   |
| John O. McCoy, Jr.    |   | Executive Vice President and Chief  Administrative Officer                  |   | 51      |   | 2002             |   |
| David R. Beathard     |   | Senior  Vice President – Engineering                                   |   | 44      |   | 2002             |   |
| Gerald A. Morton      |   | Senior Vice President and Regional Manager –  Asia and Pacific         |   | 44      |   | 2003             |   |
| James P. Ulm, II      |   | Senior  Vice President and Chief Financial Officer                          |   | 39      |   | 2002             |   |
| Thomas E. Hart        |   | Vice  President and Chief Accounting Officer                                |   | 59      |   | 1999             |   |
| Michael J. Killelea   |   | Vice  President and General Counsel                                         |   | 40      |   | 2001             |   |

 

Mr. Van Wagenen, who joined the Company in 1979, hasserved in his current position since 1991. Prior to assuming their presentpositions with the Company, the business experience of each of the otherexecutive officers for more than the last five years was as follows: Mr.Brunner, who joined the Company in 1994, served as Vice President – Operationssince 1997; Mr. Burbach served as Vice President and Offshore Division Managersince rejoining the Company in 1991; Mr. Cooper, who joined the Company in1979, served as Senior Vice President and Western Division Manager since 1998and prior thereto, served as Vice President and Western Division Manager since1990; Mr. McCoy, who joined the Company in 1978, served as Senior VicePresident and Chief Administrative Officer of the Company since 1998 and asVice President and Chief Administrative Officer since 1989; Mr. Beathard, whojoined the Company in 1982, served as Vice President – Engineering since 1997;Mr. Morton, who joined the Company in 1993, served as Vice President andRegional Manager – Asia and Pacific since

 

19

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2002, Vice President – Law, Chief Regulatory Officer and CorporateSecretary since 2001, and prior thereto was Vice President – Law and CorporateSecretary since 1997; Mr. Ulm served as Treasurer of Newfield ExplorationCompany from 1995 until joining the Company as its Vice President and ChiefFinancial Officer in 1999; Mr. Hart joined the Company in 1977 and served asVice President and Controller since 1988; and Mr. Killelea was Chief Counsel ofthe Company since he joined the Company in 2000 and prior thereto served asChief Counsel of CMS Oil and Gas Company for more than three years.

 

###### **PART II**

 

**ITEM 5.  *Market for the Registrant’s Common Equity and RelatedStockholder Matters.***

 

The following table shows the range of low and highsales prices of the Company’s Common Stock (the “Common Stock”) on the New YorkStock Exchange composite tape where the Common Stock trades under the symbolPPP. The Common Stock is also listed on the Pacific Exchange under the samesymbol.

 
|        |   | **Low** |   | **High** |   |
|-------------|--------|---------|--------|----------|--------|
| **2001**    |   |    |   |     |   |
| 1st Quarter |   | $       | 25.00  |     | $      | 34.50 |   |
| 2nd Quarter |   | $       | 23.02  |     | $      | 31.10 |   |
| 3rd Quarter |   | $       | 21.90  |     | $      | 26.89 |   |
| 4th Quarter |   | $       | 20.45  |     | $      | 29.23 |   |
|        |   |    |   |     |   |
| **2002**    |   |    |   |     |   |
| 1st Quarter |   | $       | 23.00  |     | $      | 31.75 |   |
| 2nd Quarter |   | $       | 29.44  |     | $      | 35.49 |   |
| 3rd Quarter |   | $       | 25.44  |     | $      | 34.71 |   |
| 4th Quarter |   | $       | 31.90  |     | $      | 39.28 |   |

 

As of February 26, 2003, there were 2,253 holders ofrecord of the Company’s Common Stock.

 

In each of 2001 and 2002, the Company paid four quarterly dividends of$0.03 per share on its Common Stock.  OnJanuary 21, 2003, the Company increased its dividend 67% to $0.05 per share.The declaration and payment of future dividends, and the amount of suchdividends, will depend upon, among other things, the Company’s future earningsand financial condition, liquidity and capital requirements, the generaleconomic and regulatory climate and other factors deemed relevant by theCompany’s Board of Directors.

 

The Company’s revolving credit facility with its banks under which theCompany has borrowed funds, and the Indentures relating to the Company’s 8 3/4%Senior Subordinated Notes due 2007 (the “2007 Notes”), 10 3/8% SeniorSubordinated Notes due 2009 (the “2009 Notes”) and 8 1/4% Senior SubordinatedNotes due 2011 (the “2011 Notes”) contain covenants that may restrict theability of the Company to pay future dividends on the Company’s Common Stock.The Company does not currently believe that any of these agreements willrestrict the Company’s ability to pay dividends on its Common Stock at any timein the reasonably foreseeable future.

 

20

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**ITEM 6.     *Selected Financial Data.***

 

In the followingtable, the Company’s financial, production and other data for 2002 and 2001reflect the Company’s acquisition of North Central from and on March 14,2001.  The selected financial data should be readin conjunction with “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” and the audited consolidated financialstatements and notes thereto included under “Financial Statements andSupplementary Data.”

 
|                                                                        |   | **For the  Year Ended December 31,**                                |       |
|-----------------------------------------------------------------------------|--------|---------------------------------------------------------------------|------------|
|                                                                        |   | **2002**                                                            |       | **2001(a)** |   | **2000(a)** |   | **1999(a)** |   | **1998(a)** |   |
|                                                                        |   | **(Expressed  in thousands, except per share and production data)** | ** ** |
| Financial Data                                                              |   |                                                                |       |   |   |   |   |   |   |   |   |
| Revenues:                                                                   |   |                                                                |       |   |   |   |   |   |   |   |   |
| Crude oil and condensate                                                    |   | $                                                                   | 431,826    |   | $ | 261,226 |   | $ | 272,932 |   | $ | 109,803 |   | $ | 74,703 |   |
| Natural gas                                                                 |   | 291,975                                                             |       | 322,390 |   | 190,401 |   | 111,152 |   | 116,148 |   |
| Natural gas liquids                                                         |   | 23,187                                                              |       | 12,461 |   | 15,869 |   | 9,544 |   | 9,303 |   |
| Oil and gas revenues                                                        |   | 746,988                                                             |       | 596,077 |   | 479,202 |   | 230,499 |   | 200,154 |   |
| Gains (losses) on sales                                                     |   | 3,034                                                               |       | 1,000 |   | 3,676 |   | 37,458 | (c) | (92 | ) |
| Other                                                                       |   | 1,419                                                               |       | 13,040 |   | 15,113 |   | 7,159 |   | 2,741 |   |
| Total                                                                       |   | $                                                                   | 751,441    |   | $ | 610,117 |   | $ | 497,991 |   | $ | 275,116 |   | $ | 202,803 |   |
|                                                                        |   |                                                                |       |   |   |   |   |   |   |   |   |
| Income (loss) before cumulative effect of change in accounting  principle   |   | $                                                                   | 107,031    |   | $ | 87,954 |   | $ | 89,023 |   | $ | 22,134 |   | $ | (43,098 | ) |
| Cumulative effect of change in accounting principle                         |   | —                                                              |       | — |   | (1,768 | )(b) | — |   | — |   |
| Net income (loss)                                                           |   | $                                                                   | 107,031    |   | $ | 87,954 |   | $ | 87,255 |   | $ | 22,134 |   | $ | (43,098 | ) |
|                                                                        |   |                                                                |       |   |   |   |   |   |   |   |   |
| Per share data:                                                             |   |                                                                |       |   |   |   |   |   |   |   |   |
| Income (loss) before cumulative effect of change in accounting  principle - |   |                                                                |       |   |   |   |   |   |   |   |   |
| Basic                                                                       |   | $                                                                   | 1.85       |   | $ | 1.72 |   | $ | 2.20 |   | $ | 0.55 |   | $ | (1.14 | ) |
| Diluted                                                                     |   | $                                                                   | 1.77       |   | $ | 1.62 |   | $ | 1.99 |   | $ | 0.55 |   | $ | (1.14 | ) |
| Cash dividends on common stock                                              |   | $                                                                   | 0.12       |   | $ | 0.12 |   | $ | 0.12 |   | $ | 0.12 |   | $ | 0.12 |   |
| Price range of common stock:                                                |   |                                                                |       |   |   |   |   |   |   |   |   |
| High                                                                        |   | $                                                                   | 39.28      |   | $ | 34.50 |   | $ | 33.19 |   | $ | 23.44 |   | $ | 34.69 |   |
| Low                                                                         |   | $                                                                   | 23.00      |   | $ | 20.45 |   | $ | 18.00 |   | $ | 8.94 |   | $ | 9.81 |   |
|                                                                        |   |                                                                |       |   |   |   |   |   |   |   |   |
| Weighted average number of common shares outstanding                        |   | 57,963                                                              |       | 51,031 |   | 40,445 |   | 40,178 |   | 37,902 |   |
| Long-term debt at year end                                                  |   | $                                                                   | 722,903    |   | $ | 792,561 |   | $ | 365,000 |   | $ | 375,000 |   | $ | 434,947 |   |
| Minority interest at year end                                               |   | $                                                                   | —     |   | $ | 145,086 |   | $ | 144,913 |   | $ | 144,751 |   | $ | — |   |
| Shareholders’ equity at year end                                       |   | $                                                                   | 1,077,784  |   | $ | 824,885 |   | $ | 358,271 |   | $ | 268,512 |   | $ | 249,660 |   |
| Total assets at year end                                                    |   | $                                                                   | 2,491,593  |   | $ | 2,423,979 |   | $ | 1,114,649 |   | $ | 948,193 |   | $ | 862,396 |   |
|                                                                        |   |                                                                |       |   |   |   |   |   |   |   |   |
| Production (Sales) Data                                                     |   |                                                                |       |   |   |   |   |   |   |   |   |
| Net daily average production and weighted average price:                    |   |                                                                |       |   |   |   |   |   |   |   |   |
| Natural gas (Mcf per day)                                                   |   | 279,000                                                             |       | 237,800 |   | 164,600 |   | 141,600 |   | 159,000 |   |
| Price (per Mcf)                                                             |   | $                                                                   | 2.87       |   | $ | 3.71 |   | $ | 3.16 |   | $ | 2.15 |   | $ | 2.00 |   |
| Crude oil-condensate (Bbl per day)                                          |   | 47,360                                                              |       | 29,590 |   | 25,788 |   | 16,036 |   | 15,775 |   |
| Price (per Bbl)                                                             |   | $                                                                   | 24.90      |   | $ | 23.99 |   | $ | 28.92 |   | $ | 18.76 |   | $ | 12.97 |   |
| Natural gas liquids (Bbl per day)                                           |   | 4,480                                                               |       | 2,118 |   | 2,141 |   | 2,077 |   | 2,422 |   |
| Price (per Bbl)                                                             |   | $                                                                   | 14.18      |   | $ | 16.12 |   | $ | 20.25 |   | $ | 12.59 |   | $ | 10.52 |   |
|                                                                             |        |                                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(a)    The Company’s financial statements for1998 — 2001 were audited by Arthur Andersen LLP, who have ceased operations.

(b)    Crude oil and condensate from theCompany’s producing fields located in the Kingdom of Thailand are produced intostorage vessels and are sold and recognized as revenue periodically as economicquantities are accumulated. Effective January 1, 2000, the Company adopted theprovisions of the Commission’s Staff Accounting Bulletin No. 101, RevenueRecognition. As a result, the Commission no longer accepts the oil and gasexploration and production industry’s long-standing historical practice ofrecording such product inventories at their net realizable value. Thecumulative effect of this change in accounting principle through December 31,1999 ($1,768,000, net of tax benefits of $1,768,000) was charged to earningseffective January 1, 2000.

(c)    Primarily reflects the gain on sale ofthe Company’s Lopeno field in the first quarter of 1999.

 

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|                                                  |   | **For the  Year Ended December 31,** |       |
|-------------------------------------------------------|--------|--------------------------------------|------------|
|                                                  |   | **2002**                             |       | **2001** |   | **2000** |   | **1999** |   | **1998** |   |
|                                                  |   | **(Expressed  in thousands)**        | ** ** |
| Capital Expenditures (including interest capitalized) |   |                                 |       |   |   |   |   |   |   |   |   |
| Oil and gas:                                          |   |                                 |       |   |   |   |   |   |   |   |   |
| Domestic Offshore -                                   |   |                                 |       |   |   |   |   |   |   |   |   |
| Exploration                                           |   | $                                    | 33,600     |   | $ | 18,000 |   | $ | 18,700 |   | $ | 12,600 |   | $ | 20,200 |   |
| Development                                           |   | 100,700                              |       | 169,000 |   | 43,700 |   | 43,200 |   | 42,500 |   |
| Purchase of reserves                                  |   | —                               |       | 87,700 |   | — |   | — |   | 5,000 |   |
| Onshore North America -                               |   |                                 |       |   |   |   |   |   |   |   |   |
| Exploration                                           |   | 14,500                               |       | 38,300 |   | 19,700 |   | 9,800 |   | 16,500 |   |
| Development                                           |   | 117,200                              |       | 113,600 |   | 34,700 |   | 19,800 |   | 28,100 |   |
| Purchase of reserves                                  |   | —                               |       | 1,027,200 |   | 8,400 |   | 19,500 |   | 133,100 |   |
| International -                                       |   |                                 |       |   |   |   |   |   |   |   |   |
| Exploration                                           |   | 3,100                                |       | 11,500 |   | 9,400 |   | 3,500 |   | 11,600 |   |
| Development                                           |   | 109,300                              |       | 64,700 |   | 51,500 |   | 106,300 |   | 95,500 |   |
| Purchase of  reserves                                 |   | —                               |       | — |   | — |   | — |   | — |   |
| Total oil and gas                                     |   | 378,400                              |       | 1,530,000 |   | 186,100 |   | 214,700 |   | 352,500 |   |
| Other                                                 |   | 3,300                                |       | 4,800 |   | 700 |   | 2,200 |   | 6,300 |   |
| Total                                                 |   | $                                    | 381,700    |   | $ | 1,534,800 |   | $ | 186,800 |   | $ | 216,900 |   | $ | 358,800 |   |
|                                                       |        |                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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

 

Statements in thefollowing discussion may be forward-looking and involve risks anduncertainties. The Company’s financial results are most directly affected bychanging prices for its production.Changing prices can influence not only current results of operations but thedetermination of the Company’s proved reserves and available sources offinancing, including the determination of the borrowing base under its bankcredit facility. The Company’s results depend not only on hydrocarbon pricesgenerally, but on its ability to market its production on favorable terms inthe areas in which it is produced, including foreign areas such as Thailandwhere the Company’s operations may be subject to local constraints on demand, currencyrestrictions, exchange rate fluctuations, the possibility of increases in taxesor other charges and non-renewal or other adverse action relating toconcessions or contracts, and other political risks. On a longer term basis theCompany’s financial condition and results of operations are affected by itsability to replace reserves as they are produced through successfulexploration, development and acquisition activity. The Company’s results couldalso be adversely affected by adverse regulatory developments and operationalrisks associated with oil and gas operations. Some of the other risks anduncertainties that may affect the Company’s results are mentioned in thediscussion that follows.

 

On March 14, 2001,the merger of Pogo Producing Company (the “Company”) and NORIC Corporation(“NORIC”) was consummated.  As a resultof the merger, the Company acquired all of the outstanding capital stock ofNorth Central Oil Corporation (“North Central”), an independent domestic oiland gas exploration and production company, which was the principal asset ofNORIC.  The merger was accounted forusing the purchase method of accounting. Commencing March 14, 2001, the resultsof North Central’s operations are consolidated with the Company’s.  Pursuant to the merger agreement among theCompany, NORIC and certain NORIC shareholders dated as of November 19, 2000,former shareholders of NORIC received 12,615,816 shares of the Company’s common stock and approximately$344,711,000 in cash.  In addition, atclosing the Company repaid all $78,600,000 principal amount of North Central’sexisting bank debt.  The sources offunds used in connection with the merger included cash on hand at the Companyand NORIC and borrowings under the Company’s revolving credit agreement.

 

Pogo Trust I, asubsidiary of the Company, called its 61⁄2% Cumulative Quarterly Income Convertible Preferred Securities due2029 (the “Trust Preferred Securities”) for redemption on June 3, 2002.  Prior to their redemption, holders of

 

22

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2,997,196 of the 3,000,000 outstanding Trust Preferred Securitiesconverted their Trust Preferred Securities, representing over $149,850,000 facevalue of Trust Preferred Securities, into 6,309,972 shares of the Company’scommon stock.  In connection with theredemption, Pogo Trust I paid a total of $147,000 to former holders of theTrust Preferred Securities.  Subsequentto June 3, 2002, there were no Trust Preferred Securities outstanding.

 

**Application of Critical Accounting Policiesand Management’s Estimates**

 

The discussion and analysis of the Company’s financial condition andresults of operations is based upon the consolidated financial statements,which have been prepared in accordance with accounting principles generally acceptedin the United States. The preparation of these financial statements requires usto make estimates and judgments that affect the reported amounts of assets,liabilities, revenues and expenses. Our significant accounting policies aredescribed in Note 1 to our consolidated financial statements for the year endedDecember 31, 2002 included in this Form 10-K. We have identified below policies that areof particular importance to the portrayal of our financial position and resultsof operations and which require the application of significant judgment bymanagement. We analyze our estimates, including those related to oil and gasrevenues, bad debts, oil and gas properties, marketable securities, incometaxes, derivatives, contingencies and litigation, and base our estimates onhistorical experience and various other assumptions that we believe to bereasonable under the circumstances. Actual results may differ from theseestimates under different assumptions or conditions. We believe the followingcritical accounting policies affect our more significant judgments andestimates used in the preparation of the Company’s financial statements:

 

*Successful Efforts Method Of Accounting*

 

The Company accounts forits oil and gas exploration and development activities utilizing the successfulefforts method of accounting. Under this method, costs of productiveexploratory wells, development dry holes and productive wells and undevelopedleases are capitalized. Oil and gas lease acquisition costs are also capitalized.Interest costs related to financing major oil and gas projects in progress arecapitalized until the projects are evaluated or until the projects aresubstantially complete and ready for their intended use if the projects areevaluated as successful.  Explorationcosts, including personnel costs, certain geological and geophysical expensesand delay rentals for oil and gas leases, are charged to expense as incurred.Exploratory drilling costs are initially capitalized, but such costs arecharged to expense if and when the well is determined not to have foundreserves in commercial quantities. In most cases, a gain or loss is recognizedfor sales of producing properties.

 

The application of thesuccessful efforts method of accounting requires management’s judgment todetermine the proper designation of wells as either developmental orexploratory, which will ultimately determine the proper accounting treatment ofthe costs incurred. The results from a drilling operation can take considerabletime to analyze, and the determination that commercial reserves have beendiscovered requires both judgment and application of industry experience. Wellsmay be completed that are assumed to be productive and actually deliver oil andgas in quantities insufficient to be economic, which may result in theabandonment of the wells at a later date. On occasion, wells are drilled whichhave targeted geologic structures that are both developmental and exploratoryin nature, and in such instances an allocation of costs is required to properlyaccount for the results. Delineation seismic costs incurred to selectdevelopment locations within a productive oil and gas field are typicallytreated as development costs and capitalized, but often these seismic programsextend beyond the proved reserve areas and therefore management must estimatethe portion of seismic costs to expense as exploratory. The evaluation of oiland gas leasehold acquisition costs requires management’s judgment to estimatethe fair value of exploratory costs related to drilling activity in a givenarea. Drilling activities in an area by other companies may also effectivelycondemn leasehold positions.

 

The successful effortsmethod of accounting can have a significant impact on the operational resultsreported when the Company enters a new exploratory area in hopes of finding oiland gas reserves. Seismic costs can be substantial which will result inadditional exploration expenses when incurred. The initial exploratory wells may be unsuccessful and the associatedcosts will be expensed as dry hole costs.

 

*ReserveEstimates*

 

The Company’s estimatesof oil and gas reserves are, by necessity, projections based on geologic andengineering data, and there are uncertainties inherent in the interpretation ofsuch data as well as the projection of future rates of production and thetiming of development expenditures. Reserve engineering is a subjective processof estimating underground accumulations of oil and gas that are difficult tomeasure. The accuracy of any reserve estimate is a function of the quality ofavailable data, engineering and geological interpretation and judgment.Estimates of economically recoverable oil and gas reserves and future net cashflows necessarily depend upon a number of variable factors and assumptions,such as historical production from the area compared with production from otherproducing 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 factvary considerably from actual results. The future drilling costs associatedwith reserves assigned to proved undeveloped locations may ultimately increaseto the extent that these reserves may be later determined to be uneconomic. Forthese reasons, estimates of the economically recoverable quantities of expectedoil and gas attributable to any

 

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particular group of properties, classifications of such reserves basedon risk of recovery, and estimates of the future net cash flows may varysubstantially. Any significant variance in the assumptions could materiallyaffect the estimated quantity and value of the reserves, which could affect thecarrying value of the Company’s oil and gas properties and/or the rate ofdepletion of such oil and gas properties. Actual production, revenues andexpenditures with respect to the Company’s reserves will likely vary fromestimates, and such variances may be material.

 

*ImpairmentOf Oil and Gas Properties*

 

The Company reviews itsproved oil and gas properties for impairment on an annual basis and wheneverevents and circumstances indicate a potential decline in the recoverability oftheir carrying value. The Company estimates the expected future cash flows fromits proved oil and gas properties and compares these future cash flows to thecarrying amount of the oil and gas properties to determine if the carryingamount is recoverable. If the carrying amount exceeds the estimatedundiscounted future cash flows, the Company will adjust the carrying amount ofthe oil and gas properties to its fair value in the current period. The factorsused to determine fair value include, but are not limited to, estimates ofreserves, future commodity pricing, future production estimates, anticipatedcapital expenditures, and a discount rate commensurate with the risk associatedwith realizing the expected cash flows projected. Unproved properties arereviewed quarterly to determine if there has been impairment of the carryingvalue, with any such impairment charged to expense in the period.  The Company recognized significantimpairment expense due to poor reservoir performance at one of its Gulf ofMexico properties in the first quarter of 2001, and has recognized other lesssignificant impairment expenses related to other properties in subsequentperiods. Given the complexities associated with oil and gas reserve estimatesand the history of price volatility in the oil and gas markets, events mayarise that will require the Company to record an impairment of its oil and gasproperties and there can be no assurance that such impairments will not berequired in the future.

 

*FairValues Of Derivative Instruments*

 

The estimated fair valuesof the Company’s derivative instruments are recorded on the Company’sconsolidated balance sheet. Historically, substantially all of the Company’sderivative instruments represent cash flow hedges of the price of future oiland natural gas production. Therefore, while fair values of such hedginginstruments must be estimated at the end of each reporting period, the relatedchanges in such fair values are not included in the Company’s consolidatedresults of operations, to the extent they are expected to offset the futurecash flows from oil and natural gas production. Instead, the changes in fairvalue of hedging instruments are recorded directly to shareholders’ equityuntil the hedged oil or natural gas quantities are produced.

 

The estimation of fairvalues for the Company’s hedging derivatives requires substantial judgment. TheCompany estimates the fair values of its derivatives on a monthly basis usingan option-pricing model. To utilize the option-pricing model, the Company uses various factors that include closingexchange prices on the NYMEX, over-the-counter quotations, volatility and thetime value of options.  Theestimated future prices are compared to the prices fixed by the hedgeagreements, and the resulting estimated future cash inflows (outflows) over thelives of the hedges are discounted using the Company’s current borrowing ratesunder its revolving credit facility. These pricing and discounting variablesare sensitive to market volatility as well as changes in future price forecasts,regional price differentials and interest rates.  Currently, all of the Company’s derivative instruments are hedgesof the price of crude oil and natural gas production. The Company is notinvolved in any derivative trading activities.

 

*BusinessCombinations/Acquisitions*

 

The Company grewsubstantially in 2001 through the acquisition of North Central. As statedearlier, this acquisition was accounted for using the purchase method ofaccounting, and subsequent accounting pronouncements require that all futureacquisitions be accounted for using the purchase method.

 

Under the purchasemethod, the acquiring company adds to its balance sheet the estimated fairvalues of the acquired company’s assets and liabilities. Any excess of thepurchase price over the fair values of the tangible and intangible net assetsacquired is recorded as goodwill.  As ofJanuary 1, 2002, the accounting for goodwill has changed. In prior years,goodwill was amortized.  EffectiveJanuary 1, 2002, goodwill and other intangibles with an indefinite useful lifeare no longer amortized, but instead are assessed for impairment at leastannually. The Company has never recorded any goodwill in connection with theacquisition of any assets.  However,there can be no assurance that the Company may not do so in the future.

 

There are variousassumptions made by the Company in determining the fair values of an acquiredcompany’s assets and liabilities. The most significant assumptions, and theones requiring the most judgment, involve the estimated fair values of the oiland gas properties acquired. To determine the fair values of these properties,the Company prepares estimates of oil, natural gas and natural gas liquid(“NGL”) reserves. These estimates are based on work performed by the Company’sengineers and outside petroleum reservoir consultants. The judgments associatedwith the estimation of reserves are described earlier in this section.  The fair value of the estimated reservesacquired in a business combination is then calculated based on the Company’sestimates of future oil, natural gas and NGL prices. The Company’s estimates offuture prices are based on its own analysis of

 

24

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pricing trends. These estimates are based on current data obtained withregard to regional and worldwide supply and demand dynamics, such as economicgrowth forecasts. They are also based on industry data regarding natural gasstorage availability, drilling rig activity, changes in delivery capacity andtrends in regional pricing differentials. Future price forecasts fromindependent third parties are also taken into account in arriving at theCompany’s own pricing estimates.  The Company’s estimates offuture prices are applied to the estimated reserve quantities acquired toarrive at estimated future net revenues. For estimated proved reserves, the future net revenues are thendiscounted to derive a fair value for such reserves.  The Company also applies these same general principles inarriving at the fair value of unproved reserves acquired in a businesscombination. These unproved reserves are generally classified as eitherprobable or possible reserves. Because of their very nature, probable andpossible reserve estimates are less precise than those of proved reserves.  Generally, in the Company’s businesscombinations, the determination of the fair values of oil and gas propertiesrequires more judgment than the estimates of fair values for other acquiredassets and liabilities.

 

*Future Development and Abandonment Costs*

 

Future development costsinclude costs incurred to obtain access to proved reserves, including drillingcosts and the installation of production equipment. Future abandonment costsinclude costs to dismantle and relocate or dispose of our production platforms,FPSOs, FSOs, gathering systems, wells and related structures and restorationcosts of land and seabed. We develop estimates of these costs for each of ourproperties based upon the type of production structure, depth of water, reservoircharacteristics, depth of the reservoir, market demand for equipment, currentlyavailable procedures and consultations with construction and engineeringconsultants. Because these costs typically extend many years into the future,estimating these future costs is difficult and requires management to makeestimates and judgments that are subject to future revisions based uponnumerous factors, including changing technology and the political andregulatory environment. The accounting for future development and abandonmentcosts changed on January 1, 2003, with the adoption of Statement of FinancialAccounting Standards No. 143, “Accounting for Asset RetirementObligations”.  See “Liquidity andCapital Resources - Recent Accounting Pronouncements” for a further discussionof this accounting standard.

 

*Pensionand Other Post-Retirement Benefits*

 

Accounting for pensionsand other postretirement benefits involves several assumptions including theexpected rates of return on plan assets, determination of discount rates forremeasuring plan obligations, determination of inflation rates regardingcompensation levels and health care cost projections.   The Companydevelops its demographics and utilizes the work of actuaries to assist with themeasurement of employee-related obligations.  The assumptions used varyfrom year-to-year, which will affect future results of operations.  Anydifferences among these assumptions and the results actually experienced willalso impact future results of operations.

 

*IncomeTaxes*

 

For financial reportingpurposes, the Company generally provides taxes at the rate applicable for theappropriate tax jurisdiction.  Where theCompany’s present intention is to reinvest in foreign ventures the unremittedearnings of certain of its foreign operations, the Company does not provide forU.S. income taxes on such unremitted earnings of those foreignsubsidiaries.  Management periodicallyassesses the need to utilize these unremitted earnings to finance the foreignoperations of the Company.  Thisassessment is based on cash flow projections that are the result of estimatesof future production, commodity pricing and expenditures by tax jurisdictionfor the Company’s operations. Such estimates are inherently imprecise sincemany assumptions utilized in the cash flow projections are subject to revisionin the future.

 

Management alsoperiodically assesses, by tax jurisdiction, the probability of recovery ofrecorded deferred tax assets based on its assessment of future earningsoutlooks. Such estimates are inherently imprecise since many assumptionsutilized in the assessments are subject to revision in the future.

 

***Results ofOperations***

 

*NetIncome*

 

The Company reported netincome for 2002 of $107,031,000 or $1.85 per share ($113,803,000 or $1.77 pershare on a diluted basis), compared to net income for 2001 of $87,954,000 or$1.72 per share ($98,403,000 or $1.62 per share on a diluted basis), and netincome for 2000 of $87,255,000 or $2.16 per share ($97,704,000 or $1.95 pershare on a diluted basis). Among other items affecting net income for 2002,2001 and 2000 were pre-tax gains of $3,034,000, $1,000,000 and $3,676,000,respectively, related to the Company’s sale of certain non-strategic propertiesas part of its asset rationalization process. The $3,034,000 recorded in 2002reflects gains of $3,900,000 on the sale of the Company’s Sea Robin gas plant,which was partially offset by losses on the sale of various other non-strategicoffshore properties. The Company has announced that it will continue to examineits non-strategic assets and will sell them if it believes that it can obtain afair price, but that it does not currently believe that such sales will have amaterial impact on the Company’s ongoing business activities.

 

25

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Earnings per common shareare based on the weighted average number of common shares outstanding for 2002of 57,963,000 (64,321,000 on a diluted basis), compared to 51,031,000(60,822,000 on a diluted basis) for 2001 and 40,445,000 (50,155,000 on adiluted basis) for 2000. The increase in the weighted average number of commonshares outstanding for 2002, compared to 2001, resulted primarily from theconversion of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securitiesinto 6,309,972 shares of the Company’s common stock on June 3, 2002 and to amuch lesser extent, the issuance of shares upon the exercise of stock optionspursuant to the Company’s stock option plans and stock issued as compensation.The increase in the weighted average number of common shares outstanding for2002, compared to 2000, resulted primarily from the issuance of 12,615,816shares of common stock to former shareholders of NORIC on March 14, 2001, theconversion of the Trust Preferred Securities into the Company’s common stockand to a much lesser extent, the issuance of shares upon the exercise of stockoptions pursuant to the Company’s stock option plans and stock issued ascompensation. The earnings per share computations on a diluted basis in 2002,2001 and 2000 primarily reflect additional shares of common stock issuable uponthe assumed conversion of the Company’s 51⁄2% Convertible Subordinated Notes due2006 (the “2006 Notes”) and the Trust Preferred Securities (on a weightedaverage basis in 2002) and the elimination of related interest requirements, asadjusted for applicable federal income taxes and, to a lesser extent, theassumed exercise of options to purchase common shares. In addition, the numberof common shares outstanding in the diluted computation is adjusted to includedilutive shares that are assumed to have been issued by the Company inconnection with outstanding options, less treasury shares that are assumed tohave been purchased by the Company from the option proceeds.

 

*TotalRevenues*

 

The Company’s totalrevenues for 2002 were $751,441,000, an increase of approximately 23% comparedto total revenues of $610,117,000 for 2001, and an increase of approximately51% compared to total revenues of $497,991,000 for 2000. The increase in theCompany’s total revenues for 2002, compared to 2001 and 2000, resultedprimarily from increased oil and gas revenues, partially offset by a decreasein pipeline sales which are included in other revenues.

 

*Oil andGas Revenues*

 

The Company’s oil and gasrevenues for 2002 were $746,988,000, an increase of approximately 25% from oiland gas revenues of $596,077,000 for 2001, and an increase of approximately 56%from oil and gas revenues of $479,202,000 for 2000. The following tablereflects an analysis of variances in the Company’s oil and gas revenues(expressed in thousands) between 2002 and the previous two years:

 

|                                                                   |   | **2002 Compared to** |    |
|------------------------------------------------------------------------|--------|----------------------|---------|
|                                                                   |   | **2001**             |    | **2000** |   |
|                                                                   |   |                 |    |   |   |
| Increase (decrease) in oil and gas revenues resulting in variances in: |   |                 |    |   |   |
| **Natural gas -**                                                      |   |                 |    |   |   |
| Price                                                                  |   | $                    | (73,521 | ) | $ | (17,653 | ) |
| Production                                                             |   | 43,106               |    | 119,227 |   |
|                                                                   |   | (30,415              | )       | 101,574 |   |
| **Crude oil and condensate -**                                         |   |                 |    |   |   |
| Price                                                                  |   | 9,910                |    | (37,933 | ) |
| Production                                                             |   | 160,690              |    | 196,827 |   |
|                                                                   |   | 170,600              |    | 158,894 |   |
|                                                                   |   |                 |    |   |   |
| **Natural gas liquids**                                                |   | 10,726               |    | 7,318 |   |
| Increase in oil and gas revenues                                       |   | $                    | 150,911 |   | $ | 267,786 |   |

 

The increase in theCompany’s oil and gas revenues in 2002, compared to 2001, is related toincreases in the Company’s hydrocarbon production volumes which were onlypartially offset by a decrease in the average price that the Company receivedfor natural gas production volumes. The increase in the Company’s oil and gasrevenues in 2002, compared to 2000, is related to increases in the Company’shydrocarbon production volumes which were only partially offset by decreases inthe average prices that the Company received for such production volumes. Theincrease in oil and gas revenues for 2002, compared to 2001 and  2000, was also partially offset by a declinein the average price that the Company received for its NGL production volumesfrom $20.25 and $16.12 in 2000 and 2001, respectively, to $14.18 in 2002.

 

26

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| **Comparison  of Increases (Decreases) in:**            |   | **2002**   | ** ** | **2001** | ** ** | **%****Change  2002  to  2001** | ** ** | **2000** | ** ** | **%****Change  2002  to  2000** |       |
|---------------------------------------------------------|--------|------------|------------|----------|------------|---------------------------------|------------|----------|------------|---------------------------------|------------|
| **Natural Gas --**                                      |   |       |       |     |       |                            |       |     |       |                            | ** ** |
| Average prices                                          |   |       | ** ** |     | ** ** |                            | ** ** |     | ** ** |                            | ** ** |
| North America (a)                                       |   | **$**      | **3.12**   |     | $          | 4.25                            | ** ** | **(27**  | **)%**     | $                               | 3.69       | ** ** | **(15** | **)%** |
| Kingdom of Thailand (b)                                 |   | **$**      | **2.22**   |     | $          | 2.30                            | ** ** | **(3**   | **)%**     | $                               | 2.20       | ** ** | **1** | **%** |
| Company-wide average price                              |   | **$**      | **2.87**   |     | $          | 3.71                            | ** ** | **(23**  | **)%**     | $                               | 3.16       | ** ** | **(9** | **)%** |
|                                                    |   |       | ** ** |     | ** ** |                            | ** ** |     | ** ** |                            | ** ** |
| Average daily production volumes   (MMcf per day):      |   |       | ** ** |     | ** ** |                            | ** ** |     | ** ** |                            | ** ** |
| North America (a)                                       |   | **201.3**  |       | 172.8    | ** ** | **16**                          | **%**      | 106.2    | ** ** | **90**                          | **%**      |
| Kingdom of Thailand                                     |   | **77.8**   |       | 65.1     | ** ** | **20**                          | **%**      | 58.4     | ** ** | **33**                          | **%**      |
| Company-wide average daily production                   |   | **279.1**  |       | 237.9    | ** ** | **17**                          | **%**      | 164.6    | ** ** | **70**                          | **%**      |
|                                                    |   |       |       |     |       |                            | ** ** |     |       |                            | ** ** |
| **Crude Oil and Condensate  --**                   |   |       | ** ** |     | ** ** |                            | ** ** |     | ** ** |                            | ** ** |
| Average prices (c)                                      |   |       | ** ** |     | ** ** |                            | ** ** |     | ** ** |                            | ** ** |
| North America                                           |   | **$**      | **24.95**  |     | $          | 24.60                           | ** ** | **1**    | **%**      | $                               | 27.83      | ** ** | **(10** | **)%** |
| Kingdom of Thailand                                     |   | **$**      | **24.80**  |     | $          | 23.38                           | ** ** | **6**    | **%**      | $                               | 30.10      | ** ** | **(18** | **)%** |
| Company-wide average price                              |   | **$**      | **24.90**  |     | $          | 23.99                           | ** ** | **4**    | **%**      | $                               | 28.92      | ** ** | **(14** | **)%** |
| Average daily production volumes (Bbls per day):        |   |       | ** ** |     | ** ** |                            | ** ** |     | ** ** |                            | ** ** |
| North America (c)                                       |   | **30,971** |       | 14,804   | ** ** | **109**                         | **%**      | 13,432   | ** ** | **131**                         | **%**      |
| Kingdom of Thailand (d)                                 |   | **16,389** |       | 14,786   | ** ** | **11**                          | **%**      | 12,356   | ** ** | **33**                          | **%**      |
| Company-wide average daily production                   |   | **47,360** |       | 29,590   | ** ** | **60**                          | **%**      | 25,788   | ** ** | **84**                          | **%**      |
|                                                    |   |       |       |     |       |                            | ** ** |     |       |                            | ** ** |
| **Total Liquid Hydrocarbons --**                        |   |       |       |     |       |                            | ** ** |     |       |                            | ** ** |
| Company-wide average daily production (Bbls per day)(d) |   | **51,840** |       | 31,707   | ** ** | **63**                          | **%**      | 27,929   | ** ** | **86**                          | **%**      |

 

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(a)    North American average prices andproduction reflect production from the United States and Canada and the impactof the Company’s price hedging activity**. **Price hedging activity added$0.04 and $0.23 to the average price of the Company’s North American naturalgas production during 2002 and 2001, respectively, and reduced the averageprice $0.30 during 2000.  The Companysold its operations in Canada effective August 31, 2001, as part of an assetrationalization process.  Consequently,results for the 2002 and a portion of the 2001 comparative periods do notreflect any production from Canada.

(b)    The Company is paid for its natural gasproduction in the Kingdom of Thailand in Thai Baht.  The average prices are presented in U.S. dollars based on therevenue recorded in the Company’s financial records.

(c)    North American average prices andproduction reflect production from the United States and Canada.  The Company sold its operations in Canadaeffective August 31, 2001, as part of an asset rationalization process.  Consequently, results for the 2002 and aportion of the 2001 comparative periods do not reflect any production fromCanada.  Average prices are computed onproduction that is actually sold during the period and include the impact ofthe Company’s price hedging activity. Price hedging activity added $0.08 to the average price of the Company’sNorth American crude oil and condensate production during 2002 and reduced theaverage price $2.03 during 2000.  ForNorth American average prices, sales volumes equate to actual production.  However, in the Gulf of Thailand, crude oiland condensate sold may be more or less than actual production.  See footnote (d).

(d)    Oil and condensate production in the Gulfof Thailand is produced and stored on the FPSO and FSO pending sale and is soldin tanker loads that typically average between 300,000 and 750,000 barrels persale. Therefore, oil and condensate sales volumes for a given period in theGulf of Thailand may not equate to actual production.  In accordance with generally accepted accounting principles,reported revenues are based on sales volumes. However, the Company believes that actual production volumes alsoprovide a meaningful measure of the Company’s operating results.  The Company produced 58,000 barrels lessthan it sold in 2002, 90,000 barrels less than it sold in 2001 and 135,000barrels more than it sold in 2000.

 

***Natural Gas***

 

*ThailandPrices.*    The price that the Companyreceives under the Gas Sales Agreement with PTT is based upon a formula thattakes into account a number of factors including, among other items, changes inthe Thai/U.S. exchange rate and fuel oil prices in Singapore.  The contract price is also subject toadjustments for quality.  An amendmentto the Gas Sales Agreement provided that for certain volumes the Companyproduces in excess of the base contractual amount (currently 145 MMcf per day)the price that the Company receives from PTT will be equal to 88% of thethen-current price calculated under its Gas Sales Agreement.  The decrease in the average price that theCompany received for its natural gas production in the Kingdom of Thailand for2002 compared to 2001 and 2000, reflects a downward adjustment in the averageprice received under the Gas Sales Agreement and, to a lesser extent, a reducedaverage price received on the excess production sold at lower prices.  See “Business — International Operations;Contractual Terms Governing the Thailand Concession and Related Production.”

 

*Production.*    The increase in the Company’s naturalgas production during 2002, compared to 2001 and 2000, was primarily related toproduction 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

 

27

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production, partially offset by natural production declines at otherproperties and weather related shut downs in the Gulf of Mexico.

 

*CrudeOil and Condensate*

 

*ThailandPrices.*    Since the inception ofproduction from the Tantawan Field, crude oil and condensate have been storedon the FPSO until an economic quantity is accumulated for offloading and sale.The first such sale of crude oil and condensate from the Tantawan Field occurredin July 1997. Commencing in July 1999 when production began from the BenchamasField, crude oil and condensate from that field has been stored on the FSO andsold as economic quantities were accumulated*.* A typical sale ranges from 300,000 to 750,000 barrels. Prices that theCompany receives for its crude oil and condensate production from Thailand arebased on world benchmark prices, typically as a differential to Malaysian Tapiscrude, and are denominated in U.S. dollars. As discussed further under “Costs and Expenses, Lease OperatingExpenses,” the Company records all crude oil held in the FPSO and the FSO atthe end of an accounting period as inventory held at cost. When such crude oilis sold, usually during the following month, the difference between the cost ofthe crude oil and the sales revenue is recognized in the income statement.

 

*Production.*    The increase in the Company’s crudeoil and condensate production during 2002, compared to 2001 and 2000, resultedprimarily from the continuing success of the Company’s development program inthe Benchamas Field in the Kingdom of Thailand, the commencement of productionfrom the Company’s Main Pass Blocks 61/62 Field, its Mississippi Canyon 661/705Field and its Ewing Bank Block 871 Field and, to a lesser extent, increasedcrude oil and condensate production in the Kingdom of Thailand.  These increases were partially offset bynatural production declines at certain other properties and weather-relatedshut downs in the Gulf of Mexico.

 

In accordance withgenerally accepted accounting principles, the Company records its oilproduction in the Kingdom of Thailand at the time of sale, rather than whenproduced.  At the end of each quarter,the crude oil and condensate stored on board the FSO and FPSO pending sale isaccounted for as inventory at cost. Reported revenues are based on sales volumes. When a tanker load of oilis sold in Thailand, the entire amount will be accounted for as productionsold, regardless of when it was produced. As of December 31, 2002, the Company had approximately 202,000 netbarrels stored on board the FPSO and FSO.

 

*NGLProduction.*    The Company’s oil and gasrevenues, and its total liquid hydrocarbon production, reflect the productionand sale by the Company of NGL, which are liquid products that are extractedfrom natural gas production. The increase in NGL revenues for 2002, comparedwith 2001 and 2000, primarily related to NGL removed from the Company’sMississippi Canyon Blocks 661/705 Field gas production.  These increases were partially offset by adecline in the average prices that the Company received for its NGL productionduring the comparative periods, from $20.25 in 2000 to $16.12 in 2001 and$14.18 in 2002.

 

28

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*Costsand Expenses*

 
| **Comparison  of Increases (Decreases) in:** |   | **2002**    |        | **2001**    |       | **%****Change  2002 to 2001** |       | **2000**    |       | **%****Change  2002 to 2000** |        |
|----------------------------------------------|--------|-------------|-------------|-------------|------------|-------------------------------|------------|-------------|------------|-------------------------------|-------------|
| **Lease Operating Expenses**                 |   |        | ** **  |        | ** ** |                          | ** ** |        | ** ** |                          | ** **  |
| North America                                |   | $           | 101,201,000 |        | $          | 81,164,000                    |       | 25          | %          | $                             | 60,072,000  |   | 68 | % |
| Kingdom of Thailand                          |   | $           | 38,247,000  |        | $          | 36,993,000                    |       | 3           | %          | $                             | 33,568,000  |   | 14 | % |
| Total Lease Operating Expenses               |   | $           | 139,448,000 |        | $          | 118,157,000                   |       | 18          | %          | $                             | 93,640,000  |   | 49 | % |
|                                         |   |        |        |        |       |                          |       |        |       |                          |        |
| **General and Administrative Expenses**      |   | $           | 49,490,000  |        | $          | 39,162,000                    |       | 26          | %          | $                             | 34,568,000  |   | 43 | % |
| **Exploration Expenses**                     |   | $           | 4,783,000   |        | $          | 23,373,000                    |       | (80%        | )          | $                             | 15,291,000  |   | (69 | )% |
| **Dry Hole and Impairment Expenses**         |   | $           | 26,999,000  |        | $          | 26,945,000                    |       | 0           | %          | $                             | 28,608,000  |   | (6 | )% |
| **Depreciation, Depletion and**              |   |        |        |        |       |                          |       |        |       |                          |        |
| **Amortization (DD&A) Expenses**         |   | $           | 287,809,000 |        | $          | 206,609,000                   |       | 39          | %          | $                             | 131,151,000 |   | 119 | % |
| DD&A rate                                |   | $           | 1.33        |        | $          | 1.32                          |       | 1           | %          | $                             | 1.07        |   | 25 | % |
| Mcfe sold (a)                                |   | 215,728,000 |        | 156,780,000 |       | 38                            | %          | 121,581,000 |       | 77                            | %           |
| **Natural Gas Purchases and Other**          |   | $           | 2,739,000   |        | $          | 15,990,000                    |       | (83         | )%         | $                             | 15,090,000  |   | (82 | )% |
| **Interest–**                           |   |        |        |        |       |                          |       |        |       |                          |        |
| Charges                                      |   | $           | (57,450,000 | )           | $          | (56,259,000                   | )          | 2           | %          | $                             | (34,064,000 | ) | 69 | % |
| Interest Income                              |   | $           | 1,760,000   |        | $          | 3,226,000                     |       | (45         | )%         | $                             | 2,634,000   |   | (33 | )% |
| Capitalized Interest Expense                 |   | $           | 24,033,000  |        | $          | 33,242,000                    |       | (28         | )%         | $                             | 20,918,000  |   | 15 | % |
| **Minority Interest - Dividends and Costs**  |   | $           | (4,140,000  | )           | $          | (9,999,000                    | )          | (59         | )%         | $                             | (9,965,000  | ) | (58 | )% |
| **Foreign Currency Transaction Gain (Loss)** |   | $           | 435,000     |        | $          | (524,000                      | )          | (183        | )%         | $                             | (3,174,000  | ) | (114 | )% |
| **Income Tax Expense**                       |   | $           | (97,780,000 | )           | $          | (61,613,000                   | )          | 59          | %          | $                             | (66,969,000 | ) | 46 | % |

 

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(a) “Mcfe” stands for thousands of cubic feetequivalent

 

*Lease Operating Expenses*

 

The increase in NorthAmerican lease operating expenses for 2002, compared to 2001, is related tohigher production from the Company’s Gulf of Mexico properties, and to a lesserextent, increased maintenance costs during 2002, partially offset by decreasedseverance taxes.  As a result of theincreased production from its Gulf of Mexico properties, the Company has alsoincurred increased product transportation and processing expenses and increasedrental expenses for compressors and other equipment during 2002.  In addition to the above factors, theincreased lease operating expenses associated with properties acquired in theacquisition of North Central (completed on March 14, 2001) also impact thecomparison of 2002 to 2001.  Theincrease in North American lease operating expenses for 2002, compared to 2000,was primarily related to increased costs in 2002 associated with propertiesacquired in the North Central acquisition, higher production from the Company’sGulf of Mexico properties, increased product transportation and processingexpenses and increased rental expenses for compressors and other equipmentrelated to the higher production levels.

 

The increase in leaseoperating expenses in the Kingdom of Thailand for 2002, compared to 2001,primarily related to an increase in insurance expenses related to theconstruction of platforms and processing facilities for the Benchamas Field.  The increase in lease operating expenses inthe Kingdom of Thailand for 2002, compared to 2000, primarily related toincreased equipment rental expenses and increased insurance expenses related toconstruction of platforms for the Benchamas Field.  In accordance with generally accepted accounting principles, theportion of lifting costs that is attributable to crude oil and condensatestored on the FPSO and FSO is treated as an inventoried cost until that crudeoil and condensate is sold.  At the timethe crude oil and condensate is sold, those inventoried lifting costs arerecognized as lease operating expenses. Variances in production, sales and operating costs will result invariances in the amount of lease operating expense that is currently recognizedas expense and the amount recorded as product inventory to be recognized insubsequent periods.  A substantialportion of the Company’s lease operating expenses in the Kingdom of Thailandrelates to the lease payments made in connection with the bareboat charter ofthe FPSO for the Tantawan Field and the FSO for the Benchamas Field.  Collectively, these lease payments accountedfor approximately $14,500,000, $14,500,000 and $15,100,000 (net to theCompany’s interest) of the Company’s Thailand lease operating expenses for2002, 2001 and 2000, respectively. The Company currently expects these leasepayments to remain relatively constant at approximately $14,500,000 (net to theCompany’s interest) for the next four years. See “Liquidity and CapitalResources; Capital Requirements; Other Material Long-Term Commitments.”

 

On a per unit ofproduction basis, the Company’s total lease operating expenses have continuedto decrease slightly from an average of $0.77 per Mcfe for 2000 and $0.75 perMcfe for 2001 to $0.65 per Mcfe for 2002.

 

29

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*Generaland Administrative Expenses*

 

The increase in generaland administrative expenses for 2002, compared with 2001 and 2000, primarilyrelated to increased expenses associated with the Company’s acquisition ofNorth Central and its employees, as well as other increases in the size of theCompany’s work force, normal increases in compensation and concomitant benefitexpense and, to a lesser extent, increases in map purchases, office rent,insurance costs and audit fees.  On aper unit of production basis, the Company’s general and administrative expensesdeclined to $0.23 per Mcfe in 2002, from $0.25 per Mcfe in 2001 and $0.28 perMcfe in 2000.

 

*ExplorationExpenses*

 

Exploration expensesconsist primarily of rental payments required under oil and gas leases to holdnon-producing properties (“delay rentals”) and exploratory geological andgeophysical costs that are expensed as incurred. The decrease in explorationexpenses for 2002, compared to 2001 and 2000, resulted primarily from adecrease in 3-D seismic acquisition activities during 2002. The 2001 and 2000expense includes the cost of conducting 3-D surveys in Hungary, the cost ofacquiring substantial new speculative 3-D data sets in the Gulf of Mexico andseismic operations in Canada.  The 2001expense also includes the cost of transferring certain seismic licenses inconnection with the North Central acquisition. There were no comparable expenses incurred in 2002.

 

*DryHole and Impairment Expenses*

 

Dry hole and impairmentexpenses relate to costs of unsuccessful exploratory wells drilled andimpairment of oil and gas properties. During 2002 the Company drilled 6 grossunsuccessful exploratory wells (5.17 net to the Company’s interest), in 2001the Company drilled 6 gross unsuccessful exploratory wells (3.06 net to theCompany’s interest) and in 2000 the Company drilled 13 gross unsuccessfulexploratory wells (6.22 net to the Company’s interest.) Inclusive ofdevelopment drilling, the Company had an overall drilling success rate of 92%in 2002, 93% in 2001 and 87% in 2000. Generally accepted accounting principles also require that if theexpected future cash flow of the Company’s reserves on a property fall belowthe cost that is recorded on the Company’s books, these reserves must beimpaired and written down to the property’s fair value.  Depending on market conditions, includingthe prices for oil and natural gas, and the results of operations, a similartest may be conducted at any time to determine whether impairments areappropriate. Depending on the results of this test, an impairment could berequired on some of the Company’s properties and this impairment could have amaterial negative non-cash impact on the Company’s earnings and balance sheet.

 

*Depreciation,Depletion and Amortization Expenses*

 

The Company’s provisionfor DD&A expense is based on its capitalized costs,  plus future costs to abandon offshore wellsand platforms, and is determined on a cost center by cost center basis usingthe units of production method. The Company generally creates cost centers on afield-by-field basis for oil and gas activities in the Gulf of Mexico and Gulfof Thailand. Generally, the Company establishes cost centers on the basis of anoil or gas trend or play for its onshore oil and gas activities. The increasein the Company’s DD&A expenses for 2002, compared to 2001 and 2000,resulted primarily from an increase in the Company’s natural gas and liquidhydrocarbon production and, to a lesser extent, an increase in the Company’scomposite DD&A rate.

 

The increase in thecomposite DD&A rate for all of the Company’s producing fields for 2002,compared to 2001 and 2000, resulted primarily from having a full year’sproduction from fields acquired in the North Central acquisition that, becausethey were valued at fair market value in connection with the acquisition,contribute a DD&A rate higher than the Company’s historic average. Theincrease was partially offset by an increased percentage of the Company’sproduction coming from certain of the Company’s fields that have DD&A ratesthat are lower than the Company’s recent historical composite rate (principallythe Benchamas Field and certain Gulf of Mexico properties) and a correspondingdecrease in the percentage of the Company’s production coming from fields thathave DD&A rates that are higher than the Company’s recent historicalcomposite DD&A rate.

 

*NaturalGas Purchases and Other*

 

Revenue from thesale of natural gas purchased for resale is reported under “Revenues - Other.”The cost of purchasing natural gas, in addition to the costs of operating theCompany’s pipeline carrying the natural gas, is recorded as an expense under“Natural gas purchases and other.” During 2001 and 2000, primarily all of the natural gas purchased andresold by the Company was transported on Pogo Onshore Pipeline Company’sSaginaw pipeline, which was sold during the fourth quarter of 2001 as part ofthe Company’s ongoing asset rationalization process.  During 2002, substantially all of the gas purchased by theCompany is the result of purchases of natural gas volumes required to replacethe reduction in heating content of the gas stream after the extraction ofNGLs.  These purchases were made tobring the gas stream to pipeline quality standards.  Prior to 2002, the Company had been using its own natural gasproduction to replenish this extracted gas. Consequently, there is no meaningful comparison between the 2002 periodand the 2001 and 2000 periods.

 

30

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*Interest*

 

*InterestCharges.*    The increase in theCompany’s interest charges for 2002, compared to 2001 and 2000, resultedprimarily from an increase in the average amount of the Company’s outstandingdebt (largely related to the acquisition of North Central in March 2001),partially offset by a decline in the average interest rate on the outstandingdebt.

 

*InterestIncome.*    The decrease in the Company’sinterest income for 2002, compared to 2001 and 2000, resulted primarily from adecrease in the interest rate received, partially offset by an increase in theamount of cash and cash equivalents temporarily invested. The cash and cashequivalents on the Company’s balance sheet are primarily held by the Company’sinternational subsidiaries for future investment overseas, in part due to thenegative tax effects that would result from the repatriation of these funds.

 

*CapitalizedInterest.*    Interest costs related tofinancing major oil and gas projects in progress are capitalized until theprojects are substantially complete and ready for their intended use ifprojects are evaluated as successful. The change in capitalized interest for2002, compared to 2001 and 2000, resulted primarily from a decrease in theamount of capital expenditures subject to interest capitalization during 2002(approximately $346,000,000), compared to 2001 (approximately $365,000,000),and an increase in the amount of capital expenditures subject to interestcapitalization during 2002 compared to 2000 (approximately $248,000,000). Thesechanges were also impacted by a decrease in the computed rate incurred by theCompany and applied to such capital expenditures to arrive at the total amountof capitalized interest. A substantial percentage of the Company’s capitalizedinterest related to unevaluated properties acquired in the North Centralacquisition and capital expenditures for the development of the Benchamas Fieldin the Gulf of Thailand, as well as several development projects in the Gulf ofMexico.

 

*MinorityInterest—Dividends and Costs Associated with Mandatorily Redeemable ConvertiblePreferred Securities of a Subsidiary Trust*

 

Pogo Trust I, abusiness 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 PreferredSecurities for redemption on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000outstanding Trust Preferred Securities converted their Trust PreferredSecurities, representing over $149,850,000 face value of Trust PreferredSecurities, into 6,309,972 shares of the Company’s common stock.  In connection with the redemption, PogoTrust I paid a total of $147,000 to former holders of the Trust PreferredSecurities.  Subsequent to June 3, 2002,there were no Trust Preferred Securities outstanding.  The amounts recorded under Minority Interest — Dividends andCosts Associated with Preferred Securities of a Subsidiary Trust principallyreflect cumulative dividends and, to a lesser extent, the amortization ofissuance expenses related to the offering and sale of the Trust PreferredSecurities.

 

*ForeignCurrency Transaction Gain (Loss)*

 

The foreign currencytransaction gain reported in 2002 and the losses reported for 2001 and 2000resulted primarily from the fluctuation against the U.S. dollar of cash andother monetary assets and liabilities denominated in Thai Baht related to theCompany’s Thai operations. During 2002, the Thai Baht — U.S. dollar dailyaverage exchange rate fluctuated between 40.4 and 44.4 Baht to the U.S. dollar.The Company cannot predict what the Thai Baht to U.S. dollar exchange rate willbe in the future. As of February 26, 2003, the Company was not a party to anyfinancial instrument that was intended to constitute a foreign currency hedgingarrangement.

 

*IncomeTax Expense*

 

Changes in theCompany’s income tax expense are a function of the Company’s consolidatedeffective tax rate and its pre-tax income. The increase in the Company’s taxexpense for 2002, compared to 2001 and 2000, resulted primarily from anincrease in the Company’s effective tax rate during the comparative periods andfrom increased pre-tax income during 2002. The Company’s consolidated effectivetax rate for 2002, 2001 and 2000 was 48%, 41% and 43%, respectively.  The higher effective tax rate is the resultof higher pre-tax income derived from the Company’s Thailand operations duringthe comparative periods, which is taxed at a rate higher than the U.S. statutoryrate, relative to its pre-tax income from North American operations.  Management currently expects that foreignincome taxes will constitute a substantial portion of its overall tax burdenfor the foreseeable future.

 

**Liquidity and Capital Resources**

 

The Company’s cashflow provided by operating activities for 2002 was $466,479,000.  This compares to cash flow from operatingactivities of $368,076,000 in 2001 and $239,059,000 in 2000.  The resulting increases are attributable tothe reasons described under “Results of Operations” above.  Cash flow from operating activities in 2002was more  than adequate to fund$368,466,000 in cash expenditures for capital and exploration projects for theyear.  The Company also repaid

 

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approximately $70,000,000 of financing obligations during 2002.  As of December 31, 2002, the Company hadcash and cash equivalents of $134,449,000 (including $118,987,000 ininternational subsidiaries which the Company currently intends to reinvest inits foreign operations), positive working capital, excluding cash, of$3,522,000 and long-term debt obligations of $724,987,000 (excluding debtdiscount of $2,084,000) with no repayment obligations until 2006.  In addition, the Company had $365,000,000 ofavailable borrowing capacity under its revolving credit facility. See “CapitalStructure — Credit Facility”.

 

*FutureCapital and Other Expenditure Requirements*

 

The Company’s capital andexploration budget for 2003, which does not include any amounts that may beexpended for the purchase of proved reserves or any interest which may becapitalized resulting from projects in progress, was established by theCompany’s Board of Directors at $320,000,000. The Company currently anticipatesthat its cash provided by operating activities, available cash and cashinvestments and funds available under its Credit Agreement and its banker’sacceptance facility, will be sufficient to fund the Company’s ongoingoperating, interest and general and administrative expenses, its authorizedcapital budget and dividend payments at current levels for the forseeablefuture. The declaration and amount of future dividends on the Company’s commonstock will depend upon, among other things, the Company’s future earnings andfinancial condition, liquidity and capital requirements, its ability to paydividends and other payments under certain covenants contained in its debtinstruments, the general economic and regulatory climate and other factorsdeemed relevant by the Company’s Board of Directors.

 

*OtherMaterial Long-Term Commitments*

 

*ContractualCash Obligations.* The Company’s material contractual cashobligations include long-term debt, operating leases, and other contracts.  Material contractual cash obligations forwhich the ultimate settlement amounts are not fixed and determinable includederivative contracts that are sensitive to future changes in commodity pricesand other factors.  See “Quantitativeand Qualitative Disclosure about Market Risk.”

 

A summary of theCompany’s known contractual cash obligations as of December 31, 2002 are setforth on the following table**:**

 
|                               |   | **Payments  Due By Year (in millions)** |       |
|------------------------------------|--------|-----------------------------------------|------------|
|                               |   | **2003**                                | ** ** | **2004** | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **After  2007** | ** ** | **Total** | ** ** |
| Long Term Debt                     |   | $                                       | 0.0        |   | $ | 0.0 |   | $ | 0.0 |   | $ | 275.0 |   | $ | 100.0 |   | $ | 350.0 |   | $ | 725.0 |   |
| Operating Leases (a)               |   | $                                       | 21.7       |   | $ | 21.5 |   | $ | 21.4 |   | $ | 21.3 |   | $ | 18.1 |   | $ | 46.7 |   | $ | 150.7 |   |
| Drilling obligations (b)           |   | $                                       | 9.0        |   | $ | 0.0 |   | $ | 0.0 |   | $ | 0.0 |   | $ | 0.0 |   | $ | 0.0 |   | $ | 9.0 |   |
| Firm transportation agreements (c) |   | $                                       | 1.2        |   | $ | 1.2 |   | $ | 1.2 |   | $ | 1.2 |   | $ | 1.2 |   | $ | 3.9 |   | $ | 9.9 |   |
| Total                              |   | $                                       | 31.9       |   | $ | 22.7 |   | $ | 22.6 |   | $ | 297.5 |   | $ | 119.3 |   | $ | 400.6 |   | $ | 894.6 |   |

 

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(a)    Operating leases principally include thelease of the FPSO and FSO in Thailand, the Company’s office lease commitmentsand various other equipment rentals, including gas compressors.  Where rented equipment, such as compressors,is considered essential to the operation of the oil and gas property, theCompany has assumed that such equipment will be leased for the estimatedproductive life of the reserves, even if the existing contract for suchequipment terminates prior to such date.

(b)    This represents the Company’s share ofthe contractual commitments for one rig drilling in the Gulf of Thailand andits license commitment to drill a well in the Danish North Sea.  No other drilling rigs working for theCompany are currently under contracts that have a term greater than six monthsor cannot be terminated at the end of the well that is currently being drilled.  Due to their short-term nature and ourinability to quantify the remaining liabilities on rigs drilling on awell-by-well basis, such obligations have not been included in this table.

(c)    Firm transportation agreements represent“ship-or-pay” arrangements whereby the Company has committed to ship certainvolumes of gas for a fixed transportation fee (principally from the MaddenField in Wyoming).  The Company enteredinto these arrangements to ensure its access to gas markets and currentlyexpects to produce sufficient volumes to satisfy substantially all of its firmtransportation obligations.

 

*Commitmentsunder Joint Operating Agreements. *Theoil and gas industry operates in many instances through joint ventures underjoint operating agreements and the Company’s operations are no exception.  Typically, the operator under a jointoperating agreement enters into contracts, such as drilling contracts, for thebenefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, andin some cases advance, the funds necessary to meet the contractual obligationsentered into by the operator.  Theseobligations are typically shared on a “working interest” basis.  The joint operating agreement providesremedies to the operator in the event that the non-operator does not satisfyits share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreementto enter into lease obligations and other contractual commitments that are thenpassed on to the non-operating joint interest owners as lease operatingexpenses, frequently without any identification as to the long-term nature ofany commitments underlying such expenses. The contractual obligations set forth above represent the Company’s workinginterest share of the contractual commitments that it

 

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has entered into as operator and, to the extent that it is aware, thecontractual commitments entered into by the operator of projects that theCompany does not operate.

 

*SuretyBonds.*    In the ordinary course of theCompany’s business and operations, it is required to post surety bonds fromtime to time with third parties, including governmental agencies, primarily tocover self insurance, site restoration, equipment dismantlement, plugging andabandonment obligations. As of December 31, 2002, the Company had obtainedsurety bonds from a number of insurance and bonding institutions coveringcertain operations in the United States in the aggregate amount ofapproximately $7,000,000 that are not included in the prior table.  In connection with their administration ofoffshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee’splugging and abandonment liabilities. The MMS reviews this information andapplies certain financial tests including, but not limited to, current assetand net worth tests. The MMS determines whether each lessee is financiallycapable of paying the estimated costs of such plugging and abandonmentliabilities. The Company must annually provide the MMS with financialinformation. If the Company does not satisfy the MMS requirements, it could berequired to post supplemental bonds. In the past, the Company has not beenrequired to post supplemental bonds; however, there can be no assurance that theCompany will satisfy the financial tests and remain on the list of MMS lesseesexempt from the supplemental bonding requirements. The Company cannot predictor quantify the amount of any such supplemental bonds or the annual premiumsrelated thereto and therefore has not included them in the prior table, but theamount could be substantial.

 

*Guaranteeand Letters of Credit.  *TheCompany has also issued performance guarantees related to the operations of itssubsidiaries in Thailand, Hungary, the United Kingdom and Denmark.  If its subsidiaries do not fulfill theircontractual obligations or legal obligations under the relevant local laws, theCompany could be obligated to make payments to satisfy the subsidiaries’ obligations.  Most of these obligations relate to workcommitments, plugging, abandoment, site restoration and compliance withenvironmental laws.  The Company alsohas guaranteed performance of its subsidiaries’ obligations under the FPSOlease.  To the extent quantifiable, suchsubsidiaries’ contractual commitments have been included in the priortable.  However, the Company’s guaranteeof these obligations has not been so included. Currently, a letter of credit inthe amount of $1.4 million has been issued on the Company’s behalf.

 

*CapitalStructure*

 

*CreditFacility.*    Effective March 8, 2001,the Company entered into a revolving credit facility (the “Credit Facility”)with a group of lenders. The Credit Facility provides for a $515,000,000revolving loan facility terminating on March 7, 2006. The amount that may beborrowed under the new facility may not exceed a borrowing base that isdetermined no less than semi-annually and is calculated based uponsubstantially all of the Company’s proved oil and gas properties. The borrowingbase is currently set at $500,000,000. The next redetermination of theborrowing base is expected to occur by May 1, 2003. The borrowing base isdetermined by the lenders based on their own proprietary credit criteria, whichappear to be strongly correlated to the quantity of the Company’s proven oiland gas reserves and the lenders’ expectations as to the future revenues thatthe Company can expect to receive from the sale of these oil and gas reserves.A significant decline in the prices that the Company is expected to receive forits future oil and gas production could have a materially negative impact onthe borrowing base under the Credit Facility which, in turn, could have amaterial negative impact on the Company’s liquidity. The Credit Facility isgoverned by various financial and other covenants, including requirements tomaintain positive working capital (excluding current maturities of debt) and afixed charge coverage ratio, and limitations on creation of liens, commodityhedging above specified limits, the prepayment of subordinated debt, thepayment of dividends, mergers and consolidations, investments and assetdispositions. In addition, the Company is prohibited from pledging borrowingbase properties as security for other debt. The Company has pledged the stockof North Central and its inter-company receivables with North Central ascollateral for its obligations under the Credit Facility. If at aredetermination of the borrowing base, the lenders reduce the borrowing basebelow the amount then outstanding under the Credit Agreement and other seniordebt arrangements, the Company must repay the excess to the lenders in no morethan five substantially equal monthly installments, commencing not later than90 days after the Company is notified of the new borrowing base. The CreditFacility 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 underthe 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 theborrowing base being utilized and, with respect to the LIBOR rate loans, theCompany’s credit rating. A commitment fee on the unborrowed amount that iscurrently available under the Credit Facility is also charged based upon thepercentage of the borrowing base that is being utilized. As of February 26,2003, there was $105,000,000 outstanding under the Credit Facility.

 

*Banker’sAcceptances.*    Under a Master Banker’sAcceptance Agreement, one of the Company’s lenders makes available to theCompany banker’s drafts on an uncommitted basis up to $25,000,000. Drafts drawnunder this agreement are reflected as long-term debt on the Company’s balancesheet because the Company currently has the ability and intent to reborrow suchamounts under the Credit Facility. The Company’s 2011 Notes, 2009 Notes and its2007 Notes may restrict all or a portion of the amounts that may be borrowedunder the Master Banker’s Acceptance Agreement as senior debt. The MasterBanker’s Acceptance Agreement permits either party to terminate the letteragreement at any time upon five-business days notice. As of February 26, 2003,there was $24,957,000 outstanding under this agreement.

 

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*2011Notes.*    On April 10, 2001, the Companyissued $200,000,000 principal amount of 2011 Notes. The 2011 Notes bearinterest at a rate of 81⁄4%, payable semi-annually in arrears on April 15 andOctober 15 of each year. The 2011 Notes are general unsecured seniorsubordinated obligations of the Company, are subordinated in right of paymentto the Company’s senior indebtedness, which currently includes the Company’sobligations under the Credit Facility and its Banker’s Acceptances, are equalin right of payment to the 2009 Notes and the 2007 Notes, but are senior inright of payment to the Company’s subordinated indebtedness, which currentlyincludes the 2006 Notes.  The Company,at its option, may redeem the 2011 Notes in whole or in part, at any time on orafter April 15, 2006, at a redemption price of 104.125% of their principalvalue and decreasing percentages thereafter. The indenture governing the 2011 Notesalso imposes certain covenants on the Company that are substantially identicalto the covenants contained in the indentures governing the 2009 Notes and the2007 Notes, including covenants limiting: incurrence of indebtedness includingsenior indebtedness; restricted payments; the issuance and sales of restrictedsubsidiary capital stock; transactions with affiliates; liens; disposition ofproceeds of asset sales; non-guarantor restricted subsidiaries; dividends andother payment restrictions affecting restricted subsidiaries; and mergers,consolidations and the sale of assets.

 

*2009Notes.*    On January 15, 1999, theCompany issued $150,000,000 principal amount of 2009 Notes. The 2009 Notes bearinterest at a rate of 10 3/8 %, payable semi-annually in arrears onFebruary 15 and August 15 of each year. The 2009 Notes are general unsecuredsenior subordinated obligations of the Company, are subordinated in right ofpayment to the Company’s senior indebtedness, which currently includes theCompany’s obligations under the Credit Facility and its Banker’s Acceptances,are equal in right of payment to the 2007 Notes and 2011 Notes, but are seniorin right of payment to the Company’s subordinated indebtedness, which currentlyincludes the 2006 Notes.  The Company,at its option, may redeem the 2009 Notes in whole or in part, at any time on orafter February 15, 2004, at a redemption price of 105.188% of their principalvalue and decreasing percentages thereafter. The indenture governing the 2009Notes also imposes certain covenants on the Company that are substantiallyidentical to the covenants contained in the indenture governing the 2011 Notesdescribed previously and the 2007 Notes.

 

*2007Notes.*    On May 22, 1997, the Companyissued $100,000,000 principal amount of 2007 Notes. The 2007 Notes bearinterest at a rate of 8 3⁄4 %, payable semi-annually in arrears onMay 15 and November 15 of each year. The 2007 Notes are general unsecuredsenior subordinated obligations of the Company, are subordinated in right ofpayment to the Company’s senior indebtedness, which currently includes theCompany’s obligations under the Credit Facility and its Banker’s Acceptances,are equal in right of payment to the 2009 Notes and 2011 Notes, but are seniorin right of payment to the Company’s subordinated indebtedness, which currentlyincludes the 2006 Notes.  The 2007 Notesare currently redeemable at the option of the Company, in whole or in part, atany time, at a redemption price of 104.375% of their principal. The redemptionpremium will decline to 102.917% on May 15, 2003 and will continue to decreaseover the next several years.   Theindenture governing the 2007 Notes also imposes certain covenants on theCompany that are substantially identical to the covenants contained in theindenture governing the 2011 Notes described previously and the 2009 Notes.

 

*2006Notes.*    The outstanding principalamount of 2006 Notes was $115,000,000 as of December 31, 2002. The 2006 Notesare convertible into Common Stock at $42.185 per share, subject to adjustmentupon the occurrence of certain events. The 2006 Notes bear interest at a rateof 5 1⁄2 %, payable semi-annually in arrears onJune 15 and December 15 of each year. The 2006 Notes are general unsecuredsubordinated obligations of the Company, are subordinated in right of paymentto the Company’s senior indebtedness, which currently includes the Company’sobligations under the Credit Facility, its Banker’s Acceptances and its seniorsubordinated indebtedness, which currently includes the 2011 Notes, 2009 Notesand the 2007 Notes.  The 2006 Notes arecurrently redeemable at the option of the Company, in whole or in part, at anytime, at a redemption price of 102.2% of their principal. The redemptionpremium will decline over the next several years.

 

*OtherMatters*

 

*Inflation.*    Publicly held companies are asked tocomment on the effects of inflation on their business. Currently annualinflation in terms of the decrease in the general purchasing power of thedollar is running much below the general annual inflation rates experienced inthe past. While the Company, like other companies, continues to be affected byfluctuations in the purchasing power of the dollar due to inflation, sucheffect is not currently considered significant.

 

*SoutheastAsia Economic Issues.*    A substantialportion of the Company’s oil and gas operations are conducted in SoutheastAsia, and a substantial portion of its natural gas and liquid hydrocarbonproduction is sold there. Southeast Asia in general, and the Kingdom ofThailand in particular, experienced severe economic difficulties in 1997 and1998 which were characterized by sharply reduced economic activity,illiquidity, highly volatile foreign currency exchange rates and unstable stockmarkets. Since that time, the economic situation in the Kingdom of Thailand hasgenerally stabilized. However, as with most emerging market economies, the Thaieconomy remains particularly sensitive to worldwide economic trends. Theeconomic health of the Thai economy and its effect on the volatility of theThai Baht against the dollar will continue to have a material impact on theCompany’s operations in the Kingdom of Thailand, together with the prices thatthe Company receives for its oil and natural gas production there. See “Resultsof Operations; Oil and Gas Revenues” and “Results of Operations; ForeignCurrency Transaction Gain (Loss).”

 

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All of the Company’scurrent natural gas production from the Thailand Concession is committed undera long-term Gas Sales Agreement to PTT at prices denominated in Thai Baht whichare determined in accordance with a formula that is intended to ameliorate, atleast in part, any decline in the purchasing power of the Thai Baht against thedollar. See “Business International Operations; Contractual Terms Governing theThailand Concession” and “Business Miscellaneous; Sales.” Although the Companycurrently believes that PTT will honor its commitments under the Gas SalesAgreement, a failure by PTT to honor such commitments could have a materialadverse effect on the Company. During 2001, the government of Thailandpartially privatized the Petroleum Authority of Thailand, forming PTT andretaining an ownership interest of approximately 70%. PTT is a publicly tradedentity that currently constitutes one of, if not the largest, public companiesin the Kingdom of Thailand. However, its contractual obligations are no longerbacked by the full faith and credit of the Thai government.

 

Prices that the Companyreceives for production from its Thailand Concession are based on worldbenchmark prices, which are denominated in dollars, and are typically paid indollars. See “Business—International Operations; Contractual Terms Governingthe Thailand Concession and Related Production” and “Business—Miscellaneous;Sales.”

 

*RecentAccounting Pronouncements*

 

The Financial AccountingStandards Board (“FASB”) has issued several new pronouncements including,Statement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accountingfor Asset Retirement Obligations”, Statement of Financial Accounting StandardsNo. 146, “Accounting for Exit or Disposal Activities” (“SFAS 146”) andStatement of Financial Accounting Standards No. 148, “Accounting for StockBased Compensation – Transition and Disclosure – an amendment of FAS No.123”  (“SFAS 148”.)

 

*SFAS143.*  SFAS 143requires that the fair value of a liability for an asset retirement obligationbe recorded in the period in which it is incurred and the corresponding costcapitalized by increasing the carrying amount of the related long-lived asset.The liability is accreted to its present value each period, and the capitalizedcost is depreciated over the useful life of the related asset. If the liabilityis settled for an amount other than the recorded amount, a gain or loss isrecognized.  The Company adopted thisstandard as required on January 1, 2003 and will reflect an after-tax non-cashcharge to earnings of approximately $4 million representing the cumulative effectof the change in accounting principle.

 

*SFAS146.*  SFAS 146addresses significant issues regarding the recognition, measurement andreporting of costs that are associated with exit and disposal activities,including restructuring activities that are currently accounted for pursuant tothe guidance set forth in EITF Issue No. 94-3, “Liability Recognition forCertain Employee Termination Benefits and Other Costs to Exit anActivity”.  The Company adopted thisstandard as required on January 1, 2003.  Implementation of the new standard had no impact upon adoption and isnot expected to have a material financial statement impact on the Company.

 

*SFAS148.*  SFAS 148provides alternative methods of transition for a voluntary change to the fairvalue based  method of accounting foremployee stock-based compensation.  Inaddition, SFAS 148 requires prominent disclosures in both annual and interimfinancial statements about the method of accounting for employee stock-basedcompensation and the effect of the method used on reported results.  Effective January 1, 2003, the Companyadopted the fair value recognition provisions of SFAS 123, prospectively to allemployee awards granted, modified or settled after January 1, 2003.  The adoption of the fair value recognitionprovisions of SFAS 123 will result in compensation expense for stock optiongrants. Had the Company followed the fair value recognition provisions of SFAS123 during 2002, net income and shareholders’ equity would have been reduced byapproximately $5.7 million.  However,since the Company has elected a prospective transition method, the impact on2003 net income will be limited to awards granted after January 1, 2003, and nocompensation expense will be recognized on unvested awards outstanding at January1, 2003.

 

**ITEM 7A.     *Quantitative and Qualitative Disclosures About MarketRisk.***

 

The Company is exposed tomarket risk, including adverse changes in commodity prices, interest rates andforeign 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 thesecommodity prices fluctuate widely in response to changing market forces. In thepast, the Company has made limited use of a variety of derivative financialinstruments only for non-trading purposes as a hedging strategy to managecommodity prices associated with oil and gas sales and to reduce the impact ofcommodity price fluctuations. See “Business—Competition and Market Conditions.”

 

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**Interest Rate Risk**

 

From time to time, theCompany has entered into various financial instruments, such as interest rateswaps, to manage the impact of changes in interest rates. As of February 26,2003, the Company has no open interest rate swap or interest rate lockagreements. Therefore, the Company’s exposure to changes in interest ratesprimarily results from its short-term and long-term debt with both fixed andfloating interest rates. The following table presents principal or notionalamounts (stated in thousands) and related average interest rates by year ofmaturity for the Company’s debt obligations and their indicated fair market valueat December 31, 2002:

 
|                  |   | **2002** |   | **2003** |   | **2004** |   | **2005** |   | **2006** |   | **Thereafter** |   | **Total** |    | **Fair Value** |   |
|-----------------------|--------|----------|--------|----------|--------|----------|--------|----------|--------|----------|--------|----------------|--------|-----------|---------|----------------|--------|
| **Long-Term  Debt:**  |   |     |   |     |   |     |   |     |   |     |   |           |   |      |    |           |   |
| Variable Rate         |   | $        | 0      |     | $      | 0        |   | $        | 0      |     | $      | 0              |   | $         | 160,000 |           | $      | 0 |   | $ | 160,000 |   | $ | 160,000 |   |
| Average Interest Rate |   | —   |   | —   |   | —   |   | —   |   | 2.52     | %      | —         |   | 2.52      | %       | —         |   |
| Fixed Rate            |   | $        | 0      |     | $      | 0        |   | $        | 0      |     | $      | 0              |   | $         | 115,000 |           | $      | 450,000 |   | $ | 565,000 |   | $ | 598,961 |   |
| Average Interest Rate |   | —   |   | —   |   | —   |   | —   |   | 5.50     | %      | 9.07           | %      | 8.34      | %       | —         |   |

 

**Foreign Currency Exchange Rate Risk**

 

In addition to the U.S.dollar, the Company and certain of its subsidiaries conduct their business inThai Baht and Hungarian Forint and are therefore subject to foreign currencyexchange rate risk on cash flows related to sales, expenses, financing andinvesting transactions. The Company conducts a substantial portion of its oiland gas production and sales in Southeast Asia. Southeast Asia in general, andthe Kingdom of Thailand in particular, have experienced severe economicdifficulties in the recent past, including sharply reduced economic activity,illiquidity, highly volatile foreign currency exchange rates and unstable stockmarkets. See “Management’s Discussion and Analysis of Financial Condition andResults of Operations—Results of Operations; Foreign Currency Transaction Gain(Loss)” and “—Liquidity and Capital Resources; Other Matters; Southeast AsiaEconomic Issues.” The economic situation in Thailand and the volatility of theThai Baht against the dollar could have a material impact on the Company’sThailand operations and prices that the Company receives for its oil and gasproduction there. Although the Company’s sales to PTT under the Gas SalesAgreement are denominated in Baht, because predominantly all of the Company’scrude oil sales and its capital and most other expenditures in the Kingdom of Thailandare denominated in dollars, the dollar is the functional currency for theCompany’s operations in the Kingdom of Thailand. As of February 26, 2003, theCompany is not a party to any foreign currency exchange agreement.

 

Exposure from market ratefluctuations related to activities in Hungary, where the Company’s functionalcurrency is the legal tender in Hungary (currently the Forint), is not materialat this time.

 

**Current Hedging Activity**

 

As of December 31, 2002,the Company held various derivative instruments.  During 2002, the Company entered into natural gas and crude oiloption agreements referred to as “collars”. Collars are designed to establish floor and ceiling prices onanticipated future natural gas and crude oil production. The Company hasdesignated these contracts as cash flow hedges designed to achieve a morepredictable cash flow, as well as to reduce its exposure to price volatility.While the use of these derivative instruments limits the downside risk ofadverse price movements, they may also limit future revenues from favorableprice movements. The use of derivatives also involves the risk that thecounterparties to such instruments will be unable to meet the financial termsof such contracts.  Currently, theCompany does not expect losses due to credit worthiness of its counterparties.

 

The gas hedgingtransactions are generally settled based upon the average of the reportingsettlement prices on the NYMEX for the last three trading days of a particularcontract month.  The oil hedgingtransactions are generally settled based on the average of the reportingsettlement prices on the NYMEX for each trading day of a particular calendarmonth.  For any particular collartransaction, the counterparty is required to make a payment to the Company ifthe settlement price for any settlement period is below the floor price forsuch transaction, and the Company is required to make a payment to thecounterparty if the settlement price for any settlement period is above theceiling price of such transaction.

 

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Theestimated fair value of these transactions is based upon various factors thatinclude closing exchange prices on the NYMEX, over-the-counter quotations,volatility and the time value of options. Further details related to the Company’s hedging activities as ofDecember 31, 2002, are as follows:

 

 

| **Contract Period and  Type of Contract** |       |       | ** ** | **NYMEX  Contract  Price** | ** **  | **Fair Value  of  Liability** |   |
|-------------------------------------------|------------|------------|------------|----------------------------|-------------|-------------------------------|--------|
|                                      | **Volume** | ** ** | **Floor**  | ** **                 | **Ceiling** | ** **                    |   |
|                                      |       |       |       |                       |        |                          |   |   |   |
| **Natural  Gas Contracts (MMBtu) (a)**    |       |       |       |                       |        |                          |   |   |   |
| Collar Contracts:                         |       |       |       |                       |        |                          |   |   |   |
| January 2003  -  December 2003  |       | 14,600     |       | $                          | 3.85        |                          | $      | 5.00 |   | $ | (2,127,192 | ) |
|                                      |       |       |       |                       |        |                          |   |   |   |
| **Crude  Oil Contracts (Barrels)**        |       |       |       |                       |        |                          |   |   |   |
| Collar Contracts:                         |       |       |       |                       |        |                          |   |   |   |
| January 2003  -  December 2003  |       | 3,650,000  |       | $                          | 25.00       |                          | $      | 30.00 |   | $ | (305,636 | ) |

 

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(a)  MMBtu means million British Thermal Units.

 

In January 2003, theCompany entered into additional natural gas collars to establish floor andceiling prices on anticipated future natural gas production.  The Company has designated these contracts as cash flow hedges.  Further details related to this hedgingactivity is as follows:

 

| **Contract Period and  Type of Contract** |      | **Volume** |        | **NYMEX  Contract  Price** |   |
|-------------------------------------------|-----------|------------|-------------|----------------------------|--------|
| ** **                                | **Floor** | ** ** | **Ceiling** | ** **                 |
|                                      |      |       |        |                       |   |   |   |
| **Natural  Gas Contracts (MMBtu)**        |      |       |        |                       |   |   |   |
| Collar Contracts:                         |      |       |        |                       |   |   |   |
| February 2003  -  December 2003 |      | 6,680      |        | $                          | 4.25   |   | $ | 7.00 |   |
|                                           |           |            |             |                            |        |  |  |  |  |

 

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**ITEM8.    *FinancialStatements and Supplementary Data.***

 

**REPORTOF INDEPENDENT ACCOUNTANTS**

 

 

To the Shareholders and Board of

Directors of Pogo Producing Company:

 

In our opinion, the accompanying consolidated balance sheet as ofDecember 31, 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 itssubsidiaries at December 31, 2002, and the results of their operations andtheir cash flows for the year then ended****in conformity with accounting principlesgenerally accepted in the United States of America.  These financial statements are the responsibility of theCompany’s management; our responsibility is to express an opinion on thesefinancial statements based on our audit. We conducted our audit of these statements in accordance with auditingstandards generally accepted in the United States of America, which requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement.  An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements, assessing the accounting principles used and significant estimatesmade by management, and evaluating the overall financial statementpresentation.  We believe that our auditprovides a reasonable basis for our opinion. The financial statements of the Company as of December 31, 2001, and foreach of the two years in the period ended December 31, 2001, were audited byother independent accountants who have ceased operations.  Those independent accountants expressed anunqualified opinion on those financial statements in their report datedFebruary 28, 2002.

 

PRICEWATERHOUSECOOPERS LLP

 

Houston, Texas

February 21, 2003

 

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**REPORTOF INDEPENDENT PUBLIC ACCOUNTANTS**

 

THE FOLLOWING REPORT IS ACOPY OF THE PREVIOUSLY ISSUED REPORT FROM ARTHUR ANDERSEN LLP (ANDERSEN).  ANDERSEN DID NOT PERFORM ANY PROCEDURES INCONNECTION 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 theaccompanying consolidated balance sheets of Pogo Producing Company (a Delawarecorporation) and subsidiaries as of December 31, 2001 and 2000, and the relatedconsolidated statements of income, cash flows and shareholders’ equity for eachof the three years in the period ended December 31, 2001. These financial statementsare the responsibility of the Company’s management. Our responsibility is toexpress an opinion on these financial statements based on our audits.

 

We conducted our auditsin accordance with auditing standards generally accepted in the United States.Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, 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 materialrespects, the financial position of Pogo Producing Company and subsidiaries asof December 31, 2001 and 2000, and the results of their operations and theircash flows for each of the three years in the period ended December 31, 2001,in conformity with accounting principles generally accepted in the UnitedStates.

 

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

 

ARTHUR ANDERSEN LLP 

 

Houston, Texas

February 28, 2002

 

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

**CONSOLIDATED STATEMENTS OF INCOME**

 
|                                                                                                                                      |   | **Year Ended December 31,**                             |    |
|-------------------------------------------------------------------------------------------------------------------------------------------|--------|---------------------------------------------------------|---------|
|                                                                                                                                      |   | **2002**                                                |    | **2001** |   | **2000** |   |
|                                                                                                                                      |   | **(Expressed in thousands,  except per share amounts)** |    |
| **Revenues:**                                                                                                                             |   |                                                    |    |   |   |   |   |
| Oil and gas                                                                                                                               |   | $                                                       | 746,988 |   | $ | 596,077 |   | $ | 479,202 |   |
| Gains on sales                                                                                                                            |   | 3,034                                                   |    | 1,000 |   | 3,676 |   |
| Other                                                                                                                                     |   | 1,419                                                   |    | 13,040 |   | 15,113 |   |
| Total                                                                                                                                     |   | 751,441                                                 |    | 610,117 |   | 497,991 |   |
|                                                                                                                                      |   |                                                    |    |   |   |   |   |
| **Operating Costs and Expenses:**                                                                                                         |   |                                                    |    |   |   |   |   |
| Lease operating                                                                                                                           |   | 139,448                                                 |    | 118,157 |   | 93,640 |   |
| General and administrative                                                                                                                |   | 49,490                                                  |    | 39,162 |   | 34,568 |   |
| Exploration                                                                                                                               |   | 4,783                                                   |    | 23,373 |   | 15,291 |   |
| Dry hole and impairment                                                                                                                   |   | 26,999                                                  |    | 26,945 |   | 28,608 |   |
| Depreciation, depletion and amortization                                                                                                  |   | 287,809                                                 |    | 206,609 |   | 131,151 |   |
| Natural gas purchases and other                                                                                                           |   | 2,739                                                   |    | 15,990 |   | 15,090 |   |
| Total                                                                                                                                     |   | 511,268                                                 |    | 430,236 |   | 318,348 |   |
| **Operating Income**                                                                                                                      |   | 240,173                                                 |    | 179,881 |   | 179,643 |   |
| **Interest:**                                                                                                                             |   |                                                    |    |   |   |   |   |
| Charges                                                                                                                                   |   | (57,450                                                 | )       | (56,259 | ) | (34,064 | ) |
| Income                                                                                                                                    |   | 1,760                                                   |    | 3,226 |   | 2,634 |   |
| Capitalized                                                                                                                               |   | 24,033                                                  |    | 33,242 |   | 20,918 |   |
| **Minority Interest -**Dividends and costs associated with  mandatorily redeemable convertible preferred securities of a subsidiary trust |   | (4,140                                                  | )       | (9,999 | ) | (9,965 | ) |
| **Foreign Currency Transaction Gain (Loss)**                                                                                              |   | 435                                                     |    | (524 | ) | (3,174 | ) |
| **Income Before Taxes and Cumulative Effect of Change  in Accounting Principle**                                                          |   | 204,811                                                 |    | 149,567 |   | 155,992 |   |
| **Income Tax Expense**                                                                                                                    |   | (97,780                                                 | )       | (61,613 | ) | (66,969 | ) |
| **Income Before Cumulative Effect of Change in  Accounting Principle**                                                                    |   | 107,031                                                 |    | 87,954 |   | 89,023 |   |
| **Cumulative Effect of Change in Accounting Principle**                                                                                   |   | —                                                  |    | — |   | (1,768 | ) |
| **Net Income**                                                                                                                            |   | $                                                       | 107,031 |   | $ | 87,954 |   | $ | 87,255 |   |
|                                                                                                                                      |   |                                                    |    |   |   |   |   |
| **Earnings (Loss) per Common Share:**                                                                                                     |   |                                                    |    |   |   |   |   |
| Basic                                                                                                                                     |   |                                                    |    |   |   |   |   |
| Income before cumulative effect of change in accounting principle                                                                         |   | $                                                       | 1.85    |   | $ | 1.72 |   | $ | 2.20 |   |
| Cumulative effect of change in accounting principle                                                                                       |   | —                                                  |    | — |   | (0.04 | ) |
| Net income                                                                                                                                |   | $                                                       | 1.85    |   | $ | 1.72 |   | $ | 2.16 |   |
|                                                                                                                                      |   |                                                    |    |   |   |   |   |
| Diluted                                                                                                                                   |   |                                                    |    |   |   |   |   |
| Income before cumulative                                                                                                                  |   |                                                    |    |   |   |   |   |
| effect of change in accounting principle                                                                                                  |   | $                                                       | 1.77    |   | $ | 1.62 |   | $ | 1.99 |   |
| Cumulative effect of change in accounting principle                                                                                       |   | —                                                  |    | — |   | (0.04 | ) |
| Net income                                                                                                                                |   | $                                                       | 1.77    |   | $ | 1.62 |   | $ | 1.95 |   |
|                                                                                                                                      |   |                                                    |    |   |   |   |   |
| **Dividends per Common Share**                                                                                                            |   | $                                                       | 0.12    |   | $ | 0.12 |   | $ | 0.12 |   |

 

 

The accompanying notes toconsolidated financial statements are an integral part hereof.

 

40

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

#### **CONSOLIDATEDBALANCE SHEETS**

 
|                                                       |   | **December 31,**              |      |
|------------------------------------------------------------|--------|-------------------------------|-----------|
|                                                       |   | **2002**                      |      | **2001** |   |
|                                                       |   | **(Expressed  in thousands)** |      |
| **ASSETS**                                                 |   |                          |      |   |   |
|                                                       |   |                          |      |   |   |
| **Current Assets:**                                        |   |                          |      |   |   |
| Cash and cash equivalents                                  |   | $                             | 134,449   |   | $ | 94,294 |   |
| Accounts receivable                                        |   | 101,807                       |      | 52,440 |   |
| Other receivables                                          |   | 14,634                        |      | 32,159 |   |
| Federal income taxes receivable                            |   | —                        |      | 27,441 |   |
| Deferred income tax                                        |   | 20,041                        |      | 25,712 |   |
| Inventory - product                                        |   | 2,501                         |      | 3,129 |   |
| Inventories - tubulars                                     |   | 9,406                         |      | 8,430 |   |
| Price hedge contracts                                      |   | —                        |      | 34,275 |   |
| Other                                                      |   | 4,818                         |      | 1,970 |   |
| Total current assets                                       |   | 287,656                       |      | 279,850 |   |
|                                                       |   |                          |      |   |   |
| **Property and Equipment:**                                |   |                          |      |   |   |
| Oil and gas, on the basis of successful efforts accounting |   |                          |      |   |   |
| Proved properties                                          |   | 3,396,669                     |      | 2,956,673 |   |
| Unevaluated properties                                     |   | 141,094                       |      | 257,158 |   |
| Pipelines, at cost                                         |   | 775                           |      | 775 |   |
| Other, at cost                                             |   | 25,851                        |      | 21,638 |   |
|                                                       |   | 3,564,389                     |      | 3,236,244 |   |
| Accumulated depreciation, depletion, and amortization      |   |                          |      |   |   |
| Oil and gas                                                |   | (1,389,976                    | )         | (1,133,560 | ) |
| Pipelines                                                  |   | (744                          | )         | (739 | ) |
| Other                                                      |   | (14,620                       | )         | (11,217 | ) |
|                                                       |   | (1,405,340)                   |      | (1,145,516 | ) |
| Property and equipment, net                                |   | 2,159,049                     |      | 2,090,728 |   |
|                                                       |   |                          |      |   |   |
| **Other Assets:**                                          |   |                          |      |   |   |
| Deferred income tax                                        |   | 2,416                         |      | 13,359 |   |
| Debt issue costs                                           |   | 11,368                        |      | 13,136 |   |
| Foreign value added taxes receivable                       |   | 13,908                        |      | 6,200 |   |
| Other                                                      |   | 17,196                        |      | 20,706 |   |
|                                                       |   | 44,888                        |      | 53,401 |   |
|                                                       |   |                          |      |   |   |
|                                                       |   | $                             | 2,491,593 |   | $ | 2,423,979 |   |

 

The accompanying notes toconsolidated financial statements are an integral part hereof.

 

41

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

**CONSOLIDATEDBALANCE SHEETS**

 
|                                                                                                                                |   | **December 31,**              |       |
|-------------------------------------------------------------------------------------------------------------------------------------|--------|-------------------------------|------------|
|                                                                                                                                |   | **2002**                      |       | **2001** |   |
|                                                                                                                                |   | **(Expressed  in thousands)** |       |
|                                                                                                                                |   |                          |       |   |   |
| **LIABILITIES  AND SHAREHOLDERS’ EQUITY**                                                                                      |   |                          | ** ** |   | ** ** |
|                                                                                                                                |   |                          |       |   |   |
| **Current Liabilities:**                                                                                                            |   |                          |       |   |   |
| Accounts payable  - operating  activities                                                                                      |   | $                             | 41,102     |   | $ | 34,962 |   |
| Accounts payable  - investing  activities                                                                                      |   | 68,963                        |       | 94,523 |   |
| Accrued interest payable                                                                                                            |   | 11,096                        |       | 11,450 |   |
| Foreign income taxes payable                                                                                                        |   | 15,527                        |       | 7,966 |   |
| Accrued dividends associated with preferred securities of a subsidiary  trust                                                       |   | —                        |       | 813 |   |
| Accrued payroll and related benefits                                                                                                |   | 3,011                         |       | 2,670 |   |
| Deferred income tax                                                                                                                 |   | 5,324                         |       | 3,875 |   |
| Price hedge contracts                                                                                                               |   | 2,433                         |       | - |   |
| Other                                                                                                                               |   | 2,229                         |       | 1,892 |   |
| Total current liabilities                                                                                                           |   | 149,685                       |       | 158,151 |   |
|                                                                                                                                |   |                          |       |   |   |
| **Long-Term Debt**                                                                                                                  |   | 722,903                       |       | 792,561 |   |
|                                                                                                                                |   |                          |       |   |   |
| **Deferred Income Tax**                                                                                                             |   | 526,897                       |       | 488,639 |   |
|                                                                                                                                |   |                          |       |   |   |
| **Other Liabilities and Deferred Credits**                                                                                          |   | 14,324                        |       | 14,657 |   |
|                                                                                                                                |   |                          |       |   |   |
| Total liabilities                                                                                                                   |   | 1,413,809                     |       | 1,454,008 |   |
|                                                                                                                                |   |                          |       |   |   |
| **Commitments and Contingencies (Note 1)**                                                                                          |   | —                        |       | — |   |
|                                                                                                                                |   |                          |       |   |   |
| **Minority Interests:**                                                                                                             |   |                          |       |   |   |
| Company-obligated mandatorily redeemable convertible preferred  securities of a subsidiary trust, net of unamortized issue expenses |   | —                        |       | 145,086 |   |
|                                                                                                                                |   |                          |       |   |   |
| **Shareholders’ Equity:**                                                                                                      |   |                          |       |   |   |
| Preferred stock, $1 par; 4,000,000 shares authorized                                                                                |   | —                        |       | — |   |
| Common stock, $1 par; 200,000,000 shares authorized, and 61,061,888  and 53,690,827 shares issued, respectively                     |   | 61,062                        |       | 53,691 |   |
| Additional capital                                                                                                                  |   | 822,526                       |       | 659,227 |   |
| Retained earnings                                                                                                                   |   | 202,155                       |       | 102,019 |   |
| Accumulated other comprehensive income (loss)                                                                                       |   | (6,249                        | )          | 10,272 |   |
| Treasury stock (55,359 and 15,575 shares, respectively), at cost                                                                    |   | (1,710                        | )          | (324 | ) |
| Total shareholders’ equity                                                                                                     |   | 1,077,784                     |       | 824,885 |   |
|                                                                                                                                |   |                          |       |   |   |
|                                                                                                                                |   | $                             | 2,491,593  |   | $ | 2,423,979 |   |

 

Theaccompanying notes to consolidated financial statements are an integral parthereof.

 

42

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

 

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

 
|                                                                                                                                  |   | **Year  Ended December 31,** |    |
|---------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------|---------|
|                                                                                                                                  |   | **2002**                     |    | **2001** |   | **2000** |   |
|                                                                                                                                  |   | **(Expressed in thousands)** |    |
| **Cash flows from operating activities:**                                                                                             |   |                         |    |   |   |   |   |
| Cash received from customers                                                                                                          |   | $                            | 701,429 |   | $ | 625,538 |   | $ | 446,184 |   |
| Income taxes received                                                                                                                 |   | 25,884                       |    | 1,381 |   | 6,000 |   |
| Cash received (paid) related to price hedge contracts                                                                                 |   | 14,931                       |    | 20,142 |   | (24,022 | ) |
| Operating, exploration and general and administrative expenses paid                                                                   |   | (199,104                     | )       | (205,004 | ) | (152,979 | ) |
| Interest paid                                                                                                                         |   | (55,526                      | )       | (48,458 | ) | (32,028 | ) |
| Income taxes paid                                                                                                                     |   | (19,287                      | )       | (31,115 | ) | (9,444 | ) |
| Value added taxes (paid) received                                                                                                     |   | (7,708                       | )       | 1,062 |   | 4,763 |   |
| Other                                                                                                                                 |   | 5,860                        |    | 4,530 |   | 585 |   |
| Net cash provided by operating activities                                                                                             |   | 466,479                      |    | 368,076 |   | 239,059 |   |
| **Cash flows from investing activities:**                                                                                             |   |                         |    |   |   |   |   |
| Capital expenditures                                                                                                                  |   | (368,466                     | )       | (386,164 | ) | (139,062 | ) |
| Proceeds from the sale of property and tubular stock                                                                                  |   | 4,215                        |    | 9,243 |   | 3,745 |   |
| Acquisition of NORIC, net of $21,235,000 cash acquired                                                                                |   | —                       |    | (323,476 | ) |   |   |
| Purchase of proved reserves                                                                                                           |   | —                       |    | (2,714 | ) | (8,393 | ) |
| Proceeds from the sale of Canadian subsidiary                                                                                         |   | —                       |    | 13,739 |   | - |   |
| Net cash used in investing activities                                                                                                 |   | (364,251                     | )       | (689,372 | ) | (143,710 | ) |
| **Cash flows from financing activities:**                                                                                             |   |                         |    |   |   |   |   |
| Proceeds from issuance of new debt                                                                                                    |   | —                       |    | 200,000 |   | — |   |
| Borrowings under senior debt agreements                                                                                               |   | 703,077                      |    | 1,322,990 |   | 67,000 |   |
| Payments under senior debt agreements                                                                                                 |   | (773,080                     | )       | (1,093,000 | ) | (77,000 | ) |
| Payment of North Central senior debt acquired                                                                                         |   | —                       |    | (78,600 | ) | — |   |
| Proceeds from exercise of stock options                                                                                               |   | 20,154                       |    | 7,469 |   | 6,115 |   |
| Payment of preferred dividends of a subsidiary trust                                                                                  |   | (4,850                       | )       | (9,750 | ) | (9,750 | ) |
| Payment of cash dividends on common stock                                                                                             |   | (6,895                       | )       | (6,047 | ) | (4,852 | ) |
| Payment of financing issue costs and other                                                                                            |   | (329                         | )       | (8,720 | ) | (135 | ) |
| Net cash provided by (used in) financing activities                                                                                   |   | (61,923                      | )       | 334,342 |   | (18,622 | ) |
| Effect of exchange rate changes on cash                                                                                               |   | (150                         | )       | (262 | ) | (1,484 | ) |
| Net increase  in cash and cash  equivalents                                                                                      |   | 40,155                       |    | 12,784 |   | 75,243 |   |
| Cash and cash equivalents at the beginning of the year                                                                                |   | 94,294                       |    | 81,510 |   | 6,267 |   |
| Cash and cash equivalents at the end of the year                                                                                      |   | $                            | 134,449 |   | $ | 94,294 |   | $ | 81,510 |   |
| **Reconciliation of net income to net cash provided by  operating activities:**                                                       |   |                         |    |   |   |   |   |
| Net income                                                                                                                            |   | $                            | 107,031 |   | $ | 87,954 |   | $ | 87,255 |   |
| Adjustments to reconcile net income to net cash provided by operating  activities Cumulative effect of change in accounting principle |   | —                       |    | — |   | 1,768 |   |
| Minority interest                                                                                                                     |   | 4,140                        |    | 9,999 |   | 9,965 |   |
| Gains on sales                                                                                                                        |   | (3,034                       | )       | (1,000 | ) | (3,676 | ) |
| Depreciation, depletion and amortization                                                                                              |   | 287,809                      |    | 206,609 |   | 131,151 |   |
| Dry hole and impairment                                                                                                               |   | 26,999                       |    | 26,945 |   | 28,608 |   |
| Interest capitalized                                                                                                                  |   | (24,033                      | )       | (33,242 | ) | (20,918 | ) |
| Price hedge contracts                                                                                                                 |   | 17,589                       |    | 5,550 |   | (24,022 | ) |
| Foreign currency transaction (gain) loss and other                                                                                    |   | 728                          |    | 524 |   | 3,174 |   |
| Increase (decrease) in deferred income taxes                                                                                          |   | 70,929                       |    | 50,617 |   | 63,495 |   |
| Change in assets and liabilities:                                                                                                     |   |                         |    |   |   |   |   |
| (Increase) decrease in accounts receivable                                                                                            |   | (50,521                      | )       | 40,436 |   | (48,425 | ) |
| Increase in federal income taxes receivable                                                                                           |   | —                       |    | (22,809 | ) | — |   |
| Decrease in inventory - product                                                                                                       |   | 173                          |    | 12 |   | 601 |   |
| (Increase) decrease in other current assets                                                                                           |   | (12,571                      | )       | (534 | ) | 1,062 |   |
| (Increase) decrease in other assets                                                                                                   |   | (6,784                       | )       | 6,257 |   | 2,902 |   |
| Increase (decrease) in accounts payable                                                                                               |   | 6,170                        |    | (17,786 | ) | 5,447 |   |
| Increase in foreign income taxes payable                                                                                              |   | 33,610                       |    | 3,684 |   | — |   |
| Increase (decrease) in accrued interest payable                                                                                       |   | (352                         | )       | 4,010 |   | (14 | ) |
| Increase in accrued payroll and related benefits                                                                                      |   | 343                          |    | 385 |   | 132 |   |
| Increase (decrease) in other current liabilities                                                                                      |   | 6,377                        |    | (241 | ) | 624 |   |
| Increase (decrease) in deferred credits                                                                                               |   | 1,876                        |    | 706 |   | (70 | ) |
| Net cash provided by operating activities                                                                                             |   | $                            | 466,479 |   | $ | 368,076 |   | $ | 239,059 |   |

 

Theaccompanying notes to consolidated financial statements are an integral parthereof.

 

43

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

#### **CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY**

**(Expressedin thousands)**

 
|                                                              |   | **Common  Stock** | **(a)** | **Additional  Capital** |    | **Retained  Earnings  (Deficit)** |   | **Accumulated  Other  Compre-  hensive  Income  (Loss)** |   | **Treasury  Stock** |   | **Share-  holders’  Equity** |   | **Compre-  hensive  Income  (Loss)** |    |
|-------------------------------------------------------------------|--------|-------------------|---------|-------------------------|---------|-----------------------------------|--------|----------------------------------------------------------|--------|---------------------|--------|-----------------------------------|--------|--------------------------------------|---------|
|                                                              |   |              |    |                    |    |                              |   |                                                     |   |                |   |                              |   |                                 |    |
| **Balance at December 31, 1999**                                  |   | 40,279            |    | $                       | 291,909 |                              | $      | (62,291                                                  | )      | $                   | (1,061 | )                                 | $      | (324                                 | )       | $ | 268,512 |   |   |   |
| Net income                                                        |   | —            |    | —                  |    | 87,255                            |   | —                                                   |   | —              |   | 87,255                            |   | $                                    | 87,255  |   |
| Exercise of stock options                                         |   | 315               |    | 5,754                   |    | —                            |   | —                                                   |   | —              |   | 6,069                             |   |                                 |    |
| Shares issued as compensation                                     |   | 66                |    | 1,222                   |    | —                            |   | —                                                   |   | —              |   | 1,288                             |   |                                 |    |
| Dividends ($0.12 per common share)                                |   | —            |    | —                  |    | (4,852                            | )      | —                                                   |   | —              |   | (4,852                            | )      |                                 |    |
| Exchange loss on Canadian currency                                |   | —            |    | —                  |    | —                            |   | (1                                                       | )      | —              |   | (1                                | )      | (1                                   | )       |
| Comprehensive income                                              |   | —            |    | —                  |    | —                            |   | —                                                   |   | —              |   | —                            |   | $                                    | 87,254  |   |
|                                                              |   |              |    |                    |    |                              |   |                                                     |   |                |   |                              |   |                                 |    |
| **Balance at December 31, 2000**                                  |   | 40,660            |    | 298,885                 |    | 20,112                            |   | (1,062                                                   | )      | (324                | )      | 358,271                           |   |                                 |    |
| Net income                                                        |   | —            |    | —                  |    | 87,954                            |   | —                                                   |   | —              |   | 87,954                            |   | $                                    | 87,954  |   |
| Shares issued for stock and debt of acquired company              |   | 12,615            |    | 351,729                 |    | —                            |   | —                                                   |   | —              |   | 364,344                           |   |                                 |    |
| Exercise of stock options                                         |   | 378               |    | 7,718                   |    | —                            |   | —                                                   |   | —              |   | 8,096                             |   |                                 |    |
| Shares issued as compensation                                     |   | 38                |    | 895                     |    | —                            |   | —                                                   |   | —              |   | 933                               |   |                                 |    |
| Dividends ($0.12 per common share)                                |   | —            |    | —                  |    | (6,047                            | )      | —                                                   |   | —              |   | (6,047                            | )      |                                 |    |
| Exchange gain on Canadian currency                                |   | —            |    | —                  |    | —                            |   | 389                                                      |   | —              |   | 389                               |   | 389                                  |    |
| Reclassification adjustment included in net income                |   | —            |    | —                  |    | —                            |   | 673                                                      |   | —              |   | 673                               |   | (389                                 | )       |
| Cumulative effect of change in accounting principle               |   | —            |    | —                  |    | —                            |   | (2,438                                                   | )      | —              |   | (2,438                            | )      | (2,438                               | )       |
| Unrealized gains arising during the year on price hedge contracts |   | —            |    | —                  |    | —                            |   | 22,195                                                   |   | —              |   | 22,195                            |   |                                 |    |
| Reclassification adjustment included in net income                |   | —            |    | —                  |    | —                            |   | (9,485                                                   | )      | —              |   | (9,485                            | )      |                                 |    |
| Net unrealized gains on price hedge contracts                     |   | —            |    | —                  |    | —                            |   | —                                                   |   | —              |   | —                            |   | 12,710                               |    |
| Comprehensive income                                              |   | —            |    | —                  |    | —                            |   | —                                                   |   | —              |   | —                            |   | $                                    | 98,226  |   |
|                                                              |   |              |    |                    |    |                              |   |                                                     |   |                |   |                              |   |                                 |    |
| **Balance at December 31, 2001**                                  |   | 53,691            |    | $                       | 659,227 |                              | $      | 102,019                                                  |   | $                   | 10,272 |                              | $      | (324                                 | )       | $ | 824,885 |   |   |   |
| Net income                                                        |   | —            |    | —                  |    | 107,031                           |   | —                                                   |   | —              |   | 107,031                           |   | $                                    | 107,031 |   |
| Exercise of stock options                                         |   | 1,022             |    | 23,460                  |    | —                            |   | —                                                   |   | —              |   | 24,482                            |   |                                 |    |
| Shares issued as compensation                                     |   | 39                |    | 1,124                   |    | —                            |   | —                                                   |   | —              |   | 1,163                             |   |                                 |    |
| Conversion of Trust Preferred Securities                          |   | 6,310             |    | 138,715                 |    | —                            |   | —                                                   |   | —              |   | 145,025                           |   |                                 |    |
| Dividends ($0.12 per common share)                                |   | —            |    | —                  |    | (6,895                            | )      | —                                                   |   | —              |   | (6,895                            | )      |                                 |    |
| Shares received in satisfaction of note receivable                |   | —            |    | —                  |    | —                            |   | —                                                   |   | (1,386              | )      | (1,386                            | )      |                                 |    |
| Unrealized loss arising during the year on price hedge contracts  |   | —            |    | —                  |    | —                            |   | (14,155                                                  | )      | —              |   | (14,155                           | )      |                                 |    |
| Reclassification adjustment included in net income                |   | —            |    | —                  |    | —                            |   | (2,366                                                   | )      | —              |   | (2,366                            | )      |                                 |    |
| Net unrealized losses on price hedge contracts                    |   | —            |    | —                  |    | —                            |   | —                                                   |   | —              |   | —                            |   | (16,521                              | )       |
| Comprehensive income                                              |   | —            |    | —                  |    | —                            |   | —                                                   |   | —              |   | —                            |   | $                                    | 90,510  |   |
|                                                              |   |              |    |                    |    |                              |   |                                                     |   |                |   |                              |   |                                 |    |
| **Balance at December 31, 2002**                                  |   | 61,062            |    | $                       | 822,526 |                              | $      | 202,155                                                  |   | $                   | (6,249 | )                                 | $      | (1,710                               | )       | $ | 1,077,784 |   |   |   |

 

----

(a)  Reflects both dollar andshare amounts at $1.00 par value.

 

The accompanying notes toconsolidated financial statements are an integral part hereof.

 

44

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS**

 

**(1)  Summaryof Significant Accounting Policies**

 

*Natureof Operations—*

 

Pogo Producing Companywas incorporated in 1970. Pogo Producing Company and its subsidiaries (the“Company”) are engaged in oil and gas exploration, development, production andacquisition activities in the United States, both offshore in the Gulf ofMexico (primarily in federal waters offshore Louisiana and Texas) and onshoreprincipally in the states of New Mexico, Texas, Louisiana and Wyoming. TheCompany also conducts exploration, development and production activitiesinternationally in the Kingdom of Thailand (offshore in the Gulf of Thailand)and exploration activities in Hungary and the British and Danish sectors of theNorth Sea.

 

*Use ofEstimates—*

 

The preparation of thesefinancial statements requires the use of certain estimates by management indetermining the Company’s assets, liabilities, revenues and expenses. Actualresults could differ from such estimates. Depreciation, depletion and amortization of oil and gas properties andthe impairment of oil and gas properties are determined using estimates of oiland gas reserves. There are numerous uncertainties in estimating the quantityof reserves and in projecting the future rates of production and timing ofdevelopment expenditures. Oil and gas reserve engineering must be recognized asa subjective process of estimating underground accumulations of oil and gasthat cannot be measured in an exact way. Proved reserves of crude oil,condensate, natural gas and natural gas liquids are estimated quantities thatgeological and engineering data demonstrate with reasonable certainty to berecoverable in the future from known reservoirs under existing conditions.

 

*Principlesof Consolidation—*

 

The consolidatedfinancial statements include the accounts of Pogo Producing Company and itssubsidiaries and affiliates, after elimination of all significant intercompanytransactions. Majority owned subsidiaries are fully consolidated. Minorityowned oil and gas affiliates are pro rata consolidated in the same manner asthe Company accounts for its operating or working interest in oil and gas jointventures.

 

*PriorYear Reclassifications—*

 

Certain prior yearamounts have been reclassified to conform with the current yearpresentation.  Such reclassificationshad no effect on the Company’s operating income, net income or shareholders’equity.

 

*ForeignCurrency—*

 

The U.S. dollar is thefunctional currency for all areas of operations of the Company with theexception of Hungary, where the functional currency is the legal tender ofHungary, currently the Forint. Accordingly, monetary assets and liabilities anditems of income and expense denominated in a foreign currency are remeasured toU.S. dollars at the rate of exchange in effect at the end of each month or theaverage for the month, and the resulting gains or losses on foreign currencytransactions are included in the consolidated statements of income for theperiod.

 

*RevenueRecognition—*

 

The Company follows the“sales” (takes or cash) method of accounting for oil and gas revenues.  Under this method, the Company recognizesrevenues on production as it is taken and delivered to its purchasers.  The volumes sold may be more or less thanthe volumes the Company is entitled to based on its ownership interest in theproperty.  These differences result in acondition known in the industry as a production imbalance.  At December 31, 2002, the Company had takenapproximately 1,202 MMcf of natural gas less than it was entitled to based onits interest in certain properties, and approximately 1,062 MMcf more than itsentitlement on other properties. Therefore, the Company is owed a net positionof approximately 140 MMcf of natural gas based on its working interestownership in such properties. The Company’s crude oil imbalances are notsignificant.  Such imbalances arereflected as adjustments to proved reserves and future cash flows in theunaudited supplementary oil and gas data included herein.

 

*Inventory—Product*

 

Crude oil and condensatefrom the Company’s producing fields located in the Kingdom of Thailand areproduced into storage vessels and are sold and recognized as revenue periodicallyas economic quantities are accumulated. Effective January 1, 2000, the Companyadopted the provisions of the Securities and Exchange Commission’s (the“Commission”) Staff

 

45

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Accounting Bulletin No. 101, Revenue Recognition. As a result, theComission no longer accepts the oil and gas exploration and productionindustry’s long-standing historical practice of recording such productinventories at their net realizable value. The cumulative effect of this changein accounting principle through December 31, 1999 ($1,768,000, net of taxbenefits of $1,768,000) has been charged to earnings effective January 1,2000.   The product inventory atDecember 31, 2002 consists of approximately 202,397 barrels of crude oil andcondensate, net to the Company’s interest, and is carried at the Company’sestimated average cost of $12.35 per barrel. The product inventory at December31, 2001 consisted of approximately 260,087 barrels of crude oil andcondensate, net to the Company’s interest, and is carried at its estimatedaverage cost of $12.03 per barrel.

 

*Inventories—Tubulars*

 

Tubular inventoriesconsist primarily of goods used in the Company’s operations and are stated atthe lower of average cost or market value.

 

*Earningsper Share—*

 

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

 

46

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|                                                                                                                                                                                                    |   | **For the Year Ended December 31, 2002** |    |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------------------|---------|
|                                                                                                                                                                                                    |   | **Income**                               |    | **Shares** |   | **Per Share** |   |
|                                                                                                                                                                                                    |   |                                     |    |   |   |   |   |
| **Basic earnings per share**                                                                                                                                                                            |   | $                                        | 107,031 |   | 57,963 |   | $ | 1.85 |   |
| Effect of potential dilutive securities:                                                                                                                                                                |   |                                     |    |   |   |   |   |
| Shares assumed issued from the exercise of options to purchase common  shares, net of treasury shares assumed purchased from the proceeds, at the  average market price for the period                  |   | —                                   |    | 980 |   |   |   |
| Interest expense incurred, net of taxes,  and shares issued related to the assumed conversion at $42.185  per share of the 2006 Notes                                                              |   | 4,111                                    |    | 2,726 |   |   |   |
| Minority interest expense incurred, net of taxes,  and shares issued related to the assumed  conversion at $23.75 per share of the Trust Preferred Securities (redeemed on  June 3, 2002)          |   | 2,661                                    |    | 2,652 |   |   |   |
| **Diluted earnings per share**                                                                                                                                                                          |   | $                                        | 113,803 |   | 64,321 |   | $ | 1.77 |   |
|                                                                                                                                                                                                    |   |                                     |    |   |   |   |   |
| Antidilutive securities:                                                                                                                                                                                |   |                                     |    |   |   |   |   |
| Shares assumed not issued from options to purchase common shares as  the exercise prices are above the average market price for the period or the  effect of the assumed exercise would be antidilutive |   | $                                        | —  |   | 143 |   | $ | 38.00 |   |

 
|                                                                                                                                                                                                    |   | **For the Year Ended December 31, 2001** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------------------|------------|
|                                                                                                                                                                                                    |   | **Income**                               |       | **Shares** |   | **Per Share** | ** ** |
|                                                                                                                                                                                                    |   |                                     |       |   |   |   |   |
| **Basic earnings per share**                                                                                                                                                                            |   | $                                        | 87,954     |   | 51,031 |   | $ | 1.72 |   |
| Effect of potential dilutive securities:                                                                                                                                                                |   |                                     |       |   |   |   |   |
| Shares assumed issued from the exercise of options to purchase common  shares, net of treasury shares assumed purchased from the proceeds, at the  average market price for the period                  |   | —                                   |       | 749 |   |   |   |
| Interest expense incurred, net of taxes,  and shares issued related to the assumed conversion at $42.185  per share of the 2006 Notes                                                              |   | 4,111                                    |       | 2,726 |   |   |   |
| Minority interest expense incurred, net of taxes,  and shares issued related to the assumed  conversion at $23.75 per share of the Trust Preferred Securities                                      |   | 6,338                                    |       | 6,316 |   |   |   |
| **Diluted earnings per share**                                                                                                                                                                          |   | $                                        | 98,403     |   | 60,822 |   | $ | 1.62 |   |
|                                                                                                                                                                                                    |   |                                     |       |   |   |   |   |
| Antidilutive securities:                                                                                                                                                                                |   |                                     |       |   |   |   |   |
| Shares assumed not issued from options to purchase common shares as  the exercise prices are above the average market price for the period or the  effect of the assumed exercise would be antidilutive |   | $                                        | —     |   | 266 |   | $ | 33.75 |   |

 

47

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|                                                                                                                                                                                                    |   | **For the Year Ended December 31, 2000** |   |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|------------------------------------------|--------|
|                                                                                                                                                                                                    |   | **Income (a)**                           |   | **Shares** |   | **Per Share** |   |
|                                                                                                                                                                                                    |   |                                     |   |   |   |   |   |
| **Basic earnings per share**                                                                                                                                                                            |   | $                                        | 89,023 |   | 40,445 |   | $ | 2.20 |   |
| Effect of potential dilutive securities:                                                                                                                                                                |   |                                     |   |   |   |   |   |
| Shares assumed issued from the exercise of options to purchase common  shares, net of treasury shares assumed purchased from the proceeds, at the  average market price for the period                  |   | —                                   |   | 668 |   |   |   |
| Interest expense incurred, net of taxes,  and shares issued related to the assumed conversion at $42.185  per share of the 2006 Notes                                                              |   | 4,111                                    |   | 2,726 |   |   |   |
| Minority interest expense incurred, net of taxes,  and shares issued related to the assumed  conversion at $23.75 per share of the Trust Preferred Securities                                      |   | 6,338                                    |   | 6,316 |   |   |   |
| **Diluted earnings per share**                                                                                                                                                                          |   | $                                        | 99,472 |   | 50,155 |   | $ | 1.99 |   |
|                                                                                                                                                                                                    |   |                                     |   |   |   |   |   |
| (a)  Represents income before  cumulative effect of change in accounting principle                                                                                                                 |   |                                     |   |   |   |   |   |
|                                                                                                                                                                                                    |   |                                     |   |   |   |   |   |
| Antidilutive securities:                                                                                                                                                                                |   |                                     |   |   |   |   |   |
| Shares assumed not issued from options to purchase common shares as  the exercise prices are above the average market price for the period or the  effect of the assumed exercise would be antidilutive |   | $                                        | — |   | 219 |   | $ | 34.93 |   |

 

*Oil andGas Activities and Depreciation, Depletion and Amortization—*

 

The Company follows thesuccessful efforts method of accounting for its oil and gas activities. Underthe successful efforts method, lease acquisition costs and all developmentcosts are capitalized. Proved oil and gas properties are reviewed whencircumstances suggest the need for such a review and, if required, the provedproperties are written down to their estimated fair value. Unproved propertiesare reviewed quarterly to determine if there has been impairment of thecarrying value, with any such impairment charged to expense in the period.Estimated fair value includes the estimated present value of all reasonablyexpected future production, prices, and costs. Exploratory drilling costs arecapitalized until the results are determined. If proved reserves are notdiscovered, the exploratory drilling costs are expensed. Interest costs relatedto financing major oil and gas projects in progress are capitalized until theprojects are evaluated or until the projects are substantially complete andready for their intended use if the projects are evaluated as successful. Otherexploratory costs are expensed as incurred. The provision for depreciation,depletion and amortization is based on the capitalized costs as determinedabove, plus future cost to abandon offshore wells and platforms, and iscomputed on a cost center by cost center basis using the units of productionmethod, with lease acquisition costs amortized over total proved reserves andother costs amortized over proved developed reserves. The Company generallycreates cost centers on a field-by-field basis for oil and gas activities inthe Gulf of Mexico and the Gulf of Thailand. Generally, the Company establishescost centers on the basis of an oil or gas trend or play for its onshore oiland gas activities.  As described furtherbelow, the Company’s method of accounting for asset retirement obligations(i.e. future abandonment costs) changed effective January 1, 2003.

 

The Company has anongoing asset rationalization process. In connection with this process, theCompany has from time to time disposed of certain non-core properties and otherassets that it considers to be under performing, to have little or no remainingupside potential, or which face significant future expenditures that wouldresult in an unacceptable rate of return. Refer to the captions “Gains onsales” in the Consolidated Statements of Income and “Proceeds from the sale ofproperty and tubular stock” in the Consolidated Statements of Cash Flows.

 

Other properties andequipment are depreciated using a straight-line method in amounts which, in theopinion of management, are adequate to allocate the cost of the properties overtheir estimated useful lives.

 

*ConsolidatedStatements of Cash Flows—*

 

For the purpose of cashflows, the Company considers all highly liquid investments with a maturity dateof three months or less when purchased to be cash equivalents. Significanttransactions may occur which do not directly affect cash balances and, as such,are not disclosed in the Consolidated Statements of Cash Flows. Certain suchnon-cash transactions are disclosed in the Consolidated Statements ofShareholders’ Equity, including shares issued upon conversion of TrustPreferred Securities

 

48

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(Note 4), shares issued as compensation, and shares issued for stockand debt of an acquired company. The shares issued for stock of an acquiredcompany are also discussed in the following “Acquisition” section of this note.

 

*Commitmentsand Contingencies—*

 

The Company hascommitments for operating leases (primarily for office space) in Houston,Midland, Fort Worth, Bangkok, Budapest, other equipment (including gascompressors) and for an FPSO and FSO in the Gulf of Thailand. Rental expensefor office space was $2,821,000 in 2002, $2,623,000 in 2001, and $1,911,000 in2000. Rental expense for other equipment was $2,022,000 in 2002, $654,000 in2001 and $500,000 in 2000. Expenses for the FPSO lease were approximately$10,600,000 in 2002 and 2001 and $11,100,000 in 2000. Expenses for the FSOlease were approximately $4,000,000 in each of the years 2002, 2001 and 2000.

 

Future minimum leasepayments related to the Company’s operating leases at December 31, 2002 areapproximately $21,700,000 in 2003; $21,500,000 in 2004; $21,400,000 in 2005;$21,300,000 in 2006;  $18,100,000 in2007 and $46,700,000 thereafter. Where rented equipment such as compressors isconsidered essential to the operation of the lease, the Company has assumedthat such equipment will be leased for the estimated productive life of thereserves, even if the contract terminates prior to such date.

 

*Acquisition—*

 

On March 14, 2001, themerger of the Company and NORIC was consummated. As a result of the merger, theCompany acquired all of the outstanding capital stock of North Central whichwas the principal asset of NORIC. North Central was an independent domestic oiland gas exploration and production company. The merger was accounted for usingthe purchase method of accounting. Accordingly, the purchase price wasallocated to the net assets acquired based on their estimated fair values atthe date of acquisition. Commencing March 14, 2001, North Central’s operationswere consolidated with the operations of the Company. Pursuant to the mergeragreement among the Company and NORIC and certain former NORIC shareholders,the former shareholders received 12,615,816 shares of the Company’s commonstock and approximately $344,711,000 in cash. In addition, at the closing allthe $78,600,000 principal amount of North Central’s existing bank debt wasrepaid.

 

The following summarypresents unaudited pro forma consolidated results of operations as if theacquisition had occurred at the beginning of each period presented. The proforma results are for illustrative purposes only and include adjustments inaddition to the pre-acquisition historical results of North Central, such asincreased depreciation, depletion and amortization expense resulting from theallocation of fair value to oil and gas properties acquired and increasedinterest expense on acquisition debt. The unaudited pro forma information(presented in thousands of dollars, except per share amounts) is notnecessarily indicative of the operating results that would have occurred hadthe acquisition been consummated at those dates, nor are they necessarilyindicative of future operating results.

 

|                                                              |   | **Year Ended  December 31,** |    |
|-------------------------------------------------------------------|--------|------------------------------|---------|
|                                                              |   | **2001**                     |    | **2000** |   |
| Revenues                                                          |   | $                            | 668,480 |   | $ | 643,091 |   |
| Income before cumulative effect of change in accounting principle |   | $                            | 104,348 |   | $ | 89,608 |   |
| Net income                                                        |   | $                            | 104,348 |   | $ | 87,840 |   |
| Earnings per share:                                               |   |                         |    |   |   |
| Basic -                                                           |   |                         |    |   |   |
| Income before cumulative effect of change in accounting principle |   | $                            | 1.95    |   | $ | 1.69 |   |
| Net income                                                        |   | $                            | 1.95    |   | $ | 1.66 |   |
| Diluted -                                                         |   |                         |    |   |   |
| Income before cumulative effect of change in accounting principle |   | $                            | 1.81    |   | $ | 1.48 |   |
| Net income                                                        |   | $                            | 1.81    |   | $ | 1.45 |   |

 

*Income Taxes—*

 

Deferredincome tax assets and liabilities are recognized for temporary differencesbetween the basis of assets and liabilities for financial reporting and taxpurposes.  Changes in tax legislationare included in the relevant computations in the

 

49

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period in which such changes are effective.  Deferred tax assets are reduced by a valuation allowance for theamount of any tax benefit we do not expect to be realized.  Note 2 contains information about theCompany’s income taxes, including the components of income tax provision andthe composition of deferred income tax assets and liabilities.

 

*PriceRisk Management—*

 

The Company from time totime enters into commodity price hedging contracts with respect to its oil andgas production to achieve a more predictable cash flow, as well as reduce itsexposure to price volatility. For periods prior to 2001, the Company accountedfor such contracts as hedges, in accordance with Statement of FinancialAccounting Standards No. 80 (“SFAS 80”). Effective January 1, 2001, the Companyadopted Statement of Financial Accounting Standards No. 133 “Accounting forDerivative Instruments and Hedging Activities” (“SFAS 133”).

 

*Accountingfor Commodity Price Hedging Contracts prior to the adoption of SFAS 133:*

 

For periods prior to theadoption of SFAS 133, the Company recognized gains and losses on commodityprice hedging contracts in revenue in the period in which the underlyingproduction was delivered. In 2000, the Company hedged 16,910 MMcf of gas and1,509,500 barrels of crude oil (25,967 equivalent MMcf) or approximately 21% ofits equivalent 2000 production and recorded hedge losses of $11,549,000 in connectionwith its natural gas contracts and hedge losses of $9,976,000 in connectionwith its crude oil contracts

 

*Accountingfor Commodity Price Hedging Contracts after the adoption of SFAS 133:*

 

In June 1998, theFinancial Accounting Standards Board (“FASB”) issued SFAS 133. In June 2000,the FASB issued SFAS 138, “Accounting for Derivative Instruments and HedgingActivities, an amendment of FASB Statement No. 133.” SFAS 133, as amended,established accounting and reporting standards requiring that every derivativeinstrument (including certain derivative instruments embedded in othercontracts) be recorded in the balance sheet as either an asset or liabilitymeasured at its fair value. The statement requires that changes in thederivative’s fair value be recognized currently in earnings unless specifichedge criteria are met. Special accounting for qualifying hedges allows aderivative’s gains and losses to offset related results on the hedged item inthe income statement, and requires that a company must formally document,designate and assess the effectiveness of transactions that receive hedgeaccounting. Based on the nature of the Company’s derivative instrumentscurrently outstanding and the historical volatility of oil and gas commodityprices, the Company expects that SFAS 133 could increase volatility in theCompany’s earnings and other comprehensive income for future periods.

 

SFAS 133 provides thatthe effective portion of the gain or loss on a derivative instrument designatedand qualifying as a cash flow hedging instrument be reported as a component ofother comprehensive income and be reclassified into earnings in the same periodduring which the hedged forecasted transaction affects earnings. The remaininggain or loss on the derivative instrument, if any, must be recognized currentlyin earnings.

 

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

 

*Accountingfor Stock-Based Compensation:*

 

Prior to January 1, 2003,the Company accounted for employee stock-based compensation using the intrinsicvalue recognition provisions of APB Opinion No. 25, “Accounting for StockIssued to Employees,” and related interpretations.  Under this method, the Company recognizes no compensation expensefor stock options granted when the exercise price of the options is equal to orgreater than the quoted market price of the Company’s common stock on the grantdate.  Effective January 1, 2003, theCompany has adopted the fair value recognition provisions of Statement of FinancialAccounting Standards No. 123, “Accounting for Stock Based Compensation” (“SFAS123”) and the prospective method transition provisions of Statement ofFinancial Accounting Standards No. 148, “Accounting for Stock BasedCompensation — Transition and Disclosure — an amendment of FAS No. 123”  (“SFAS 148”) for all employee awardsgranted, modified or settled after January 1, 2003.

 

50

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The following tableillustrates the effect on net income and earnings per share if the Company hadapplied the fair value recognition provisions of SFAS 123 to employeestock-based compensation (in thousands of dollars, except per share amounts):

 

|                                                                                                                                      |   | **2002** |    | **2001** |   | **2000** |   |
|-------------------------------------------------------------------------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
|                                                                                                                                      |   |     |    |     |   |     |   |
| Net income, as  reported                                                                                                                  |   | $        | 107,031 |     | $      | 87,954   |   | $ | 87,255 |   |
|                                                                                                                                      |   |     |    |     |   |     |   |
| Deduct: Total  employee stock-based compensation expense, determined under fair value method  for all awards, net of relatred tax effects |   | (5,710   | )       | (4,413   | )      | (2,932   | )      |
| Pro forma                                                                                                                                 |   | $        | 101,321 |     | $      | 83,541   |   | $ | 84,323 |   |
|                                                                                                                                      |   |     |    |     |   |     |   |
| Earnings per  share:                                                                                                                      |   |     |    |     |   |     |   |
| Basic - as  reported                                                                                                                      |   | $        | 1.85    |     | $      | 1.72     |   | $ | 2.16 |   |
| Basic - pro  forma                                                                                                                        |   | $        | 1.75    |     | $      | 1.65     |   | $ | 2.12 |   |
| Diluted - as  reported                                                                                                                    |   | $        | 1.77    |     | $      | 1.62     |   | $ | 1.95 |   |
| Diluted - pro  forma                                                                                                                      |   | $        | 1.68    |     | $      | 1.57     |   | $ | 1.91 |   |

 

The fair value of grantswas estimated on the date of grant using the Black-Scholes option pricing modelwith the following weighted-average assumptions used in 2002, 2001 and 2000,respectively: risk free interest rates of 4.20%, 4.85% and 6.03%, expectedvolatility of 33.9%, 44.41% and 42.85%, dividend yields of 0.51%, 0.49% and0.59%, and an expected life of the options of seven, six and five years.

 

*RecentAccounting Pronouncements—*

 

The Financial AccountingStandards Board (“FASB”) has issued several new pronouncements, includingStatement of Financial Accounting Standards No. 143 (“SFAS 143”), “Accountingfor Asset Retirement Obligations”, Statement of Financial Accounting StandardsNo. 146, “Accounting for Exit or Disposal Activities” (“SFAS 146”) and SFAS148.

 

*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. The Company adopted this standard as required on January 1, 2003 and will record an after-tax non-cash charge to earnings of approximately $4 million representing the cumulative effect of the change in accounting principle.

 

*SFAS 146.*  SFAS 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity”.  The Company adopted this standard as required on January 1, 2003.   Implementation of the new standard had no impact upon adoption and is not expected to have a material financial statement impact on the Company.

 

*SFAS 148.*  SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based  method of accounting for employee stock-based compensation.  In addition, SFAS 148 requires prominent disclosures in both annual and interim financial statements about the method of accounting for employee stock-based compensation and the effect of the method used on reported results.  These disclosure provisions have been adopted by the Company in connection with this Form 10-K.  As previously described, effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS 123, prospectively to all employee awards granted, modified or settled after January 1, 2003.  Adoption of the fair value recognition provisions of SFAS 123 will result in compensation expense for stock option grants. The impact of applying the fair value recognition standard on the Company’s future results of operation is anticipated to be consistent with that shown in the historical pro-forma disclosures above.  However, since the Company has elected a prospective transition method, the impact on 2003 net income will be limited to awards granted after January 1, 2003, and no compensation expense will be recognized on unvested awards outstanding at January 1, 2003.

 

51

 

**(2)  IncomeTaxes**

 

The components ofincome before income taxes for each of the three years in the period endedDecember 31, 2002, are as follows (expressed in thousands):

 
|                                                                                |   | **2002** |    | **2001** |   | **2000** |   |
|-------------------------------------------------------------------------------------|--------|----------|---------|----------|--------|----------|--------|
| United States                                                                       |   | $        | 101,349 |     | $      | 81,619   |   | $ | 67,967 |   |
| Foreign                                                                             |   | 103,462  |    | 67,948   |   | 88,025   |   |
| Income before income taxes and cumulative effect of change in  accounting principle |   | $        | 204,811 |     | $      | 149,567  |   | $ | 155,992 |   |

 

The components of income tax expense (benefit) for each of the threeyears in the period ended December 31, 2002, are as follows (expressed inthousands):

 
|               |   | **2002** |   | **2001** |   | **2000** |   |
|--------------------|--------|----------|--------|----------|--------|----------|--------|
| Current            |   |     |   |     |   |     |   |
| United States      |   | $        | 15,497 |     | $      | -        |   | $ | 9,000 |   |
| Foreign            |   | 11,351   |   | 10,996   |   | -        |   |
| Deferred           |   |     |   |     |   |     |   |
| United States      |   | 32,451   |   | 59,823   |   | 12,392   |   |
| Foreign            |   | 38,481   |   | (9,206   | )      | 45,577   |   |
| Income tax expense |   | $        | 97,780 |     | $      | 61,613   |   | $ | 66,969 |   |

 

Total income tax expensefor each of the three years in the period ended December 31, 2002, differs fromthe amounts computed by applying the statutory federal income tax rate toincome before taxes as follows (expressed as a percent of pretax income):

 

|                                                      |   | **2002** |   | **2001** |   | **2000** |   |
|-----------------------------------------------------------|--------|----------|--------|----------|--------|----------|--------|
| Federal statutory income tax rate                         |   | 35.0     | %      | 35.0     | %      | 35.0     | %      |
| Increases (reductions) resulting from:                    |   |     |   |     |   |     |   |
| Foreign income taxed at different rates                   |   | 7.8      |   | 11.3     |   | 8.7      |   |
| Recognition of previously unbenefitted loss carryforwards |   | -        |   | (20.4    | )      | -        |   |
| U.S. taxes on repatriation of foreign earnings            |   | 2.3      |   | 5.7      |   | -        |   |
| State income taxes, net of federal benefit                |   | 0.5      |   | 4.0      |   | -        |   |
| Other                                                     |   | 2.2      |   | 5.6      |   | (0.8     | )      |
|                                                      |   | 47.8     | %      | 41.2     | %      | 42.9     | %      |

 

52

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The principal componentsof the Company’s deferred income tax assets and liabilities at December 31,2002 and 2001 (expressed in thousands) are as follows:

 

|                                                                        |   | **December  31,** |     |
|-----------------------------------------------------------------------------|--------|-------------------|----------|
|                                                                        |   | **2002**          |     | **2001** |   |
| Deferred tax assets:                                                        |   |              |     |   |   |
|                                                                        |   |              |     |   |   |
| Foreign net operating loss carry forwards                                   |   | $                 | 22,457   |   | $ | 39,071 |   |
| Tax basis in excess of book basis for price hedge contracts                 |   | 8,895             |     | — |   |
| Other                                                                       |   | —            |     | 5,055 |   |
|                                                                        |   | 31,352            |     | 44,126 |   |
| Deferred tax liabilities:                                                   |   |              |     |   |   |
|                                                                        |   |              |     |   |   |
| Book basis in excess of tax basis for oil and gas properties and  equipment |   | (538,132          | )        | (490,496 | ) |
| Book basis in excess of tax basis for price hedge contracts                 |   | —            |     | (5,531 | ) |
| Other                                                                       |   | (2,984            | )        | (1,542 | ) |
|                                                                        |   | (541,116          | )        | (497,569 | ) |
|                                                                        |   |              |     |   |   |
| Net deferred tax liability                                                  |   | $                 | (509,764 | ) | $ | (453,443 | ) |

 

Book basis in excess oftax basis for oil and gas properties and equipment primarily results fromdiffering methodologies for recording property costs and depreciation,depletion and amortization under United States generally accepted accountingprinciples and income tax reporting. In addition, the Company recorded adeferred tax liability resulting from book and tax basis differences of theacquired NORIC net assets (see “Acquisition” under Note 1).

 

As of December 31, 2002,the Company has foreign net operating loss carryforwards of approximately$53,504,000 which are available to offset future income tax. These losses areprimarily related to the Company’s Thailand operations, and will begin toexpire in 2007.

 

Where the Company’spresent intention is to reinvest the unremitted earnings in its foreignoperations, the Company does not provide for U.S. income taxes on unremittedearnings of foreign subsidiaries. Unremitted earnings of foreign subsidiariesfor which U.S. income taxes have not been provided are approximately$91,566,000 at December 31, 2002. It is not practical to determine the amountof U.S. income taxes that would be payable upon remittance of the assets thatrepresent those earnings.

 

During the third quarterof 2001, the Company reevaluated its global tax and cash position, includingestimates regarding the realization of its Thailand operating losscarryforwards as well as its ability to indefinitely reinvest all unremittedforeign earnings in its foreign operations. Based on the Company’s futureexpectations for its Thailand operations, the Company believes that it is morelikely than not that its remaining Thailand operating loss carryforwards willbe realized and, therefore, reversed the remaining valuation allowanceaccordingly. In addition, the Company provided for U.S. income taxes on theunremitted earnings from a portion of its Thailand operations determined to besubject to repatriation. However, where the Company’s continued intention is toreinvest the unremitted earnings of a foreign subsidiary in foreign operations,the Company will continue to not provide U.S. income taxes on those earnings.

 

53

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**(3)  Long-TermDebt**

 

Long-term debt atDecember 31, 2002 and 2001, consists of the following (dollars expressed inthousands):

 

|                                                                                                                           |   | **December 31,** |    |
|--------------------------------------------------------------------------------------------------------------------------------|--------|------------------|---------|
|                                                                                                                           |   | **2002**         |    | **2001** |   |
| Senior debt -                                                                                                                  |   |             |    |   |   |
| Bank revolving credit agreement:                                                                                               |   |             |    |   |   |
| LIBOR based loans, borrowings at December 31, 2002 and 2001 at  interest rates of 2.5625% and 3.1875%, respectively            |   | $                | 135,000 |   | $ | 185,000 |   |
| Prime based loans, borrowings at December 31, 2001 at an interest rate  of 4.75%                                               |   | —           |    | 10,000 |   |
| Swing line money market loans, borrowings at December 31, 2001 at an  interest rate of 3.3125%                                 |   | —           |    | 10,000 |   |
| Banker’s Acceptance loans, borrowings at December 31, 2002 and 2001 at  interest rates of 2.2765% and 2.45%, respectively |   | 24,987           |    | 24,990 |   |
| Total senior debt                                                                                                              |   | 159,987          |    | 229,990 |   |
| Subordinated debt -                                                                                                            |   |             |    |   |   |
| 8 3/4% Senior subordinated notes, due 2007                                                                                     |   | 100,000          |    | 100,000 |   |
| 10 3/8% Senior subordinated notes, due 2009                                                                                    |   | 150,000          |    | 150,000 |   |
| 8 1/4% Senior subordinated notes, due 2011                                                                                     |   | 200,000          |    | 200,000 |   |
| 5 1/2% Convertible subordinated notes, due 2006                                                                                |   | 115,000          |    | 115,000 |   |
| Total subordinated debt                                                                                                        |   | 565,000          |    | 565,000 |   |
| Unamortized discount on 2009 Notes                                                                                             |   | (2,084           | )       | (2,429 | ) |
| Long-term debt                                                                                                                 |   | $                | 722,903 |   | $ | 792,561 |   |

 

On March 8, 2001, theCompany entered into the Credit Facility, a reserve based revolving creditfacility. The Credit Facility provides for a $515,000,000 revolving creditfacility until March 7, 2006. The amount that may be borrowed may not exceed aborrowing base which is determined semi-annually and is calculated based uponsubstantially all of the Company’s proved oil and gas properties. The borrowingbase is currently established at $500,000,000. The Credit Facility is governedby various financial and other covenants, including requirements to maintainpositive working capital (excluding current maturities of debt) and a fixedcharge coverage ratio, and limitations on the creation of liens, commodityhedging above specified limits, the prepayment of subordinated debt, thepayment of dividends, mergers and consolidations, investments and assetdispositions. In addition, the Company is prohibited from pledging borrowingbase properties as security for other debt. The Company has pledged the stockof North Central and its inter-company receivables with North Central ascollateral for its obligations under the Credit Facility. The Credit Facilityalso 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 theCredit Facility bear interest, at the Company’s option, at a base (prime) rateplus a variable margin (currently none) or LIBOR plus a variable margin(currently l.125%). The margin varies as a function of the percentage of theborrowing base utilized and, with respect to the LIBOR rate, the Company’scredit rating. A commitment fee on the unborrowed amount that is currentlyavailable under the Credit Facility is also charged based on the percentage ofthe borrowing base that is being utilized.

 

Under a Master Banker’sAcceptance Agreement between the Company and one of its lenders, the lendermakes available to the Company banker’s drafts on an uncommitted basis up to$25,000,000. Drafts drawn under this agreement are reflected as long-term debton the Company’s balance sheet because the Company currently has the abilityand intent to reborrow such amount under the Credit Facility. The Company’s2007 Notes, 2009 Notes, and 2011 Notes may restrict all or a portion of theamounts that may be borrowed under the Master Banker’s Acceptance Agreement assenior debt. The Master Banker’s Acceptance Agreement permits either party toterminate the letter agreement at any time upon five-business days notice.

 

On May 22, 1997, theCompany issued $100,000,000 of principal amount of 2007 Notes. The 2007 Notesbear interest at a rate of 8 3⁄4 %, payable semi-annually in arrears on May 15 and November 15 ofeach year. The 2007 Notes are general unsecured senior subordinated obligationsof the Company and are subordinated in right of payment to the Company’s seniorindebtedness, which currently includes the Company’s obligations under theCredit Facility and its Banker’s Acceptances, are equal in right of payment tothe 2009 Notes and the 2011 Notes, but are senior in right of payment to theCompany’s subordinated indebtedness which currently includes the 2006 Notes.  The Company, at its option, may redeem the2007 Notes in whole or in part, at any time, at a redemption price of 104.375%of their principal value. The redemption premium will decline to 102.917% onMay 15, 2003 and continue to decrease over the next several years. Theindenture governing the 2007

 

54

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Notes also imposes certain covenants on the Company that aresubstantially identical to the covenants contained in the indenture governingthe 2011 Notes described below.

 

On January 15, 1999, the Company issued $150,000,000 principal amountof 2009 Notes. The 2009 Notes bear interest at a rate of 10 3/8%, payable semi-annually in arrears on February 15 and August 15 of eachyear. The 2009 Notes are generally unsecured senior subordinated obligations ofthe Company, are subordinated in right of payment to the Company’s seniorindebtedness, which currently includes the Company’s obligations under theCredit Facility and its Banker’s Acceptances, are equal in right of payment tothe 2007 Notes and 2011 Notes, but are senior in right of payment to itssubordinated indebtedness, which currently includes the 2006 Notes. TheCompany, at its option, may redeem the 2009 Notes in whole or in part, at anytime on or after February 15, 2004, at a redemption price of 105.188% of theirprincipal value and decreasing percentages thereafter. The indenture governingthe 2009 Notes also imposes certain covenants on the Company that are substantiallyidentical to the covenants contained in the indenture governing the 2011 Notes,described below.

 

On April 10, 2001, theCompany issued $200,000,000 principal amount of 2011 Notes. The 2011 Notes bearinterest at a rate of  8 1⁄4 %, payable semi-annually in arrears onApril 15 and October 15 of each year. The 2011 Notes are general unsecuredsenior subordinated obligations of the Company, are subordinated in right ofpayment to the Company’s senior indebtedness, which currently includes theCompany’s obligations under the Credit Facility and its Banker’s Acceptances,are equal in right of payment to the 2007 Notes and the 2009 Notes, but aresenior in right of payment to the Company’s subordinated indebtedness, whichcurrently includes the 2006 Notes.  The Company,at its option, may redeem the 2011 Notes in whole or in part, at any time on orafter April 15, 2006, at a redemption price of 104.125% of their principalvalue and decreasing percentages thereafter. The indentures governing the 2011Notes also imposes certain covenants on the Company including covenantslimiting: incurrence of indebtedness including senior indebtedness; restrictedpayments; 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 restrictionsaffecting restricted subsidiaries; and merger, consolidations and the sale ofassets. 

 

The outstanding principalamount of 2006 Notes was $115,000,000 as of December 31, 2002. The 2006 Notesbear interest at a rate of 5 1⁄2  %,payable semi-annually in arrears on June 15 and December 15 of each year. The2006 Notes are convertible into Common Stock at $42.185 per share subject toadjustment upon the occurrence of certain events. The 2006 Notes are generalunsecured subordinated obligations of the Company, and are subordinated inright of payment to the Company’s senior indebtedness which currently includesthe Company’s obligations under the Credit Facility and its Banker’sAcceptances, its senior subordinated indebtedness, which currently includes the2011 Notes, the 2009 Notes and the 2007 Notes. The 2006 Notes are currently redeemable at the option of the Company, inwhole or in part, at any time, at a redemption price of 102.2% of theirprincipal. The redemption premium will decline over the next several years.

 

The Company currently hasno maturities or sinking fund requirements during the next three years inconnection with the above long-term debt. In 2006, maturities of $274,987,000will become due consisting of the senior debt currently outstanding and theoutstanding principal of the 2006 Notes. In 2007, maturities of $100,000,000 will become due consisting of theoutstanding principal of the 2007 Notes.

 

**(4)  MinorityInterest**

 

Pogo Trust I, asubsidiary of the Company, called its 61⁄2% Cumulative Quarterly IncomeConvertible Preferred Securities due 2029 (the “Trust Preferred Securities”)for redemption on June 3, 2002.  Priorto their redemption, holders of 2,997,196 of the 3,000,000 outstanding TrustPreferred Securities converted their Trust Preferred Securities, representing$149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares ofthe Company’s common stock.  In connectionwith the redemption, Pogo Trust I paid a total of $147,000 to former holders ofthe Trust Preferred Securities. Subsequent to June 3, 2002, there were no Trust Preferred Securitiesoutstanding.

 

The amounts recordedunder “Minority Interests—Dividends and costs associated with preferredsecurities of a subsidiary trust” principally reflect cumulative dividends and,to a lesser extent, the amortization of issuance expenses related to theoffering and sale of the Trust Preferred Securities.

 

55

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**(5)  BusinessSegment Information**

 

The Company’s reportablesegments, which are primarily in the business of natural gas and crude oilexploration and production, are identified below. The accounting policies ofthe segments are the same as those described in the summary of significantpolicies. The Company evaluates performance based on profit or loss fromoperations before income and expense items incidental to oil and gas operationsand income taxes. Financial information by operating segment is presentedbelow:

 

|                                  |   | **Total  Company**            |      | **Oil  and Gas** |   | **Pipelines** |   | **Corporate  & Other** |   |
|---------------------------------------|--------|-------------------------------|-----------|------------------|--------|---------------|--------|----------------------------|--------|
|                                  |   | **(Expressed  in thousands)** |      |
| **Long-Lived Assets:**                |   |                          |      |             |   |          |   |                       |   |
| As of December 31, 2002:              |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 1,780,431 |             | $      | 1,772,742     |   | $                          | 31     |   | $ | 7,658 |   |
| Kingdom of Thailand                   |   | 378,260                       |      | 374,775          |   | —        |   | 3,485                      |   |
| Other                                 |   | 358                           |      | 271              |   | —        |   | 87                         |   |
| Total                                 |   | $                             | 2,159,049 |             | $      | 2,147,788     |   | $                          | 31     |   | $ | 11,230 |   |
| As of December 31, 2001:              |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 1,748,046 |             | $      | 1,741,035     |   | $                          | 36     |   | $ | 6,975 |   |
| Kingdom of Thailand                   |   | 342,411                       |      | 338,965          |   | —        |   | 3,446                      |   |
| Canada and other                      |   | 271                           |      | 271              |   | —        |   | —                     |   |
| Total                                 |   | $                             | 2,090,728 |             | $      | 2,080,271     |   | $                          | 36     |   | $ | 10,421 |   |
|                                  |   |                          |      |             |   |          |   |                       |   |
| **Capital Expenditures:**             |   |                          |      |             |   |          |   |                       |   |
| (including interest capitalized)      |   |                          |      |             |   |          |   |                       |   |
| For the year ended December 31, 2002: |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 280,391   |             | $      | 277,147       |   | $                          | — |   | $ | 3,244 |   |
| Kingdom of Thailand                   |   | 101,299                       |      | 101,299          |   | —        |   | —                     |   |
| Other                                 |   | —                        |      | —           |   | —        |   | —                     |   |
| Total                                 |   | $                             | 381,690   |             | $      | 378,446       |   | $                          | — |   | $ | 3,244 |   |
| For the year ended December 31, 2001: |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 1,458,549 |             | $      | 1,453,756     |   | $                          | — |   | $ | 4,793 |   |
| Kingdom of Thailand                   |   | 73,192                        |      | 73,192           |   | —        |   | —                     |   |
| Canada and other                      |   | 3,071                         |      | 3,071            |   | —        |   | —                     |   |
| Total                                 |   | $                             | 1,534,812 |             | $      | 1,530,019     |   | $                          | — |   | $ | 4,793 |   |
|                                  |   |                          |      |             |   |          |   |                       |   |
| **Revenues:**                         |   |                          |      |             |   |          |   |                       |   |
| For the year ended December 31, 2002  |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 538,601   |             | $      | 534,304       |   | $                          | 79     |   | $ | 4,218 |   |
| Kingdom of Thailand                   |   | 212,763                       |      | 212,684          |   | —        |   | 79                         |   |
| Other                                 |   | 77                            |      | —           |   | —        |   | 77                         |   |
| Total                                 |   | $                             | 751,441   |             | $      | 746,988       |   | $                          | 79     |   | $ | 4,374 |   |
| For the year ended December 31, 2001  |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 422,120   |             | $      | 408,514       |   | $                          | 12,037 |   | $ | 1,569 |   |
| Kingdom of Thailand                   |   | 183,074                       |      | 183,005          |   | —        |   | 69                         |   |
| Canada                                |   | 4,923                         |      | 4,558            |   | —        |   | 365                        |   |
| Total                                 |   | $                             | 610,117   |             | $      | 596,077       |   | $                          | 12,037 |   | $ | 2,003 |   |
| For the year ended December 31, 2000  |   |                          |      |             |   |          |   |                       |   |
| United States                         |   | $                             | 309,602   |             | $      | 291,266       |   | $                          | 15,277 |   | $ | 3,059 |   |
| Kingdom of Thailand                   |   | 182,965                       |      | 183,060          |   | —        |   | (95                        | )      |
| Canada                                |   | 5,424                         |      | 4,876            |   | —        |   | 548                        |   |
| Total                                 |   | $                             | 497,991   |             | $      | 479,202       |   | $                          | 15,277 |   | $ | 3,512 |   |

 

56

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|                                                   |   | **Total  Company**            |    | **Oil  and Gas** |   | **Pipelines** |   | **Corporate  & Other** |   |
|--------------------------------------------------------|--------|-------------------------------|---------|------------------|--------|---------------|--------|----------------------------|--------|
|                                                   |   | **(Expressed  in thousands)** |    |
|                                                   |   |                          |    |             |   |          |   |                       |   |
| **Depreciation, depletion, and amortization expense:** |   |                          |    |             |   |          |   |                       |   |
| For the year ended December 31, 2002                   |   |                          |    |             |   |          |   |                       |   |
| United States                                          |   | $                             | 221,646 |             | $      | 218,636       |   | $                          | 6      |   | $ | 3,004 |   |
| Kingdom of Thailand                                    |   | 66,099                        |    | 65,229           |   | —        |   | 870                        |   |
| Other                                                  |   | 64                            |    | —           |   | —        |   | 64                         |   |
| Total                                                  |   | $                             | 287,809 |             | $      | 283,865       |   | $                          | 6      |   | $ | 3,938 |   |
| For the year ended December 31, 2001                   |   |                          |    |             |   |          |   |                       |   |
| United States                                          |   | $                             | 142,643 |             | $      | 140,304       |   | $                          | 231    |   | $ | 2,108 |   |
| Kingdom of Thailand                                    |   | 61,814                        |    | 61,243           |   | —        |   | 571                        |   |
| Canada and other                                       |   | 2,152                         |    | 2,129            |   | —        |   | 23                         |   |
| Total                                                  |   | $                             | 206,609 |             | $      | 203,676       |   | $                          | 231    |   | $ | 2,702 |   |
| For the year ended December 31, 2000                   |   |                          |    |             |   |          |   |                       |   |
| United States                                          |   | $                             | 77,828  |             | $      | 76,516        |   | $                          | 247    |   | $ | 1,065 |   |
| Kingdom of Thailand                                    |   | 51,250                        |    | 50,968           |   | —        |   | 282                        |   |
| Canada                                                 |   | 2,073                         |    | 1,992            |   | —        |   | 81                         |   |
| Total                                                  |   | $                             | 131,151 |             | $      | 129,476       |   | $                          | 247    |   | $ | 1,428 |   |
|                                                   |   |                          |    |             |   |          |   |                       |   |
| **Operating income (loss):**                           |   |                          |    |             |   |          |   |                       |   |
| For the year ended December 31, 2002                   |   |                          |    |             |   |          |   |                       |   |
| United States                                          |   | $                             | 138,934 |             | $      | 134,482       |   | $                          | 234    |   | $ | 4,218 |   |
| Kingdom of Thailand                                    |   | 103,021                       |    | 102,942          |   | —        |   | 79                         |   |
| Other                                                  |   | (1,782                        | )       | (1,859           | )      | —        |   | 77                         |   |
| Total                                                  |   | $                             | 240,173 |             | $      | 235,565       |   | $                          | 234    |   | $ | 4,374 |   |
| For the year ended December 31, 2001                   |   |                          |    |             |   |          |   |                       |   |
| United States                                          |   | $                             | 113,976 |             | $      | 117,096       |   | $                          | (72    | ) | $ | (3,048 | ) |
| Kingdom of Thailand                                    |   | 76,493                        |    | 76,424           |   | —        |   | 69                         |   |
| Canada and other                                       |   | (10,588                       | )       | (10,953          | )      | —        |   | 365                        |   |
| Total                                                  |   | $                             | 179,881 |             | $      | 182,567       |   | $                          | (72    | ) | $ | (2,614 | ) |
| For the year ended December 31, 2000                   |   |                          |    |             |   |          |   |                       |   |
| United States                                          |   | $                             | 86,996  |             | $      | 84,491        |   | $                          | (554   | ) | $ | 3,059 |   |
| Kingdom of Thailand                                    |   | 92,735                        |    | 92,830           |   | —        |   | (95                        | )      |
| Canada                                                 |   | (88                           | )       | (636             | )      | —        |   | 548                        |   |
| Total                                                  |   | $                             | 179,643 |             | $      | 176,685       |   | $                          | (554   | ) | $ | 3,512 |   |

 

**(6)  Salesto Major Customers**

 

The Company is an oil andgas exploration and production company that generally sells its oil and gas tonumerous customers on a month-to-month basis. For purposes of comparison, 2002sales have been presented for those customers who have in either of theprevious two years exceeded 10% of revenues (expressed in thousands):

 

|                       |   | **2002** |   | **2001** |   | **2000** |   |
|----------------------------|--------|----------|--------|----------|--------|----------|--------|
| Enron Corp. and affiliates |   | $        | 5,594  |     | $      | 96,970   |   | $ | 66,083 |   |
|                            |        |          |        |          |        |          |        |  |  |  |

 

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**(7)  CreditRisk**

 

Substantially all of theCompany’s accounts receivable at December 31, 2002 and 2001, result from oiland gas sales and joint interest billings to other companies in the energyindustry. This concentration of customers and joint interest owners may impactthe Company’s overall credit risk, either positively or negatively, in thatthese entities may be similarly affected by industry-wide changes in economicor other conditions. Such receivables are generally not collateralized.   As of December 31, 2002 and 2001, theCompany had provided reserves for receivables from customers and joint interestowners that are considered doubtful of collection of $5,542,000 and $4,519,000,respectively.

 

During 2001 and 2002, theCompany sold a portion of its oil and natural gas production to Enron Corp. andaffiliated companies. On December 2, 2001, Enron Corp. declared bankruptcy.Prior to such bankruptcy filing, the Company requested financial assurancesfrom an Enron affiliate concerning performance under a natural gas salesagreement with North Central. The requested assurances were not provided andNorth Central subsequently suspended performance under the contract and ceasedselling to such Enron affiliate. As of December 31, 2002, the Company had anaccounts receivable of $1,538,000, net of an applicable reserve, for physicalsales of natural gas during November 2001 to such Enron affiliate.  During 2002, the Company sold $5,594,000 toEOTT, an affiliated company of Enron Corp.

 

A substantial portion ofthe Company’s oil and gas operations are conducted in Southeast Asia, and asubstantial portion of its natural gas and liquids hydrocarbon production aresold there. Southeast Asia in general, and the Kingdom of Thailand inparticular, experienced severe economic difficulties in 1997 and 1998 whichwere characterized by sharply reduced economic activity, illiquidity, highlyvolatile foreign currency exchange rates and unstable stock markets. Since thattime, the economic situation in the Kingdom of Thailand has generallystabilized. However, as with most emerging market economies, the Thai economyremains particularly sensitive to worldwide economic trends. The economichealth of the Thai economy and its effect on the volatility of the Thai Bahtagainst the U.S. dollar will continue to have a material impact on theCompany’s operations in the Kingdom of Thailand, together with the prices thatthe company receives for its oil and natural gas production there.

 

As a result of thesubstantial oil and gas operations and earnings from its Thailand operations,the Company generates a significant amount of cash which is maintained invarious bank accounts with multi-national banks for future foreigninvestment.  These balances arediversified between cash and other short-term investments.

 

**(8)  EmployeeBenefits**

 

The Company has atax-advantaged savings plan in which all U.S. salaried employees mayparticipate. Under such plan, a participating employee may allocate up to 10%of their salary, up to a maximum allowed by law, and the Company will thenmatch the employee’s contribution on a dollar for dollar basis up to the lesserof 6% of the employees salary or $11,000 in 2002. Funds contributed by theemployee and the matching funds contributed by the Company are held in trust bya bank trustee in six separate funds. Amounts contributed by the employee andearnings and accretions thereon may be used to purchase shares of common stock,invest in a money market fund or invest in four stock, bond, or blended stockand bond mutual funds according to instructions from the employee. Matchingfunds contributed to the savings plan by the Company are invested only inCompany common stock. The Company contributed $1,068,000 to the savings plan in2002, $928,000 in 2001, and $886,000 in 2000.

 

The Company has adopted atrusteed retirement plan for its U.S. salaried employees. The benefits arebased on years of service and the employee’s average compensation for fiveconsecutive years within the final ten years of service which produce thehighest average compensation. The Company makes annual contributions to the planin the amount of retirement plan cost accrued or the maximum amount that can bededucted for federal income tax purposes. The plan is invested approximately99% in equities and 1% in cash equivalents. Although the Company has noobligation to do so, the Company currently provides full medical benefits toits retired U.S. employees and dependents. For current employees, the Companyassumes all or a portion of post-retirement medical and term life insurancecosts based on the employee’s age and length of service with the Company. Thepost-retirement medical plan has no assets and is currently funded by theCompany on a pay-as-you-go basis.

 

58

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The following table sets forth the plans’ status (in thousands ofdollars) as of December 31, 2002 and 2001.

 
|                                           |   | **Retirement Plan** |   | **Post-Retirement  Medical Plan** |   |
|------------------------------------------------|--------|---------------------|--------|-----------------------------------|--------|
|                                           |   | **2002**            |   | **2001**                          |   | **2002** |   | **2001** |   |
| **Change in benefit obligation**               |   |                |   |                              |   |   |   |   |   |
| Benefit obligation at beginning of year        |   | $                   | 19,020 |                              | $      | 14,979 |   | $ | 9,904 |   | $ | 8,002 |   |
| Service cost                                   |   | 1,929               |   | 1,577                             |   | 736 |   | 602 |   |
| Interest cost                                  |   | 1,395               |   | 1,144                             |   | 715 |   | 556 |   |
| Plan amendments                                |   | 348                 |   | 499                               |   | — |   | — |   |
| Acquisitions/divestitures                      |   | —              |   | —                            |   | — |   | 737 |   |
| Benefits paid                                  |   | (704                | )      | (413                              | )      | (358 | ) | (212 | ) |
| Actuarial loss                                 |   | 2,309               |   | 1,234                             |   | 4,070 |   | 219 |   |
| Benefit obligation at end of year              |   | $                   | 24,297 |                              | $      | 19,020 |   | $ | 15,067 |   | $ | 9,904 |   |
| **Change in plan assets**                      |   |                |   |                              |   |   |   |   |   |
| Fair value of plan assets at beginning of year |   | $                   | 33,465 |                              | $      | 38,337 |   | $ | — |   | $ | — |   |
| Actual return on plan assets                   |   | (5,721              | )      | (4,145                            | )      | — |   | — |   |
| Employer contributions                         |   | —              |   | —                            |   | 358 |   | 212 |   |
| Benefits paid                                  |   | (704                | )      | (413                              | )      | (358 | ) | (212 | ) |
| Administrative expenses                        |   | (416                | )      | (314                              | )      | — |   | — |   |
| Fair value of plan assets at end of year       |   | $                   | 26,624 |                              | $      | 33,465 |   | $ | — |   | $ | — |   |
| **Reconciliation of funded status**            |   |                |   |                              |   |   |   |   |   |
| Funded status                                  |   | $                   | 2,327  |                              | $      | 14,445 |   | $ | (15,067 | ) | $ | (9,904 | ) |
| Unrecognized actuarial loss (gain)             |   | 12,085              |   | 523                               |   | 2,957 |   | (1,113 | ) |
| Unrecognized transition (asset) or obligation  |   | —              |   | —                            |   | 913 |   | 1,217 |   |
| Unrecognized past service cost                 |   | 714                 |   | 372                               |   | — |   | — |   |
| Prepaid (accrued) benefit cost at year-end     |   | $                   | 15,126 |                              | $      | 15,340 |   | $ | (11,197 | ) | $ | (9,800 | ) |
|                                           |   |                |   |                              |   |   |   |   |   |
| Discount rate                                  |   | 6.50                | %      | 7.25                              | %      | 6.50 | % | 7.25 | % |
| Expected return on plan assets                 |   | 8.50                | %      | 9.50                              | %      | — |   | — |   |
| Rate of compensation increase                  |   | 4.75                | %      | 4.75                              | %      | — |   | — |   |
| **Components of net periodic benefit cost**    |   |                |   |                              |   |   |   |   |   |
| Service cost                                   |   | $                   | 1,929  |                              | $      | 1,577 |   | $ | 736 |   | $ | 602 |   |
| Interest cost                                  |   | 1,395               |   | 1,144                             |   | 715 |   | 556 |   |
| Expected return on plan assets                 |   | (3,116              | )      | (3,593                            | )      | — |   | — |   |
| Amortization of prior service cost             |   | 6                   |   | (43                               | )      | — |   | — |   |
| Amortization of transition (asset) obligation  |   | —              |   | (26                               | )      | 305 |   | 304 |   |
| Recognized actuarial gain                      |   | —              |   | (476                              | )      | — |   | (96 | ) |
|                                           |   | $                   | 214    |                              | $      | (1,417 | ) | $ | 1,756 |   | $ | 1,366 |   |

 

For measurement purposes,a 13% annual rate of increase in the per capita cost of covered health carebenefits was assumed for 2003. The rate is assumed to decrease gradually to 5%for 2012 and remain at that level thereafter.  This compares to the amounts used for 2002 measurement purposes, where a10% annual rate of increase in the per capita cost of covered health carebenefits was assumed, decreasing gradually to 5% for 2007 and remaining levelthereafter.

 

59

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

 

|                                                             |   | **One  Percentage Point** |   |
|------------------------------------------------------------------|--------|---------------------------|--------|
|                                                             |   | **Increase**              |   | **Decrease** |   |
| Effect on total of service and interest cost components for 2002 |   | $                         | 260    |   | $ | (209 | ) |
| Effect on year-end 2002 postretirement benefit obligation        |   | $                         | 2,349  |   | $ | (1,917 | ) |

 

(9)          **Stock-BasedCompensation Plans**

 

The Company’s incentiveplans authorize awards granted wholly or partly in common stock (includingrights or options which may be exercised for or settled in common stock) to keyemployees and non-employee directors. Awards to employees of the Company may bemade as grants of stock options, stock appreciation rights, stock awards, cashawards, performance awards or any combination thereof (collectively,“Awards”).  Employee Awards generallybecome exercisable in three installments. Non-employee directors are granted options to purchase 10,000 shares ofcommon stock on the first business day of June following such director’sinitial election or appointment and options to purchase 5,000 shares of commonstock each year of their service as a director thereafter.  Stock options, if not exercised, expire 10years from the date of grant.  A summaryof the status of the Company’s incentive plans as of December 31, 2002, 2001and 2000, and changes during the years ended on those dates is presented below:

 

|                                                       |   | **Number of  Options** |   | **Weighted  Average  Exercise  Price** |   |
|------------------------------------------------------------|--------|------------------------|--------|----------------------------------------|--------|
|                                                       |   |                   |   |                                   |   |
| Outstanding, December 31, 1999                             |   | 3,005,615              |   | $                                      | 19.78  |   |
| Granted in 2000                                            |   | 722,800                |   | $                                      | 20.58  |   |
| Exercised in 2000                                          |   | (314,850               | )      | $                                      | 15.33  |   |
| Canceled in 2000                                           |   | (5,942                 | )      | $                                      | 13.32  |   |
| Outstanding, December 31, 2000                             |   | 3,407,623              |   | $                                      | 20.37  |   |
| Exercisable, December 31, 2000                             |   | 2,026,517              |   | $                                      | 20.72  |   |
| Available for grant, December 31, 2000                     |   | 932,677                |   |                                   |   |
| Weighted-average fair value of options granted during 2000 |   |                   |   | $                                      | 9.58   |   |
|                                                       |   |                   |   |                                   |   |
| Outstanding, December 31, 2000                             |   | 3,407,623              |   | $                                      | 20.37  |   |
| Granted in 2001                                            |   | 1,035,400              |   | $                                      | 25.35  |   |
| Exercised in 2001                                          |   | (377,764               | )      | $                                      | 17.30  |   |
| Canceled in 2001                                           |   | (208,832               | )      | $                                      | 21.75  |   |
| Outstanding, December 31, 2001                             |   | 3,856,427              |   | $                                      | 21.93  |   |
| Exercisable, December 31, 2001                             |   | 2,267,561              |   | $                                      | 21.09  |   |
| Available for grant, December 31, 2001                     |   | 898,520                |   |                                   |   |
| Weighted-average fair value of options granted during 2001 |   |                   |   | $                                      | 11.98  |   |
|                                                       |   |                   |   |                                   |   |
| Outstanding, December 31, 2001                             |   | 3,856,427              |   | $                                      | 21.93  |   |
| Granted in 2002                                            |   | 960,900                |   | $                                      | 29.84  |   |
| Exercised in 2002                                          |   | (1,022,034             | )      | $                                      | 19.72  |   |
| Canceled in 2002                                           |   | (61,847                | )      | $                                      | 23.49  |   |
| Outstanding, December 31, 2002                             |   | 3,733,446              |   | $                                      | 24.54  |   |
| Exercisable, December 31, 2002                             |   | 1,992,883              |   | $                                      | 22.41  |   |
| Available for grant, December 31, 2002                     |   | 2,911,565              |   |                                   |   |
| Weighted-average fair value of options granted during 2002 |   |                   |   | $                                      | 12.43  |   |

 

60

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The following tablesummarizes information about stock options outstanding at December 31, 2002

 
|                        |   | **Options  Outstanding** |   | **Options  Exercisable**                                    |   |
|-----------------------------|--------|--------------------------|--------|-------------------------------------------------------------|--------|
| **Range of  Option Prices** |   | **Number  Outstanding**  |   | **Weighted  Average  Remaining  Contractual  Life  (days)** |   | **Weighted  Average  Exercise  Price** |   | **Number  Exercisable** |   | **Weighted  Average  Exercise  Price** |   |
|                        |   |                     |   |                                                        |   |   |   |   |   |   |   |
| $ 15.13 to $19.56           |   | 700,808                  |   | 2,055                                                       |   | $ | 18.89 |   | 698,808 |   | $ | 18.90 |   |
| $ 20.31 to $24.81           |   | 1,800,403                |   | 2,599                                                       |   | $ | 22.63 |   | 1,028,633 |   | $ | 21.93 |   |
| $ 25.38 to $29.78           |   | 1,054,735                |   | 3,392                                                       |   | $ | 29.53 |   | 90,942 |   | $ | 27.39 |   |
| $ 31.18 to $33.94           |   | 58,500                   |   | 2,772                                                       |   | $ | 32.17 |   | 55,500 |   | $ | 32.20 |   |
| $ 36.00                     |   | 50,000                   |   | 1,250                                                       |   | $ | 36.00 |   | 50,000 |   | $ | 36.00 |   |
| $ 40.63 to $41.00           |   | 69,000                   |   | 1,626                                                       |   | $ | 40.92 |   | 69,000 |   | $ | 40.92 |   |
| Total                       |   | 3,733,446                |   | 2,688                                                       |   | $ | 24.54 |   | 1,992,883 |   | $ | 22.41 |   |

 

**(10)  FairValue of Financial Instruments**

 

The following methods andassumptions were used to estimate the fair value of each class of financialinstruments for which it is practicable to estimate that value.

 

*Cashand Cash Equivalents*

 

Fair value is carryingvalue.

 

*Receivablesand Payables*

 

Fair value approximatescarrying value.

 

*DerivativeFinancial Instruments*

 

Fair value is carryingvalue.

 

61

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*Debtand Other*

 
| **Instrument******                                                                                         |   | **Basis of Fair Value Estimate******                                                                                                                                        |   |
|------------------------------------------------------------------------------------------------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
| Bank revolving  credit agreement                                                                           |   | Fair value was carrying  value as of December 31, 2002 and 2001   based on the market value interest rates.                                                            |   |
| Banker’s  acceptance loans                                                                            |   | Fair value was carrying  value as of December 31, 2002 and 2001 based on the market value interest  rates.                                                                  |   |
| 2007 Notes                                                                                                 |   | Fair value was 104.25%  and 102%, of carrying value as of December 31, 2002 and 2001, respectively,  based on quoted market values.                                         |   |
| 2009 Notes                                                                                                 |   | Fair value was 108% and  107.5%, of carrying value as of December 31, 2002 and 2001, respectively,  based on quoted market values.                                          |   |
| 2011 Notes                                                                                                 |   | Fair value was 105% and  101.25% of carrying value as of December 31, 2002 and 2001, respectively,  based on quoted market value.                                           |   |
| 2006 Notes                                                                                                 |   | Fair value was 106.71%  and 95.625%, of carrying value as of December 31, 2002 and 2001,  respectively, based on quoted market values.                                      |   |
| Minority interest in  company-obligated mandatorily redeemable preferred securities of a subsidiary  trust |   | Fair value was 117.8%  of carrying value as of December 31, 2001, based on quoted market values.  This instrument was called for redemption by the Company on June 3, 2002. |   |

 

The carrying value andestimated fair value of the Company’s financial instruments at December 31,2002 and 2001 (in thousands of dollars) are as follows:

 

|                                                                                                      |   | **2002**            |       | **2001**        |       |
|-----------------------------------------------------------------------------------------------------------|--------|---------------------|------------|-----------------|------------|
|                                                                                                      |   | **Carrying  Value** |       | **Fair  Value** |       | **Carrying  Value** |   | **Fair  Value** |   |
|                                                                                                      |   |                | ** ** |            | ** ** |   | ** ** |   | ** ** |
| Cash and cash equivalents                                                                                 |   | $                   | 134,449    |            | $          | 134,449 |   | $ | 94,294 |   | $ | 94,294 |   |
| Receivables                                                                                               |   | $                   | 116,441    |            | $          | 116,441 |   | $ | 112,040 |   | $ | 112,040 |   |
| Payables                                                                                                  |   | $                   | (125,592   | )               | $          | (125,592 | ) | $ | (137,451 | ) | $ | (137,451 | ) |
| Debt:                                                                                                     |   |                |       |            |       |   |   |   |   |
| Bank revolving credit agreement loans                                                                     |   | $                   | (135,000   | )               | $          | (135,000 | ) | $ | (205,000 | ) | $ | (205,000 | ) |
| Banker’s acceptance loans                                                                            |   | $                   | (24,987    | )               | $          | (24,987 | ) | $ | (24,990 | ) | $ | (24,990 | ) |
| 2007 Notes                                                                                                |   | $                   | (100,000   | )               | $          | (104,250 | ) | $ | (100,000 | ) | $ | (102,000 | ) |
| 2009 Notes                                                                                                |   | $                   | (147,916   | )               | $          | (162,000 | ) | $ | (147,571 | ) | $ | (161,250 | ) |
| 2011 Notes                                                                                                |   | $                   | (200,000   | )               | $          | (210,000 | ) | $ | (200,000 | ) | $ | (202,500 | ) |
| 2006 Notes                                                                                                |   | $                   | (115,000   | )               | $          | (122,711 | ) | $ | (115,000 | ) | $ | (109,969 | ) |
| Minority interest in company obligated mandatorily redeemable  preferred securities of a subsidiary trust |   | $                   | —     |            | $          | — |   | $ | (150,000 | ) | $ | (176,700 | ) |

 

The Company occasionallyenters into hedging contracts to minimize the impact of oil and gas pricefluctuations. See Note 11 for a further discussion of these contracts.

 

62

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**(11)Hedging Activities —**

 

During 2002 and 2001, the Company recognizedpre-tax gains of $3,640,000  ($2,367,000after tax) and $14,592,000 ($9,485,000 after tax), respectively, from its pricehedge contracts which are included in oil and gas revenues.  No ineffectiveness on these hedge contractswas recognized in income.  Unrealizedlosses on derivative instruments of $16,521,000 (net of deferred taxes of$8,896,000) have been reflected as a component of other comprehensive incomefor the year ended December 31, 2002. Based on the fair value of the hedgecontracts as of December 31, 2002, the Company would reclassify additionalpre-tax losses of approximately $9,614,000 (approximately $6,249,000 aftertaxes) from accumulated other comprehensive income (shareholders’ equity) tonet income during the next twelve months.

 

As of December 31, 2002, the Company heldvarious derivative instruments.  During2002, the Company entered into natural gas and crude oil option agreementsreferred to as “collars”.  Collars aredesigned to establish floor and ceiling prices on anticipated future naturalgas and crude oil production. The Company has designated these contracts ascash flow hedges designed to achieve a more predictable cash flow, as well asto reduce its exposure to price volatility. While the use of these derivativeinstruments limits the downside risk of adverse price movements, they may alsolimit future revenues from favorable price movements. The use of derivativesalso involves the risk that the counterparties to such instruments will beunable to meet the financial terms of such contracts.  Currently, the Company does not expect losses due to creditworthiness of its counterparties.

 

The gas hedging transactions are generallysettled based upon the average of the reporting settlement prices on the NYMEXfor the last three trading days of a particular contract month. The oil hedgingtransactions are generally settled based on the average of the reportingsettlement prices for West Texas Intermediate on the NYMEX for each trading dayof a particular calendar month.  For anyparticular collar transaction, the counterparty is required to make a paymentto the Company if the settlement price for any settlement period is below thefloor price for such transaction, and the Company is required to make a paymentto the counterparty if the settlement price for any settlement period is abovethe ceiling price of such transaction.

 

The estimated fair value of these derivative instruments is based upon various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options.  Further details related to the Company’s hedging activities as of December 31, 2002, are as follows:

 

| **Contract  Period and  Type of Contract** |   | **Volume**  |   | **NYMEX  Contract  Price** |   | **Fair  Value of  Liability** |   |
|--------------------------------------------|--------|-------------|--------|----------------------------|--------|-------------------------------|--------|
| **Floor**                                  |   | **Ceiling** |
|                                       |   |        |   |                       |   |                          |   |   |   |
| **Natural  Gas Contracts (MMBtu) (a)**     |   |        |   |                       |   |                          |   |   |   |
| Collar Contracts:                          |   |        |   |                       |   |                          |   |   |   |
| January 2003  -  December 2003   |   | 14,600      |   | $                          | 3.85   |                          | $      | 5.00 |   | $ | (2,127,192 | ) |
|                                       |   |        |   |                       |   |                          |   |   |   |
| **Crude  Oil Contracts (Barrels)**         |   |        |   |                       |   |                          |   |   |   |
| Collar Contracts:                          |   |        |   |                       |   |                          |   |   |   |
| January 2003  -  December 2003   |   | 3,650,000   |   | $                          | 25.00  |                          | $      | 30.00 |   | $ | (305,636 | ) |

 

----

(a)  MMBtu means million British Thermal Units.

 

63

 

In January 2003,the Company entered into additional natural gas collars to establish floor andceiling prices on anticipated future natural gas production.  The Company has designated these contracts as cash flow hedges.  Further details related to this hedgingactivity is as follows:

 

| **Contract  Period and  Type of Contract** |   | **Volume**  |   | **NYMEX  Contract  Price** |   |
|--------------------------------------------|--------|-------------|--------|----------------------------|--------|
| **Floor**                                  |   | **Ceiling** |
|                                       |   |        |   |                       |   |   |   |
| **Natural  Gas Contracts (MMBtu)**         |   |        |   |                       |   |   |   |
| Collar Contracts:                          |   |        |   |                       |   |   |   |
| January 2003  -  December 2003   |   | 6,680       |   | $                          | 4.25   |   | $ | 7.00 |   |
|                                            |        |             |        |                            |        |  |  |  |  |

 

64

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

**UNAUDITEDSUPPLEMENTARY FINANCIAL DATA**

 

**Oil andGas Producing Activities**

 

The results of operationsfrom oil and gas producing activities exclude non-oil and gas revenues, generaland administrative expenses, depreciation expense, interest charges, interestincome and interest capitalized. Income tax (expense) or benefit was determinedby applying the statutory rates to pretax operating results with adjustmentsfor permanent differences.

 
|                                             |   | **Total  Company**            |    | **United  States** |   | **Kingdom of  Thailand** |   | **Canada** |    | **Other** |   |
|--------------------------------------------------|--------|-------------------------------|---------|--------------------|--------|--------------------------|--------|------------|---------|-----------|--------|
|                                             |   | **(Expressed  in thousands)** |
|                                             |   |                          |    |               |   |                     |   |       |    |      |   |
|                                             |   | **2002**                      |
|                                             |   |                          |    |               |   |                     |   |       |    |      |   |
| Revenues                                         |   | $                             | 746,952 |               | $      | 534,268                  |   | $          | 212,684 |      | $      | — |   | $ | — |   |
| Lease operating expense                          |   | (139,466                      | )       | (101,219           | )      | (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                  | )      | —     |    | —    |   |
| Pretax operating results                         |   | 291,839                       |    | 183,253            |   | 108,664                  |   | —     |    | (78       | )      |
| Income tax (expense) benefit                     |   | (128,498                      | )       | (65,545            | )      | (62,967                  | )      | —     |    | 14        |   |
| Operating results                                |   | $                             | 163,341 |               | $      | 117,708                  |   | $          | 45,697  |      | $      | — |   | $ | (64 | ) |
|                                                  |        |                               |         |                    |        |                          |        |            |         |           |        |  |  |  |  |  |  |

 
|                                             |   | **2001** |
|--------------------------------------------------|--------|----------|
|                                             |   |     |   |   |   |   |   |   |   |   |   |
| Revenues                                         |   | $        | 596,077 |   | $ | 408,514 |   | $ | 183,005 |   | $ | 4,558 |   | $ | — |   |
| Lease operating expense                          |   | (118,157 | ) | (79,916 | ) | (36,993 | ) | (1,248 | ) | — |   |
| Exploration expense                              |   | (23,373  | ) | (11,877 | ) | (2,162 | ) | (600 | ) | (8,734 | )(a) |
| Dry hole and impairment expense                  |   | (26,945  | ) | (26,136 | ) | — |   | (809 | ) | — |   |
| Depreciation, depletion and amortization expense |   | (203,676 | ) | (140,304 | ) | (61,243 | ) | (2,129 | ) | — |   |
| Pretax operating results                         |   | 223,926  |   | 150,281 |   | 82,607 |   | (228 | ) | (8,734 | ) |
| Income tax (expense) benefit                     |   | (96,590  | ) | (52,598 | ) | (46,322 | ) | 100 |   | 2,230 |   |
| Operating results                                |   | $        | 127,336 |   | $ | 97,683 |   | $ | 36,285 |   | $ | (128 | ) | $ | (6,504 | ) |

 
|                                             |   | **2000** |
|--------------------------------------------------|--------|----------|
|                                             |   |     |   |   |   |   |   |   |   |   |   |
| Revenues                                         |   | $        | 479,202 |   | $ | 291,266 |   | $ | 183,060 |   | $ | 4,876 |   | $ | — |   |
| Lease operating expense                          |   | (93,368  | ) | (58,916 | ) | (33,568 | ) | (884 | ) | — |   |
| Exploration expense                              |   | (15,291  | ) | (6,532 | ) | (3,507 | ) | (856 | ) | (4,396 | )(b) |
| Dry hole and impairment expense                  |   | (28,608  | ) | (28,142 | ) | — |   | (466 | ) | — |   |
| Depreciation, depletion and amortization expense |   | (129,476 | ) | (76,516 | ) | (50,968 | ) | (1,992 | ) | — |   |
| Pretax operating results                         |   | 212,459  |   | 121,160 |   | 95,017 |   | 678 |   | (4,396 | ) |
| Income tax (expense) benefit                     |   | (87,307  | ) | (41,059 | ) | (47,509 | ) | (278 | ) | 1,539 |   |
| Operating results                                |   | $        | 125,152 |   | $ | 80,101 |   | $ | 47,508 |   | $ | 400 |   | $ | (2,857 | ) |

 

----

(a) Included in Other are costs associated with activities relatedalmost entirely to Hungary.

 

(b) Included in Other arecosts associated with  initialactivities related to Hungary of $3,396, the British sector of the North Sea of$836, and the Danish sector of the North Sea of $164.

 

65

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The following table setsforth the Company’s costs incurred (expressed in thousands) for oil and gasproducing activities during the years indicated.

 
|                                                     |   | **Total  Company** |      | **United  States** |   | **Kingdom of  Thailand** |   | **Canada** |    | **Other** |   |
|----------------------------------------------------------|--------|--------------------|-----------|--------------------|--------|--------------------------|--------|------------|---------|-----------|--------|
| Costs incurred (capitalized unless otherwise indicated): |   |               |      |               |   |                     |   |       |    |      |   |
| **2002:**                                                |   |               |      |               |   |                     |   |       |    |      |   |
| Property acquisition                                     |   |               |      |               |   |                     |   |       |    |      |   |
| Unproved                                                 |   | $                  | 8,030     |               | $      | 8,030                    |   | $          | —  |      | $      | — |   | $ | — |   |
| Exploration                                              |   |               |      |               |   |                     |   |       |    |      |   |
| Capitalized                                              |   | 43,165             |      | 40,028             |   | 3,137                    |   | —     |    | —    |   |
| Expensed                                                 |   | 4,783              |      | 2,797              |   | 1,907                    |   | —     |    | 79        | (a)    |
| Development                                              |   | 303,197            |      | 205,035            |   | 98,162                   |   | —     |    | —    |   |
| Interest                                                 |   | 24,033             |      | 12,892             |   | 11,141                   |   | —     |    | —    |   |
| Total oil and gas costs incurred                         |   | $                  | 383,208   |               | $      | 268,782                  |   | $          | 114,347 |      | $      | — |   | $ | 79 |   |
| Provision for depreciation, depletion and amortization   |   | $                  | 283,865   |               | $      | 218,636                  |   | $          | 65,229  |      | $      | — |   | $ | — |   |
|                                                     |   |               |      |               |   |                     |   |       |    |      |   |
| **2001:**                                                |   |               |      |               |   |                     |   |       |    |      |   |
| Property acquisition                                     |   |               |      |               |   |                     |   |       |    |      |   |
| Proved                                                   |   | $                  | 949,704   |               | $      | 949,673                  |   | $          | —  |      | $      | 31 |   | $ | — |   |
| Unproved                                                 |   | 172,947            |      | 172,947            |   |                     |   |       |    | —    |   |
| Exploration                                              |   |               |      |               |   |                     |   |       |    |      |   |
| Capitalized                                              |   | 59,390             |      | 48,290             |   | 9,180                    |   | 1,920      |    | —    |   |
| Expensed                                                 |   | 23,373             |      | 11,877             |   | 2,162                    |   | 600        |    | 8,734     | (a)    |
| Development                                              |   | 314,736            |      | 255,800            |   | 57,816                   |   | 1,120      |    | —    |   |
| Interest                                                 |   | 33,242             |      | 27,046             |   | 6,196                    |   | —     |    | —    |   |
| Total oil and gas costs incurred                         |   | $                  | 1,553,392 |               | $      | 1,465,633                |   | $          | 75,354  |      | $      | 3,671 |   | $ | 8,734 |   |
| Provision for depreciation, depletion and amortization   |   | $                  | 203,676   |               | $      | 140,304                  |   | $          | 61,243  |      | $      | 2,129 |   | $ | — |   |
|                                                     |   |               |      |               |   |                     |   |       |    |      |   |
| **2000:**                                                |   |               |      |               |   |                     |   |       |    |      |   |
| Property acquisition                                     |   |               |      |               |   |                     |   |       |    |      |   |
| Proved                                                   |   | $                  | 8,393     |               | $      | 8,393                    |   | $          | —  |      | $      | — |   | $ | — |   |
| Unproved                                                 |   | 10,725             |      | 7,602              |   | 1,394                    |   | 1,729      |    | —    |   |
| Exploration                                              |   |               |      |               |   |                     |   |       |    |      |   |
| Capitalized                                              |   | 37,076             |      | 23,978             |   | 8,006                    |   | 5,092      |    | —    |   |
| Expensed                                                 |   | 15,291             |      | 6,532              |   | 3,507                    |   | 856        |    | 4,396     | (b)    |
| Development                                              |   | 108,991            |      | 71,621             |   | 36,034                   |   | 1,336      |    | —    |   |
| Interest                                                 |   | 20,918             |      | 5,446              |   | 15,472                   |   | -          |    | —    |   |
| Total oil and gas costs incurred                         |   | $                  | 201,394   |               | $      | 123,572                  |   | $          | 64,413  |      | $      | 9,013 |   | $ | 4,396 |   |
| Provision for depreciation, depletion and amortization   |   | $                  | 129,476   |               | $      | 76,516                   |   | $          | 50,968  |      | $      | 1,992 |   | $ | — |   |

 

----

(a)  Included in Other are costs associated withactivities related almost entirely to Hungary.

 

(b)  Included in the expensed exploration costsreflected in Other are costs associated with initial activities related to Hungary of $3,396, the British sector ofthe North Sea of $836, and the Danish sector of the North Sea.

 

66

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The following informationregarding estimates of the Company’s proved oil and gas reserves, which arelocated offshore in United States waters of the Gulf of Mexico, onshore in theUnited States and offshore in the Kingdom of Thailand is based on reportsprepared by Ryder Scott Company, L.P. and Miller & Lents, Ltd. Thedefinitions and assumptions that serve as the basis for the discussions underthe caption “Item 1, Business—Exploration and Production Data—Reserves” shouldbe referred to in connection with the following information.

 

**Estimatesof Proved Reserves**

 

**Oil,Condensate and Natural Gas Liquids (Bbls.)**

 
|                                        |   | **Total  Company** |   | **United  States** |   | **Kingdom  of Thailand** |   | **Canada** |   |
|---------------------------------------------|--------|--------------------|--------|--------------------|--------|--------------------------|--------|------------|--------|
|                                        |   |               |   |               |   |                     |   |       |   |
| Proved Reserves as of December 31, 1999     |   | 78,776,417         |   | 41,553,662         |   | 36,655,697               |   | 567,058    |   |
| Revisions of previous estimates             |   | 2,335,209          |   | 2,561,793          |   | (480,335                 | )      | 253,751    |   |
| Extensions, discoveries and other additions |   | 24,741,720         |   | 19,115,830         |   | 5,546,923                |   | 78,967     |   |
| Purchase of properties                      |   | 23,657             |   | 23,657             |   | —                   |   | —     |   |
| Sale of properties                          |   | (205,506           | )      | (205,506           | )      | —                   |   | —     |   |
| Estimated 2000 production                   |   | (10,350,000        | )      | (5,571,000         | )      | (4,657,000               | )      | (122,000   | )      |
| 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               |   | —     |   |
|                                        |   |               |   |               |   |                     |   |       |   |
| Proved Developed Reserves as of:            |   |               |   |               |   |                     |   |       |   |
| December 31, 1999                           |   | 53,894,653         |   | 35,136,156         |   | 18,407,852               |   | 350,645    |   |
| 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               |   | —     |   |

 

67

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**Estimatesof Proved Reserves**

** **

**NaturalGas (MMcf)**

** **
|                                        |   | **Total  Company** |   | **United  States** |   | **Kingdom of  Thailand** |   | **Canada** |   |
|---------------------------------------------|--------|--------------------|--------|--------------------|--------|--------------------------|--------|------------|--------|
|                                        |   |               |   |               |   |                     |   |       |   |
| Proved Reserves as of December 31, 1999     |   | 374,698            |   | 220,129            |   | 153,588                  |   | 981        |   |
| Revisions of previous estimates             |   | (2,245             | )      | 3,110              |   | (5,518                   | )      | 163        |   |
| Extensions, discoveries and other additions |   | 56,372             |   | 28,623             |   | 26,605                   |   | 1,144      |   |
| Purchase of properties                      |   | 2,601              |   | 2,601              |   | —                   |   | —     |   |
| Sale of properties                          |   | (1,195             | )      | (1,195             | )      | —                   |   | —     |   |
| Estimated 2000 production                   |   | (60,248            | )      | (38,647            | )      | (21,371                  | )      | (230       | )      |
| 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                  |   | —     |   |
|                                        |   |               |   |               |   |                     |   |       |   |
| Proved Developed Reserves as of:            |   |               |   |               |   |                     |   |       |   |
| December 31, 1999                           |   | 245,257            |   | 156,398            |   | 88,041                   |   | 818        |   |
| 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                   |   | —     |   |

 

68

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**POGOPRODUCING COMPANY & SUBSIDIARIES**

 

**STANDARDIZEDMEASURE OF DISCOUNTED FUTURE**

**NETCASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES—Unaudited**

 

The standardized measureof discounted future net cash flows from the production of proved reserves isdeveloped as follows:

 

1.    Estimatesare made of quantities of proved reserves and the future periods in which theyare expected to be produced based on year-end economic conditions.

 

2.    Theestimated future gross revenues from proved reserves are priced on the basis ofyear-end market prices, except in those instances where fixed and determinablenatural gas price escalations are covered by contracts.

 

3.    Thefuture gross revenue streams are reduced by estimated future costs to developand to produce the proved reserves, as well as certain abandonment costs basedon year-end cost estimates, and the estimated effect of future income taxes.These cost estimates are subject to some uncertainty.

 

The standardized measureof discounted future net cash flows does not purport to present the fair valueof the Company’s oil and gas reserves. An estimate of fair value would alsotake into account, among other things, the recovery of reserves in excess ofproved reserves, anticipated future changes in prices and costs, a discountfactor more representative of the time value of money and the risks inherent inreserve estimates.

 

The following are the principalsources of change in the standardized measure of discounted future net cashflows. All amounts are related to changes in reserves located in the UnitedStates, the Kingdom of Thailand, and Canada, as noted.

 
|                                                                                  |   | **Year Ended  December 31, 2002** |       |
|---------------------------------------------------------------------------------------|--------|-----------------------------------|------------|
|                                                                                  |   | **Total  Company**                | ** ** | **United  States** | ** ** | **Kingdom of  Thailand** | ** ** |
|                                                                                  |   | (Expressed  in thousands)         |       |
| Beginning balance                                                                     |   | $                                 | 1,138,048  |   | $ | 826,570 |   | $ | 311,478 |   |
| Revisions to prior years’ proved reserves:                                       |   |                              |       |   |   |   |   |
| Net changes in prices and production costs                                            |   | 1,285,867                         |       | 1,096,580 |   | 189,287 |   |
| Net changes due to revisions in quantity estimates                                    |   | 255,617                           |       | 202,952 |   | 52,665 |   |
| Net changes in estimates of future development costs                                  |   | (183,597                          | )          | (97,784 | ) | (85,813 | ) |
| Accretion of discount                                                                 |   | 240,283                           |       | 189,055 |   | 51,228 |   |
| Changes in production rate and other                                                  |   | (69,640                           | )          | (15,695 | ) | (53,945 | ) |
| Total revisions                                                                       |   | 1,528,530                         |       | 1,375,108 |   | 153,422 |   |
| New field discoveries and extensions, net of future production and  development costs |   | 334,335                           |       | 218,991 |   | 115,344 |   |
| Sales of properties                                                                   |   | (2,344                            | )          | (2,344 | ) | - |   |
| Sales of oil and gas produced, net of production costs                                |   | (607,486                          | )          | (433,049 | ) | (174,437 | ) |
| Previously estimated development costs incurred                                       |   | 304,661                           |       | 206,499 |   | 98,162 |   |
| Net change in income taxes                                                            |   | (640,529                          | )          | (476,987 | ) | (163,542 | ) |
| Net change in standardized measure of discounted future net cash flows                |   | 917,167                           |       | 888,218 |   | 28,949 |   |
|                                                                                  |   |                              |       |   |   |   |   |
| Ending balance                                                                        |   | $                                 | 2,055,215  |   | $ | 1,714,788 |   | $ | 340,427 |   |

 

69

----

 
|                                                                                  |   | **Year Ended  December 31, 2001** |       |
|---------------------------------------------------------------------------------------|--------|-----------------------------------|------------|
|                                                                                  |   | **Total  Company**                | ** ** | **United  States** | ** ** | **Kingdom of  Thailand** | ** ** | **Canada** | ** ** |
|                                                                                  |   | (Expressed  in thousands)         |       |
| Beginning balance                                                                     |   | $                                 | 1,715,176  |   | $ | 1,327,734 |   | $ | 370,630 |   | $ | 16,812 |   |
| Revisions to prior years’ proved reserves:                                       |   |                              |       |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |   | (1,184,494                        | )          | (1,083,561 | ) | (100,933 | ) | — |   |
| Net changes due to revisions in quantity estimates                                    |   | 85,497                            |       | 32,533 |   | 53,016 |   | (52 | ) |
| Net changes in estimates of future development costs                                  |   | (149,719                          | )          | (120,496 | ) | (28,784 | ) | (439 | ) |
| Accretion of discount                                                                 |   | 245,492                           |       | 192,555 |   | 50,602 |   | 2,335 |   |
| Changes in production rate and other                                                  |   | 19,636                            |       | 19,571 |   | (4,666 | ) | 4,731 |   |
| Total revisions                                                                       |   | (983,588                          | )          | (959,398 | ) | (30,765 | ) | 6,575 |   |
| New field discoveries and extensions, net of future production and  development costs |   | 166,518                           |       | 126,429 |   | 40,089 |   | — |   |
| Purchases of properties                                                               |   | 345,728                           |       | 345,728 |   | — |   | — |   |
| Sales of properties                                                                   |   | (93,384                           | )          | (65,787 | ) | — |   | (27,597 | ) |
| Sales of oil and gas produced, net of production costs                                |   | (477,970                          | )          | (328,648 | ) | (146,012 | ) | (3,310 | ) |
| Previously estimated development costs incurred                                       |   | 128,440                           |       | 86,484 |   | 40,974 |   | 982 |   |
| Net change in income taxes                                                            |   | 337,128                           |       | 294,028 |   | 36,562 |   | 6,538 |   |
| Net change in standardized measure of discounted future net cash flows                |   | (577,128                          | )          | (501,164 | ) | (59,152 | ) | (16,812 | ) |
|                                                                                  |   |                              |       |   |   |   |   |   |   |
| Ending balance                                                                        |   | $                                 | 1,138,048  |   | $ | 826,570 |   | $ | 311,478 |   | $ | — |   |

 
|                                                                                  |   | **Year Ended  December 31, 2000** |       |
|---------------------------------------------------------------------------------------|--------|-----------------------------------|------------|
|                                                                                  |   | **Total  Company**                | ** ** | **United  States** | ** ** | **Kingdom of  Thailand** | ** ** | **Canada** | ** ** |
|                                                                                  |   | (Expressed  in thousands)         |       |
| Beginning balance                                                                     |   | $                                 | 868,683    |   | $ | 448,629 |   | $ | 410,468 |   | $ | 9,586 |   |
| Revisions to prior years’ proved reserves:                                       |   |                              |       |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |   | 817,201                           |       | 839,536 |   | (26,592 | ) | 4,257 |   |
| Net changes due to revisions in quantity estimates                                    |   | 55,574                            |       | 63,945 |   | (13,759 | ) | 5,388 |   |
| Net changes in estimates of future development costs                                  |   | (22,657                           | )          | (43,119 | ) | 21,527 |   | (1,065 | ) |
| Accretion of discount                                                                 |   | 115,465                           |       | 57,584 |   | 56,959 |   | 922 |   |
| Changes in production rate and other                                                  |   | 110,717                           |       | 125,761 |   | (13,029 | ) | (2,015 | ) |
| Total revisions                                                                       |   | 1,076,300                         |       | 1,043,707 |   | 25,106 |   | 7,487 |   |
| New field discoveries and extensions, net of future production and  development costs |   | 494,689                           |       | 460,239 |   | 25,147 |   | 9,303 |   |
| Purchases of properties                                                               |   | 11,135                            |       | 11,135 |   | — |   | — |   |
| Sales of properties                                                                   |   | (5,712                            | )          | (5,712 | ) | — |   | — |   |
| Sales of oil and gas produced, net of production costs                                |   | (385,834                          | )          | (232,350 | ) | (149,492 | ) | (3,992 | ) |
| Previously estimated development costs incurred                                       |   | 109,692                           |       | 72,690 |   | 35,666 |   | 1,336 |   |
| Net change in income taxes                                                            |   | (453,777                          | )          | (470,604 | ) | 23,735 |   | (6,908 | ) |
| Net change in standardized measure of discounted future net cash flows                |   | 846,493                           |       | 879,105 |   | (39,838 | ) | 7,226 |   |
|                                                                                  |   |                              |       |   |   |   |   |   |   |
| Ending balance                                                                        |   | $                                 | 1,715,176  |   | $ | 1,327,734 |   | $ | 370,630 |   | $ | 16,812 |   |

 

70

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|                                                                                             |   | **Total  Company**        |       | **United  States** |   | **Kingdom of  Thailand** |   | **Canada** |      |
|--------------------------------------------------------------------------------------------------|--------|---------------------------|------------|--------------------|--------|--------------------------|--------|------------|-----------|
|                                                                                             |   | (Expressed  in thousands) |       |
|                                                                                             |   |                      |       |               |   |                     |   |       |      |
|                                                                                             |   | **2002**                  | ** ** |
|                                                                                             |   |                      |       |               |   |                     |   |       |      |
| Future gross revenues                                                                            |   | $                         | 7,078,353  |               | $      | 5,486,454                |   | $          | 1,591,899 |   | $ | — |   |
| Future production costs:                                                                         |   |                      |       |               |   |                     |   |       |      |
| Lease operating expense                                                                          |   | (1,819,485                | )          | (1,150,305         | )      | (669,180                 | )      | —     |      |
| Future development and abandonment costs                                                         |   | (406,101                  | )          | (267,578           | )      | (138,523                 | )      | —     |      |
| Future net cash flows before income taxes                                                        |   | 4,852,767                 |       | 4,068,571          |   | 784,196                  |   | —     |      |
| Discount at 10% per annum                                                                        |   | (1,754,411                | )          | (1,573,013         | )      | (181,398                 | )      | —     |      |
| Discounted future net cash flows before income taxes                                             |   | 3,098,356                 |       | 2,495,558          |   | 602,798                  |   | —     |      |
| Future income taxes, net of discount at 10% per annum                                            |   | (1,043,141                | )          | (780,770           | )      | (262,371                 | )      | —     |      |
| Standardized measure of discounted future net cash flows related to  proved oil and gas reserves |   | $                         | 2,055,215  |               | $      | 1,714,788                |   | $          | 340,427   |   | $ | — |   |
|                                                                                             |   |                      |       |               |   |                     |   |       |      |
|                                                                                             |   | **2001**                  | ** ** |
|                                                                                             |   |                      |       |               |   |                     |   |       |      |
| Future gross revenues                                                                            |   | $                         | 4,202,888  |               | $      | 3,115,416                |   | $          | 1,087,472 |   | $ | — |   |
| Future production costs:                                                                         |   |                      |       |               |   |                     |   |       |      |
| Lease operating expense                                                                          |   | (1,354,815                | )          | (899,262           | )      | (455,553                 | )      | —     |      |
| Future development and abandonment costs                                                         |   | (445,239                  | )          | (325,600           | )      | (119,639                 | )      | —     |      |
| Future net cash flows before income taxes                                                        |   | 2,402,834                 |       | 1,890,554          |   | 512,280                  |   | —     |      |
| Discount at 10% per annum                                                                        |   | (862,174                  | )          | (760,201           | )      | (101,973                 | )      | —     |      |
| Discounted future net cash flows before income taxes                                             |   | 1,540,660                 |       | 1,130,353          |   | 410,307                  |   | —     |      |
| Future income taxes, net of discount at 10% per annum                                            |   | (402,612                  | )          | (303,783           | )      | (98,829                  | )      | —     |      |
| Standardized measure of discounted future net cash flows related to  proved oil and gas reserves |   | $                         | 1,138,048  |               | $      | 826,570                  |   | $          | 311,478   |   | $ | — |   |
|                                                                                             |   |                      |       |               |   |                     |   |       |      |
|                                                                                             |   | **2000**                  | ** ** |
|                                                                                             |   |                      |       |               |   |                     |   |       |      |
| Future gross revenues                                                                            |   | $                         | 4,926,262  |               | $      | 3,624,205                |   | $          | 1,250,223 |   | $ | 51,834 |   |
| Future production costs:                                                                         |   |                      |       |               |   |                     |   |       |      |
| Lease operating expense                                                                          |   | (1,043,108                | )          | (550,020           | )      | (473,022                 | )      | (20,066    | )         |
| Future development and abandonment costs                                                         |   | (316,467                  | )          | (196,308           | )      | (119,476                 | )      | (683       | )         |
| Future net cash flows before income taxes                                                        |   | 3,566,687                 |       | 2,877,877          |   | 657,725                  |   | 31,085     |      |
| Discount at 10% per annum                                                                        |   | (1,111,771                | )          | (952,332           | )      | (151,704                 | )      | (7,735     | )         |
| Discounted future net cash flows before income taxes                                             |   | 2,454,916                 |       | 1,925,545          |   | 506,021                  |   | 23,350     |      |
| Future income taxes, net of discount at 10% per annum                                            |   | (739,740                  | )          | (597,811           | )      | (135,391                 | )      | (6,538     | )         |
| Standardized measure of discounted future net cash flows related to  proved oil and gas reserves |   | $                         | 1,715,176  |               | $      | 1,327,734                |   | $          | 370,630   |   | $ | 16,812 |   |

 

71

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**Quarterly Results—Unaudited**

 

Summaries of the Company’s results of operations by quarter for theyears 2002 and 2001 are as follows:

 
|                    |   | **Quarter Ended**                                   |    |
|-------------------------|--------|-----------------------------------------------------|---------|
|                    |   | **Mar. 31**                                         |    | **June 30** |   | **Sept. 30** |   | **Dec. 31** |   |
|                    |   | (Expressed  in thousands, except per share amounts) |    |
| **2002**                |   |                                                |    |   |   |   |   |   |   |
| Revenues                |   | $                                                   | 142,910 |   | $ | 184,385 |   | $ | 207,808 |   | $ | 216,338 |   |
| Gross profit (a)        |   | $                                                   | 40,821  |   | $ | 71,006 |   | $ | 86,040 |   | $ | 91,795 |   |
| Net income              |   | $                                                   | 9,025   |   | $ | 28,618 |   | $ | 31,637 |   | $ | 37,751 |   |
| Earnings per share (b): |   |                                                |    |   |   |   |   |   |   |
| Basic                   |   | $                                                   | 0.17    |   | $ | 0.51 |   | $ | 0.52 |   | $ | 0.62 |   |
| Diluted                 |   | $                                                   | 0.17    |   | $ | 0.48 |   | $ | 0.51 |   | $ | 0.60 |   |
|                    |   |                                                |    |   |   |   |   |   |   |
| **2001**                |   |                                                |    |   |   |   |   |   |   |
| Revenues                |   | $                                                   | 169,851 |   | $ | 170,384 |   | $ | 144,275 |   | $ | 125,607 |   |
| Gross profit (a)        |   | $                                                   | 85,232  |   | $ | 64,071 |   | $ | 45,938 |   | $ | 23,802 |   |
| Net income              |   | $                                                   | 39,946  |   | $ | 30,979 |   | $ | 15,603 |   | $ | 1,426 |   |
| Earnings per share (b): |   |                                                |    |   |   |   |   |   |   |
| Basic                   |   | $                                                   | 0.93    |   | $ | 0.58 |   | $ | 0.29 |   | $ | 0.03 |   |
| Diluted                 |   | $                                                   | 0.80    |   | $ | 0.53 |   | $ | 0.28 |   | $ | 0.03 |   |

 

----

(a)   Represents revenues less lease operating,natural gas purchases and other, exploration, dry hole, and impairment, anddepreciation, depletion and amortization expenses.

 

(b)   The sum of the individual quarterlyearnings (loss) per share may not agree with year-to-date earnings (loss) pershare as each quarterly computation is based on the income or loss for thatquarter and the weighted average number of common shares outstanding during thatperiod.

 

**ITEM 9. Changes in and DisagreementsWith Accountants on Accounting and Financial Disclosure.**

 

Previously reported onForm 8-K, dated April 17, 2002.

 

72

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###### **PART III**

 

**ITEM 10.*    Directorsand Executive Officers of the Registrant.***

 

The information responsive to Items 401 and 405 ofRegulation S-K in the Company’s definitive Proxy Statement for its annualmeeting to be held on April 22, 2003, to be filed within 120 days of December31, 2002 pursuant to Regulation 14A under the Securities Exchange Act of 1934,as amended (the Company’s “2003 Proxy Statement”), is incorporated herein byreference. See also Item S-K 401(b) appearing in Part I of this Form 10-K.

 

**ITEM 11.*    ExecutiveCompensation.***

 

The information responsiveto Item 402 of Regulation S-K inthe Company’s 2003 Proxy Statement, other than the information regarding theCompensation Committee Report on Executive Compensation, is incorporated hereinby

reference.

 

**ITEM 12.*    SecurityOwnership of Certain Beneficial Owners and Management and Related StockholderMatters.***

 

The information responsive to Item 403 of RegulationS-K in the Company’s 2003 Proxy Statement is incorporated herein by reference.

 

**EQUITYCOMPENSATION PLAN INFORMATION**

 

The following table sets forth information about theCommon Stock that may be issued under all of the Company's existing equitycompensation plans as of December 31, 2002:

 
| **Plan  category**                                          |   | **Number of  securities  to be issued upon  exercise of  outstanding options,  warrants and rights** |   | **Weighted  average  exercise price of  outstanding options,  warrants and rights** |   | **Number of  securities  remaining available for  future issuance** |      |
|-------------------------------------------------------------|--------|------------------------------------------------------------------------------------------------------|--------|-------------------------------------------------------------------------------------|--------|---------------------------------------------------------------------|-----------|
| Equity compensation plans  approved by security holders     |   | 2,553,642                                                                                            |   | $                                                                                   | 24.14  |                                                                | 1,983,632 | (1) |
| Equity compensation plans  not approved by security holders |   | 1,179,804                                                                                            |   | $                                                                                   | 25.47  |                                                                | 927,933   | (2) |
| Total                                                       |   | 3,733,446                                                                                            |   | $                                                                                   | 24.54  |                                                                | 2,911,565 |   |

 

----

(1)           The securities remaining availablefor issuance under the approved plans may be issued in the form of stockoptions, stock appreciation rights, stock awards and performance shares.  The shares remaining available for issuancemay be used for any of these types of awards. The exercise price may be paid in cash or by tendering already-ownedCommon Stock.  Awards are in general nottransferrable, subject to exceptions in certain cases involving transfers to afamily member or related entities if approved by the committee administeringthe plan.

 

(2)           Shares remaining available forissuance under the 1998 Nonqualified Incentive Plan (the only non-approvedplan) include only stock options and stock appreciation rights, the exercise orreference price of which may not exceed the fair market value of the CommonStock on the date of grant.  The exerciseprice may be paid in cash or by tendering already-owned common stock.  Awards are in general not transferrable,subject to exceptions in certain cases involving transfers to a family memberor related entities if approved by the committee administering the plan.

 

**ITEM 13.*    CertainRelationships and Related Transactions.***

 

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

 

**ITEM 14. *Controls and Procedures.***

 

Within 90 days prior to the filing of this report, anevaluation was performed under the supervision and with the participation ofthe Company’s management, including the Chairman, President and Chief ExecutiveOfficer and the Senior Vice President and Chief Financial Officer, of theeffectiveness of the design and operation of the  Company’s disclosure controls and procedures. Based on thatevaluation, the Company’s management, including the Chairman, President andChief Executive Officer and the Senior Vice President and Chief FinancialOfficer, concluded that the Company’s disclosure controls and procedures wereeffective in ensuring that material information relating to the Company withrespect to the period covered by this report was made known to them. There havebeen no significant changes in the Company’s internal controls or in otherfactors that could significantly affect internal controls subsequent to thedate of that evaluation.

 

###### **PART IV**

 

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

 

*(a)  FinancialStatements and Supplementary Data, Financial Statement Schedules and Exhibits*

 
|   |                                                  | **Page** |
|--------|-------------------------------------------------------|----------|
| **1.** | **Financial  Statements and Supplementary Data:**     |     |
|   | Reports of  Independent Public Accountants            | 38       |
|   | Consolidated  statements of income                    | 40       |
|   | Consolidated balance sheets                           | 41       |
|   | Consolidated  statements of cash flows                | 43       |
|   | Consolidated  statements of shareholders’ equity | 44       |
|   | Notes to  consolidated financial statements           | 45       |
|   | Unaudited  supplementary financial data               | 65       |
|   |                                                  |     |
| **2.** | **Financial  Statement Schedules:**                   |     |

 

All Financial StatementSchedules have been omitted because they are not required, are not applicableor the information required has been included elsewhere herein.

 

73

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| **3.**       | **Exhibits:**                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|--------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *2.1         | Agreement  and Plan of Merger dated as of November 19, 2000, among Pogo Producing  Company, NORIC Corporation, and the shareholders signatory thereto (Exhibit  4.1, Current Report on Form 8-K filed March 26, 2001, File No. 1-7792).                                                                                                                                                                                                                                       |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *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 June 15, 1996, between Pogo Producing Company and Fleet National  Bank (now State Street Bank & Trust Company as successor in interest  under the Indenture), as Trustee (Exhibit 4(f), Quarterly Report on Form 10-Q  for the quarter ended June 30, 1996, File No. 001-7792).                                                                                                                                                                    |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4.3         | Indenture  dated as of May 15, 1997, between Pogo Producing Company and Fleet National  Bank (now State Street Bank & Trust Company as successor in interest  under the Indenture), as Trustee (Exhibit 4.3, Registration Statement on Form  S-4, filed July 2, 1997, File No. 333-30613).                                                                                                                                                                                |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4.4         | 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).                                                                                                                                                                                                                                                 |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4.5         | Indenture  dated as of April 10, 2001, between Pogo Producing Company and Wells Fargo  Bank Minnesota, National Association, as Trustee (Exhibit 4.2, Registration  Statement on Form S-4, filed April 24, 2001, File No. 333-59426).                                                                                                                                                                                                                                         |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4.6         | 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, 2002. 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 10.18, 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 Stuart P.  Burbach, dated February 1, 2003.                                                                                                                                                                                                                                                                                                                                                         |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.9  | Executive  Employment Agreement by and between Pogo Producing Company and Jerry A.  Cooper, dated February 1, 2003.                                                                                                                                                                                                                                                                                                                                                           |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.10 | Executive  Employment Agreement by and between Pogo Producing Company and R. Phillip  Laney, dated February 1, 2003.                                                                                                                                                                                                                                                                                                                                                          |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.11 | Executive  Employment Agreement by and between Pogo Producing Company and John O. McCoy,  Jr., dated February 1,2003.                                                                                                                                                                                                                                                                                                                                                         |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.12 | Executive  Employment Agreement by and between Pogo Producing Company and Paul G. Van  Wagenen, dated February 1,2003.                                                                                                                                                                                                                                                                                                                                                        |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.13 | Executive  Employment Agreement by and between Pogo Producing Company and Bruce E.  Archinal, dated as of February 1, 2003.                                                                                                                                                                                                                                                                                                                                                   |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.14 | Executive  Employment Agreement by and between Pogo Producing Company and David R.  Beathard, dated as of February 1, 2003.                                                                                                                                                                                                                                                                                                                                                   |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.15 | Executive  Employment Agreement by and between Pogo Producing Company and Stephen R.  Brunner, dated as of February 1, 2003.                                                                                                                                                                                                                                                                                                                                                  |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.16 | Executive  Employment Agreement by and between Pogo Producing Company and J. D.  McGregor, dated as of February 1,2003.                                                                                                                                                                                                                                                                                                                                                       |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.17 | Executive  Employment Agreement by and between Pogo Producing Company and Gerald A.  Morton, dated as of February 1, 2003.                                                                                                                                                                                                                                                                                                                                                    |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.18 | Executive  Employment Agreement by and between Pogo Producing Company and James P. Ulm,  II, dated as of February 1, 2003.                                                                                                                                                                                                                                                                                                                                                    |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *10.19       | 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).                                                                                                                                                                                                                   |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *10.20       | 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).                                                                                                                                                                                  |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *10.21       | 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).                                                                                                                                                                                                              |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *10.22       | 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).                                                                                                                                                          |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   10.23 | 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.                                                                                                                                                                                                                                   |
|         |                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   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 & 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, 2002.                                                                                                                                                                                                                                                                                                                              |

 

* Asterisk indicates exhibits incorporated byreference as shown.

 

*(b)  Reports on Form8-K*

 

No reports on Form 8-Khave been filed during the last quarter of the period covered by this report.

 

74

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**SIGNATURES**

 

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

 
|                          | POGO PRODUCING COMPANY                             |
|-------------------------------|----------------------------------------------------|
|                          | (REGISTRANT)                                       |
|                          |                                               |
|                          | BY:                                                | /s/  PAUL G. VAN WAGENEN |   |
|                          | **Paul G. Van Wagenen**                            |
|                          | *Chairman,  President and Chief Executive Officer* |
|                          |                                               |
| Date:  February 27, 2003 |                                               |

 

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the Registrant and in the capacitiesindicated on February 27, 2003.

 
| **Signatures**                                                            |   | **Title**                                 |
|---------------------------------------------------------------------------|--------|-------------------------------------------|
|                                                                      |   |                                      |
| /s/ PAUL G. VAN WAGENEN                                                   |   |                                      |
| **Paul G. Van Wagenen***Chairman,  President and Chief Executive Officer* |   | Principal Executive Officer  and Director |
|                                                                      |   |                                      |
| /s/ JAMES P. ULM, II                                                      |   |                                      |
| **James P. Ulm, II***Senior  Vice President and Chief Financial Officer*  |   | Principal Financial Officer               |
|                                                                      |   |                                      |
| /s/ THOMAS E. HART                                                        |   |                                      |
| **Thomas E. Hart***Vice  President and Chief Accounting Officer*          |   | Principal Accounting  Officer             |
|                                                                      |   |                                      |
| /s/ JERRY M. ARMSTRONG                                                    |   |                                      |
| **Jerry M. Armstrong**                                                    |   | Director                                  |
|                                                                      |   |                                      |
| /s/ ROBERT H. CAMPBELL                                                    |   |                                      |
| **Robert H. Campbell**                                                    |   | Director                                  |
|                                                                      |   |                                      |
| /s/ WILLIAM L. FISHER                                                     |   |                                      |
| **William L. Fisher**                                                     |   | Director                                  |
|                                                                      |   |                                      |
| /s/ GERRIT W. GONG                                                        |   |                                      |
| **Gerrit W. Gong**                                                        |   | Director                                  |
|                                                                      |   |                                      |
| /s/ CARROLL W. SUGGS                                                      |   |                                      |
| **Carroll W. Suggs**                                                      |   | Director                                  |
|                                                                      |   |                                      |
| /s/ STEPHEN A. WELLS                                                      |   |                                      |
| **Stephen A. Wells**                                                      |   | Director                                  |
|                                                                      |   |                                      |
| /s/ THOMAS A. HART                                                        |   |                                      |
| **Thomas E. Hart***Attorney-in-Fact*                                      |   |                                      |

 

75

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**CERTIFICATIONS**

 

I, Paul G. Van Wagenen, certify that:

 

1.       I have reviewed this annual report onForm 10-K of Pogo Producing Company (the “Company”);

 

2.       Based on my knowledge, this annual reportdoes not contain any untrue statement of a material fact or omit to state amaterial fact necessary in order to make the statements made, in light of thecircumstances under which they were made, not misleading with respect to theperiod covered by this annual report;

 

3.       Based on my knowledge, the financialstatements and other financial information included in this annual reportfairly presents, in all material respects, the financial condition, results ofoperations and cash flows of the Company as of, and for, the periods presentedin this annual report;

 

4.       The Company’s other certifying officerand I are responsible for establishing and maintaining disclosure controls andprocedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Companyand have:

 

a.       designed such disclosure controls andprocedures to ensure that material information relating to the Company,including its consolidated subsidiaries, are made known to us by others withinthose entities, particularly during the period in which this annual report is beingpresented;

 

b.       evaluatedthe effectiveness of the Company’s disclosure controls and procedures as of adate within 90 days prior to the filing date of this annual report (the“Evaluation Date”); and

 

c.       presented in this annual report ourconclusions about the effectiveness of the disclosure controls and proceduresbased on our evaluation as of the Evaluation Date;

 

5.       The Company’s other certifying officerand I have disclosed, based on our most recent evaluation, to the Company’sauditors and the Audit Committee of the Company’s Board of Directors:

 

a.       all significant deficiencies in thedesign or operation of internal controls that could adversely affect theCompany’s ability to record, process, summarize and report financial data andhave identified for the Company’s auditors any material weaknesses in internalcontrols; and

 

b.       anyfraud, whether or not material, that involves management or other employees whohave a significant role in the Company’s internal controls;

 

6.       The Company’s other certifying officerand I have indicated in this annual report whether there were significantchanges in internal controls or in other factors that could significantlyaffect internal controls subsequent to the date of our most recent evaluation,including any corrective actions with regard to significant deficiencies andmaterial weaknesses.

 

Date: February 27, 2003

 
|   | /s/ Paul G. Van Wagenen                         |   |
|--------|-------------------------------------------------|--------|
|   | Paul G. Van Wagenen                             |
|   | Chairman, President and Chief Executive Officer |

** **

76

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**CERTIFICATIONS**

 

I, James P. Ulm, II, certify that:

 

7.       I have reviewed this annual report onForm 10-K of Pogo Producing Company (the “Company”);

 

8.       Based on my knowledge, this annual reportdoes not contain any untrue statement of a material fact or omit to state amaterial fact necessary in order to make the statements made, in light of thecircumstances under which they were made, not misleading with respect to theperiod covered by this annual report;

 

9.       Based on my knowledge, the financialstatements and other financial information included in this annual reportfairly presents, in all material respects, the financial condition, results ofoperations and cash flows of the Company as of, and for, the periods presentedin this annual report;

 

10.     TheCompany’s other certifying officer and I are responsible for establishing andmaintaining disclosure controls and procedures (as defined in Exchange ActRules 13a-14 and 15d-14) for the Company and have:

 

a.       designed such disclosure controls andprocedures to ensure that material information relating to the Company,including its consolidated subsidiaries, are made known to us by others withinthose entities, particularly during the period in which this annual report isbeing presented;

 

b.       evaluatedthe effectiveness of the Company’s disclosure controls and procedures as of adate within 90 days prior to the filing date of this annual report (the“Evaluation Date”); and

 

c.       presented in this annual report ourconclusions about the effectiveness of the disclosure controls and proceduresbased on our evaluation as of the Evaluation Date;

 

11.     TheCompany’s other certifying officer and I have disclosed, based on our mostrecent evaluation, to the Company’s auditors and the Audit Committee of theCompany’s Board of Directors:

 

a.       all significant deficiencies in thedesign or operation of internal controls that could adversely affect theCompany’s ability to record, process, summarize and report financial data andhave identified for the Company’s auditors any material weaknesses in internalcontrols; and

 

b.       anyfraud, whether or not material, that involves management or other employees whohave a significant role in the Company’s internal controls;

 

12.     TheCompany’s other certifying officer and I have indicated in this annual reportwhether there were significant changes in internal controls or in other factorsthat could significantly affect internal controls subsequent to the date of ourmost recent evaluation, including any corrective actions with regard tosignificant deficiencies and material weaknesses.

 

 

Date: February 27, 2003

 
|   | /s/ James P. Ulm, II                              |   |
|--------|---------------------------------------------------|--------|
|   | James P. Ulm, II                                  |
|   | Senior Vice President and Chief Financial Officer |

 

77

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